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<SEC-DOCUMENT>0000072741-01-000075.txt : 20010329
<SEC-HEADER>0000072741-01-000075.hdr.sgml : 20010329
ACCESSION NUMBER:		0000072741-01-000075
CONFORMED SUBMISSION TYPE:	10-K
PUBLIC DOCUMENT COUNT:		18
CONFORMED PERIOD OF REPORT:	20001231
FILED AS OF DATE:		20010328

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			NORTHEAST UTILITIES SYSTEM
		CENTRAL INDEX KEY:			0000072741
		STANDARD INDUSTRIAL CLASSIFICATION:	ELECTRIC SERVICES [4911]
		IRS NUMBER:				042147929
		STATE OF INCORPORATION:			MA
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		10-K
		SEC ACT:		
		SEC FILE NUMBER:	001-05324
		FILM NUMBER:		1581348

	BUSINESS ADDRESS:	
		STREET 1:		174 BRUSH HILL AVE
		CITY:			WEST SPRINGFIELD
		STATE:			MA
		ZIP:			01090-0010
		BUSINESS PHONE:		4137855871

	MAIL ADDRESS:	
		STREET 1:		107 SELDON ST
		CITY:			BERLIN
		STATE:			CT
		ZIP:			06037-1616

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			CONNECTICUT LIGHT & POWER CO
		CENTRAL INDEX KEY:			0000023426
		STANDARD INDUSTRIAL CLASSIFICATION:	ELECTRIC SERVICES [4911]
		IRS NUMBER:				060303850
		STATE OF INCORPORATION:			CT
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		10-K
		SEC ACT:		
		SEC FILE NUMBER:	000-00404
		FILM NUMBER:		1581349

	BUSINESS ADDRESS:	
		STREET 1:		SELDEN STREET
		CITY:			BERLIN
		STATE:			CT
		ZIP:			06037-1616
		BUSINESS PHONE:		8606655000

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			WESTERN MASSACHUSETTS ELECTRIC CO
		CENTRAL INDEX KEY:			0000106170
		STANDARD INDUSTRIAL CLASSIFICATION:	ELECTRIC SERVICES [4911]
		IRS NUMBER:				041961130
		STATE OF INCORPORATION:			MA
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		10-K
		SEC ACT:		
		SEC FILE NUMBER:	000-07624
		FILM NUMBER:		1581350

	BUSINESS ADDRESS:	
		STREET 1:		174 BRUSH HILL AVE
		CITY:			WEST SPRINGFIELD
		STATE:			MA
		ZIP:			01090-0010
		BUSINESS PHONE:		4137855871

	MAIL ADDRESS:	
		STREET 1:		107 SELDON ST
		CITY:			BERLIN
		STATE:			CT
		ZIP:			06037-1616

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			PUBLIC SERVICE CO OF NEW HAMPSHIRE
		CENTRAL INDEX KEY:			0000315256
		STANDARD INDUSTRIAL CLASSIFICATION:	ELECTRIC SERVICES [4911]
		IRS NUMBER:				020181050
		STATE OF INCORPORATION:			NH
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		10-K
		SEC ACT:		
		SEC FILE NUMBER:	001-06392
		FILM NUMBER:		1581351

	BUSINESS ADDRESS:	
		STREET 1:		1000 ELM ST
		CITY:			MANCHESTER
		STATE:			NH
		ZIP:			03105
		BUSINESS PHONE:		6036694000

	MAIL ADDRESS:	
		STREET 1:		1000 ELM STREET
		CITY:			MANCHESTER
		STATE:			NH
		ZIP:			03105

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			NORTH ATLANTIC ENERGY CORP /NH
		CENTRAL INDEX KEY:			0000880416
		STANDARD INDUSTRIAL CLASSIFICATION:	ELECTRIC SERVICES [4911]
		IRS NUMBER:				061339460
		STATE OF INCORPORATION:			NH
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		10-K
		SEC ACT:		
		SEC FILE NUMBER:	033-43508
		FILM NUMBER:		1581352

	BUSINESS ADDRESS:	
		STREET 1:		1000 ELM ST
		CITY:			MANCHESTER
		STATE:			NH
		ZIP:			03105
		BUSINESS PHONE:		6036694000

	MAIL ADDRESS:	
		STREET 1:		1000 ELM STREET
		CITY:			MANCHESTER
		STATE:			NH
		ZIP:			03105
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>0001.txt
<TEXT>



                                     FORM 10-K

                         SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549-1004

             [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                  SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]

                   For the fiscal year ended December 31, 2000

                                        OR

          [  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
                   SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

                 For the transition period from ________ to ________

Commission     Registrant; State of Incorporation;           I.R.S. Employer
File Number       Address; and Telephone Number              Identification No.
- -----------    -----------------------------------           ------------------

1-5324         NORTHEAST UTILITIES                               04-2147929
               (a Massachusetts voluntary association)
               174 Brush Hill Avenue
               West Springfield, Massachusetts 01090-2010
               Telephone:  (413) 785-5871

0-11419        THE CONNECTICUT LIGHT AND POWER COMPANY           06-0303850
               (a Connecticut corporation)
               107 Selden Street
               Berlin, Connecticut 06037-1616
               Telephone:  (860) 665-5000

1-6392         PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE           02-0181050
               (a New Hampshire corporation)
               1000 Elm Street
               Manchester, New Hampshire 03105-0330
               Telephone:  (603) 669-4000

0-7624         WESTERN MASSACHUSETTS ELECTRIC COMPANY            04-1961130
               (a Massachusetts corporation)
               174 Brush Hill Avenue
               West Springfield, Massachusetts 01090-2010
               Telephone:  (413) 785-5871

33-43508       NORTH ATLANTIC ENERGY CORPORATION                 06-1339460
               (a New Hampshire corporation)
               1000 Elm Street
               Manchester, New Hampshire 03105-0330
               Telephone:  (603) 669-400

Securities registered pursuant to Section 12(b) of the Act:

                                                  Name of Each Exchange
Registrant            Title of Each Class         on Which Registered
- ----------            -------------------         ---------------------

Northeast Utilities   Common Shares,              New York Stock Exchange, Inc.
                      $5.00 par value

The Connecticut       9.3% Cumulative             New York Stock Exchange, Inc.
Light and Power       Monthly Income
Company               Preferred Securities
                      Series A (1)

(1) Issued by CL&P Capital LP (CL&P LP), a wholly owned subsidiary of The
    Connecticut Light and Power Company (CL&P), and guaranteed by CL&P.

Securities registered pursuant to Section 12(g) of the Act:

      Registrant                          Title of Each Class
      ----------                          -------------------

The Connecticut Light       Preferred Stock, par value $50.00 per share,
  and Power Company         issuable in series, of which the following
                            series are outstanding:

                             $1.90  Series   of 1947    4.96% Series   of 1958
                             $2.00  Series   of 1947    4.50% Series   of 1963
                             $2.04  Series   of 1949    5.28% Series   of 1967
                             $2.20  Series   of 1949   $3.24  Series G of 1968
                              3.90% Series   of 1949    6.56% Series   of 1968
                             $2.06  Series E of 1954
                             $2.09  Series F of 1955
                              4.50% Series   of 1956

Public Service Company      Preferred Stock, par value $25.00 per share,
  of New Hampshire          issuable in series, of which the following series
                            is outstanding:

                             10.60% Series A of 1991

Western Massachusetts       Preferred Stock, par value $100.00 per share,
  Electric Company          issuable in series, of which the following series
                            is outstanding:

                              7.72% Series B of 1971

                            Class A Preferred Stock, par value $25.00 per
                            share, issuable in series, of which the following
                            series is outstanding:

                              7.60% Series of 1987

Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days.

                            Yes  X             No
                                ---            ---

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.  [ ]


The aggregate market value of Northeast Utilities' Common Shares, $5.00 Par
Value, held by nonaffiliates, was $3,035,128,320 based on a closing sales
price of $20.40 per share for the 148,780,800 common shares outstanding on
February 28, 2001.  Northeast Utilities holds all of the 7,584,884 shares,
1,000 shares, 590,093 shares, and 1,000 shares of the outstanding common
stock of The Connecticut Light and Power Company, Public Service Company
of New Hampshire, Western Massachusetts Electric Company, and North Atlantic
Energy Corporation, respectively.

Documents Incorporated by Reference:

                                                     Part of Form 10-K
                                                     into Which Document
                   Description                         is Incorporated
                   -----------                       -------------------

Portions of Annual Reports of the following
companies for the year ended December 31, 2000:

     The Connecticut Light and Power Company               Part II
     Public Service Company of New Hampshire               Part II
     Western Massachusetts Electric Company                Part II
     North Atlantic Energy Corporation                     Part II





                               GLOSSARY OF TERMS


     The following is a glossary of frequently used abbreviations or acronyms
that are found throughout this report:


COMPANIES

CL&P............................... The Connecticut Light and Power Company
Con Edison......................... Consolidated Edison, Inc.
CYAPC.............................. Connecticut Yankee Atomic Power Company
Dominion........................... Dominion Resources, Inc.
HEC................................ HEC Inc.
HWP................................ Holyoke Water Power Company
Mode 1............................. Mode 1 Communications, Inc.
MYAPC.............................. Maine Yankee Atomic Power Company
NAEC............................... North Atlantic Energy Corporation
NAESCO............................. North Atlantic Energy Service Corporation
NEON............................... NEON Communications, Inc.
NGC................................ Northeast Generation Company
NGS................................ Northeast Generation Services Company
NNECO.............................. Northeast Nuclear Energy Company
NU or the Company.................. Northeast Utilities
NUEI............................... NU Enterprises, Inc.
NUSCO or the Service Company....... Northeast Utilities Service Company
PSNH............................... Public Service Company of New Hampshire
RRR................................ The Rocky River Realty Company
Select Energy...................... Select Energy, Inc.
SEPPI.............................. Select Energy Portland Pipeline, Inc.
The NU system...................... The Northeast Utilities System
The Yankee Companies............... CYAPC, MYAPC, VYNPC, and YAEC
VYNPC.............................. Vermont Yankee Nuclear Power Corporation
WMECO.............................. Western Massachusetts Electric Company
YAEC............................... Yankee Atomic Electric Company
Yankee............................. Yankee Energy System, Inc.
Yankee Gas......................... Yankee Gas Services Company

GENERATING UNITS

Millstone 1........................ Millstone Unit No. 1, a 660 MW nuclear
                                    unit completed in 1970; Millstone 1 is
                                    currently in decommissioning status.
Millstone 2........................ Millstone Unit No. 2, an 870 MW nuclear
                                    electric generating unit completed in 1975
Millstone 3........................ Millstone Unit No. 3, a 1,154 MW nuclear
                                    electric generating unit completed in 1986
Seabrook or Seabrook 1............. Seabrook Unit No. 1, a 1,148 MW nuclear
                                    electric generating unit completed in 1986.
                                    Seabrook 1 went into service in 1990.
REGULATORS

CDEP............................... Connecticut Department of
                                    Environmental Protection
DOE................................ United States Department of Energy
DPUC............................... Connecticut Department of
                                    Public Utility Control
DTE................................ Massachusetts Department of
                                    Telecommunications and Energy
EPA................................ United States Environmental
                                    Protection Agency
FERC............................... Federal Energy Regulatory Commission
NHDES.............................. New Hampshire Department of
                                    Environmental Services
NHPUC.............................. New Hampshire Public Utilities Commission
NRC................................ Nuclear Regulatory Commission
SEC................................ Securities and Exchange Commission

OTHER

1935 Act........................... Public Utility Holding Company Act of 1935
CAAA............................... Clean Air Act Amendments of 1990
kWh................................ Kilowatt-hour
MW................................. Megawatt
NEPOOL............................. New England Power Pool
NUG&T.............................. Northeast Utilities Generation and
                                    Transmission Agreement



                                 NORTHEAST UTILITIES
                       THE CONNECTICUT LIGHT AND POWER COMPANY
                       PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
                        WESTERN MASSACHUSETTS ELECTRIC COMPANY
                          NORTH ATLANTIC ENERGY CORPORATION


                             2000 Form 10-K Annual Report
                                  Table of Contents

                                        PART I
                                                                           Page
                                                                           ----

Item 1.    Business...................................................       1

     The Northeast Utilities System...................................       1

     Safe Harbor Statement............................................       2

     Mergers and Acquisitions.........................................       3

           Consolidated Edison, Inc. Merger...........................       3
           Yankee Energy System, Inc. Merger..........................       4

     Rates and Electric Industry Restructuring........................       4

           General....................................................       4
           Connecticut Rates and Restructuring........................       6
           Massachusetts Rates and Restructuring......................       8
           New Hampshire Rates and Restructuring......................       9

     Competitive System Businesses....................................      10

           Energy-Related Products and Services and Gas Investments...      10
           Energy Generation and Services.............................      12
           Energy Management Services.................................      13
           Gas Investments............................................      13
           Telecommunications.........................................      13

     Financing Program................................................      14

           2000 Financings............................................      14
           2001 Financing Requirements................................      16
           2001 Financing Plans.......................................      16
           Financing Limitations......................................      17

     Construction Program.............................................      22

     Regulated Electric Operations....................................      22

           Distribution and Sales.....................................      22
           Regional and System Coordination...........................      23
           Transmission Access and FERC Regulatory Changes............      25

     Regulated Gas Operations.........................................      26

           Regulation.................................................      26

      Nuclear Generation...............................................     27

           General....................................................      27
           Nuclear Plant Performance..................................      28
           Nuclear Insurance..........................................      29
           Nuclear Fuel...............................................      29
           Decommissioning............................................      31

     Other Regulatory and Environmental Matters.......................      34

           Environmental Regulation...................................      34
           Electric and Magnetic Fields...............................      37
           FERC Hydroelectric Project Licensing.......................      37

     Employees........................................................      38

Item 2.    Properties.................................................      39

Item 3.    Legal Proceedings..........................................      44

Item 4.    Submission of Matters to a Vote of Security Holders........      49

                                    PART II

Item 5.    Market for Registrants' Common Equity and Related
           Shareholder Matters.......................................       49

Item 6.    Selected Financial Data...................................       50

Item 7.    Management's Discussion and Analysis of Financial
           Condition and Results of Operations.......................       50

Item 7A.   Quantitative and Qualitative Disclosures About
           Market Risk...............................................       50

Item 8.    Financial Statements and Supplementary Data...............       51

Item 9.    Changes in Disagreements with Accountants on
           Accounting and Financial Disclosure.......................       51

                                   PART III

Item 10.   Directors and Executive Officers of the Registrants.......       52

Item 11.   Executive Compensation....................................       61

Item 12.   Security Ownership of Certain Beneficial Owners and
           Management................................................       71

Item 13.   Certain Relationships and Related Transactions............       76

                                    PART IV

Item 14.   Exhibits, Financial Statement Schedules and
           Reports on Form 8-K......................................        77




                                 NORTHEAST UTILITIES
                       THE CONNECTICUT LIGHT AND POWER COMPANY
                       PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
                        WESTERN MASSACHUSETTS ELECTRIC COMPANY
                          NORTH ATLANTIC ENERGY CORPORATION

                                        PART I

ITEM 1.    BUSINESS

                              THE NORTHEAST UTILITIES SYSTEM

     Northeast Utilities (NU or the Company) is the parent company of the
Northeast Utilities system (NU system).  The NU system furnishes franchised
retail electric service in Connecticut, New Hampshire and western Massachusetts
through three of NU's wholly owned subsidiaries (CL&P, Public Service Company
of New Hampshire [PSNH] and Western Massachusetts Electric Company [WMECO])
and to a limited number of customers through another wholly owned subsidiary,
Holyoke Water Power Company (HWP).  The NU system serves approximately 30
percent of New England's electric needs and is one of the 25 largest electric
utility systems in the country as measured by revenues.

     The NU system also furnishes retail natural gas service in most of
Connecticut through its Yankee Gas Services Company (Yankee Gas) subsidiary,
the largest natural gas distribution company in Connecticut.  Yankee Gas serves
approximately 187,000 residential, commercial and industrial customers in 69
cities and towns in Connecticut.

     NU, through its wholly owned subsidiary, NU Enterprises, Inc. (NUEI), owns
a number of competitive energy and telecommunications related businesses,
including Northeast Generation Company (NGC), Northeast Generation Services
Company (NGS), Select Energy, Inc. (Select Energy), HEC Inc. (HEC), Mode 1
Communications, Inc. (Mode 1), and Select Energy Portland Pipeline, Inc.
(SEPPI).  For information regarding the activities of these subsidiaries, see
"Competitive System Businesses."

     North Atlantic Energy Corporation (NAEC) is a wholly owned special-purpose
operating subsidiary of NU that owns a 35.98 percent interest in the Seabrook
Station nuclear unit (Seabrook) in Seabrook, New Hampshire, and sells its share
of the capacity and output from Seabrook to PSNH under two life-of-unit,
full-cost recovery contracts (Seabrook Power Contracts).

     Several wholly owned subsidiaries of NU provide support services for the
NU system companies and, in some cases, for other New England utilities.
Northeast Utilities Service Company (NUSCO) provides centralized accounting,
administrative, information technology, engineering, financial, legal,
operational, planning, purchasing, and other services to the NU system
companies.  North Atlantic Energy Service Corporation (NAESCO) has operational
responsibility for Seabrook.  Northeast Nuclear Energy Company (NNECO) acts as
agent for the NU system companies in operating the Millstone nuclear generating
units (Millstone) in Waterford, Connecticut.  Three other subsidiaries
construct, acquire or lease some of the property and facilities used by the NU
system companies.

     The NU system is regulated in virtually all aspects of its business by
various federal and state agencies, including the Securities and Exchange
Commission (SEC), the Federal Energy Regulatory Commission (FERC), the Nuclear
Regulatory Commission (NRC) and various state and/or local regulatory
authorities with jurisdiction over the industry and the service areas in which
each company operates, including the Connecticut Department of Public Utility
Control (DPUC), the New Hampshire Public Utilities Commission (NHPUC) and the
Massachusetts Department of Telecommunications and Energy (DTE).  In recent
years, there has been significant legislative and regulatory activity changing
the nature of regulation of the industry.  For more information regarding these
restructuring initiatives, see "Rates and Electric Industry Restructuring" and
"Regulated Electric Operations."

     SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM
     ACT OF 1995

     In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 (Reform Act), NU and its reporting subsidiaries
are hereby filing cautionary statements identifying important factors that
could cause NU or its subsidiaries' actual results to differ materially from
those projected in forward looking statements (as such term is defined in the
Reform Act) made by or on behalf of NU or its subsidiaries in this combined
Form 10-K, in any subsequent filings with the SEC, in presentations, in
response to questions, or otherwise.  Any statements that express or involve
discussions as to expectations, beliefs, plans, objectives, assumptions or
future events, or performance (often, but not always, through the use of words
or phrases such as will likely result, are expected to, will continue, is
anticipated, estimated, projection, outlook) are not statements of historical
facts and may be forward looking.  Forward looking statements involve
estimates, assumptions and uncertainties that could cause actual results to
differ materially from those expressed in the forward looking statements.
Accordingly, any such statements are qualified in their entirety by reference
to, and are accompanied by, the following important factors that could cause NU
or its subsidiaries' actual results to differ materially from those contained
in forward looking statements of NU or its subsidiaries made by or on behalf
of NU or its subsidiaries.

     Any forward looking statement speaks only as of the date on which such
statement is made, and NU and its subsidiaries undertake no obligation to
update any forward looking statement or statements to reflect events or
circumstances after the date on which such statement is made or to reflect the
occurrence of unanticipated events.  New factors emerge from time to time and
it is not possible for management to predict all of such factors, nor can it
assess the impact of each such factor on the business or the extent to which
any factor, or combination of factors may cause actual results to differ
materially from those contained in any forward looking statements.

     Some important factors that could cause actual results or outcomes to
differ materially from those discussed in the forward looking statements
include prevailing governmental policies and regulatory actions, including
those of the SEC, the NRC, the FERC, and state regulatory agencies, with
respect to allowed rates of return, industry and rate structure, operation of
nuclear power facilities, acquisition and disposal of assets and facilities,
operation and construction of plant facilities, recovery of purchased-power
costs, stranded costs, decommissioning costs, and present or prospective
wholesale and retail competition (including but not limited to retail
wheeling and transmission costs).

     The business and profitability of NU and its subsidiaries are also
influenced by economic and geographic factors including political and economic
risks, changes in environmental and safety laws and policies, weather
conditions (including natural disasters), population growth rates and
demographic patterns, competition for retail and wholesale customers, pricing
and transportation of commodities, market demand for energy from plants or
facilities, changes in tax rates or policies or in rates of inflation, changes
in project costs, unanticipated changes in certain expenses and capital
expenditures, capital market conditions, competition for new energy development
opportunities, and legal and administrative proceedings (whether civil or
criminal) and settlements.

     All such factors are difficult to predict, contain uncertainties which
may materially affect actual results and are beyond the control of NU or its
subsidiaries.

                             MERGERS AND ACQUISITIONS

     CONSOLIDATED EDISON, INC. MERGER

     In October 1999, NU and Consolidated Edison, Inc. (Con Edison) agreed to a
merger to combine the two companies.  During 2000, NU and Con Edison received
most of the approvals needed to complete the merger.  Shareholders from both
companies approved the merger in April 2000 and all required state regulatory
approvals were granted by the end of the year.  Additionally, the FERC approved
the merger in May 2000, which approval was reaffirmed on January 24, 2001, when
FERC denied The United Illuminating Company's request for rehearing of the
approval.  The NRC and the U.S. Department of Justice approved the transaction
in August 2000 and February 2001, respectively.  The final required approval,
that of the SEC, was expected in mid-March 2001.

     On February 28, 2001, NU announced that it had requested that Con Edison
provide assurance in writing of its intent to close the merger on the agreed
upon terms by March 2, 2001, which date was later extended to March 5, 2001.
On March 5, 2001, NU announced that Con Edison had advised NU that Con Edison
was not willing to close the merger on the previously agreed upon terms.  NU
said that it had notified Con Edison that it was treating its refusal to
proceed on the terms set forth in the merger agreement as a repudiation and
breach of the merger agreement, and that it would file a lawsuit to obtain
the benefits of the transaction as negotiated for NU's shareholders.  On
March 6, 2001, Con Edison announced that Con Edison had filed suit in the
U.S. District Court for the Southern District of New York (Southern District)
seeking a declaratory judgment that NU failed to satisfy conditions precedent
under the merger agreement and that Con Edison had no further obligations
under the merger agreement.  On March 12, 2001, NU filed suit in the Southern
District seeking substantial monetary damages against Con Edison arising out
of Con Edison's breach of the merger agreement.  NU cannot predict the
outcome of these matters nor their effect upon NU.  For further information
on litigation relating to the proposed merger, see "Item 3. Legal Proceedings."

     Under the terms of the proposed transaction, NU shares would have been
acquired by Con Edison for a base price of $25.00 per share, comprised of 50
percent cash and 50 percent Con Edison shares.  NU shareholders would have
received an additional $1 per share in proceeds because of the progress made in
selling the Millstone nuclear station.  NU shareholders would have received
another $0.0034 per share for each day it took to complete the merger after
August 5, 2000.  Under the agreement, the overall value of the stock and the
overall value of the cash that Con Edison would have provided to NU
shareholders would have been the same if Con Edison's shares averaged between
$36 and $46 per share during the pricing period.  Should Con Edison shares have
averaged below $36 per share, the value of the stock proceeds received by NU
shareholders would have fallen, but should Con Edison shares have averaged
above $46 per share, the value of the stock proceeds would have risen.
Con Edison's share price had no bearing on the value of the cash portion of
the proceeds.  Assuming that Con Edison's stock price averaged between $36
and $46 per share during the applicable pricing period, NU shareholders would
have received approximately $26.84 per share had the merger closed on
April 10, 2001.

     Ultimately the value of the transaction to NU shareholders would have
depended on the timing of the closing, the average price of Con Edison shares
during the pricing period and the effect of proration among all shareholders.

     YANKEE ENERGY SYSTEM, INC. (YANKEE) MERGER

     On March 1, 2000, NU acquired Yankee, and Yankee became a wholly owned
subsidiary of NU.  Yankee is the parent of Yankee Gas, the largest natural gas
distribution company in Connecticut.  NU paid $45 per share, aggregating $478
million, in cash and stock for all Yankee shares.  In addition, NU assumed
$164 million of Yankee's outstanding long-term debt and all of its short-term
debt, which totaled $70 million at closing.  Yankee shareholders received 45
percent of the $478 million in NU common shares and 55 percent in cash.
NU borrowed the cash portion of the acquisition through a short-term loan of
$263 million, and met the stock component by issuing 11.1 million new NU
shares.  NU expects to redeem approximately the same number of shares in the
second quarter of this year by closing out a forward share purchase program
with proceeds from restructuring of its electric utility businesses.  The
forward share purchase program was conducted late in 1999 and early in 2000
through two financial institutions. With certain limited exceptions, NU's
merger agreement with Con Edison prohibited NU from purchasing additional
shares, but the forward shares may be retired at any time.

     Yankee continues to act as the holding company of Yankee Gas and its three
nonutility subsidiaries, NorConn Properties, Inc., which holds the property and
facilities of the Yankee companies; Yankee Energy Financial Services Company,
which provides customers with financing for energy equipment installations,
and; R.M. Services, Inc., which provides debt collection service to utilities
and other businesses nationwide.  For further information on the Yankee
companies, see "Regulated Gas Operations."

                       RATES AND ELECTRIC INDUSTRY RESTRUCTURING

     GENERAL

     NU's electric utility subsidiaries, CL&P, WMECO and PSNH, are undergoing
fundamental changes in their business operations as a result of the
restructuring of the electric industry in their respective jurisdictions.  Most
notably, the companies have been divesting, and are continuing to divest,
their generation assets and will act solely as transmission and distribution
companies in the future.  In general, their customers will be able to choose
their energy suppliers, with the electric utility companies furnishing
"standard offer" service just to those customers who do not choose a
competitive supplier.  Critical to this restructuring is the companies' ability
to recover their stranded costs.  Stranded costs are expenditures incurred, or
commitments for future expenditures made, on behalf of customers with the
expectation such expenditures would continue to be recoverable in the future
through rates.  However, under certain circumstances these costs might not be
recoverable from customers in a fully competitive electric utility industry
(i.e., the costs may result in above-market energy prices).

     As discussed more fully below, Connecticut and Massachusetts have enacted
restructuring legislation that permits CL&P and WMECO to recover substantially
all of their prudently incurred stranded costs. NU, PSNH and the state of New
Hampshire have reached a settlement (Settlement Agreement), which affects
restructuring as to PSNH and will permit PSNH to recover a substantial portion
of its stranded costs.

     Electric utility restructuring in Connecticut, New Hampshire and
Massachusetts provides for a transition period of several years following the
opening of each state's electric market to customer choice.  During that
interim period, the energy delivery companies, including CL&P, WMECO and PSNH,
are responsible for arranging for the supply of power to customers who do not
select alternative energy suppliers.  Management recognizes that in other
states electric companies have been negatively affected by the inability to
recover supply costs on a timely basis.  However, the Company believes that
current statutes and regulatory policy in the three states in which NU
subsidiaries operate electric delivery businesses will permit timely recovery.

     CL&P has signed fixed-price contracts with three suppliers who together
will serve all of CL&P's standard offer requirements through 2003.  One of
these suppliers is the Company's competitive marketing affiliate, Select
Energy.  CL&P is fully recovering all of the payments it is making to those
suppliers and has financial guarantees from each supplier to shield CL&P from
risk in the event any of the suppliers encounters financial difficulties.
See "Connecticut Rates and Restructuring."

     WMECO signed new one-year supply contracts with three unaffiliated
suppliers in December 2000 that will continue through the end of 2001.  In
January 2001, the DTE approved a 17.4 percent increase in overall bills to
allow WMECO to fully recover its supply costs on a current basis.   See
"Massachusetts Rates and Restructuring."

     As of the beginning of 2001, PSNH remained a vertically integrated utility
with cost-of-service ratemaking and a fuel adjustment clause.  For the first
nine months following the commencement of retail competition, customers who do
not choose alternative suppliers will be served by PSNH with energy from PSNH's
existing generating plants and power purchase contracts.  When they are fully
operable, PSNH's current supply sources are generally well in excess of
customer demand.  Nine months after the commencement of retail competition,
PSNH is required to bid out the supply of its transition service customers
(those who do not take service from competitive suppliers).  PSNH is currently
limited to charging residential and small commercial customers 4.4 cents per
kilowatt-hour for the first 12 months after the bids take effect and 4.6 cents
per kilowatt-hour for the second 12 months.  Those prices are now well below
the wholesale market price for firm requirements power in New England.  Under
the New Hampshire restructuring statute, PSNH will be required to expense the
first $7 million of costs that cannot be collected under the rate cap and then
will be able to defer the balance for future recovery.  See "New Hampshire
Rates and Restructuring."

     CONNECTICUT RATES AND RESTRUCTURING

     In a series of decisions issued during 1999 and 2000, the DPUC approved
CL&P's restructuring consistent with Connecticut's 1998 restructuring law.
Choice of electric supplier was available to CL&P customers living in
distressed cities (35 percent of CL&P total load) on January 1, 2000, and to
all CL&P customers effective July 1, 2000.  CL&P rates were unbundled effective
January 1, 2000, with total rates 10 percent below rates in effect in December
1996, or 5 percent lower than rates in effect on December 31, 1999.

     Effective January 1, 2000, CL&P's primary responsibility is to serve as
transmission and distribution provider to all customers within its service
territory and to provide standard offer service to those customers who have not
chosen a competitive supplier.  CL&P's standard offer supply was obtained via a
request for proposal process, conducted by J.P. Morgan Securities, Inc.
(J.P. Morgan) on behalf of the DPUC.  As approved by the DPUC, 50 percent of
the standard offer supply is met by a CL&P affiliate and 50 percent by two
unaffiliated suppliers.  The contracts with all three suppliers terminate
December 31, 2003.  CL&P is recovering all of its supply costs in rates.

     The Connecticut restructuring legislation authorized the collection of
mitigated generation-related stranded costs and the securitization of
nonnuclear generation-related stranded costs.  Securitization is the
monetization of stranded costs through the sale of nonrecourse debt securities
(rate reduction bonds) by a special purpose entity, which are collateralized
by a company's interests in stranded cost recoveries.  Securitization proceeds
are applied in general to retire higher cost debt of the utility.  The
legislation also required the divestiture of all generating assets and the
mitigation of purchased power contracts.  Proceeds from asset divestiture are
required to be used to offset stranded costs.

     The DPUC approved the divestiture plans, engaged J.P. Morgan to conduct
the auctions and approved the ultimate transactions regarding the divestiture
of all of CL&P's fossil and hydroelectric plants and the Millstone nuclear
station.  In December 1999, CL&P sold 2,235 megawatts (MW) of fossil-fueled
generation assets to an unaffiliated company for $460 million.  In March 2000,
CL&P transferred 1,057 MW of hydroelectric generation assets in Connecticut
and Massachusetts to NGC, an affiliated company, for $681 million.  All
proceeds have been used to offset stranded costs.

     In the fall of 1999, CL&P and WMECO sold the capacity and energy
associated with their unit entitlements in Millstone 2 and 3 and Seabrook to
Select Energy and five unaffiliated companies for the period beginning
January 1, 2000, through December 31, 2001.  The revenues that result from
these contracts over the two year period (or until the units are sold, if
earlier) are expected to recover CL&P's and WMECO's share of the nuclear
operating costs, including a return on and the remaining nuclear plant
balances.

     On August 7, 2000, the DPUC announced that an agreement had been reached
with Dominion Resources, Inc. (Dominion) for the sale of Millstone 1, Millstone
2 and approximately 94 percent of Millstone 3, including nuclear fuel and
inventory, for approximately $1.3 billion.  All necessary state approvals for
CL&P, WMECO, PSNH, and the other selling joint owners have been obtained.
On February 20, 2001, the Connecticut Coalition Against Millstone (CCAM)
appealed the DPUC's approval of the agreement to the Connecticut Superior
Court and asked the court to issue a stay of the transaction pending resolution
of the appeal.  The parties are pursuing the necessary federal regulatory
approvals to close the transaction as early as the end of March 2001.  The
DPUC has approved recovery of Millstone-related stranded costs not offset by
asset divestiture proceeds.  Pursuant to the DPUC order, CL&P will seek
recovery of Millstone post-1997 capital additions in the nuclear proceeds
calculation which will be filed after closing on the Millstone transaction.
CL&P must prove that the costs are not related to the extended outage that
began in 1996 and that the costs are reasonable relative to the benefits.
Among other rulings in the DPUC's restructuring decisions, the Connecticut
Office of Consumer Counsel (OCC) has appealed CL&P's ability to recover these
costs.  Oral argument on these issues is scheduled in Connecticut Superior
Court for March 29, 2001.  For further information on litigation relating to
the sale of Millstone, see "Item 3. Legal Proceedings."

     CL&P intends to auction its interest in Seabrook when NAEC auctions its
Seabrook interests.  Divestiture plans were filed simultaneously with the DPUC
and the NHPUC in December 2000.  DPUC hearings are scheduled to commence in
March 2001.

     The DPUC has approved CL&P negotiated buy-downs and buy-outs of 15
contracts with independent power producers (IPPs) and one wholesale power
contract.  The DPUC has approved securitization of $1.026 billion in buy down
and buy out payments.  Payments to the IPP projects will be made after receipt
of funds from the issuance of rate reduction bonds.

     CL&P was unable to negotiate buy-downs or buy-outs with 15 IPPs that
produce approximately 345 MW.  The DPUC authorized J.P. Morgan to auction the
long-term purchased power contracts and ultimately Constellation Power Source,
Inc. (Constellation) was selected as the winning bidder.  Constellation and
CL&P entered an agreement, subject to DPUC approval, whereby Constellation
would obtain the power from the power purchase agreements and assume CL&P's
obligations thereunder, in exchange for monthly support payments from CL&P.
The DPUC rejected the agreement between Constellation and CL&P, finding that
it did not fully mitigate stranded costs.  CL&P is selling the output from
the projects into the market and will continue to collect the difference
between the contract prices and the market revenues as stranded costs.
These stranded costs cannot be securitized.

     The DPUC also approved recovery of and securitization of approximately
$439 million of generation-related regulatory assets.  The OCC appealed to
the Connecticut Superior Court the methodology used by CL&P and endorsed by
the DPUC to calculate the regulatory assets.  The parties have reached a
settlement of this appeal pursuant to which the OCC appeal will be withdrawn
and securitization, including the full amount of generation-related
regulatory assets, will go forward.  DPUC approval of the settlement was
received on March 12, 2001.  On March 16, 2001, the OCC withdrew its appeal.

     On December 1, 2000, the Connecticut Attorney General (AG) and the OCC
each filed a petition requesting that the DPUC initiate a proceeding to
consider whether an interim decrease in the rates charged by CL&P is required.
The applicable statute requires the DPUC to commence a special public hearing
on the need for an interim rate decrease when, among other reasons, a public
service company has for six consecutive months earned a return on equity (ROE)
that exceeds the return authorized by the DPUC by at least one percentage
point.  The AG and the OCC petitions were filed after CL&P reported ROEs of
13.12 percent for the second quarter of 2000 and 14.17 percent for the third
quarter of 2000.  The DPUC conducted public hearings in this matter in February
and March 2001, and a decision from the DPUC is expected in April 2001.

     MASSACHUSETTS RATES AND RESTRUCTURING

     Massachusetts enacted comprehensive electric utility industry
restructuring in November 1997.  That legislation required each electric
company to submit a restructuring plan and to reduce its rates by 15 percent
adjusted for inflation by September 1999.  The 15 percent rate reduction is a
rate cap for standard offer service customers that extends until February
2005, the end of the restructuring transition period.  WMECO filed, and in
1999, the DTE approved, WMECO's restructuring plan.  The plan allows WMECO's
customers to choose their energy suppliers and allows WMECO to recover
generation-related stranded costs.  Two parties have appealed the DTE's
decision on WMECO's restructuring plan to the Massachusetts Supreme Judicial
Court.  There has been no significant action in these appeals since they were
filed in December 1999.

     In addition, the DTE-approved plan requires WMECO to procure competitively
priced standard offer service and default service.  These services provide
power to customers that decline to purchase energy from a competitive supplier.
WMECO competitively procured standard offer service and default service for
2000.  For 2001, standard offer service has been procured as a composite rate
of 7.383 cents per kilowatt-hour (kWh), including congestion costs.  Default
service has been procured through June 30, 2001, at a somewhat higher rate.

     In December 2000, WMECO requested that the DTE approve a standard offer
service fuel adjustment for calendar year 2001.  This fuel adjustment
recognizes significant increases in fuel prices.  On December 29, 2000, the
DTE approved a fuel adjustment for standard offer customers of approximately
1.8 cents/kWh.  The standard offer fuel adjustment and certain other rate
factors offset, to some extent, by a slowing of the amortization of WMECO's
stranded costs resulted in an average 17.4 percent rate increase for standard
offer service customers as of January 1, 2001.  A slightly higher increase
was approved for default service customers as of February 1, 2001.

     Pursuant to the Massachusetts restructuring act, electric companies were
required to divest their nonnuclear generation facilities.  In July 1999,
WMECO sold 290 MW of fossil and hydroelectric generation assets for $47 million
to Consolidated Edison Energy Massachusetts, Inc.  In March 2000, WMECO sold
272 MW of hydroelectric generation to NGC for approximately $184 million.
In addition, in August 2000, WMECO agreed to sell its Millstone nuclear assets
to Dominion.

     WMECO filed an application with the DTE in April 2000, requesting
authorization to securitize a portion of its stranded costs.  On February 7,
2001, the DTE approved the securitization of $155 million of stranded costs
and issued the required financing order and in March 2001, WMECO received the
approvals of the two Massachusetts state agencies directed by statute to
oversee the bond issuance.  The stranded costs to be securitized include the
unrecovered plant balances of Millstone 2 and 3 and the buydown payment of
one IPP contract.  Final approval for the issuance of the rate reduction
bonds must be obtained from the SEC.

     NEW HAMPSHIRE RATES AND RESTRUCTURING

     The state of New Hampshire's attempts to restructure the electric utility
industry in that state have resulted in extensive litigation in various federal
and state courts.  In 1996, New Hampshire enacted legislation requiring a
competitive electric industry beginning in 1997.  In February 1997, the NHPUC
issued restructuring orders that would have forced PSNH and NAEC to write off
all of their regulatory assets and possibly seek protection under Chapter 11 of
the bankruptcy laws.  Following the issuance of these orders, PSNH obtained
injunctive relief on various grounds from federal district court that prevents
implementation of the NHPUC's restructuring orders.

     In September 2000, the NHPUC approved a Settlement Agreement intended to
settle most of these proceedings.  As required under the agreement, PSNH has
written off in excess of $200 million after-tax of its stranded costs and
will be allowed to recover the remaining amount.  PSNH's obligations under
the Settlement Agreement are contingent upon the issuance of $725 million in
rate reduction bonds.  In July 2000, the New Hampshire legislature endorsed
the Settlement Agreement as approved by the NHPUC with several amendments.
Other approvals are also required from the FERC and various financial lenders.

     Under the terms of the Settlement Agreement, as amended by the
Legislature, customers' bills were reduced by 5 percent on October 1, 2000, and
on the effective date, PSNH's rates will be further reduced from current levels
by an average of 10.3 percent.  The 5 percent rate reduction can be rescinded
on April 1, 2001, if PSNH has not closed on the sale of rate reduction bonds by
that time.

     The Settlement Agreement also requires PSNH to divest its generation
assets and offer retail choice to its more than 420,000 electric customers
following the sale of the rate reduction bonds.  The net proceeds from all
generation divestitures will be used to reduce PSNH's stranded costs.  The
sales are to be accomplished through a sale process administered by the NHPUC.
Following the divestiture, the transmission and distribution portion of PSNH's
business will continue to be cost-of-service regulated.

     On September 8, 2000, the NHPUC issued an order addressing various motions
for clarification and the rehearing of its April 19, 2000, order.  In its
order, the NHPUC rejected motions for rehearing by various parties, granted the
relief requested by PSNH related to certain regulatory obligations and reduced
the amount PSNH could securitize from $725 million to up to $670 million, less
$6 million for each month beginning October 2000, until competition begins, and
found PSNH's compliance filing to be in conformance with New Hampshire law.
The NHPUC also issued an order addressing specific issues related to
securitization permitted under the Settlement Agreement.

     In October 2000, the securitization process and the implementation of the
Settlement Agreement were delayed by two appeals of the NHPUC's order to the
New Hampshire Supreme Court.  The New Hampshire Supreme Court issued an order
on January 16, 2001, rejecting both appeals, and on February 2, 2001,
reaffirmed its decision.  One of the appellants indicated publicly it would
request a review of the New Hampshire decision by the United States Supreme
Court.  Such a request must be filed by May 1, 2001.  Management believes that
such an appeal would have a low probability of success, but cannot determine
what effect it might have on the timing of the sale of rate reduction bonds
and the implementation of customer choice.  PSNH anticipates closing on its
rate reduction bonds early in the second quarter of 2001, with competition to
begin on the first day of the calendar month after such closing.

     In November 1999, the NHPUC also approved continuation of the fuel and
purchased-power adjustment clause charge for PSNH at its current level until
the beginning of electric supply choice in New Hampshire.

     In December 2000, PSNH filed divestiture plans with the NHPUC seeking
approval to begin the process of selling its fossil and hydroelectric
generation assets and NAEC's ownership share of Seabrook.

                           COMPETITIVE SYSTEM BUSINESSES

     NU is engaged in a variety of competitive businesses.  They are grouped
essentially into two separate and distinct business activities:  the
competitive energy business and the telecommunications business.  Select Energy
is the lead competitive energy business within NU.  Select Energy is an
integrated energy business that buys, sells and markets electricity, gas and
oil and energy-related products and services.  Under the umbrella of the Select
Energy brand, Select Energy, collectively with its affiliated competitive
energy businesses, provides a wide range of energy products and energy
services.  These affiliated competitive energy companies include HEC, NGC, HWP,
NGS, and SEPPI.  With the exception of HEC, the competitive businesses operate
primarily in the Northeast region of the United States.

     ENERGY-RELATED PRODUCTS AND SERVICES AND GAS INVESTMENTS

     Select Energy sells multiple energy products including electricity,
natural gas and oil to wholesale and retail customers in the northeastern
United States.  Select Energy procures and delivers energy and capacity
required to serve its electric, gas and oil customers.  Select Energy is the
largest wholesale and retail electric energy marketer in New England as
measured by MW load.  In order to support and complement its growing wholesale
and retail business, Select Energy contracted in December of 1999 with NGC,
its unregulated generation company affiliate, to purchase and market all of
NGC's 1,289 MW for a 6-year period.  These resources were acquired at auction
from CL&P and WMECO.  In addition, Select Energy is purchasing approximately
200 MW of coal and hydroelectric generating resources from HWP and more than
1,500 MW of electrical supply from various New England generating facilities
on a long-term basis.  Select Energy also utilizes generation failure
insurance, options and energy futures to hedge its supply requirements.
Moreover, Select Energy markets natural gas and develops and markets energy-
related products and services.  It offers energy management consulting and
construction services through its affiliate, HEC, discussed more fully below.
Select Energy and its integrated competitive energy business affiliates had
aggregate revenues of approximately $1.9 billion in 2000, as compared to
approximately $648.9 million in 1999, and contributed $13.6 million to
consolidated earnings before extraordinary items in 2000, as compared to an
aggregate loss of approximately $37 million in 1999.

     Select Energy is licensed to provide retail electric supply in
Connecticut, Delaware, Maryland, New Jersey, Maine, Pennsylvania, New York,
Massachusetts, Rhode Island, and New Hampshire.  Within these states, Select
Energy is currently registered with approximately 36 electric distribution
companies and 52 gas distribution companies to provide retail services.  Select
Energy's goal is to be the regional leader in providing electric service to
those Northeast markets opened to retail competition.  In 2000, Select Energy
provided more than 5,000 MW of standard offer load, making it the largest
provider of standard offer service in the Northeast.  During 2000, Select
Energy provided several utilities with standard offer full requirements
service and default services, comprising in the aggregate approximately 43
percent of its 2000 revenues.  This included providing about 3,000 MW to a
Massachusetts utility.  A new contract for default service was signed with
the same utility for a 6-month period in 2001.

     On January 1, 2000, Select Energy began serving one half of CL&P's
standard offer load for a 4-year period.  This equates to approximately 2,000
MW annually for each of the four contract years.  Approximately 26 percent of
2000 competitive energy revenues came from this contract.  The servicing of
this load is a significant risk for Select Energy, as this contract is
through the end of 2003, at fixed prices.  This risk is partially mitigated
by Select Energy entering into purchase contracts with other energy providers
to supply a portion of the standard offer requirement, including its contracts
with NGC, the purchase of 850 MW of output from the Millstone and Seabrook
nuclear units through 2001, and other resources in the energy marketplace.
Although there can be no assurance that it will be able to do so, management
believes that Select Energy will be able to source its remaining load
requirement at reasonable prices.  If Select Energy is unable to source its
remaining load requirement at prices below the standard offer contract price
as a result of energy price increases, Select Energy's earnings would be
adversely impacted.  Select Energy has also entered into contracts with various
retail customers to provide energy services at fixed rates.  Under these retail
contracts, Select Energy has the option to have the host utility provide energy
services and is obligated to compensate the customer as defined in the
contracts (CFD Payments).  For the 12 months ended December 31, 2000, these CFD
Payments totaled approximately $3.55 million.  These CFD Payments may increase
in the future.  Policies and procedures have been established to manage these
exposures, including the use of risk management instruments and the purchase of
insurance for the output from the Millstone nuclear entitlements.  In addition,
beginning in January 2000, Select Energy assumed responsibility for serving
approximately 500 MW of market-based wholesale contracts throughout New England
with electric energy supply that was previously provided by CL&P and WMECO.
For the most part, the prices are fixed by contract and applicable to actual
volumes.

     As of December 31, 2000, Select Energy had contracts with high volume
retail electric customers in states throughout the Northeast with primarily
one-year terms.  These contracts represent approximately 300 MW of load at
about 10,000 service locations and include predominantly commercial,
institutional and industrial accounts.  This retail load is supplied by the
Select Energy wholesale business line and establishes Select Energy among the
largest competitive retail suppliers in New England as measured by MW load.
However, recent significant increases in electric supply costs may cause the
number of retail electric customers to decrease in the first quarter of 2001
as a result of contract expirations or terminations.  There is no single
retail customer that accounts for over 10 percent of Select Energy's expected
retail revenues.

     The energy marketing business is intensely competitive.  There are many
large energy companies bidding for business in the increasingly restructured
New England market.  In 2000, the sharp increases in the cost of power supply
caused by the extreme increases in oil and gas fuel costs, among other
things, provided significant challenges and opportunities for Select Energy.
In 2000, Select Energy increased its revenue by more than 300 percent over
the 1999 revenue level, reporting $1.79 billion in 2000, as compared with
$555 million in 1999.

     Disputes with respect to interpretation and implementation of the New
England Power Pool (NEPOOL) market rules have arisen with respect to various
competitive product markets.  In certain cases, Select Energy and the NU
operating companies stand to gain as a result of resolution of such disputes.
In other cases, Select Energy and the NU operating companies could incur
additional costs as a result of resolution of the disputes.  These disputes
are in various stages of resolution through alternative dispute resolution
and regulatory review.  It is too early to ascertain the level of potential
gain or loss that may result upon resolution of these issues.

     During 2000, Select Energy significantly increased its competitive
retail and wholesale natural gas business.  Its revenue for this business
segment increased from approximately $21 million in 1999, to approximately
$221 million in 2000.  As of December 31, 2000, Select Energy had contracts
with approximately 2,000 retail gas customers, primarily located in
Connecticut, Massachusetts and Pennsylvania.  These contracts generally have
one-year terms and include only commercial, institutional and industrial
accounts.  There is no single retail gas customer that accounts for over 5
percent of Select Energy's expected retail gas revenues.  In 2000, Select
Energy's retail gas revenues were approximately $67 million representing a
550 percent increase, as compared to 1999.  The competitive retail gas
business has contracted for approximately $100 million in gas sales which
will extend into 2001 and 2002.

     ELECTRIC GENERATION AND SERVICES

     Select Energy buys, manages and markets the entire generation output from
its unregulated generation affiliate, NGC, to retail and wholesale customers.
NGC is a competitive business affiliate formed in 1999 to acquire generation
facilities.  In March 2000, NGC received 1,289 MW of hydroelectric and pumped
storage generating assets in Connecticut and Massachusetts from CL&P and WMECO.
These assets include seven hydroelectric facilities along the Housatonic River
System (123 MW), the three facilities comprising the Eastern Connecticut
System, including one gas turbine (27 MW), the Northfield Mountain pumped
storage station and the Cabot and Turners Falls No. 1 hydroelectric stations
located in Massachusetts previously owned by WMECO.  NGC began selling the
capacity and output of the plants to Select Energy for a period of 6 years
in March 2000.

     HWP is another NU subsidiary which is considered part of the competitive
energy businesses.  Select Energy buys, markets and manages the entire
generation output from its HWP affiliate.  This generation consists of about
190 MW.  HWP is selling all of its capacity and output to Select Energy through
the end of December 2001, with annual or longer contract renewals available
thereafter.  Select Energy markets the entire output of electricity to retail
and wholesale customers.  HWP recognized as an extraordinary loss a decrease
of $19.7 million, net of taxes in 2000, as a reduction in the value of its
hydro assets.

     NGS was formed in 1999 to provide energy-related operation and maintenance
services to owners of generation facilities and the industrial market in the
Northeast.  NGS currently focuses on providing turnkey management and operation
services and also a full range of industrial and consulting services.  Select
Energy has contracted with NGS to operate and maintain all of the generating
plants within the Select Energy affiliated businesses.

     NGS's industrial services include maintenance, permitting, environmental,
and specialized electrical testing services to large and medium-sized
industrial businesses.  NGS also provides consulting services to these
customers, including engineering and design, construction management, asset
development, due diligence reviews and environmental regulatory compliance,
and permitting services.  During 2000, NGS's revenues were approximately $44
million and are expected to grow significantly in 2001.  This anticipated
growth will be due to NGS's increased geographical scope as a result of its
recent acquisition of an electrical contracting business and a number of
pending contracts with both new and repeat customers.

     ENERGY MANAGEMENT SERVICES

     As part of the Select Energy portfolio of products and services, Select
Energy, in conjunction with its affiliate HEC, markets energy efficiency and
design solutions to customers.  In general, HEC contracts to reduce its
customers' energy costs, improve their operating efficiency within their
facilities and conserve energy and other resources.  HEC's engineering,
construction management and financing assistance services have been directed
primarily to governmental and institutional markets and utilities in the
eastern United States.  HEC increased its vertical integration through its
subsidiary Select Energy Contracting, Inc., which also provides mechanical
and electrical contracting services in new construction and service
contracts, primarily directed to commercial markets.

     In competitive procurements by the U.S. Departments of Defense and Energy
during 1998 and 1999, HEC was selected as an "Energy Saving Performance
Contractor" (ESPC) for all fifty states and overseas bases.  Recent orders have
been received calling for design, construction, financing, and long-term
operation and maintenance of energy-efficient and environmentally clean systems
to replace older infrastructure.  Select Energy and HEC have recently begun
construction of a central energy plant for a school in Middletown, Connecticut.
This plant will include the largest U.S. installation of fuel cells yet
achieved.  In 2000, federal ESPC work constituted 27 percent of HEC's revenues,
which were approximately $82.5 million (an increase of 20 percent over 1999).
NU's aggregate equity investment in HEC was approximately $25 million as of
December 31, 2000.

     GAS INVESTMENTS

     SEPPI was formed in March 1999 to hold a five percent partnership interest
in the Portland Natural Gas Transmission System.  SEPPI's investment in the
project was $5.4 million as of December 31, 2000.  During 2000, SEPPI
recognized a $3.9 million reduction in the value of its investment.

     TELECOMMUNICATIONS

     Mode 1 was established in 1996 to participate in a wide range of
telecommunications activities both within and outside New England.  NU's
cumulative, total investment in Mode 1 was approximately $10.1 million as of
December 31, 2000.  Mode 1 is a licensed competitive local exchange carrier
authorized to provide local phone service within the state of Connecticut.

     Mode 1 currently owns approximately 4.8 million common shares of NEON
Communications, Inc. (formerly NorthEast Optic Network, Inc.) (NEON), or 20.5
percent of its outstanding shares fully diluted (assuming the issuance of all
shares to Consolidated Edison Communications, Inc. (CECI) and Exelon Ventures
(Exelon), as discussed below).  NEON is constructing a fiber optic
communications network through New England, New York, Philadelphia, and
Washington, D.C., utilizing a portion of the NU system companies'
transmission and distribution facilities.  An officer and trustee of NU and
an officer of NUSCO are members of the Board of Directors of NEON.  In
addition, NU is a party to an agreement with Central Maine Power Company
(CMP), an owner of approximately 19.2 percent of NEON's common shares, fully
diluted, wherein NU and CMP each agree that, as long as NU owns at least 10
percent of the outstanding common stock of NEON, fully diluted, and the
cumulative holdings of NU and CMP are at least 33 1/3 percent, fully diluted,
neither NU nor CMP will take any action which will allow NEON to merge,
consolidate, liquidate or sell, lease or transfer substantially all of its
assets, or commence or acquiesce to any action or proceeding under any
bankruptcy laws.

     In September 2000, CECI, a subsidiary of Con Edison, and Exelon, another
unaffiliated company, acquired 10.75 and 9.25 percent, respectively, of NEON's
common shares in exchange for contributions to NEON by each company of
telecommunications assets in kind and cash.  Mode 1 is party to two reciprocal
agreements which commit it to vote for CMP's, CECI's and Exelon's nominees for
director of NEON and such companies agree to support Mode 1's nominees.  Under
these arrangements, Mode 1 can presently designate two directors, and CMP,
CECI and Exelon can designate two, one and one director(s), respectively.

                               FINANCING PROGRAM

     2000 FINANCINGS

     On March 1, 2000, NU completed its acquisition of Yankee.  NU financed
this acquisition with a combination of 11.1 million in newly issued shares and
a $263 million term loan credit facility.  On February 28, 2001, NU repaid this
facility with the proceeds of a $263 million floating rate senior note
issuance.  The senior notes bore an effective interest cost of 6.9 percent at
February 28, 2001, and mature in February 2003.  Also, in anticipation of the
Yankee acquisition, in late 1999 and early 2000, NU entered into forward share
purchase arrangements with two financial institutions for a total of $215
million.  These forward arrangements, which originally were due to expire on
December 31, 2000, terminate on June 29, 2001.

     On March 14, 2000, CL&P and WMECO transferred to NGC certain of their
hydroelectric generation assets.  NGC financed this acquisition with a $435
million equity infusion from NU and a $430 million credit facility.  In
November 2000, the credit facility was extended from its original December 29,
2000, maturity date to June 29, 2001, with the ability to further extend to
September 28, 2001, if certain conditions are met.

     On April 4, 2000, PSNH entered into two letters of credit and
reimbursement agreements totaling $115.4 million, which support its Series D
and E pollution control revenue bonds (PCRBs).  The new letters of credit,
which replaced similar letters of credit that were set to expire on April 12,
2000, allow the PCRBs to remain in a flexible, floating interest rate mode.
On August 4, 2000, $39.5 million in principal amount of Series D PCRBs were
redeemed and the related letter of credit and reimbursement agreement was
terminated.  On September 7, 2000, $69.7 million in principal amount of
Series E PCRBs were redeemed and the related letter of credit and
reimbursement agreement was terminated.

     On November 9, 2000, NAEC entered into an unsecured $200 million 364-day
term credit agreement with four banks.  This new facility replaced a 5-year
$225 million term loan dated November 9, 1995, which had $200 million
outstanding and was set to expire on November 9, 2000.  An interest rate
collar and swaps related to the $200 million 5-year term credit agreement
also expired on November 9, 2000, and were not replaced.

     On November 17, 2000, NU entered into a new 364-day revolving credit
facility for $400 million, replacing the previous $350 million revolving credit
facility which was to expire on that date.  The new credit facility is subject
to two overlapping sublimits.  First, subject to the notional amount of any
letters of credit outstanding, amounts up to $300 million may be borrowed.
Second, subject to outstanding borrowings, NU subsidiaries may access up to
$200 million in letters of credit.

     On November 17, 2000, CL&P and WMECO entered into a new 364-day revolving
credit facility for $350 million, replacing the previous $500 million facility,
which was to expire on November 17, 2000.  Under this agreement, CL&P and WMECO
may borrow up to $200 million and $150 million, respectively.  Once CL&P and
WMECO receive the proceeds of securitization, the borrowing limits will be
reduced to $250 million, with a $150 million limit for CL&P and a $100 million
limit for WMECO.

     On November 17, 2000, Yankee Gas extended its $60 million revolving credit
facility for an additional 364-day period from November 17, 2000, to
November 16, 2001.  Also on November 17, 2000, Yankee permanently retired $25
million of short-term bank debt.

     The level of common dividends totaled $57.4 million in 2000, up
significantly from the $13.2 million paid in 1999.  The increase was a result
of NU paying a $0.10 per share quarterly common dividend for all of 2000, as
compared to only paying a $0.10 per share dividend in the fourth quarter of
1999.

     Total NU system debt, including short-term and capitalized lease
obligations, was $3.8 billion as of December 31, 2000, compared with $3.3
billion as of December 31, 1999.  The increase was primarily due to the
acquisition of Yankee.  For more information regarding NU system financing,
see "Notes to Consolidated Statements of Capitalization" in NU's financial
statements, other footnotes related to long-term debt, short-term debt, and
the sale of accounts receivables, as applicable, in the notes to NU's, CL&P's,
PSNH's, WMECO's, and NAEC's financial statements and "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations."

     2001 FINANCING REQUIREMENTS

     The NU system's aggregate capital requirements for 2001 are approximately
as follows:

                     CL&P     PSNH    WMECO   NAEC   Yankee   Other  NU system
                                           (Millions)

Construction        $231.3   $ 78.7   $26.6   $ 6.6   $39.2   $37.6   $420.0
Nuclear Fuel           -        -       -      14.5     -       -       14.5
Maturities           160.0      -      60.0     -       -       -      220.0
Cash Sinking Funds     -       24.3     1.5    70.0     1.1    23.1    120.0
                    ------   ------   -----   -----   -----   -----   ------
Total               $391.3   $103.0   $88.1   $91.1   $40.3   $60.7   $774.5
                    ======   ======   =====   =====   =====   =====   ======

     For further information on the NU system's 2001 and 5-year financing
requirements, see "Notes to Consolidated Statements of Capitalization" in NU's
financial statements, "Long-Term Debt" in the notes to CL&P's, PSNH's, WMECO's,
and NAEC's financial statements and "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations."

     2001 FINANCING PLANS

     In 2001, NU expects to reduce the capitalization of its regulated electric
subsidiaries significantly as a result of securitization of stranded costs and
continued asset sales.  NU expects its subsidiaries to receive about $830
million after expenses, certain cash settlements and taxes as a result of the
sale of its interest in Millstone station to Dominion.  The sale is projected
to close as early as the end of March 2001.  CL&P and WMECO will receive the
vast majority of the $830 million (approximately $600 million for CL&P and more
than $140 million for WMECO) and they are expected to use the cash to reduce
their level of debt and capitalized lease obligations and to return equity
capital to the parent company.

     In 2001, the Company hopes to complete the process of securitizing
stranded costs for each of its major electric operating companies.  In November
2000, the DPUC approved the securitization of up to $1.55 billion of CL&P's
stranded costs, including the buyout and buydown of more than $1 billion in
purchased power obligations.  CL&P currently plans to securitize approximately
$1.45 billion of these stranded costs in late March 2001.  Of that sum, CL&P
plans to use about $400 million to reduce debt.

     In September 2000, the NHPUC approved a comprehensive restructuring order
that allows PSNH to securitize up to $670 million of stranded costs.  In
January 2001, the New Hampshire Supreme Court upheld the restructuring order
on appeal and PSNH currently expects to work with the State of New Hampshire
to issue securitization bonds early in the second quarter of 2001.  Proceeds
would be combined with cash on hand and used primarily to buy down the power
contract between PSNH and NAEC, allowing a total reduction in debt at the two
companies of approximately $300 million, the retirement of approximately
$25 million of PSNH preferred stock and the return of equity capital to NU
from PSNH and NAEC of another $375 million.  By the end of 2002, PSNH also
expects to complete the sale of approximately 1,200 megawatts of fossil and
hydroelectric generating plants and all 418 megawatts of NAEC's share of
Seabrook.  PSNH's restructuring settlement was predicated upon PSNH and NAEC
receiving approximately $400 million of net proceeds from those sales.

     In February 2001, the DTE approved the securitization of $155 million of
stranded costs by WMECO.  A significant amount of those proceeds would be used
to buy out a purchased power contract with the remainder used to reduce WMECO's
debt.  WMECO hopes to complete the issuance early in the second quarter of
2001.

     Should NU's operating subsidiaries successfully complete all of the asset
sales and securitization noted above, the regulated companies would receive in
excess of $5 billion of cash between 1999 and 2002.

     Management currently expects NU's operating subsidiaries to use the
proceeds in four primary ways.  More than $2 billion would be used to repay
debt and preferred stock; more than $1 billion to buy out and buy down high-
cost nonutility generator arrangements; approximately $600 million to pay taxes
on gains from the sale of generation assets; and approximately $1.2 billion
would be returned to NU from these operating companies.  Of that $1.2 billion,
CL&P and WMECO repurchased $390 million of their common stock from NU in March
2000, the proceeds of which were immediately invested in NGC.  NU will use
another $215 million to settle the forward share purchase noted above.

     On February 28, 2001, NU issued $263 million aggregate principal amount
floating rate notes due February 2003.  The proceeds were used to pay off the
$263 million term loan credit facility used to finance NU's acquisition of
Yankee.

     In the first half of 2001, NGC expects to issue up to $440 million of
long-term debt to replace the $430 million credit facility discussed above.

     Due to the fourth quarter write-down of certain assets owned by HWP, HWP
did not meet its equity maintenance covenant under certain of its letter of
credit and reimbursement agreements.  In February 2001, HWP received a waiver
to permit its common equity ratio to fall below 30 percent for the quarters
ended December 31, 2000, March 31, 2001, and June 30, 2001.  Thereafter, NU
will provide a guarantee of HWP's obligations for the benefit of the banks.
NU expects to receive approval from the SEC to implement this guarantee during
the second quarter of 2001.

     FINANCING LIMITATIONS

     Many of the NU system companies' charters and borrowing facilities contain
financial limitations that must be satisfied before borrowings can be made and
for outstanding borrowings to remain outstanding.

     Under their current revolving credit facility, CL&P and WMECO are required
to maintain a ratio of common equity to total capitalization (common equity
ratio) of at least 30 percent.   At December 31, 2000, CL&P's and WMECO's
common equity ratios were 32.8 percent and 34.4 percent, respectively.  This
agreement also requires CL&P to maintain a 12-month earnings before interest
and taxes to interest expense ratio (interest coverage ratio) of at least 2.5
to 1.0 for the quarters ending December 31, 2000, and March 31, 2001, and 3.0
to 1.0 thereafter.  WMECO is required to maintain a quarterly interest coverage
ratio of at least 2.0 to 1.0 for the quarters ending December 31, 2000, and
March 31, 2001, and 2.2 to 1.0 thereafter.  At December 31, 2000, CL&P's and
WMECO's interest coverage ratios were 3.5 to 1 and 3.0 to 1, respectively.

     Under NU's revolving credit facility and its term loan credit agreement,
NU is required to maintain a consolidated common equity ratio of at least 30
percent.   At December 31, 2000, NU's consolidated common equity ratio was 35.1
percent.  In addition, NU is required to maintain a 12-month consolidated
interest coverage ratio of at least 2.0 to 1.0 for the quarters ending
December 31, 2000, and March 31, 2001, and 2.2 to 1.0 thereafter.  At
December 31, 2000, NU's consolidated interest coverage ratio was 2.4 to 1.0.
In addition, NU is required to maintain as of the end of each quarter with
respect to the four quarters then ended a ratio of operating cash flow to fixed
charges (cash flow ratio) of at least 1.5 to 1.0.  At December 31, 2000,
NU's cash flow ratio was 2.1 to 1.0.

     These agreements also limit NU's ability, without creditor approval, to
incur additional debt and to make future investments, including acquisitions
in excess of $25 million and investments in Select Energy and other
subsidiaries in excess of $200 million and $100 million, respectively.

     NAEC is party to a 364-day term credit agreement which provides that
outstanding advances can be terminated or accelerated if NAEC does not maintain
specified minimum ratios of common equity to capitalization (as defined in the
agreement).  For NAEC, the minimum common equity ratio under its term credit
agreement is 25 percent; at December 31, 2000, NAEC's common equity ratio was
32.4 percent.  The agreement also requires a 12-month adjusted net income to
interest expense ratio (interest coverage ratio) of not less than 1.5 to 1.0.
At December 31, 2000, the ratio for NAEC was 2.0 to 1.0.  The term credit
agreement also provides for mandatory prepayment of 50 percent of the aggregate
principal amount of advances outstanding within two days of a buydown of NAEC's
interest in Seabrook (Seabrook Interest) to $100 million as contemplated by the
PSNH restructuring Settlement Agreement, and prepayment of 100 percent within
two business days of the sale of the Seabrook Interest or earlier termination
of the Unit Contract as contemplated by the PSNH restructuring Settlement
Agreement.  The 364-day term credit agreement also limits NAEC's other
unsecured debt to $60 million.

     Under Yankee Gas' 364-day revolving credit facility, Yankee Gas is
required to maintain a common equity to stockholder's equity (common equity
ratio) of at least 37.5 percent and to maintain stockholders' equity of at
least $90 million.  At December 31, 2000, Yankee Gas' common equity ratio was
75.0 percent and its consolidated stockholder's equity was $467.2 million.
Yankee Gas is also required to maintain a 12-month interest coverage ratio of
at least 2.0 to 1.0 for each fiscal quarter.  At December 31, 2000, Yankee
Gas's interest coverage ratio was 4.2 to 1.0.

     The amount of short-term debt that may be incurred by NU, CL&P, WMECO,
PSNH, NNECO, HWP, and NAEC is also subject to periodic approval by the SEC
under the Public Utility Holding Company Act of 1935 (1935 Act).  PSNH's and
NAEC's short-term debt in excess of 10 percent of net fixed plant is also
regulated by the NHPUC.  The following table shows the amount of short-term
borrowings authorized by the SEC or the NHPUC for each company, as the case may
be, as of December 31, 2000, and the net amounts of outstanding short-term debt
and cash investments of those companies at the end of 2000 and as of March 1,
2001:

                                              Short-Term Debt
                                                Outstanding
                                            (Cash Investments) (1)
               Maximum Authorized           ------------------
                Short-Term Debt       December 31, 2000   March 1, 2001
               ------------------     -----------------   -------------
                                                  (Millions)

NU Parent           $400.0                $ 144.6            $ 182.5
CL&P                 375.0                   77.0               47.6
PSNH (2)             225.0                 (110.0)             (62.9)
WMECO                250.0                  110.6               90.7
HWP                    5.0                  (16.2)             (17.1)
NAEC(3)              260.0                  172.2              132.8
NNECO                 75.0                   (9.3)              16.8
Yankee Parent         50.0                     -                (1.5)
Yankee Gas           100.0                   49.6               48.1
Other                  N/A                   71.2              134.7
                                          -------            -------
Total                                     $ 489.7            $ 571.7
                                          =======            =======

(1) These columns include borrowings of or cash investments by various NU
system companies from NU and other NU system companies excluding borrowings
under the NU term loan credit agreement and NGC credit facility.  Total NU
system short-term indebtedness to unaffiliated lenders excluding the NU term
loan facility and NGC credit facility was $644.6 million at December 31,
2000, and $598 million at March 1, 2001.  The NU term loan facility was
separately approved by the SEC and is not considered short-term debt for
purposes of the SEC authorization noted above.  NGC's short-term debt is not
subject to SEC approval.  At December 31, 2000, NU had $263 million borrowed
under the NU term loan facility and NGC had $403 million borrowed under the
NGC credit facility.  As of March 1, 2001, NU had paid off the $263 million
term loan facility with proceeds from a $263 million debt issuance and NGC
had $388 million borrowed under the NGC credit facility.

(2) Under applicable NHPUC provisions, PSNH can incur short-term debt up to 10
percent of net fixed plant.  As of December 31, 2000, PSNH's net fixed plant
as measured by FERC was approximately $712.9 million; accordingly, PSNH could
borrow up to $71.3 million of short-term debt.

(3) Under applicable NHPUC regulations, NAEC can incur short-term debt up to
10 percent of net fixed plant.  As of December 31, 2000, NAEC's net fixed
plant as measured by FERC was approximately $524.8 million; accordingly, NAEC
could borrow up to $52.5 million of short-term debt.  In connection with the
issuance of NAEC's 364-day term credit agreement, NAEC obtained NHPUC approval
for a short-term debt limit of $260 million, representing $200 million of
borrowings under the 364-day term credit agreement and $60 million of other
short-term debt.

     The supplemental indentures under which NU issued $175 million in
principal amount of 8.58 percent amortizing notes in December 1991, and $75
million in principal amount of 8.38 percent amortizing notes in March 1992,
contain restrictions on dispositions of certain NU system companies' stock,
limitations of liens on NU assets and restrictions on distributions on and
acquisitions of NU stock.  Under these provisions, NU, CL&P, PSNH, and WMECO
may not dispose of voting stock of CL&P, PSNH or WMECO other than to NU or
another NU system company, except that CL&P may sell voting stock for cash to
third persons if so ordered by a regulatory agency so long as the amount sold
is not more than 19 percent of CL&P's voting stock after the sale.  The
restrictions also generally prohibit NU from pledging voting stock of CL&P,
PSNH or WMECO or granting liens on its other assets in amounts greater than
5 percent of the total common equity of NU.  Many of the NU system companies'
credit agreements have similar restrictions.  As of December 31, 2000, no NU
debt was secured by liens on NU assets.  Furthermore, NU may not declare or
make distributions on its capital stock, acquire its capital stock (or rights
thereto), or permit a NU system company to do the same, at times when there
is an event of default under the supplemental indentures under which the
amortizing notes were issued.

     Pursuant to its revolving credit facility and the $263 million term loan
credit agreement, NU may not declare dividends or make distributions, except
for dividends not to exceed $60 million during any 12-month period and stock
repurchases of up to $215 million in connection with the Yankee merger.
Similar restrictions are found in NU's merger agreement with Con Edison.

     The charters of CL&P and WMECO contain preferred stock provisions
restricting the amount of unsecured debt those companies may incur.  As of
December 31, 2000, CL&P's and WMECO's charters permit CL&P and WMECO to incur
an additional $245 million and $94 million, respectively, of unsecured debt.

     The indentures securing the outstanding first mortgage bonds of CL&P,
PSNH, WMECO, and NAEC provide that additional bonds may not be issued, except
for certain refunding purposes, unless earnings (as defined in each indenture
and before income taxes, and, in the case of PSNH, without deducting the
amortization of PSNH's regulatory asset), are at least twice the pro forma
annual interest charges on outstanding bonds, and certain prior lien
obligations and bonds to be issued.  While CL&P's and WMECO's 2000 earnings
permit them to meet those earnings coverage tests, certain loan agreements
prohibit the issuance of additional first mortgage bonds.

     The preferred stock provisions of CL&P's and WMECO's charters also
prohibit the issuance of additional preferred stock (except for refinancing
purposes) unless income before interest charges (as defined and after income
taxes and depreciation) is at least 1.5 times the pro forma annual interest
charges on indebtedness and the annual dividend requirements on preferred
stock that will be outstanding after the additional stock is issued.  CL&P's
and WMECO's earnings currently permit them to meet those earnings tests.
However, the companies are not expected to issue preferred stock during 2001.

     Certain consolidated subsidiaries have dividend restrictions imposed by
their long-term debt agreements.  These restrictions also limit the amount of
retained earnings available for NU common dividends.  At December 31, 2000,
retained earnings available for the payment of dividends totaled $180.1
million.

     CL&P and WMECO's revolving credit agreement requires the companies to
maintain at all times a ratio of common equity to total capitalization of at
least 30 percent.   At December 31, 2000, this requirement would allow CL&P
and WMECO to make additional distributions from common equity of $90 million
and $31 million, respectively.

     Under NAEC's first mortgage bond indenture, all retained earnings are
available for payment or distribution, plus an allowance of $10 million,
subject however to restrictions under New Hampshire statutes and the Federal
Power Act, which limit the payment of dividends to book retained earnings.  At
December 31, 2000, NAEC's retained earnings was approximately $0.4 million.

     During much of 2000, PSNH was prohibited from paying dividends on its
common stock and from investing any funds in the NU system money pool without
NHPUC approval.  Payment of a $50 million dividend at the time of the temporary
rate reduction contemplated by the Settlement Agreement was authorized pursuant
to New Hampshire law and was paid by PSNH to NU on October 1, 2000.  In its
finance order regarding securitization, the NHPUC authorized investment of
PSNH funds in the NU system money pool upon the write-off required by the
Settlement Agreement, which write-off was taken in the fourth quarter of 2000.
PSNH is now participating in the money pool and can pay dividends on its common
stock without NHPUC approval.

     New Hampshire statutes and the Federal Power Act limit the payment of
dividends by PSNH to retained earnings.  At December 31, 2000, PSNH's retained
earnings was approximately $123 million.

     Applicable merger accounting rules require that upon acquisition by NU,
Yankee's and its subsidiaries' retained earnings were reclassified as capital
surplus.  Also, the merger premium NU paid to acquire Yankee was allocated
among Yankee and its subsidiaries and "pushed down" to their balance sheets
and under current accounting rules is being amortized to expense.  Under
existing accounting conventions, the majority of the merger premium will be
amortized over 40 years.  The Financial Accounting Standards Board is
currently evaluating merger accounting.  The current proposal would no longer
require companies to amortize goodwill as an expense to the income statement.
Instead goodwill will be evaluated for impairment and any impairments to
goodwill would be charged to expense.  It is expected the new accounting rule
will be effective January 1, 2002.  If enacted, the effect will be an
approximately $8 million annual reduction in goodwill expense.

     Under the 1935 Act, subsidiaries of registered holding companies are only
allowed to pay dividends out of retained earnings unless the SEC allows
otherwise.  The effect of this rule would be to prevent Yankee from paying
dividends to NU from any source other than post-merger earnings, as reduced
by the merger premium amortization.  NU has received permission from the SEC,
through June 2002, for Yankee and Yankee Gas to pay dividends (i) out of
additional paid-in capital up to the amount of their respective retained
earnings just prior to the merger with NU and (ii) out of earnings before the
amortization of the merger goodwill (gross earnings) in the case of Yankee
Gas and out of distributed earnings in the case of Yankee.  To assure that
Yankee Gas has sufficient cash to fund operations, Yankee Gas will not pay
dividends in excess of 80 percent of gross earnings on a rolling 5-year
average basis.  In no case would dividends be paid by Yankee or Yankee Gas if
their common equity to total capitalization ratios were below 35 percent.

     NU has also received permission from the SEC, through June 2002, for
Yankee and Yankee Gas to repurchase their common stock such that their common
equity to total capitalization ratios do not fall below 35 percent.

     NU is required under the 1935 Act to maintain its consolidated common
equity at a level equal to at least 30 percent of its consolidated
capitalization.  Following the issuance of rate reduction bonds by its
subsidiaries, NU will temporarily be unable to meet this standard because such
bonds, although nonrecourse to the NU system company issuers, are considered to
be indebtedness of the companies under generally accepted accounting
principles.  The SEC has authorized the consolidated common equity ratio of NU
to fall below 30 percent through December 31, 2001.  The 30 percent test also
applies to NU's electric operating subsidiaries.  The SEC has authorized the
common equity ratios of CL&P, WMECO and PSNH to fall below 30 percent through
December 31, 2001.

     NU provides credit assurance in the form of guarantees, letters of credit,
performance guarantees, and other assurances for the financial performance
obligation of certain of its unregulated subsidiaries, particularly Select
Energy.  NU currently has authorization from the SEC to provide up to $500
million of guarantees.  In addition, NU is limited under its revolving credit
facility and its term loan credit agreement to $500 million of such
arrangements without creditor approval.  As of December 31, 2000, and March 1,
2001, NU had provided approximately $284 million and $376 million,
respectively, of such credit assurances.

     Certain NU system credit agreements also have covenants or trigger events
tied to credit ratings of certain NU system companies.

                              CONSTRUCTION PROGRAM

     The NU system's construction program expenditures, including allowance for
funds used during construction, is estimated to be in the range of from $395
million to $420 million in 2001.  Of such total amount, approximately $206
million to $231 million is expected to be expended by CL&P, $79 million by
PSNH, $27 million by WMECO, $7 million by NAEC, $11 million by NGC, $39 million
by Yankee, and up to $26 million by other system entities.  This construction
program data includes all anticipated costs necessary for committed projects
and for reasonably expected to become committed projects in 2001, regardless of
whether the need for the project arises from environmental compliance,
reliability requirements, nuclear safety, or other causes.  The data assumes
the sale of the Millstone units on March 30, 2001.  The construction program's
main focus in maintaining and upgrading the existing transmission and
distribution system and nuclear and hydroelectric generation assets.  The
system expects to evaluate its needs beyond 2001 in light of future
developments, such as restructuring, industry consolidation, performance, and
other events.

                          REGULATED ELECTRIC OPERATIONS

     DISTRIBUTION AND SALES

      CL&P, PSNH and WMECO furnish retail franchise service in 149, 198 and 59
cities and towns in Connecticut, New Hampshire and Massachusetts, respectively.
In December 2000, CL&P furnished retail franchise service to approximately 1.13
million customers in Connecticut, PSNH provided retail service to approximately
434,000 customers in New Hampshire and WMECO served approximately 199,000
retail franchise customers in Massachusetts.  HWP serves 30 retail customers in
Holyoke, Massachusetts.

     The following table shows the sources of 2000 electric franchise retail
revenues based on categories of customers:

                        CL&P     PSNH     WMECO     Total NU System

Residential........      46%       41%      40%           4%
Commercial.........      39%       35%      37%          38%
Industrial.........      14%       23%      22%           7%
Other..............       1%        1%       1%           1%
                        ---       ---      ---          ---
Total..............     100%      100%     100%         100%
                        ===       ===      ===          ===

     The actual changes in retail kWh sales for the last two years and the
forecasted retail sales growth estimates for the 10-year period 2000 through
2010 for CL&P, PSNH and WMECO are set forth below:

                        2000 over      1999 over        Forecast 2000-2010
                           1999           1998         Compound Rate of Growth

NU system..........        0.9%           3.8%                  1.3%
CL&P...............        0.4%           2.9%                  1.2%
PSNH...............        2.6%           5.3%                  2.0%
WMECO..............       -0.1%           3.6%                  1.0%

     Consolidated NU retail sales rose by 0.9 percent in 2000, compared with
1999, primarily due to higher heating requirements and the strong economy,
offset by lower cooling requirements.  Residential electric sales were up 0.2
percent.  Commercial sales were up by 1.3 percent for the year and industrial
sales increased by 1.1 percent.  Retail sales for all of the NU system
electric operating companies increased in 2000 with CL&P, WMECO and PSNH
sales up 0.4 percent, down 0.1 percent and up 2.6 percent, respectively.

     REGIONAL AND SYSTEM COORDINATION

     The NU system companies and most other New England utilities are parties
to an agreement (NEPOOL Agreement), which provides for coordinated planning and
operation of the region's generation and transmission facilities.  The NEPOOL
Agreement was restated and revised as of March 1997 to provide for (i) a pool-
wide open access transmission tariff; (ii) the creation of an Independent
System Operator (ISO), and; (iii) a broader governance structure for NEPOOL and
a more open, competitive market structure.  Under these new arrangements the
ISO, a nonprofit corporation whose board of directors and staff are not
controlled by or affiliated with market participants, ensures the reliability
of the NEPOOL transmission system, administers the NEPOOL tariff and oversees
the efficient and competitive functioning of the regional power market.

     The NEPOOL tariff provides for nondiscriminatory open access to the
regional transmission network at a single rate regardless of transmitting
distance for all transactions.  The rate is a formula, structured to ensure
that each transmission provider under the NEPOOL tariff recovers its revenue
requirements.

     In 1999, the NEPOOL Executive Committee filed a comprehensive settlement
of all issues set for hearing concerning the NEPOOL transmission tariff.  The
settlement resolves disputes concerning the calculation of revenue requirements
for transmission over NEPOOL facilities and resolves disputes over alleged
"double charges" under grandfathered transmission contracts retained by
individual transmission providers, including NU.  The settlement also includes
a ROE component which sets the ROE for each individual transmission provider
owning NEPOOL transmission facilities with respect to those facilities from
March 1, 1997, through at least June 1, 2000, provided no changes to individual
network transmission tariff rates are made after December 31, 1999.  NU's ROE
has been set at 11.75 percent.  NU has made no changes to its transmission
tariff rates since the settlement was reached; accordingly, its ROE has
remained unchanged.

     As part of the settlement, the ISO is required to independently audit the
charges in effect for the period June 1997 through May 2000, or direct that
such an audit be conducted under its supervision.  In June 2000, the ISO
engaged an independent auditing firm to conduct such an audit.  The audit
remains ongoing and the results of the audit will be filed at the FERC as an
informational filing.

     In December 2000, NU was notified by the FERC that it, along with several
other companies, would be the subject of a separate FERC industry-wide audit of
the accounting related to formula rate transmission tariffs.  The FERC
commenced its audit of NU in February 2001.

     Two agreements determine the manner in which costs and savings are
allocated among the NU system electric operating companies.  Under an agreement
(NUG&T) among CL&P, WMECO and HWP, these companies pool their electric
production costs and the costs of their principal transmission facilities.
Pursuant to the merger agreement between NU and PSNH, these companies and PSNH
entered into a 10-year sharing agreement (Sharing Agreement), expiring in June
2002, that provides, among other things, for the allocation of the capability
responsibility savings and energy expense savings resulting from a single-
system dispatch through NEPOOL.

     The NUG&T was revised in 1999 to eliminate the generation aspects of the
agreement.  Revision to the NUG&T was initially contested by the Massachusetts
Attorney General, who claimed that such revision would result in stranded costs
being transferred unfairly to WMECO.  In July 1999, the FERC approved the
proposed amendment subject to the outcome of a hearing which was held in
abeyance pending the outcome of state restructuring proceedings.  The DTE
rejected the Massachusetts Attorney General's arguments in a December 1999
order.  While the FERC hearing continues to be held in abeyance, NUSCO and
the Massachusetts Attorney General reached settlement on a number of issues
related to restructuring in Massachusetts.  As part of that settlement, the
Massachusetts Attorney General withdrew its opposition to the revisions to
the NUG&T.  The FERC approved such withdrawal in September 2000.

     The Settlement Agreement between PSNH and the state of New Hampshire was
approved by the NHPUC on April 19, 2000.  Accordingly, NU will file for FERC
approval to terminate the Sharing Agreement, as mandated by the Settlement
Agreement, effective December 31, 2000.  Only minor revenue changes are
expected in the future as no energy or capacity transactions have taken place
under the Sharing Agreement since CL&P and WMECO relinquished their
responsibilities to meet customer loads on January 1, 2000.  Transmission
revenues will be allocated going forward based upon the respective companies'
cost of service where these revenues had been split equally by PSNH and CL&P
under the Sharing Agreement.

     On March 6, 2001, the FERC issued an order on rehearing related to the
price for installed capacity (ICAP) in New England.  The FERC reinstituted
the previously approved $8.75 per kilowatt-month charge for installed
capacity, but made the price effective April 1, 2001.  In an earlier decision
in December 2000, the FERC had made the charge effective as of August 1,
2000, but in its revised decision, the FERC substituted a $0.17 per kilowatt-
month charge for the period of August 2000 through March 2001.  Because NU
was a major seller of installed generating capacity during the last five months
of 2000, the FERC's revised decision with respect to the August through March
time period reduced NU's fourth quarter revenues by $24.6 million and lowered
earnings by $14.8 million, or $0.10 per share.  On March 16, 2001, NU filed
with the FERC for rehearing of its order.  On the same day, several utilities,
the Massachusetts Attorney General and the Maine Public Utilities Commission
appealed that portion of the FERC's order reinstituting the $8.75 charge on
a going-forward basis to the First Circuit U.S. Appeals Court.

     TRANSMISSION ACCESS AND FERC REGULATORY CHANGES

     Pursuant to FERC Order 888 (issued in April 1996), NU system companies
operate their transmission system under an open access, nondiscrimatory
transmission tariff.

     In December 1999, the FERC issued an order calling on all transmission
owners to voluntarily join regional transmission organizations (RTOs) in order
to boost competition in electric markets (Order 2000).  In general, each such
organization would be an independent operator over all transmission facilities,
and would perform, among other functions, tariff administration, construction
planning and reliability management for the particular regional transmission
system.  NU's active voting interest in such an organization would be limited
to 5 percent under the proposal.

     NU system companies and other parties have appealed this order.  Of
primary concern to NU is the ratemaking authority granted to RTOs and its
impact on the ability of transmission owners to earn appropriate returns on
their transmission investment under the organizational structure and the
minimum functions proposed in the order.  The NU system companies are
required to participate in a collaborative process established by the FERC
beginning in March of 2000.

     On January 16, 2001, NU along with the ISO and five other New England
transmission owning utilities (National Grid, USA, The United Illuminating
Company, Bangor Hydro-Electric Company, CMP and Vermont Electric Company) filed
a proposal to establish a New England Regional Transmission Organization
(NERTO) in compliance with FERC's order.  As proposed, NERTO would consist of
the ISO and a newly formed for-profit independent transmission company
(Northeast ITC).  Pursuant to an RTO agreement, both entities would share the
minimum required functions of an RTO set forth in the FERC order.  The ISO
would be primarily responsible for short-term reliability functions and
Northeast ITC would operate (but not initially own) the transmission assets of
the participating transmission owners, develop and administer a transmission
tariff, and engage in transmission planning and expansion activities.  NU
would be a shareholder in Northeast ITC and would appoint a member of the
board of directors.  NU's voting interest would remain capped at five percent,
consistent with the requirement of the FERC order, until a change in law or
regulation that would permit NU to have an increased voting interest.

     The NERTO proposal will require changes to the existing NEPOOL
arrangements.  Proposals for such changes continue to be discussed in regional
meetings.  The NERTO proposal will also require changes to the NEPOOL tariff
and NU's other transmission tariffs and agreements.  Provided the NERTO
proposal is approved, NU expects to file tariff changes later this year.

     Since NEPOOL established competitive wholesale markets in 1999, congestion
costs (the cost of higher energy prices within the New England market due to
transmission constraints) have grown steadily surpassing $150 million in total
by year end 2000.  The ISO New England made a filing at the FERC in March 2000
to implement a congestion management system (CMS) similar to those in use in
the New York ISO and Pennsylvania - New Jersey - Maryland Interconnection.
CMS uses locational based pricing to assign costs to regional load zones,
within New England.  Individual load zones will experience higher or lower
congestion costs as the CMS will replace the current practice of distributing
and averaging congestion costs across all New England loads.  The FERC's
response to the ISO New England's CMS filing encouraged early implementation
(less than a year); the ISO New England has indicated implementation will take
18 to 24 months.  The current estimate for implementation of the CMS is during
the first quarter of 2002.

                            REGULATED GAS OPERATIONS

     REGULATION

     Yankee Gas operates the largest natural gas distribution system in
Connecticut as measured by number of customers and size of service territory.
Total throughput (sales and transportation) for 2000 was 52.6 billion cubic
feet.  In 2000, total gas operating revenue of $345 million were comprised of
the following: 48 percent residential; 28 percent commercial; 20 percent
industrial, and; the remaining 4 percent other.  Yankee Gas provides firm gas
sales service to customers who require a continuous gas supply throughout the
year, such as residential customers who rely on gas for their heating, hot
water and cooking needs.  Yankee Gas also provides interruptible gas sales
service to certain commercial and industrial customers that have the
capability to switch from natural gas to an alternative fuel on short notice.
Yankee Gas can interrupt service to these customers during peak demand
periods.  Yankee Gas offers firm and interruptible transportation services to
customers who purchase gas from sources other than Yankee Gas.  In addition,
Yankee Gas performs gas exchanges and capacity releases to marketers to
reduce its overall gas expense.

     Although Yankee Gas is not subject to FERC jurisdiction, the FERC does
regulate the interstate pipelines serving Yankee Gas' service territory.
Yankee Gas, therefore, is directly and substantially affected by the FERC's
policies and actions.  Accordingly, Yankee Gas closely follows and, when
appropriate, participates in proceedings before the FERC.

     Yankee Gas is subject to regulation by the DPUC, which, among other
things, has jurisdiction over rates, accounting procedures, certain
dispositions of property and plant, mergers and consolidations, issuances of
securities, standards of service, management efficiency, and construction and
operation of distribution, production and storage facilities.

     The DPUC may, after a special public hearing, order an interim rate
decrease if it finds that Yankee Gas' ROE exceeds a reasonable rate of return
and rates are more than just, reasonable and adequate as determined by the
DPUC.  The DPUC also is empowered to grant an interim rate increase under
compelling circumstances.

     On August 9, 2000, Yankee Gas was ordered by the DPUC to file a rate
application.  This review of Yankee Gas' rates is required under Connecticut
law because 4 years have passed since its last rate review.  In accordance with
the most recent schedule approved by the DPUC, Yankee Gas filed a cost of
service study on February 14, 2001, which reflected a historical test year
ending September 30, 2000.  Yankee Gas has asked the DPUC to approve a schedule
that would call for Yankee Gas to file a letter of intent in May 2001, and its
full filing in July 2001.

                              NUCLEAR GENERATION

     GENERAL

     Certain NU system companies have ownership interests in four nuclear
units, Millstone 1, 2 and 3 and Seabrook, and equity interests in four regional
nuclear companies (the Yankee Companies) that separately own the Connecticut
Yankee nuclear unit (CY), the Maine Yankee nuclear unit (MY), the Vermont
Yankee nuclear unit (VY), and the Yankee Rowe nuclear unit (Yankee Rowe).
NU system companies operate Millstone 2 and 3 and Seabrook.  Yankee Rowe,
CY, MY, and Millstone 1 have been permanently removed from service.

     CL&P and WMECO own 100 percent of Millstone 1 and 2 as tenants in common.
Their respective ownership interests in each unit are 81 percent and 19
percent.

     CL&P, PSNH and WMECO have agreements with other New England utilities
covering their joint ownership as tenants in common of Millstone 3.  CL&P's,
PSNH's and WMECO's ownership interests in the unit are 52.93, 2.85 and 12.24
percent, respectively.  NAEC and CL&P have 35.98 percent and 4.06 percent
ownership interests, respectively, in Seabrook.

     In 1996, one of the joint owners of Millstone 3, the Vermont Electric
Generation and Transmission Cooperative, Inc. (VEG&T), filed for bankruptcy.
The subsequent liquidation resulted in the offering of VEG&T's 0.35 percent
share of Millstone 3 for sale to the joint owners of Millstone 3.  None of
the non-NU joint owners accepted the offer.  The VEG&T ownership interest in
Millstone 3 is included in the sale of the unit to Dominion.

     The Millstone 3 and Seabrook joint ownership agreements provide for pro-
rata sharing by the owners of each unit of the construction and operating
costs, the electrical output and the associated transmission costs.  CL&P and
WMECO, through NNECO as agent, operate Millstone 3 at cost, and without
profit, under a sharing agreement that obligates them to utilize good utility
operating practice and requires the joint owners to share the risk of employee
negligence and other risks pro-rata in accordance with their ownership shares.
The sharing agreement provides that CL&P and WMECO would only be liable for
damages to the minority owners for a deliberate breach of the agreement
pursuant to authorized corporate action.

     CL&P, PSNH, WMECO, and other New England electric utilities are the
stockholders of the Yankee Companies.  Each Yankee Company owns a single
nuclear generating unit.  The stockholder-sponsors of each Yankee Company are
responsible for proportional shares of the operating and decommissioning costs
of the respective Yankee Company and are entitled to proportional shares of the
electrical output in the case of VY, which is the only operating unit of the
four Yankee Companies set forth below.  The relative rights and obligations
with respect to the Yankee Companies are approximately proportional to the
stockholders' percentage stock holdings, but vary slightly to reflect
arrangements under which nonstockholder electric utilities have contractual
rights to some of the output of particular units.  CL&P's, PSNH's and WMECO's
stock ownership percentages in the Yankee Companies are set forth below:

                                  CL&P       PSNH      WMECO   NU system
Connecticut Yankee Atomic
 Power Company (CYAPC) ......     34.5%       5.0%      9.5%     49.0%
Maine Yankee Atomic Power
 Company (MYAPC) ............     12.0%       5.0%      3.0%     20.0%
Vermont Yankee Nuclear
 Power Corporation (VYNPC)...      9.5%       4.0%      2.5%     16.0%
Yankee Atomic Electric
 Company (YAEC)  ............     24.5%       7.0%      7.0%     38.5%

     In 1999, VYNPC agreed to sell its nuclear generating unit for $22 million
to an unaffiliated company.  Among other commitments, the acquiring company
would have agreed to assume the obligation to decommission the unit after it
is taken out of service, and the owners of VYNPC (including CL&P, WMECO and
PSNH) agreed to fund their shares of the decommissioning costs up to a
negotiated amount.  Subsequent to the time that agreement was executed, the
original proposed acquiring company has increased the price it agreed to pay
and three other unaffiliated companies have indicated their interest in buying
VYNPC's generating unit on terms that have not been disclosed.  Participants in
the Vermont regulatory proceeding, including VYNPC, have argued that it is most
appropriate for the unit to be sold in an open auction proceeding.  On
February 14, 2001, the Vermont Public Service Commission rejected the agreement
to sell VY to the proposed purchaser.  VYNPC is reviewing its options relating
to VY, including the possibility of an auction.  At present, CL&P, WMECO and
PSNH expect that the unit will be sold, but the identity of the owner and the
terms of sale, including price, future decommissioning obligations and future
power purchase obligations, are not known.

     The operators of Millstone 2 and 3, VY and Seabrook hold full term
operating licenses from the NRC and are subject to the jurisdiction of the NRC.
The NRC has broad jurisdiction over the design, construction and operation of
nuclear generating stations, including matters of public health and safety,
financial qualifications, antitrust considerations, and environmental impact.
The NRC issues 40-year initial operating licenses to nuclear units and NRC
regulations permit renewal of licenses for an additional 20-year period.
The NRC also has jurisdiction over the decommissioning activities at Yankee
Rowe, CY, MY, and Millstone 1.

     The NRC also regularly conducts generic reviews of technical and other
issues, a number of which may affect the nuclear plants in which NU system
companies have interests.  The cost of complying with any new requirements that
may result from these reviews cannot be estimated at this time, but such costs
could be substantial.

     NUCLEAR PLANT PERFORMANCE

     MILLSTONE 3

     Millstone 3 has a license expiration date of November 25, 2025.  In 2000,
Millstone 3 operated at a capacity factor of virtually 100 percent.  On
February 3, 2001, Millstone 3 began a scheduled refueling outage and is
expected to return to service during March 2001.

     MILLSTONE 2

     Millstone 2 has a license expiration date of July 31, 2015.  Millstone 2
returned to service on June 1, 2000, following a 41 day outage, which began in
April 2000, and achieved a 97.4 percent capacity factor from that date to
December 31, 2000.  For the full year 2000, Millstone 2 operated at a capacity
factor of 82 percent.

     SEABROOK

     Seabrook has a license expiration date of October 17, 2026.  In 2000,
Seabrook operated at a capacity factor of 78 percent.  After an extended 101-
day refueling and maintenance outage due to repairs to an emergency diesel
generator, Seabrook returned to service on January 29, 2001.

     VERMONT YANKEE

     VY has a license expiration date of March 21, 2012.  In 2000, VY operated
at a capacity factor of 99.2 percent.

     NUCLEAR INSURANCE

     For information regarding nuclear insurance, see "Commitments and
Contingencies - Nuclear Insurance Contingencies" in the notes to NU's, CL&P's,
PSNH's, WMECO's, and NAEC's financial statements.

     NUCLEAR FUEL

          GENERAL

     The supply of nuclear fuel for the NU system's existing units requires the
procurement of uranium concentrates, followed by the conversion, enrichment and
fabrication of the uranium into fuel assemblies suitable for use in the NU
system's units.  Fuel may also be purchased at a point after any of the above
processes are completed.  The NU system expects that uranium concentrates and
related services for the units operated by the NU system and for the other
units in which the NU system companies are participating that are not covered
by existing contracts, will be available for the foreseeable future on
reasonable terms and prices.

     As a result of the Energy Policy Act, the United States commercial nuclear
power industry is required to pay the United States Department of Energy (DOE),
through a special assessment, for the costs of the decontamination and
decommissioning of uranium enrichment plants owned by the United States
government, no more than $150 million per annum for 15 years beginning in 1993.
Each domestic nuclear utility's payment is based on its pro-rata share of all
enrichment services received by the United States commercial nuclear power
industry from the United States government through October 1992.  Each year,
the DOE adjusts the annual assessment using the Consumer Price Index.  The
Energy Policy Act provides that the assessments are to be treated as reasonable
and necessary current costs of fuel, which costs shall be fully recoverable in
rates in all jurisdictions.  The NU system's remaining share to be recovered,
assuming no escalation, is approximately $28.9 million as of December 31, 2000.
Management believes that the DOE assessments against CL&P, WMECO, PSNH, and
NAEC will be recoverable in future rates.  Accordingly, each of these companies
has recognized these costs as a regulatory asset, with a corresponding
obligation on its balance sheet.

     In 1998, an action was initiated by the owners of Millstone in the U.S.
Court of Federal Claims against the DOE regarding the special annual assessment
that the DOE imposes on purchasers of enriched uranium to meet the future costs
of decontaminating and decommissioning (D&D) government owned uranium
enrichment facilities.  Similar actions for Seabrook and CY were also filed.
The lawsuits challenge the imposition of the D&D assessment on federal
constitutional grounds, and are similar to actions filed by a number of other
utilities against DOE.  Proceedings in the Millstone, Seabrook and CY cases
are stayed pending the final resolution of a similar claim brought against the
DOE by MYAPC.  In July 1999, the claims court dismissed MYAPC's complaint.
MYAPC's appeal of this decision is pending before the court.  As of
December 31, 2000, the NU system companies had paid approximately $41.7 million
into the fund.

     Nuclear fuel costs associated with nuclear plant operations include
amounts for disposal of spent nuclear fuel.  The NU system companies include
in their nuclear fuel expense spent fuel disposal costs accepted by the DPUC,
NHPUC and DTE in rate case or fuel adjustment decisions.  Spent fuel disposal
costs also are reflected in the FERC-approved wholesale charges.

     HIGH-LEVEL RADIOACTIVE WASTE

     The Nuclear Waste Policy Act of 1982 (NWPA) provides that the federal
government is responsible for the permanent disposal of spent nuclear reactor
fuel (SNF) and high-level waste.  As required by the NWPA, electric utilities
generating SNF and high-level waste are obligated to pay fees into a fund which
would be used to cover the cost of siting, constructing, developing, and
operating a permanent disposal facility for this waste.  The NU system
companies have been paying for such services for fuel burned on or after
April 7, 1983, on a quarterly basis since July 1983.  The DPUC, NHPUC and DTE
permit the fee to be recovered through rates.  For nuclear fuel used to
generate electricity prior to April 7, 1983, payment must be made prior to the
first delivery of spent fuel to the DOE.  The DOE's current estimate for an
available site is 2010.

     In return for payment of the fees prescribed by the NWPA, the federal
government is to take title to and dispose of the utilities' high-level wastes
and SNF.  There have been numerous litigation proceedings involving the DOE's
statutory and contractual obligation to accept high-level waste and SNF.  While
the courts have declined to order the DOE to begin accepting spent fuel for
disposal on January 31, 1998, the courts left open the utilities' ability to
bring damage claims against the DOE.

     In 1998, YAEC, CYAPC and MYAPC filed separate complaints against the DOE
in the U.S. Court of Federal Claims seeking monetary damages resulting from
DOE's failure to accept spent nuclear fuel for disposal. In decisions later
that year, the court found liability on the part of DOE to the companies for
breach of the standard contract, based upon the DOE's failure to begin
disposal of spent nuclear fuel.  Further proceedings to determine damages
owed to YAEC, CYAPC and MYAPC remain stayed by the court as a result of DOE's
appeal of the liability decisions and related litigation involving other
utilities.

     Until the federal government begins accepting nuclear waste for disposal,
nuclear generating plants will need to retain high-level waste and spent fuel
onsite or make some other provisions for their storage.  With the addition of
new storage racks, storage facilities for Millstone 3 are expected to be
adequate for the current licensed life of the unit.  With the implementation
of currently planned modifications, the storage facilities for Millstone 2
are expected to be adequate (maintaining the capacity to accommodate a full-
core discharge from the reactor) until 2005  Seabrook is expected to have
spent fuel storage capacity until at least 2010.

     The VY spent fuel pool is expected to be able to accommodate full-core
removal through 2004 as a result of the installation and licensing of new
racks in January 2001.  In 2003, VYNPC expects to install an additional rack
which would provide for full core off-load capability through 2008.

     Adequate storage capacity exists to accommodate all of the SNF at
Millstone 1, CY, MY, and Yankee Rowe until that fuel is removed by the DOE.

     LOW-LEVEL RADIOACTIVE WASTE

     The NU system currently has contracts to dispose of its low-level
radioactive waste (LLRW) at two privately operated facilities in Clive, Utah,
and in Barnwell, South Carolina.  In July 2000, the Northeast Interstate Low
Level Radioactive Waste Management Compact, consisting of Connecticut and New
Jersey, accepted South Carolina as a new member and is now known as the
Atlantic Compact. This arrangement entitles Millstone and CY access to
Barnwell through their decommissioning. This arrangement may eventually
exclude other nuclear plants from accessing Barnwell.  As a contingency, the
NU system has plans that will allow for onsite storage of LLRW for at least
5 years.

     DECOMMISSIONING

     Based upon the NU system's most recent comprehensive site-specific updates
of the decommissioning costs for each of the three Millstone units and for
Seabrook, the recommended decommissioning method continues to be immediate and
complete dismantlement of those units as soon as practical after their
retirement.  The table below sets forth the estimated Millstone and Seabrook
decommissioning costs for the NU system companies.  The estimates are based
on the latest site studies, stated in December 31, 2000, dollars.

                   CL&P       PSNH      WMECO      NAEC      NU system
                                     (Millions)

Millstone 1*    $  580.3     $ -       $136.1     $  -       $  716.4
Millstone 2        348.8       -         81.8        -          430.6
Millstone 3        343.1      18.4       79.3        -          440.8
Seabrook            23.8       -          -        210.8        234.6
                --------     -----     ------     ------     --------
  Total         $1,296.0     $18.4     $297.2     $210.8     $1,822.4
                ========     =====     ======     ======     ========

     *The costs shown include all of the billings associated with the funding
of decommissioning, recovery of remaining assets and other closure costs
associated with the early retirement of Millstone 1 as of December 31, 2000,
which have been recorded as an obligation on the books of the NU system
companies of which $74.4 million has been spent and reimbursed as of
December 31, 2000.

     In 1986, the DPUC approved the establishment of separate external trusts
for the currently tax-deductible portions of decommissioning expense accruals
for Millstone 1 and 2 and for all expense accruals for Millstone 3.  WMECO
has established independent trusts to hold all decommissioning expense
collections from customers.  The DTE has authorized WMECO to collect its
current decommissioning estimate for the three Millstone units.

     New Hampshire enacted a law in 1981 requiring the creation of a state-
managed fund to finance decommissioning of any units in that state.  NAEC's
costs for decommissioning Seabrook are billed by it to PSNH and recovered by
PSNH under the Rate Agreement.  During April 1999, the Nuclear Decommissioning
Finance Committee (NDFC) issued an order that adjusted the decommissioning
collection period and funding levels.  The NDFC's order concluded that
Seabrook's anticipated energy producing life was 25 years from the date it
went into commercial operation, and accordingly Seabrook will end its energy
producing life in October 2015.  This is 11 years earlier than the service life
established by Seabrook's NRC operating license.  The order also updated
Seabrook's decommissioning estimate to $513 million (in 1998 dollars).  In
December 2000, the NDFC approved an updated decommissioning estimate of $585.9
million (in 2000 dollars).  The cost of funding the decommissioning of Seabrook
continues to be accrued over the expected remaining service life of the plant,
as determined by the NDFC, and is included in depreciation expense.  After
commencement of competition, PSNH will recover decommissioning expenses as a
stranded cost.

     As of December 31, 2000, the NU system recorded balances (at market) in
its external decommissioning trust funds are as follows:

                   CL&P    PSNH     WMECO     NAEC   NU system
                                  (Millions)

   Millstone 1    $226.8   $ -     $ 62.5     $ -      $289.3
   Millstone 2     179.6     -       49.5       -       229.1
   Millstone 3     124.7    7.4      32.9       -       165.0
   Seabrook          5.8     -         -       50.8      56.6
                  ------   ----    ------     -----    ------
    Total         $536.9   $7.4    $144.9     $50.8    $740.0
                  ======   ====    ======     =====    ======

     Pursuant to NU's purchase and sale agreement (PSA) with Dominion for the
sale of the Millstone units, upon the closing of the sale, which is expected to
occur on or about April 2, 2001, the sellers are obligated to deliver to
Dominion decommissioning funds in the amounts of $268.3 million for Unit 1,
$253 million for Unit 2 and $244 million for Unit 3.  With respect to Unit 3,
the NU system companies are responsible for $178 million of the total amount
to be turned over to Dominion.  At that point, Dominion will assume full
responsibility for decommissioning the three Millstone units, and NU
shareholders, the NU system companies and their ratepayers will have no
further obligation related to decommissioning.  If the closing is delayed,
the amount of decommissioning funds to be transferred to Dominion will be
increased by 0.5 percent per month for each month of delay. Finally, the PSA
requires that Unit 1 be turned over to Dominion in "cold and dark" condition.
If it is not, the NU system companies have agreed to add to the decommissioning
trust fund the necessary additional amount to place the unit in "cold and dark"
condition.  That amount, if any, is currently unknown, as it is expected that
the unit will be turned over in a "cold and dark" condition.

     Pursuant to the PSNH Settlement Agreement, upon a successful sale of
NAEC's share of Seabrook, the existing Seabrook Power Contracts between PSNH
and NAEC will be terminated.  However, subsequent to such sale, PSNH shall
continue to be responsible for funding NAEC's former ownership share of its
decommissioning liability, calculated on the basis of full funding by
December 31, 2015, using an estimated decommissioning date of 2015, or as
otherwise determined by the NDFC.  PSNH may enter into a new contract to
provide for the payment of Seabrook nuclear decommissioning costs, with full
recovery of the costs of that contract to be recoverable from PSNH's
customers.  Under no circumstances will PSNH's customers have any
responsibility for increases in decommissioning funding above the amount
calculated based upon the payment schedule as of the sale date.

     In June 1999, NNECO filed with the NRC the Post-Shutdown Decommissioning
Activities Report for Millstone 1.  The total estimated decommissioning costs,
which have been updated to reflect the early shutdown of the unit, are
approximately $692 million as of December 31, 2000 ($560.5 million for CL&P
and $131.5 million for WMECO).

     CYAPC, VYNPC and MYAPC are all collecting revenues for decommissioning
from their power purchasers.  The table below sets forth the NU system
companies' estimated share of remaining decommissioning costs (and closure
costs where applicable) of the Yankee units as of December 31, 2000.  The
estimates are based on the latest site studies.  For information on the
equity ownership of the NU system companies in each of the Yankee units and
the proposed sale of VY, see "Nuclear Generation - General."

                         CL&P      PSNH    WMECO     NU system
                                     (Millions)

       VY              $ 42.9     $18.1    $11.3       $ 72.3
       CY*               93.5      13.5     25.8        132.8
       MY*               67.1      27.9     16.8        111.8
                       ------     -----    -----       ------
      Total            $203.5     $59.5    $53.9       $316.9
                       ======     =====    =====       ======

     *The costs shown include all of the expected future billings associated
with the funding of decommissioning, recovery of remaining assets and other
closure costs associated with the early retirement of Yankee Rowe, CY and MY
as of December 31, 2000, which have been recorded as an obligation on the
books of the NU system companies.

     As of December 31, 2000, the NU system's share of the external
decommissioning trust fund balances (at market), which have been recorded on
the books of the Yankee nuclear companies, is as follows:

                        CL&P      PSNH      WMECO    NU system
                                      (Millions)
     VY               $ 26.8     $11.3      $ 7.0      $ 45.1
     Yankee Rowe        36.8      10.5       10.5        57.8
     CY                 58.8       8.5       16.2        83.5
     MY                 18.7       7.8        4.7        31.2
                      ------     -----      -----      ------
      Total           $141.1     $38.1      $38.4      $217.6
                      ======     =====      =====      ======

     On July 26, 2000, the FERC issued a letter approving an April 7, 2000,
settlement between CYAPC, the DPUC and the OCC on CY decommissioning.
Significant terms of the settlement include (1) decommissioning collections
of $16.7 million per year, fully funding decommissioning and spent fuel
storage costs through 2023; (2) consolidation of the pre-1983 spent fuel
trust into the decommissioning trust and lowering total decommissioning
collections by $56 million over the next seven years; (3) a ROE rate of 6
percent with no refunds of prior decommissioning or ROE collections, and;
(4) an incentive/penalty mechanism for decommissioning.  The effect of this
settlement on CYAPC earnings is approximately $9.0 million, of which NU's
share would be approximately $4.4 million.

     The settlement enabled the OCC to continue to argue that CYAPC was
entitled to recover only costs directly related to decommission the plant, and
may not recover remaining unamortized investment or any ROE, a position that
had been denied by the FERC's administrative law judge. On September 28, 2000,
the FERC issued an order confirming the ALJ's rejection of the OCC's argument,
from which no further action has been taken.

     Effective January 1996, YAEC began billing its sponsors, including CL&P,
WMECO and PSNH, amounts based on a revised decommissioning cost estimate
approved by the FERC.  Under the terms of its rate settlement agreement with
the FERC, YAEC filed a revised decommissioning cost estimate, which was approved
as of March 1, 2000.  The YAEC filing assumes NRC license termination and
completion of decommissioning activities by 2004.  Billings to YAEC sponsor
companies were completed in June 2000.

     In January 2001, NNECO filed a written notification with the NRC reporting
that during a reconciliation and verification of Millstone spent nuclear fuel
records, personnel concluded that the location of two full-length irradiated
fuel rods could not be determined, and was not properly tracked in the records.
The records reconciliation and verification effort is part of ongoing
decommissioning activities at Millstone 1.  NNECO reported that the two fuel
rods are from the same fuel assembly, which was disassembled in 1972 for
inspection, and were displaced from the fuel assembly in 1974.  NNECO further
reported that records indicate that in 1979 and 1980 the displaced rods were
physically verified to be stored in a canister in the Millstone 1 spent fuel
pool, and that the rods and canister are no longer in the spent fuel pool
location documented in 1979 and 1980.  NNECO's report indicated that records
retrieved to date do not document the relocation or disposition of the two
fuel rods.

     Due to the radiation levels associated with the fuel rods, NU believes
that the two rods remain stored in the Millstone 1 spent fuel pool, or were
shipped in a shielded cask to a facility licensed to accept radioactive
material.  NU's investigation into the location of the two fuel rods is
ongoing.

                   OTHER REGULATORY AND ENVIRONMENTAL MATTERS

      ENVIRONMENTAL REGULATION

          GENERAL

      The NU system and its subsidiaries are subject to federal, state and
local regulations with respect to water quality, air quality, toxic substances,
hazardous waste, and other environmental matters.  Additionally, the NU
system's major generation and transmission facilities may not be constructed
or significantly modified without a review by the applicable state agency of
the environmental impact of the proposed construction or modification.
Compliance with environmental laws and regulations, particularly air and
water pollution control requirements, may limit operations or require
substantial investments in new equipment at existing facilities.

     SURFACE WATER QUALITY REQUIREMENTS

     The federal Clean Water Act requires every "point source" discharger of
pollutants into navigable waters to obtain a National Pollutant Discharge
Elimination System (NPDES) permit from the United States Environmental
Protection Agency (EPA) or state environmental agency specifying the allowable
quantity and characteristics of its effluent.  NU system facilities are in the
process of obtaining or renewing all required NPDES permits in effect.
Compliance with NPDES and state water discharge permits has necessitated
substantial expenditures, which are difficult to estimate, and may require
further expenditures because of additional requirements that could be imposed
in the future.   For information regarding civil lawsuits related to alleged
violations of certain facilities' NPDES permits, see "Item 3. Legal
Proceedings."

     The Federal Oil Pollution Act of 1990 (OPA 90) sets out the requirements
for facility response plans and periodic inspections of spill response
equipment at facilities that can cause substantial harm to the environment by
discharging oil or hazardous substances into the navigable waters of the United
States and onto adjoining shorelines.  The NU system companies are currently in
compliance with the requirements of OPA 90.  OPA 90 includes limits on the
liability that may be imposed on persons deemed responsible for release of oil.
The limits do not apply to oil spills caused by negligence or violation of laws
or regulations.  OPA 90 also does not preempt state laws regarding liability
for oil spills.  In general, the laws of the states in which the NU system owns
facilities and through which the NU system transports oil could be interpreted
to impose strict liability for the cost of remediating releases of oil and for
damages caused by releases.  The NU system currently carries general liability
insurance in the total amount of $100 million annual coverage, which includes
liability coverage for oil spills.

      AIR QUALITY REQUIREMENTS

     The Clean Air Act Amendments of 1990 (CAAA), as well as state laws in
Connecticut, Massachusetts and New Hampshire, impose stringent requirements on
emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) for the purpose of
controlling acid rain and ground level ozone.  In addition, the CAAA address
the control of toxic air pollutants.  Installation of continuous emissions
monitors and expanded permitting provisions also are included.  Compliance with
CAAA requirements has cumulatively cost the NU system approximately $48 million
as of December 31, 2000: $11 million for CL&P, $33 million for PSNH, $1 million
for WMECO, and $3 million for HWP.  In addition, PSNH expects to spend
approximately $2 million a year for SO2 allowances.

     Further requirements for NOX reductions became effective in 1999.  PSNH
spent approximately $20 million for improvements at its Merrimack and Schiller
Stations to meet these requirements.  These costs were offset by the sale of
$16 million of emission credits.  Massachusetts and New Hampshire have proposed
significant emission reduction requirements for power plants in those states.
It is difficult to estimate the ultimate costs, since the proposals are not yet
firm, but the total could be approximately $10 to 15 million over the next
several years at Mt. Tom Station in Massachusetts.  PSNH expects to divest the
New Hampshire plants before the new requirements become effective.  Following
divestiture of the NU system's fossil units, these federal and state air
quality regulations are not expected to have a material impact on the NU system
companies.

     HAZARDOUS WASTE REGULATIONS

     As many other industrial companies have done in the past, the NU system
companies disposed of residues from operations by depositing or burying such
materials on-site or disposing of them at off-site landfills or facilities.
Typical materials disposed of include coal gasification waste, fuel oils,
gasoline, and other hazardous materials that might contain polychlorinated
biphenyls.  It has since been determined that deposited or buried wastes, under
certain circumstances, could cause groundwater contamination or create other
environmental risks.  The NU system has recorded a liability for what it
believes is, based upon currently available information, its estimated
environmental remediation costs for waste disposal sites for which the NU
system companies expect to bear legal liability, and continues to evaluate
the environmental impact of its former disposal practices.  Under federal and
state law, government agencies and private parties can attempt to impose
liability on NU system companies for such past disposal.  At December 31,
2000, the liability recorded by the NU system for its estimated environmental
remediation costs for known sites needing remediation, including those sites
described below, exclusive of recoveries from insurance or from third parties,
was approximately $82.3 million, representing 42 sites.  This total includes
liabilities recorded by Yankee Gas of $35 million.  All cost estimates were
made in accordance with generally accepted accounting principles where
remediation costs are probable and reasonably estimable.  These costs could
be significantly higher if alternative remedies become necessary.

     Under the federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended, commonly known as Superfund, the EPA has
the authority to clean up or order the clean up of hazardous waste sites and
to impose the clean up costs on parties deemed responsible for the hazardous
waste activities on the sites.  Responsible parties include the current owner
of a site, past owners of a site at the time of waste disposal, waste
transporters, and waste generators.  The NU system currently is involved in
three Superfund sites: one in New York, one in New Hampshire, and one in
Kentucky, which could have a material impact on the NU system.  The NU system
has committed in the aggregate approximately $1.4 million to its share of the
clean up of these sites.

      The greatest liabilities currently relate to former manufactured gas
plant (MGP) facilities which represent the largest share of future clean up
costs.  These facilities were owned and operated by predecessor companies to
the NU system from the mid-1800's to mid-1900's.  Byproducts from the
manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar,
metals and other waste products that may pose risks to human health and the
environment.  The NU system currently has partial or full ownership
responsibilities at 27 former MGP sites.  Of the total NU system liabilities,
$67.9 million has been established to address future remediation costs at MGP
sites.

     Other sites undergoing comprehensive investigations or remedial actions
under state programs located in Connecticut, Massachusetts, New Hampshire or
New Jersey include four former fuel oil releases, three landfills, three
asbestos hazard abatement projects and five miscellaneous projects.  To date,
approximately $12.9 million has been established to address future
remediation costs at these sites.

     In the past, the NU system has received other claims from government
agencies and third parties for the cost of remediating sites not currently
owned by the NU system but affected by past NU system disposal activities and
may receive more such claims in the future.  The NU system expects that the
costs of resolving claims for remediating sites about which it has been
notified will not be material, but cannot estimate the costs with respect to
sites about which it has not been notified.

     ELECTRIC AND MAGNETIC FIELDS

     Published reports have discussed the possibility of adverse health effects
from electric and magnetic fields (EMF) associated with electric transmission
and distribution facilities and appliances and wiring in buildings and homes.
Most researchers, as well as numerous scientific review panels considering all
significant EMF epidemiological and laboratory studies to date, agree that
current information remains inconclusive, inconsistent and insufficient for
characterizing EMF as a health risk.

     Based on this information, management does not believe that a causal
relationship between EMF exposure and adverse health effects has been
established or that significant capital expenditures are appropriate to
minimize unsubstantiated risks.  The NU system companies have closely
monitored research and government policy developments for many years and will
continue to do so.

     If further investigation were to demonstrate that the present electricity
delivery system is contributing to increased risk of cancer or other health
problems, the industry could be faced with the difficult problem of delivering
reliable electric service in a cost-effective manner while managing EMF
exposures.  To date, no courts have concluded that individuals have been harmed
by EMF from electric utility facilities, but if utilities were to be found
liable for damages, the potential monetary exposure for all utilities,
including the NU system companies, could be enormous.  Without definitive
scientific evidence of a causal relationship between EMF and health effects,
and without reliable information about the kinds of changes in utilities'
transmission and distribution systems that might be needed to address the
problem, if one is found, no estimates of the cost impacts of remedial actions
and liability awards are available.

     FERC HYDROELECTRIC PROJECT LICENSING

     Federal Power Act licenses may be issued for hydroelectric projects for
terms of 30 to 50 years as determined by the FERC.  Upon the expiration of a
license, any hydroelectric project so licensed is subject to reissuance by
the FERC to the existing licensee or to others upon payment to the licensee
of the lesser of fair value or the net investment in the project plus
severance damages less certain amounts earned by the licensee in excess of a
reasonable rate of return.

     The NU system companies currently hold FERC licenses for 12 hydroelectric
projects aggregating approximately 1,411 MW of capacity, located in
Connecticut, Massachusetts and New Hampshire.  CL&P's and WMECO's 5 licenses
with approximately 1,302 MW of capacity were transferred to NGC in March 2000.
As part of the Settlement Agreement, PSNH has proposed to auction its 6
hydroelectric projects (totaling nine plants) with approximately 65 MW of
capacity upon approval of the agreement.

     The original license for HWP's Holyoke Project expired in late 1999.  In
August 1999, the FERC issued a new 40-year license to HWP.  HWP was the
successful applicant in a contested license application proceeding for the
project, winning over co-applicants, the City of Holyoke Gas & Electric
Department, the Massachusetts Municipal Wholesale Electric Company and the
Ashburnham Municipal Light Plant.  HWP filed a motion for stay and motion for
rehearing of the FERC's order, requesting that the FERC reconsider various
aspects of the license, including mandatory Section 18 fishway prescriptions,
bypass reach minimum flows and compliance schedules.  Motions for rehearing
of the FERC's order were also filed by various other parties. The FERC issued
an order granting rehearing.  HWP is awaiting further action by the FERC.  In
a separate but related proceeding, HWP filed an appeal of the state water
quality certificate conditions and requested an adjudicatory hearing with the
Massachusetts Department of Environmental Protection.  A settlement agreement
and revised water quality certificate were filed with the administrative law
judge on February 9, 2001.

     NGC's FERC licenses for operation of the Falls Village and Housatonic
hydroelectric projects expire in 2001.  A license application, which proposed
to combine both projects under one license, was submitted to the FERC  in
August 1999.  A settlement has been reached with the Connecticut Department
of Environmental Protection (DEP) on the Section 401 water certifications
necessary for relicensing.  The FERC has begun the process that delineates
the items that it expects to review as part of its environmental assessment
of the projects and the application for license.  Public meetings and tours
at the developments have been held and comments were filed by the public,
agencies and applicant by the January 8, 2001, FERC deadline. No additional
information requests have been received.

     PSNH's FERC license for the three dam Amoskeag project expires on
December 31, 2005.  PSNH filed a notice of intent to file for a new license
on December 29, 2001.

     The FERC has issued a notice indicating that it has authority to order
project licensees to decommission projects that are no longer economic to
operate.  The potential costs of decommissioning a project, however, could be
substantial.  The FERC has recently ordered its first project decommissioning
under this authority.  It is likely that this FERC decision will be appealed.

                                    EMPLOYEES

     As of December 31, 2000, the NU system companies had 9,260 employees on
their payrolls, of which 2,057 were employed by CL&P, 1,227 by PSNH, 406 by
WMECO, 410 by Yankee Gas, 110 by R. M. Services, 2 by HWP, 1,696 by NNECO,
2,044 by NUSCO, 782 by NAESCO, 104 by Select Energy, and 422 by HEC.  NU,
NAEC, Mode 1, NUEI, NGC, NGS, and SEPPI have no employees.

     On December 15, 2000, 498 employees of CL&P, PSNH, WMECO, HWP, NUSCO,
and Yankee Gas were offered a voluntary separation program (VSP).   There
were 361 employees who accepted the VSP and are expected to retire between
March 1, 2001, and March 2002.  Costs relating to the VSP will be reflected
in the first quarter of 2001 results.

     Approximately 2,450 employees of CL&P, PSNH, WMECO, NAESCO, HWP, and
Yankee Gas are covered by 15 union agreements, which expire between June 1,
2001, and October 1, 2003.


ITEM 2.  PROPERTIES

     The physical properties of the NU system are owned or leased by
subsidiaries of NU.  CL&P's principal plants and other properties are located
either on land which is owned in fee or on land, as to which CL&P owns
perpetual occupancy rights adequate to exclude all parties except possibly
state and federal governments, which has been reclaimed and filled pursuant
to permits issued by the United States Army Corps of Engineers.  The principal
properties of PSNH are held by it in fee.  In addition, PSNH leases space in
an office building under a 30-year lease expiring in 2002.  WMECO's principal
plants and a major portion of its other properties are owned in fee, although
one hydroelectric plant is leased.  NAEC owns a 35.98 percent interest in
Seabrook and approximately 560 acres of exclusion area land located around
the unit.  In addition, CL&P, PSNH and WMECO have certain substation equipment,
data processing equipment, nuclear fuel, nuclear control room simulators,
vehicles, and office space that are leased. With few exceptions, the NU system
companies' lines are located on or under streets or highways, or on properties
either owned or leased, or in which the Company has appropriate rights,
easements or permits from the owners.

     CL&P's and PSNH's properties are subject to the lien of each company's
respective first mortgage indenture.  WMECO's properties are subject to the
lien of its first mortgage indenture.  NAEC's first mortgage bonds are secured
by a lien on the Seabrook Interest described above, and all rights of NAEC
under the Seabrook Power Contracts.  In addition, CL&P's and WMECO's interests
in Millstone 1 are subject to second liens for the benefit of lenders under
agreements related to PCRBs.  Also, CL&P and WMECO granted, as collateral,
their second mortgage ownership interests in Millstone 2 and 3 that secure
their borrowings under the new credit agreement.  Various of these properties
are also subject to minor encumbrances which do not substantially impair the
usefulness of the properties to the owning company.

     The NU system companies' properties are well maintained and are in good
operating condition.

     TRANSMISSION AND DISTRIBUTION SYSTEM

     At December 31, 2000, the NU system companies owned 103 transmission and
370 distribution substations that had an aggregate transformer capacity of
19,751,356 kilovoltamperes (kVa) and 8,957,289 kVa, respectively; 3,075 circuit
miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV,
and 196 cable miles of underground transmission lines ranging from 69 kV to
138 kV; 33,216 pole miles of overhead and 2,191 conduit bank miles of
underground distribution lines; and 423,055 line transformers in service with
an aggregate capacity of 18,268,000 kVa.

     ELECTRIC GENERATING PLANTS

     As of December 31, 2000, the electric generating plants of the NU system
companies and the NU system companies' entitlement in the generating plant of
the VYNPC were as follows (See "Item 1. Business - Nuclear Generation" for
information on ownership and operating results for the year):

<TABLE>
<CAPTION>
                                                                               Claimed
                                                                  Year       Capability*
Owner        Plant Name (Location)               Type          Installed     (kilowatts)
- -----        --------------------                ----          ---------     -----------
<S>          <C>                                <C>              <C>          <C>
CL&P         Millstone (Waterford, CT)
               Unit 2                           Nuclear           1975          706,543
               Unit 3                           Nuclear           1986          603,436
             Seabrook (Seabrook, NH)            Nuclear           1990           47,135
             VT Yankee (Vernon, VT)             Nuclear           1972           45,189
                                                                              ---------
             Total Nuclear-Steam Plants         ( 4 units)                    1,402,303
             Total Internal Combustion          ( 4 units)        1970          195,600
                                                                              ---------
             Total CL&P Generating Plant        ( 8 units)                    1,597,903
                                                                              =========

PSNH         Millstone (Waterford, CT)
               Unit 3                           Nuclear           1986           32,461
             VT Yankee (Vernon, VT)             Nuclear           1972           18,999
                                                                              ---------
             Total Nuclear-Steam Plants         ( 2 units)                       51,460
             Total Fossil-Steam Plants          ( 7 units)       1952-78        639,568
             Total Hydro-Conventional           (20 units)       1917-83         67,930
             Total Internal Combustion          ( 5 units)       1968-70        103,594
                                                                              ---------
             Total PSNH Generating Plant        (34 units)                      862,552
                                                                              =========

WMECO        Millstone (Waterford, CT)
               Unit 2                           Nuclear           1975          165,732
               Unit 3                           Nuclear           1986          139,519
             VT Yankee (Vernon, VT)             Nuclear           1972           11,904
                                                                              ---------
             Total Nuclear-Steam Plants         ( 3 units)                      317,155
             Total Hydro-Conventional           ( 3 units)        1930           33,960**
                                                                              ---------
             Total WMECO Generating Plant       ( 6 units)                      351,115
                                                                              =========

NAEC         Seabrook (Seabrook, NH)            Nuclear           1990          417,751
                                                                              =========

HWP          Mt. Tom (Holyoke, MA)              Fossil-Steam      1960          147,000
             Total Hydro-Conventional           (15 units)       1905-83         43,560
                                                                              ---------
             Total HWP Generating Plant         (16 units)                      190,560
                                                                              =========

NGC          Total Hydro-Conventional           (36 units)       1903-55        158,220
             Total Hydro-Pumped Storage         ( 7 units)       1928-73      1,151,350
             Tunnel (Preston, CT)               ( 1 unit)         1969           20,800
                                                                              ---------
             Total NGC Generating Plant         (44 units)                    1,330,370
                                                                              =========
NU system    Millstone (Waterford, CT)
               Unit 2                           Nuclear           1975          872,275
               Unit 3                           Nuclear           1986          775,416
             Seabrook (Seabrook, NH)            Nuclear           1990          464,886
             VT Yankee (Vernon, VT)             Nuclear           1972           76,092
                                                                              ---------
             Total Nuclear-Steam Plants         ( 4 units)                    2,188,669
             Total Fossil-Steam Plants          ( 8 units)       1952-78        786,568
             Total Hydro-Conventional           (74 units)       1903-83        303,670
             Total Hydro-Pumped Storage         ( 7 units)       1928-73      1,151,350
             Total Internal Combustion          (10 units)       1968-70        319,994
                                                                              ---------
             Total NU system Generating Plant
               Including Vermont Yankee         (103 units)                   4,750,251
                                                                              =========
               Excluding Vermont Yankee         (102 units)                   4,674,159
                                                                              =========
</TABLE>

  * Claimed capability represents winter ratings as of December 31, 2000.

 ** Total Hydro-Conventional capability includes the Cobble Mtn. plant's
    33,960 kilowatts which is leased from the City of Springfield, MA.

     FRANCHISES

     CL&P.  Subject to the power of alteration, amendment or repeal by the
General Assembly of Connecticut and subject to certain approvals, permits and
consents of public authority and others prescribed by statute, CL&P has,
subject to certain exceptions not deemed material, valid franchises free from
burdensome restrictions to provide electric transmission and distribution
services, and, until January 2000, to sell electricity, in the respective
areas in which it is now supplying such service.

     In addition to the right to provide electric transmission and distribution
services as set forth above, the franchises of CL&P include, among others,
limited rights and powers, as set forth in Title 16 of the Connecticut General
Statutes and the special act of the General Assembly constituting its charter,
to manufacture, generate, purchase and sell electricity at retail, including to
provide standard offer, backup, and default service, to sell electricity at
wholesale to other utility companies and municipalities and to erect and
maintain certain facilities on public highways and grounds, all subject to such
consents and approvals of public authority and others as may be required by
law.  The franchises of CL&P include the power of eminent domain.

     PSNH.  The NHPUC, pursuant to statutory requirement, has issued orders
granting PSNH exclusive franchises free from burdensome restrictions to sell
electricity in the respective areas in which it is now supplying such
service.

     In addition to the right to sell electricity as set forth above, the
franchises of PSNH include, among others, rights and powers to manufacture,
generate, purchase, transmit, and distribute electricity, to sell electricity
at wholesale to other utility companies and municipalities and to erect and
maintain certain facilities on certain public highways and grounds, all
subject to such consents and approvals of public authority and others as may
be required by law.  The franchises of PSNH include the power of eminent
domain.

     NNECO.  Subject to the power of alteration, amendment or repeal by the
General Assembly of Connecticut and subject to certain approvals, permits and
consents of public authority and others prescribed by statute, NNECO has a
valid franchise free from burdensome restrictions to sell electricity to
utility companies doing an electric business in Connecticut and other states.

     In addition to the right to sell electricity as set forth above, the
franchise of NNECO includes, among others, rights and powers to manufacture,
generate and transmit electricity, and to erect and maintain facilities on
certain public highways and grounds, all subject to such consents and approvals
of public authority and others as may be required by law.

     WMECO.  WMECO is authorized by its charter to conduct its electric
business in the territories served by it, and has locations in the public
highways for transmission and distribution lines.  Such locations are granted
pursuant to the laws of Massachusetts by the Department of Public Works of
Massachusetts or local municipal authorities and are of unlimited duration, but
the rights thereby granted are not vested.  Such locations are for specific
lines only, and, for extensions of lines in public highways, further similar
locations must be obtained from the Department of Public Works of Massachusetts
or the local municipal authorities.  In addition, WMECO has been granted
easements for its lines in the Massachusetts Turnpike by the Massachusetts
Turnpike Authority.

     Pursuant to the Massachusetts restructuring legislation, the DTE is
required to define service territories for each distribution company,
including WMECO, based on the service territories actually served on July 1,
1997, and following to the extent possible municipal boundaries.  The DTE has
not yet defined service territories.  After established by the DTE, until
terminated by effect of law or otherwise, the distribution company shall have
the exclusive obligation to provide distribution service to all retail
customers within its service territory, and no other person shall provide
distribution service within such service territory without the written
consent of such distribution company.

     HWP and Holyoke Power and Electric Company (HP&E).  HWP, and its wholly
owned subsidiary HP&E, are authorized by their charters to conduct their
businesses in the territories served by them.  HWP's electric business is
subject to the restriction that sales be made by written contract in amounts
of not less than 100 horsepower to purchasers who use the electricity in
their own business in the counties of Hampden or Hampshire, Massachusetts and
cities and towns in these counties, and customers who occupy property in
which HWP has a financial interest, by ownership or purchase money mortgage.
HWP also has certain dam and canal and related rights, all subject to such
consents and approvals of public authorities and others as may be required by
law.  The two companies have locations in the public highways for their
transmission and distribution lines.  Such locations are granted pursuant to
the laws of Massachusetts by the Department of Public Works of Massachusetts
or local municipal authorities and are of unlimited duration, but the rights
thereby granted are not vested.  Such locations are for specific lines only
and, for extensions of lines in public highways, further similar locations
must be obtained from the Department of Public Works of Massachusetts or the
local municipal authorities.  HP&E has no retail service territory area and
sells electric power exclusively at wholesale.


ITEM 3.  LEGAL PROCEEDINGS

1.     Connecticut Superior Court - Connecticut Attorney General Civil Lawsuit
       and Appeal

In 1997, the AG initiated a civil lawsuit, on behalf of the CDEP, in
Connecticut Superior Court against NNECO and NUSCO for violations of the
Millstone water discharge permit and Connecticut water discharge regulations.
In 1998, the Superior Court approved a settlement between NNECO and the AG.
The settlement required NNECO to pay a $700,000 civil penalty and expend
$500,000 to fund three supplemental environmental projects.  Additionally,
the settlement requires NNECO to perform two environmental audits of its
water compliance program, have a third-party review of the first NNECO audit
and inform the CDEP of major changes to its environmental management system.
The first audit and the third-party review have been completed.  The second
required water compliance audit by NNECO has been completed and the audit
report was submitted to the CDEP for review on January 5, 2001.

An intervenor in the Superior Court proceeding appealed the settlement order.
On July 27, 2000, the Connecticut Supreme Court ruled in favor of NNECO and
NUSCO and affirmed the lower court's decision.

2.     Shareholder Securities Class Actions - Nuclear Matters

Consolidated Federal Court Actions:  Pursuant to a court order dated
October 1, 1997, the six class actions separately filed against NU in 1996
were consolidated for pre-trial and trial purposes.  The actions are based on
various federal securities law and common law theories alleging
misrepresentations and omissions in public disclosures related to the NU
system's nuclear problems, which resulted in extended outages at Millstone
and impacted the financial condition of NU and certain of its subsidiaries.
These complaints represent classes of plaintiffs who purchased or otherwise
acquired NU common stock from March 1994 to April 1996.

The parties executed a settlement agreement and, on March 27, 2000, filed the
agreement with the Federal court.  On that date, the court also approved the
form of the settlement notice to be sent to shareholder class members and set
down a schedule for the mailing of the notice (May 10, 2000), the formal
hearing to approve the settlement (July 24, 2000), and the date to file proof
of claim forms (September 29, 2000).  Any class member who wished to object
to or opt-out of the settlement was required to do so in writing by July 5,
2000.  On July 24, 2000, the court entered an Order approving the settlement
which provides for the dismissal of Stepak v. NU et al, a related state court
action.  The time to take an appeal has expired and the judgment is final.

3.     Merger-Related Shareholder Lawsuits

On October 13, 1999, and October 19, 1999, virtually identical complaints
were filed in the Supreme Court of New York against NU and its Board of
Trustees.  Both complaints purport to be "class action complaints" and allege
that the trustees have breached their fiduciary duties to the plaintiffs and
other members of the class by not (i) obtaining the best price for NU's
assets and businesses and (ii) entrenching themselves and their corporate
offices.  The plaintiffs seek equitable relief, including an order that the
trustees maximize shareholder value and award attorneys fees.  The cases are
now pending in state court in New York and have been inactive during the
pendency of the Federal action referred to below.

An additional action was brought in Federal court in New York by the plaintiffs
in the shareholder state court actions, alleging that NU, Con Edison and NU's
Trustees have, in addition to violating fiduciary duties, violated Section
14(a) of the Exchange Act by filing a joint proxy statement that fails to
disclose material information about the Indian Point nuclear generating plant.

To avoid a preliminary injunction proceeding and the possibility of the
cancellation of the April 14, 2000, shareholders' vote to approve the merger,
Con Edison and NU agreed to send a supplement to the proxy to the Companies'
shareholders addressing recent developments concerning Indian Point.

At a status conference on November 3, 2000, in the Federal case, a tentative
settlement agreement was reached by which a class would be certified, counsel
fees would be paid by Con Edison and the Section 14(a) claim would be
dismissed with prejudice.  The parties executed the settlement agreement
which was submitted to the Court, for approval, at the status conference on
March 16, 2001.  At the conference, the Court, as a result of the termination
of the merger agreement, dismissed the fiduciary duty claims without prejudice,
and scheduled a hearing for approval of the settlement for July 13, 2001.
Notice of the hearing will be sent to shareholders on or about May 17, 2001.

After dismissal of the Federal action, the trustees will move to dismiss the
state court actions, without prejudice, because the issues raised therein are
moot.

4.     Con Edison/NU Merger Appeals and Related Litigation

On October 19, 2000, the DPUC issued a decision (the October Decision) in
Docket No. 00-01-11, Joint Application of Con Edison and NU for Approval of
Change of Control, approving with conditions the merger of Con Edison and NU.
Subsequent to the October Decision, the AG, the OCC and Con Edison and NU
(collectively, the Applicants) filed separate petitions for reconsideration.
In a decision dated November 22, 2000 (the November Decision), the DPUC
rejected the petitions for reconsideration of the AG and the OCC.  The DPUC
granted in part and rejected in part the Applicants' petition for
reconsideration, and ordered a portion of the modifications that the
Applicants had requested.

On December 4, 2000, the AG appealed the November Decision to the Connecticut
Superior Court.  On December 6, 2000, the OCC appealed the October Decision
to the Superior Court.  The appeals are pending.  On February 13, 2001, the
AG and the OCC filed motions to stay the DPUC's approval, intended to prevent
the merger from being consummated prior to the court's determination of the
appeal.  On February 14, 2001, NU, Con Edison and the DPUC filed motions to
dismiss the appeals.  A status conference was held on February 23, 2001, at
which the court established a briefing and argument schedule for the motions
for stay and motions to dismiss.  On March 8, 2001, as a result of the events
leading to the lawsuits described below, NU filed a motion with the court to
suspend the briefing and argument schedule in the appeals.  That motion was
granted by the court on March 9, 2001.

On March 6, 2001, Con Edison filed suit in the U.S. District Court for the
Southern District seeking a declaratory judgment that NU had failed to
satisfy conditions precedent under the merger agreement and that Con Edison
had no further obligations under the merger agreement.  On March 12, 2001, NU
filed suit in the U.S. District Court for the Southern District seeking
substantial monetary damages against Con Edison arising out of Con Edison's
material breach of the merger agreement.

For further information on the events leading to these lawsuits, see "Part I,
Item 1. Business - Mergers and Acquisitions."

5.     Connecticut Superior Court - Fish Unlimited Lawsuits

In March 1999, certain parties brought a civil suit in Connecticut Superior
Court against NNECO and NUSCO seeking a temporary and a permanent injunction
to prevent the restart of Millstone 2 until a fish return system and cooling
tower are installed.  In April 1999, the Superior Court issued a temporary
restraining order (TRO) to prevent NNECO from starting up Millstone 2 until
it ruled on the temporary injunction issue.  In May 1999, the court dissolved
the TRO and denied the applications for both temporary and permanent
injunctions.  The plaintiffs appealed this decision. In July 2000, the
Connecticut Supreme Court ruled in favor of NNECO and NUSCO, holding that it
did not have jurisdiction to consider the plaintiffs' claims for injunctive
relief.  The Supreme Court vacated the prior judgment and remanded the case
to the trial court with direction to dismiss the action.  Fish Unlimited's
motion seeking reconsideration has been denied by the Supreme Court.

In July 1999, the Connecticut Superior Court granted NNECO's and NUSCO's
motion to dismiss an additional lawsuit that was filed by certain plaintiffs
in June 1999, challenging the validity of Millstone's water discharge permit.
Millstone's NPDES permit is currently under review for renewal, but both
NNECO and CDEP contend that the existing NPDES permit is valid.  The plaintiffs
appealed the court's decision, and on July 24, 2000, the Connecticut Supreme
Court ruled in favor of NNECO and NUSCO and affirmed the trial court's
decision.

6.     Millstone 3 - Damage to Fish Population Lawsuits

On April 20, 2000, two lawsuits were filed in Connecticut Superior Court
against NNECO and NUSCO seeking to enjoin operations at Millstone due to
alleged damage caused to the winter flounder population in the Niantic River
and Long Island Sound.  The first action, brought by certain citizens groups,
sought a temporary injunction to suspend Millstone 3 operations through the
second week of June 2000.  On August 30, 2000, NNECO filed a motion to dismiss
on the grounds that the plaintiffs failed to exhaust their administrative
remedies before resorting to the court.  The motion also contended that the
action should be dismissed as moot since plaintiffs only sought to enjoin the
operation of Millstone 3 through June 2000.  On October 16, 2000, NNECO's
motion to dismiss this action was granted.

The second action, brought by two fishermen, alleges two counts:  common law
nuisance and tortuous interference with a business expectancy.  The suit
alleges that Millstone has engaged in various actions, including entrainment
of winter flounder, that have caused the two fishermen to suffer damages.
The suit seeks, among other claims of relief, temporary and permanent
injunctions to suspend Millstone operations during the winter flounder
spawning season, conversion of Millstone to a close-cooling system or, in the
alternative, permanent shutdown and compensatory and punitive damages.  A
motion to strike both counts of the plaintiffs' complaint was filed on
July 31, 2000.  On December 22, 2000, NNECO's motion to strike was denied.
NNECO is now proceeding with discovery.

On April 26, 2000, another lawsuit was filed in Hartford Superior Court against
NUSCO, NNECO and the Commissioner of the CDEP challenging the validity of
previously issued CDEP emergency and temporary authorizations allowing
Millstone to discharge wastewater not expressly authorized by the facility's
NPDES permit.  The suit sought a temporary and permanent injunction against
operations at Millstone 1, 2 and 3.  On August 30, 2000, NNECO filed a motion
to dismiss, and on October 16, 2000, NNECO's motion was granted.  Plaintiffs
have since filed an appeal, which remains pending, with the Connecticut
Appellate Court.

7.     Sale of Millstone to Dominion Nuclear Connecticut, Inc.

On February 20, 2001, the CCAM filed in Connecticut Superior Court an appeal of
the DPUC's decision approving the sale of Millstone to Dominion.  CCAM alleges
that the final decision violates the Connecticut general statues on multiple
grounds and requests that the decision be reversed and vacated.  On March 2,
2001, CCAM filed a motion to stay, which was heard by the court on March 12,
2001.  The parties are awaiting a decision from the court on the motion.

On March 8, 2001, CCAM and other parties also filed a lawsuit in Connecticut
Superior Court against the CDEP, NNECO and Dominion challenging (1) the
validity of Millstone's NPDES permit (Permit) and a previously issued CDEP
emergency authorization allowing Millstone to discharge wastewater not
expressly authorized by the facility's Permit, and (2) CDEP's authority to
transfer both Millstone's Permit and emergency authorization to Dominion.

The lawsuit seeks to declare both the Permit declaratory and emergency
authorization invalid and to enjoin continued power operation at Millstone
and the transfer of NNECO's Permit and emergency authorization to Dominion.
The plaintiffs have applied for a TRO which seeks to enjoin CDEP from
transferring both the permit and emergency authorization to Dominion prior to
a full hearing.  NNECO has filed a Motion to Dismiss and a memorandum in
opposition to CCAM's request for a TRO.  On March 21, 2001, this matter was
transferred to the Superior Court's complex litigation docket.

On March 12, 2001, the Millstone Station Employees Association filed in
Connecticut Superior Court a request for a stay of the DPUC's approval of the
sale of Millstone pending resolution of certain employee pension issues.  The
DPUC and CL&P have moved to dismiss the stay request on various grounds.  No
hearing date has been established.

For further information on the sale of the Millstone units, see "Item 1.
Business - Rates and Electric Industry Restructuring" and "Nuclear
Generation."

8.     Other Legal Proceedings

The following sections of "Item 1. Business" discuss additional legal
proceedings:  See "Rates and Electric Industry Restructuring" for information
about various state restructuring proceedings and civil lawsuits related
thereto; "Regulated Electric Operations" and "Regulated Gas Operations" for
information about proceedings relating to power, transmission and pricing
issues; "Nuclear Generation" and "Nuclear Plant Performance" for information
related to nuclear plant performance, nuclear fuel enrichment pricing, high-
level and LLRW disposal, decommissioning matters, and NRC regulation, and;
"Other Regulatory and Environmental Matters" for information about proceedings
involving surface water and air quality, toxic substances and hazardous waste,
electric and magnetic fields, licensing of hydroelectric projects, and other
matters.


ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     No event that would be described in response to this item occurred with
respect to NU, CL&P, PSNH, WMECO, or NAEC.


                                   PART II

ITEM 5.  MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED SHAREHOLDER
         MATTERS

     NU.  The common shares of NU are listed on the New York Stock Exchange.
The ticker symbol is "NU," although it is frequently presented as "Noeast
Util" and/or "NE Util" in various financial publications.  The high and low
sales prices for the past two years, by quarters, are shown below.

     Year     Quarter       High          Low
     ----     -------       ----          ---

     2000     First       $21.5000     $18.0000
              Second       23.1250      20.8125
              Third        23.9600      21.5000
              Fourth       24.5600      18.2500

     1999     First       $16.4375     $13.7500
              Second       18.3125      13.5625
              Third        19.0000      17.3750
              Fourth       22.0000      17.7500

     As of January 31, 2001, there were 79,709 common shareholders of record
of NU.  As of the same date, there were a total of 148,772,670 common shares
issued, including 4,913,146 unallocated ESOP shares held in the ESOP trust.

     On January 11, 2000, the NU Board of Trustees approved the payment of a
10 cent per share dividend, payable on March 31, 2000, to shareholders of
record as of March 1, 2000.  The record date for this dividend was changed on
January 31, 2000 to March 6, 2000, to provide Yankee shareholders who
received NU common shares the opportunity to receive the dividend following
the Yankee merger.

     On April 12, 2000, the NU Board of Trustees approved the payment of a 10
cent per share dividend, payable on June 30, 2000, to shareholders of record
as of June 1, 2000.

     On July 11, 2000, the NU Board of Trustees approved the payment of a 10
cent per share dividend, payable on September 29, 2000, to shareholders of
record as of September 1, 2000.

     On October 10, 2000, the NU Board of Trustees approved the payment of a
10 cent per share dividend, payable on December 29, 2000, to shareholders of
record as of December 1, 2000.

     On September 14, 1999, the NU Board of Trustees approved the payment of
NU's first common share dividend since March 1997.  NU paid a 10 cent per
share dividend on December 30, 1999, to shareholders of record as of
December 1, 1999.

     Information with respect to dividend restrictions for NU and its
subsidiaries is contained in Item 1.  Business under the caption "Financing
Program - Financing Limitations" and in Note (b) to the "Consolidated
Statements of Shareholders' Equity" on page F-26 of this document.

     CL&P, PSNH, WMECO, and NAEC.  The information required by this item is
not applicable because the common stock of CL&P, PSNH, WMECO, and NAEC is
held solely by NU.

ITEM 6.  SELECTED FINANCIAL DATA

     NU.  Reference is made to information under the heading "Selected
Consolidated Financial Data" contained on page F-67 of this document.

     CL&P.  Reference is made to information under the heading "Selected
Consolidated Financial Data" contained on page 41 of CL&P's 2000 Annual
Report, which information is incorporated herein by reference.

     PSNH.  Reference is made to information under the heading "Selected
Financial Data" contained on page 38 of PSNH's 2000 Annual Report, which
information is incorporated herein by reference.

     WMECO.  Reference is made to information under the heading "Selected
Consolidated Financial Data" contained on page 37 of WMECO's 2000 Annual
Report, which information is incorporated herein by reference.

     NAEC.  Reference is made to information under the heading "Selected
Financial Data" contained on page 27 of NAEC's 2000 Annual Report, which
information is incorporated herein by reference.

ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
          RESULTS OF OPERATIONS; AND

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     NU.  Reference is made to information under the heading "Management's
Discussion and Analysis and Results of Operations" contained on pages F-1
through F-18 of this document.

     CL&P.  Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 1 through 11 in CL&P's 2000 Annual Report, which
information is incorporated herein by reference.

     PSNH.  Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 1 through 9 in PSNH's 2000 Annual Report, which
information is incorporated herein by reference.

     WMECO.  Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 1 through 9 in WMECO's 2000 Annual Report, which
information is incorporated herein by reference.

     NAEC.  Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 1 through 7 in NAEC's 2000 Annual Report, which
information is incorporated herein by reference.

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     NU.  Reference is made to information under the headings "Company Report,"
"Report of Independent Public Accountants," "Consolidated Statements of
Income," "Consolidated Statements of Comprehensive Income," "Consolidated
Balance Sheets," "Consolidated Statements of Shareholders' Equity,"
"Consolidated Statements of Cash Flows," "Consolidated Statements of
Capitalization," "Consolidated Statements of Income Taxes," "Notes to
Consolidated Financial Statements," and "Consolidated Statements of Quarterly
Financial Data" contained on pages F-19 through F-65 of this document.

     CL&P.  Reference is made to information under the headings "Report of
Independent Public Accountants," "Consolidated Statements of Income,"
"Consolidated Statements of Comprehensive Income," "Consolidated Balance
Sheets," "Consolidated Statements of Common Stockholder's Equity,"
"Consolidated Statements of Cash Flows," "Notes to Consolidated Financial
Statements," and "Consolidated Quarterly Financial Data" contained on pages
12 through 41 in CL&P's 2000 Annual Report, which information is incorporated
herein by reference.

     PSNH.  Reference is made to information under the headings "Report of
Independent Public Accountants," "Statements of Income," "Statements of
Comprehensive Income," "Balance Sheets," "Statements of Common Stockholder's
Equity," "Statements of Cash Flows," "Notes to Financial Statements," and
"Quarterly Financial Data" contained on pages 10 through 38 in PSNH's 2000
Annual Report, which information is incorporated herein by reference.

     WMECO.  Reference is made to information under the headings "Report of
Independent Public Accountants," "Consolidated Statements of Income,"
"Consolidated Statements of Comprehensive Income," "Consolidated Balance
Sheets," "Consolidated Statements of Common Stockholder's Equity,"
"Consolidated Statements of Cash Flows," "Notes to Consolidated Financial
Statements," and "Consolidated Quarterly Financial Data" contained on pages
10 through 37 in WMECO's 2000 Annual Report, which information is
incorporated herein by reference.

     NAEC.  Reference is made to information under the headings "Report of
Independent Public Accountants," "Statements of Income," "Balance Sheets,"
"Statements of Common Stockholder's Equity," "Statements of Cash Flows,"
"Notes to Financial Statements," and "Quarterly Financial Data" contained on
pages 8 through 27 in NAEC's 2000 Annual Report, which information is
incorporated herein by reference.

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
          ACCOUNTING AND FINANCIAL DISCLOSURE

     No event that would be described in response to this item has occurred
with respect to NU, CL&P, PSNH, WMECO, or NAEC.


                                   PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

NU.

                                                          First         First
                             Positions                   Elected       Elected
         Name                   Held                    an Officer    a Trustee
- -----------------------      ---------                  ----------    ---------

Cotton M. Cleveland          T                             n/a        06/23/92
Sanford Cloud, Jr.           T                             n/a        05/09/00
William F. Conway            T                             n/a        06/17/97
E. Gail de Planque           T                             n/a        10/01/95
John H. Forsgren             EVP, CFO                    02/01/96     05/09/00
Raymond L. Golden            T                             n/a        05/11/99
Cheryl W. Grise              SVP, SEC, GC                06/01/91        n/a
Elizabeth T. Kennan          T                             n/a        01/22/80
Bruce D. Kenyon              P                           09/03/96        n/a
Hugh C. MacKenzie (1)        P                           07/01/88        n/a
Michael G. Morris            CHB, P, CEO, T              08/19/97     08/19/97
Emery G. Olcott              T                             n/a        05/09/00
William J. Pape II           T                             n/a        04/23/74
Robert E. Patricelli         T                             n/a        05/25/93
Gary D. Simon                OTH                         04/15/98        n/a
John F. Swope                T                             n/a        06/23/92
Lisa J. Thibdaue             OTH                         01/01/98        n/a
John F. Turner               T                             n/a        05/23/95

CL&P.

                                                          First        First
                             Positions                   Elected      Elected
         Name                   Held                    an Officer   a Director
- -----------------------      ---------                  ----------   ----------

David H. Boguslawski         VP, D                       09/09/96     06/30/99
John H. Forsgren (2)         OTH                         02/10/96       n/a
Cheryl W. Grise (2)          OTH                         06/01/91       n/a
Bruce D. Kenyon (2)          OTH                         09/03/96       n/a
Hugh C. MacKenzie (1)        P, D                        07/01/88     06/06/90
Michael G. Morris (2)        OTH                         08/19/97       n/a
Rodney O. Powell             VP, D                       10/18/98     06/30/99
Lisa J. Thibdaue (2)         OTH                         01/01/98       n/a


PSNH.

                                                          First        First
                             Positions                   Elected      Elected
         Name                   Held                    an Officer   a Director
- -----------------------      ---------                  ----------   ----------

David H. Boguslawski         VP, D                       06/05/92     06/30/99
John C. Collins              D                              n/a       10/19/92
John H. Forsgren (2)         OTH, D                      02/01/96     08/05/96
Cheryl W. Grise (2)          OTH                         07/31/98        n/a
Bruce D. Kenyon (2)          OTH                         09/03/96        n/a
Gerald Letendre              D                              n/a       10/19/92
Gary A. Long                 P, COO, D                   01/01/94     07/01/00
Hugh C. MacKenzie (1)(2)     OTH, D                      02/01/96     02/01/94
Michael G. Morris            CH, D                       08/19/97     08/19/97
Jane E. Newman               D                             n/a        10/19/92
Lisa J. Thibdaue (2)         OTH                         01/01/98        n/a


WMECO.

                                                          First        First
                             Positions                   Elected      Elected
         Name                   Held                    an Officer   a Director
- -----------------------      ---------                  ----------   ----------

David H. Boguslawski          VP, D                      09/09/96     06/30/99
James E. Byrne                 D                            n/a       09/17/99
John H. Forsgren (2)          OTH, D                     02/01/96     06/10/96
Cheryl W. Grise (2)           OTH                        06/01/91        n/a
Bruce D. Kenyon (2)           OTH                        09/03/96        n/a
Kerry J. Kuhlman              P, COO, D                  10/18/98     04/01/99
Hugh C. MacKenzie (1)(2)      OTH, D                     07/01/88     06/06/90
Paul J. McDonald              D                             n/a       09/17/99
Michael G. Morris             CH, CEO, D                 08/19/97     08/19/97
Melinda M. Phelps             D                             n/a       09/17/99
Lisa J. Thibdaue (2)          OTH                         01/01/98       n/a

NAEC.

                                                          First        First
                             Positions                   Elected      Elected
         Name                   Held                    an Officer   a Director
- -----------------------      ---------                  ----------   ----------

William A. DiProfio (3)      D                              n/a       06/30/99
Ted C. Feigenbaum            EVP, CNO, D                 10/21/91     06/30/99
John H. Forsgren (2)         OTH                         02/01/96        n/a
George R. Gram II            D                              n/a       02/02/01
Cheryl W. Grise (2)          OTH                         10/21/91        n/a
Bruce D. Kenyon              P, CEO, D                   09/03/96     09/03/96
Michael G. Morris (2)        OTH                         08/19/97        n/a


1.  Mr. MacKenzie retired effective January 1, 2001.
2.  Executive Officers of Registrant because of policy-making functions for
    NU system.
3.  Mr. DiProfio retired effective February 1, 2001.


Key:
CEO  -  Chief Executive Officer          OTH  -  Executive Officer of
CFO  -  Chief Financial Officer                  Registrant because of policy-
CH   -  Chairman                                 making functions for NU system
CHB  -  Chairman of the Board            P    -  President
CNO  -  Chief Nuclear Officer            SEC  -  Secretary
COO  -  Chief Operating Officer          SVP  -  Senior Vice President
D    -  Director                         T    -  Trustee
EVP  -  Executive Vice President         VP   -  Vice President
GC   -  General Counsel

          Name              Age   Business Experience During Past 5 Years
- -------------------------   ---   ---------------------------------------

David H. Boguslawski         46   Vice President-Energy Delivery of CL&P, PSNH
                                  and WMECO, since 1996; previously Vice
                                  President-Customer Operations of PSNH from
                                  1994 to 1996 and Vice President-Marketing of
                                  PSNH from 1992 to 1994.

James E. Byrne               46   Partner, Finneran, Byrne & Dreshsler, L.L.P.,
                                  since 1982.

Cotton M. Cleveland (1)      48   President of Mather Associates, New London,
                                  New Hampshire (a firm specializing in
                                  leadership and organizational development for
                                  corporate and non-profit organizations).
                                  From 1991 until 1998, founding Executive
                                  Director of Leadership New Hampshire.

Sanford Cloud, Jr. (2)       56   President and Chief Executive Officer of The
                                  National Conference for Community and
                                  Justice, New York, New York.  From 1993 to
                                  1994, he was a partner in the law firm of
                                  Robinson and Cole, Hartford, Connecticut.
                                  Previously Vice President of Aetna Life and
                                  Casualty Company and served for two terms as
                                  a state senator of Connecticut.

John C. Collins (3)          55   Chief Executive Officer, Dartmouth-Hitchcock
                                  Clinic, Dartmouth-Hitchcock Medical Center
                                  since 1977.

William F. Conway (4)        70   President of William F. Conway & Associates,
                                  Inc., Scottsdale, Arizona (a management
                                  consulting firm to the nuclear power
                                  industry).  From 1989 to 1994 (retired July
                                  1994), he was Executive Vice President-
                                  Nuclear of Arizona Public Service Company,
                                  Phoenix, Arizona.  Previously, he was Senior
                                  Vice President of Nuclear Operations at
                                  Florida Power & Light Company, Juno Beach,
                                  Florida.

E. Gail de Planque (5)       56   President, Strategy Matters, Inc., and
                                  Director Energy Strategies Consultancy, Ltd.
                                  From 1991 to 1995, Dr. de Planque was a
                                  Commissioner with the United States NRC.  In
                                  1967, Dr. de Planque joined the Health and
                                  Safety Laboratory of the United States Atomic
                                  Energy Commission.  She served at the
                                  Laboratory, now known as the Environmental
                                  Measurements Laboratory, until December 1991,
                                  as Deputy Director beginning in 1982 and as
                                  Director in 1987.

William A. DiProfio          58   Retired February 1, 2001.  Seabrook Station
                                  Director, NAESCO from 1992 to 2000.

Ted C. Feigenbaum (6)        50   Executive Vice President and Chief Nuclear
                                  Officer of NAEC since February, 1996;
                                  previously Senior Vice President of NAEC
                                  since 1991; Senior Vice President and Chief
                                  Nuclear Officer of PSNH from June 1992 to
                                  August 1992; President and Chief Executive
                                  Officer-New Hampshire Yankee Division of PSNH
                                  from 1990 to 1992 and Chief Nuclear
                                  Production Officer of PSNH from 1990 to 1992.

John H. Forsgren (7)         54   Executive Vice President and Chief Financial
                                  Officer of NU since February 1996;
                                  previously Executive Vice President and Chief
                                  Financial Officer of CL&P, PSNH, WMECO and
                                  NAEC from February 1996 to June 1999;
                                  Managing Director of the Chase Manhattan Bank
                                  from 1995 to 1996 and Senior Vice President
                                  of The Walt Disney Company from 1990 to 1994.

Raymond L. Golden (8)        63   Independent Consultant.  Previously served as
                                  Chairman Emeritus of BT Wolfensohn, New York,
                                  New York, a business unit of BT Alex Brown
                                  Incorporated.  From August 1996 to December
                                  1997, he was Chairman of BT Wolfensohn.
                                  Prior to that, he served as President of
                                  Wolfensohn & Company.

George W. Gram II            52   Director - Support Services, Seabrook
                                  Station, NAESCO since December 1999;
                                  Previously Director - Site Support from March
                                  1999 to December 1999; and Executive Director
                                  of Support Services from 1991 to 1999.

Cheryl W. Grise              48   Senior Vice President, Secretary and General
                                  Counsel of NU since July 1998; previously
                                  Senior Vice President, Secretary and General
                                  Counsel of CL&P, PSNH and NAEC and Senior
                                  Vice President, Secretary, Assistant Clerk
                                  and General Counsel of WMECO from July 1998
                                  to June 1999; Senior Vice President and Chief
                                  Administrative Officer of CL&P, PSNH and
                                  NAEC, and Senior Vice President of WMECO from
                                  1995 to 1998; Senior Vice President-Human
                                  Resources and Administrative Services of
                                  CL&P, WMECO and NAEC from 1994 to 1995 and
                                  Vice President-Human Resources of CL&P, WMECO
                                  and NAEC from 1992 to 1994.

Elizabeth T. Kennan (9)      62   President Emeritus of Mount Holyoke College,
                                  South Hadley, Massachusetts.  Previously
                                  President of Mount Holyoke College.

Bruce D. Kenyon (10)         58   President and Chief Executive Officer of NAEC
                                  since September 1996 and President-Generation
                                  Group of NU since March 1999; previously
                                  President-Generation Group of CL&P, PSNH and
                                  WMECO from March 1999 to June 1999;
                                  President-Nuclear Group of NU, CL&P, PSNH and
                                  WMECO from September 1996 to March 1999;
                                  President and Chief Operating Officer of
                                  South Carolina Electric and Gas Company from
                                  1990 to 1996.

Kerry J. Kuhlman             50   President and Chief Operating Officer of
                                  WMECO since April 1999; previously Vice
                                  President-Customer Operations of WMECO from
                                  October 1998 to April 1999; Vice President-
                                  Central Region of CL&P from August 1997 to
                                  October 1998; and Vice President-Eastern
                                  Region of CL&P from July 1994 to August 1997.

Gerald Letendre (11)         59   President, Diamond Casting & Machine Co.,
                                  Inc. since 1972.

Gary A. Long                 49   President and Chief Operating Officer of
                                  PSNH since July 1, 2000; previously Senior
                                  Vice President-PSNH from February 2000
                                  through June 2000 and Vice President-
                                  Customer Service and Economic Development of
                                  PSNH from January 1994 to February 2000.

Hugh C. MacKenzie            58   Retired January 1, 2001; Previously President
                                  - Retail Business Group of NU from February
                                  1996 and President of CL&P from January 1994
                                  through December 2000; previously President
                                  of WMECO from January 1994 to April 1999;
                                  Senior Vice President-Customer Service
                                  Operations of CL&P and WMECO from 1990 to
                                  1994.

Paul J. McDonald (12)        57   Advisor to the Board of Directors, Friendly
                                  Ice Cream Corporation since January 2000;
                                  previously Senior Executive Vice President
                                  and Chief Financial Officer, Friendly Ice
                                  Cream Corporation, from 1986 to 1999.

Michael G. Morris (13)       54   Chairman of the Board, President and Chief
                                  Executive Officer of NU, Chairman and Chief
                                  Executive Officer of PSNH since July 1,
                                  2000, and Chairman of WMECO since August
                                  1997; previously Chairman and Chief Executive
                                  Officer of PSNH from August 1997 to March
                                  2000, previously Chairman of CL&P and NAEC
                                  from August 1997 to June 1999; President and
                                  Chief Executive Officer of Consumers Power
                                  Company from 1994 to 1997 and Executive Vice
                                  President and Chief Operating Officer of
                                  Consumers Power Company from 1992 to 1994.

Jane E. Newman (14)          55   Executive Dean, Harvard University's John F.
                                  Kennedy School of Government since July
                                  2000; Previously Managing Director, The
                                  Commerce Group, LLC, a strategic
                                  communications company, from January 1999 to
                                  July 2000;  Dean, Whittemore School of
                                  Business and Economics of the University of
                                  New Hampshire from January 1998 to January
                                  1999; Executive Vice President and Director,
                                  Exeter Trust Company from 1995 to 1997 and
                                  President, Coastal Broadcasting Corporation
                                  from 1992 to 1995.

Emery G. Olcott (15)         62   Chairman, President and Chief Executive
                                  Officer of Packard BioScience Company
                                  (f/k/a Canberra Industries Incorporated),
                                  provider of systems and reagents for the
                                  life science and genomics industries and
                                  radiation detection instrumentation for
                                  environmental monitoring and clean up.

William J. Pape II (16)      69   Publisher, Waterbury Republican-American,
                                  Waterbury, Connecticut (newspaper) and
                                  President of American-Republican, Inc.

Robert J. Patricelli (17)    61   Chairman, President and Chief Executive
                                  Officer of Women's Health USA, Inc. (provides
                                  women's health care services), and of
                                  Evolution Health, LLC (provides employee
                                  benefit services), both of Avon, Connecticut.
                                  He is also Chairman of AviaHealth, Inc.
                                  (provides internet applications to doctors
                                  and patients), of Farmington, Connecticut.
                                  From 1987 to 1997, he was Chairman, President
                                  and Chief Executive Officer of Value Health,
                                  Inc., Avon Connecticut.  Previously Executive
                                  Vice President of CIGNA Corporation and
                                  President of CIGNA's Affiliated Businesses
                                  Group.  He has held various positions in the
                                  federal government, including White House
                                  Fellow in 1965; counsel to a United States
                                  Senate Subcommittee; Deputy Undersecretary of
                                  the Department of Health, Education and
                                  Welfare; and Administrator of the United
                                  States Urban Mass Transportation
                                  Administration.

Melinda M. Phelps            57   Partner, Buckley, Richardson & Gelinas, LLP
                                  since January 1, 2001 and Police
                                  Commissioner, City of Springfield,
                                  Massachusetts since 1998.  Previously Of
                                  Counsel to Buckley, Richardson & Gelinas,
                                  LLP, from May 2000 through December 2000;
                                  and Partner, Keyes and Donnellan, P.C.,
                                  from 1992 to 2000.

Rodney O. Powell             48   Vice President-Central Region of CL&P since
                                  October 1998; previously General Manager-
                                  Simsbury of CL&P from October 1997 to October
                                  1998; Manager-Regulatory Relations of NUSCO
                                  from December 1995 to October 1997 and Senior
                                  Customer Engineering and Marketing Services
                                  Consultant of NUSCO from January 1994 to
                                  December 1995.

Gary D. Simon (18)           52   Senior Vice President-Strategy and
                                  Development of NUSCO since April 1998.

John F. Swope (19)           62   Previously President and Chief Executive
                                  Officer, Public Broadcasting Service,
                                  Alexandria, Virginia from 1999 to March 1,
                                  2000.  Retired in 1997 as of counsel to the
                                  law firm of Sheehan Phinney Bass & Green,
                                  Professional Association, Manchester, New
                                  Hampshire.  Previously President of Chubb
                                  Life Insurance Company of America, Concord,
                                  New Hampshire (retired December 1994).

Lisa J. Thibdaue             47   Vice President-Rates, Regulatory Affairs and
                                  Compliance of NUSCO since January 1998;
                                  previously Vice President-Rates, Regulatory
                                  Affairs and Compliance of CL&P, PSNH and
                                  WMECO from January 1998 to June 1999;
                                  Executive Director, Rates and Regulatory
                                  Affairs, Consumers Power Company from 1996
                                  to 1998 and Director of Regulatory Affairs,
                                  Consumers Power Company from 1991 to 1996.

John F. Turner (20)          58   President and Chief Executive Officer of The
                                  Conservation Fund, Arlington, Virginia (a
                                  national nonprofit organization dedicated to
                                  land and water conservation and economic
                                  development).  From 1989 to 1993, he was
                                  Director of the United States Fish &
                                  Wildlife Service in the United States
                                  Department of the Interior.  He has also
                                  served as President of the Wyoming State
                                  Senate.  A former Chairman of the Board of
                                  Directors of the Bank of Jackson Hole,
                                  Mr. Turner continues as a partner in the
                                  family ranch business in Wyoming.

 (1)  Ms. Cleveland is a Director of The National Grange Mutual Insurance
      Company and of the Ledyard National Bank and serves on the Board of the
      New Hampshire Center for Public Policy.  She is the moderator of the
      Town of New London, New Hampshire.  She has served on the University
      System of New Hampshire Board of Trustees as Chair, Vice Chair and a
      member and served on the Bank of Ireland First Holdings Board of
      Directors from 1986 to 1996.  She was formerly Co-Chair of the Governor's
      Commission on New Hampshire in the 21st Century and an Incorporator for
      the New Hampshire Charitable Foundation.

 (2)  Mr. Cloud is a Director of The Advest Group, Incorporated and Tenet
      Healthcare Corporation and Chairman of the Board of Ironbridge Mezzanine
      Fund, L.P.

 (3)  Mr. Collins is a Director of Blue Cross and Blue Shield of Vermont,
      Hamden Assurance Company Limited and the Business and Industry
      Association of New Hampshire.

 (4)  Mr. Conway is a member of the American Nuclear Society.  He served on
      the Board of Directors of the Nuclear Utilities Management and Resources
      Council and its Issues Management Committee.  He has also served on the
      Research Advisory Committee of the Electric Power Research Institute and
      served as Chairman of its Nuclear Power Division Advisory Committee.  A
      former Chairman of the ABB Combustion Engineering Owners Group Executive
      Committee, Mr. Conway currently serves on its Advanced Light Water
      Reactor Executive Advisory Committee.  Having been a member of the
      Institute of Nuclear Power Operations (INPO) Board of Directors, he
      currently serves on INPO's Advisory Council and is a member of the
      Accrediting Board of its National Academy for Nuclear Training.  Mr.
      Conway is a Director of First Energy Corporation and is Chairman of its
      Nuclear Committee.  He also serves on the Nuclear Safety Review Board at
      several nuclear facilities.

 (5)  Dr. de Planque is a Fellow and past President of the American Nuclear
      Society, a member of the National Academy of Engineering and the
      National Council on Radiation Protection and Measurements, a Director of
      British Nuclear Fuels, plc., a Director of British Nuclear Fuels, Inc.
      and President of the International Nuclear Societies Council.  She is a
      member of the Texas Utilities Electric Operations Review Committee; the
      Diablo Canyon Independent Safety Committee; the External Advisory
      Committee; Amarillo National Resource Center for Plutonium; the visiting
      Committee for the Department of Nuclear Engineering, Massachusetts
      Institute of Technology; and a consultant to the United Nation's
      International Atomic Energy Agency.

 (6)  Mr. Feigenbaum is a Director of CYAPC, MYAPC, and VYAPC, and YAEC.

 (7)  Mr. Forsgren is a Director of NEON and The Circle Trust Company and a
      member of the Board of Regents of Georgetown University.

 (8)  Mr. Golden serves as a Trustee on the National Wildlife Federation
      Endowment and the Board of the Jewish Federation of Palm Beach County,
      Florida.

 (9)  Dr. Kennan is a Director of The Putnam Funds and Talbots.  She is a
      member of the Folger Shakespeare Library Committee and is Chairman of
      Cambus Kenneth Bloodstock, Inc.

(10)  Mr. Kenyon is a Trustee of Columbia College and Director of CYAPC.

(11)  Mr. Letendre is a Director of the National Association of Manufacturers
      (Washington, DC).

(12)  Mr. McDonald is a Director of CIGNA Investments Inc. and Polytainer's,
      LLC (Toronto, Canada).

(13)  Mr. Morris is a Director of the Institute of Nuclear Power Operations,
      the Nuclear Energy Institute, the Edison Electric Institute, the
      Association of Edison Illuminating Companies, Nuclear Electric Insurance
      Limited, Connecticut Business & Industry Association, and the Webster
      Financial Corporation.  Mr. Morris is also a Regent of Eastern Michigan
      University.

(14)  Ms. Newman is a Director of Citizens Advisors.

(15)  Mr. Olcott is Vice Chairman and Trustee of the Loomis Chaffee School and
      serves on the Dean's Advisory Council for the Sloan School of Management
      at the Massachusetts Institute of Technology.

(16)  Mr. Pape is a Director of Platt Bros. & Co. and Paper Delivery, Inc.  He
      is a Trustee of the Connecticut Policy and Economic Council, Inc. and
      the Waterbury Y.M.C.A.

(17)  Mr. Patricelli is a Director of Curagen Corporation, the Connecticut
      Business & Industry Association, and The Bushnell, and a Trustee of
      Wesleyan University.

(18)  Mr. Simon is a Director of NEON.

(19)  Mr. Swope is a Director of the Public Broadcasting Service and PBS
      Enterprises and the New Hampshire Business Committee for the Arts.  He
      is President of The Currier Gallery of Art and a Trustee of Tabor
      Academy.

(20)  Mr. Turner is assisting schools of natural resources at the University
      of Wyoming, University of Michigan and Yale University with wildlife and
      land use projects.  He is a member of the National Coal Council and a
      Director of Land Trust Alliance and National Wildlife Refuge
      Association.

     There are no family relationships between any director or executive
officer and any other director or executive officer of NU, CL&P, PSNH, WMECO,
or NAEC.

Section 16(a) Beneficial Ownership Reporting Compliance

     Section 16(a) of the Securities Exchange Act of 1934 requires Trustees
and certain officers of NU and persons who beneficially own more than 10
percent of the outstanding common shares of NU to file reports of ownership
and changes in ownership with the SEC and the New York Stock Exchange.  Based
on review of copies of such forms furnished to NU, or written representations
that no Form 5 was required, NU believes that for the year ended December 31,
2000, all such reporting requirements were complied with in a timely manner
except that Mr. Cloud failed to include on his Form 3 shares of NU acquired
in the Yankee merger, and Mr. Pape failed to report until 2001, 800 shares of
CL&P preferred stock acquired in 1994 by a privately-held corporation of
which he is a 7.9 percent owner.

<TABLE>
ITEM 11.  EXECUTIVE COMPENSATION

                                         SUMMARY COMPENSATION TABLE

     The following tables present the cash and non-cash compensation received by the Chief Executive
Officer and the next four highest paid executive officers of NU, CL&P, PSNH, WMECO, and NAEC, in
accordance with rules of the SEC:
<CAPTION>
                                          Annual Compensation                              Long Term Compensation
                             --------------------------------------------                  ----------------------
                                                                                          Awards             Payouts

                                                                                            Securities
                                                                 Other        Restrict-     Underlying      Long Term      All
                                                                 Annual       ed Stock       Options/       Incentive      Other
                                                                Compensa-     Award(s)        Stock          Program      Compen-
    Name and                           Salary                    tion ($)       ($)        Appreciation      Payouts     sation ($)
Principal Position           Year       ($)        Bonus ($)    (Note 1)      (Note 2)       Rights (#)        ($)        (Note 3)
- ------------------           ----      ------      ---------    ---------     --------     ------------     ---------    ----------
<S>                          <C>      <C>          <C>          <C>           <C>             <C>           <C>            <C>
Michael G. Morris            2000     830,770      1,200,000        -            -            140,000           -           27,326
Chairman of the
Board, President             1999     783,173      1,253,300      92,243      348,611         118,352           -           23,210
and Chief Executive
Officer                      1998     757,692        891,000     134,376      255,261          64,574           -           22,731

Bruce D. Kenyon              2000     504,616        475,000        -            -             20,000           -           16,274
President -
Generation Group             1999     500,000           -           -          77,690          20,804        462,500        15,000

                             1998     500,000        300,000        -            -             21,236           -           14,800

John H. Forsgren             2000     444,615        450,000        -            -             36,000           -            5,100
Executive Vice
President and                1999     429,904        400,000        -         122,682          32,852         87,003        12,888
Chief Financial
Officer                      1998     373,077           -           -            -             73,183           -          104,800

Hugh C. MacKenzie            2000     270,000        250,000        -            -             15,000           -            5,100
President - Retail
Business Group               1999     270,000        250,000        -          73,612          19,712           -          108,100

                             1998     270,000           -           -            -             15,496         42,972         7,500

Cheryl W. Grise              2000     279,616        290,000        -            -             23,000           -            8,795
Senior Vice
President,                   1999     244,712        250,000        -          73,612          19,712           -           82,247
Secretary and
General Counsel              1998     209,231           -           -            -             12,916         20,720         6,123
(in NU, CL&P, PSNH and
WMECO tables only)

Ted C. Feigenbaum            2000     261,539        145,000        -            -             12,000        216,200         8,198
Executive Vice
President and                1999     260,000        130,000        -          28,620           7,664         24,827         5,849
Chief Nuclear Officer
of NAEC                      1998     260,000         48,750        -          40,961          10,044         20,723         7,800
(in NAEC table only)
</TABLE>

<TABLE>

                                             OPTION/SAR GRANTS IN LAST FISCAL YEAR
<CAPTION>
                                        Individual Grants                               Grant Date Value

                          Number of        % of Total
                          Securities      Options/SARs
                          Underlying       Granted to       Exercise or                    Grant Date
                         Options/SARs      Employees        Base Price       Expiration      Present
Name                     Granted (#)     in Fiscal Year       ($/sh)            Date        Value ($)
                           (Note 4)
- ----                     ------------    --------------     -----------      ----------    -----------
<S>                        <C>                <C>             <C>             <C>            <C>
Michael G. Morris          140,000            22.1            18.4375         2/20/2010      1,027,600

Bruce D. Kenyon             20,000             3.2            18.4375         2/20/2010        146,800

John H. Forsgren            36,000             5.7            18.4375         2/20/2010        264,240

Hugh C. MacKenzie           15,000             2.4            18.4375         2/20/2010        110,100

Cheryl W. Grise             23,000             3.6            18.4375         2/20/2010        168,820

Ted C. Feigenbaum           12,000             1.9            18.4375         2/20/2010         88,080
</TABLE>


<TABLE>
                                   AGGREGATED OPTIONS/SAR EXERCISES IN LAST
                                   FISCAL YEAR AND FY-END OPTION/SAR VALUES
<CAPTION>
                     Shares With
                     Respect to                 Number of Securities         Value of Unexercised
                        Which                  Underlying Unexercised             In-the-Money
                      SARs Were    Value            Options/SARs                  Options/SARs
                      Exercised   Realized     at Fiscal Year End (#)        at Fiscal Year End ($)
     Name               (#)         ($)      Exercisable   Unexercisable   Exercisable   Unexercisable
<S>                    <C>         <C>         <C>          <C>              <C>           <C>
Michael G. Morris        -            -        495,692      327,234          6,543,905     3,221,429

Bruce D. Kenyon          -            -         66,424       33,869            658,708       245,405

John H. Forsgren         -            -        134,605       57,901          1,244,361       413,203

Hugh C. MacKenzie      39,020      380,445      61,087       28,141 (Note 5)   618,289       209,563

Cheryl W. Grise          -            -         43,977       36,141            436,164       256,063

Ted C. Feigenbaum        -            -         12,599       36,733            103,518       231,392

</TABLE>

Notes to Summary Compensation and Option/SAR Grants Tables:

1. Other annual compensation for Mr. Morris consists of 1998 and 1999
   relocation expense reimbursements.

2. At December 31, 2000, the aggregate restricted stock holdings by the five
   individuals named in the table for NU, CL&P, WMECO, and PSNH were 31,070
   shares with a value of $753,448 and for NAEC were 29,062 shares with a
   value of $704,754.  Awards shown for 1998 have vested.  Awards shown for
   1999 vest one-third on February 23, 2000, one-third on February 23, 2001,
   and one-third on February 23, 2002.  No restricted stock was awarded in
   2000.  Dividends paid on restricted stock are either paid out or reinvested
   into additional shares.

3. "All Other Compensation" for 2000 consists of employer matching
   contributions under the Northeast Utilities Service Company 401(k) Plan,
   generally available to all eligible employees ($5,100 for each named
   officer), and matching contributions under the Deferred Compensation Plan
   for Executives (Mr. Morris - $22,226, Mr. Kenyon - $11,174, Mrs. Grise -
   $3,695, and Mr. Feigenbaum - $3,098).

4. These options were granted on February 22, 2000, under the Northeast
   Utilities Incentive Plan.  All options granted vest one-third on
   February 22, 2001, one-third on February 22, 2002, and one-third on
   February 22, 2003.  Valued using the Black-Scholes option pricing model,
   with the following assumptions:  Volatility: 26.06 percent (36 months of
   monthly data); Risk-free rate: 6.55 percent; Dividend yield: 1.82 percent;
   Exercise date: February 22, 2010.

5. Mr. MacKenzie's unvested stock options vested and became exercisable upon
   his retirement on January 1, 2001.



COMPENSATION COMMITTEE
REPORT ON EXECUTIVE COMPENSATION

Overview and Strategy

     The Compensation Committee of the Board of Trustees (the Committee) is
the administrator of executive compensation for the executives of the NU
system (the Company) with authority to establish and interpret the terms of
the Company's executive salary and incentive programs. The goal of the
Committee's executive compensation program for 2000 was to provide a
competitive compensation package to enable the Company to attract and retain
key executives with an eye towards the future in a more competitive
environment.  To help achieve this, the Committee drew upon information from
a variety of sources, including compensation consultants, utility and general
industry surveys, and other publicly available information, including proxy
statements.  The Committee further sought to align executive interests with
those of NU's shareholders and with Company performance by continuing with the
use of share-based incentives as a significant part of executives'
compensation.

Base Salary

     The Committee sets the annual base salary for each executive officer
except for the Chief Executive Officer (CEO), whose base salary is set by the
Board of Trustees following a recommendation by the Committee pursuant to an
evaluation process developed by the Committee in conjunction with the
Corporate Governance Committee of the Board of Trustees.  The Committee
periodically adjusts officers' base salaries to reflect considerations such
as changes in responsibility, market sensitivity, individual performance and
internal equity.  In 2000 the Committee reviewed the average salary growth of
officers, as reported by several national surveys, with the goal of maintaining
the current competitive salary positions.  The CEO's base salary was increased
by 12.5 percent in 2000 based on the market review and the Committee's judgment
as to his past and expected future performance.

Annual Incentive Awards

     The Committee again implemented an Annual Incentive Program during 2000.
The incentive payout target was 80 percent of base salary for the CEO, and
varied from 25 to 50 percent of base salary for the other officers.  The
Annual Incentive Program was designed to calculate actual aggregate payouts
based on the Company's performance against a net income goal and pre-
established individual goals.  Individual awards were made in cash in January
2001.  The CEO received an award under this program of $1,200,000, or 180
percent of target, determined on the fulfillment of the net income goal and
the successful achievement during 2000 of critical strategic, restructuring,
operational, and merger related goals.

Long-Term Incentive Grants

     Long-term stock-based incentive grants were made in February 2000 to
each executive officer and other officers and certain key employees of the
Company.  The Committee targeted these awards, which were made entirely in
the form of stock options, such that long-term incentive awards for the officer
group would be at the 50th percentile of general industry.  The CEO's grant
was targeted at 158 percent of base salary based upon the Committee's dual
goals of market competitiveness and alignment with shareholder interests.

Internal Revenue Service Limitation on Deductibility of Executive
Compensation

     The Committee believes that its compensation program adequately responds
to issues raised by the deductibility cap placed on executive salaries by
Section 162(m) of the Internal Revenue Code because of the use of stock options
and qualified performance-based compensation in Company incentive programs.

                                     Respectfully submitted,


                                     /s/ Robert E. Patricelli, Chairman
                                     /s/ William J. Pape II, Vice Chairman
                                     /s/ Cotton Mather Cleveland
                                     /s/ E. Gail de Planque
                                     /s/ Elizabeth T. Kennan
                                     /s/ John F. Swope


Dated:  February 27, 2001


PENSION BENEFITS

     The following table shows the estimated annual retirement benefits payable
to an executive officer of NU upon retirement, assuming that retirement occurs
at age 65 and that the officer is at that time not only eligible for a pension
benefit under the Northeast Utilities Service Company Retirement Plan (the
Retirement Plan) but also eligible for the make-whole benefit and the target
benefit under the Supplemental Executive Retirement Plan for Officers of NU
system companies (the Supplemental Plan).  The Supplemental Plan is a non-
qualified pension plan providing supplemental retirement income to system
officers.  The make-whole benefit under the Supplemental Plan, available to
all officers, makes up for benefits lost through application of certain tax
code limitations on the benefits that may be provided under the Retirement
Plan, and includes as "compensation" awards under the executive incentive plans
and deferred compensation (as earned).  The target benefit further supplements
these benefits and is available to officers at the Senior Vice President level
and higher who are selected by the Board of Trustees to participate in the
target benefit and who remain in the employ of NU companies until at least age
60 (unless the Board of Trustees sets an earlier age).

     The benefits presented below are based on a straight life annuity
beginning at age 65 and do not take into account any reduction for joint and
survivorship annuity payments.  Final average compensation for purposes of
calculating the target benefit is the highest average annual compensation of
the participant during any 36 consecutive months compensation was earned.
Compensation taken into account under the target benefit described above
includes salary, bonus, restricted stock awards, and long-term incentive
payouts shown in the Summary Compensation Table, but does not include
employer matching contributions under the 401k Plan.  In the event that an
officer's employment terminates because of disability, the retirement
benefits shown above would be offset by the amount of any disability benefits
payable to the recipient that are attributable to contributions made by NU
and its subsidiaries under long term disability plans and policies.

                                   ANNUAL BENEFIT

Final Average                 Years of Credited Service
Compensation
                  15           20          25           30          35

$ 200,000     $ 72,000     $ 96,000     $120,000     $120,000     $120,000
  250,000       90,000      120,000      150,000      150,000      150,000
  300,000      108,000      144,000      180,000      180,000      180,000
  350,000      126,000      168,000      210,000      210,000      210,000
  400,000      144,000      192,000      240,000      240,000      240,000
  450,000      162,000      216,000      270,000      270,000      270,000
  500,000      180,000      240,000      300,000      300,000      300,000
  600,000      216,000      288,000      360,000      360,000      360,000
  700,000      252,000      336,000      420,000      420,000      420,000
  800,000      288,000      384,000      480,000      480,000      480,000
  900,000      324,000      432,000      540,000      540,000      540,000
1,000,000      360,000      480,000      600,000      600,000      600,000
1,100,000      396,000      528,000      660,000      660,000      660,000
1,200,000      432,000      576,000      720,000      720,000      720,000

     Each of the executive officers of NU named in the Summary Compensation
Table is currently eligible for a target benefit, except Messrs. Morris and
Kenyon, whose Employment Agreements provide specially calculated retirement
benefits, based on their previous arrangements with CMS Energy/Consumers
Energy Company (CMS Energy) and South Carolina Electric and Gas, respectively.
Mr. Morris's agreement provides that upon retirement after reaching the fifth
anniversary of his employment date (or upon disability or termination without
cause or following a change in control, as defined) he will be entitled to
receive a special retirement benefit calculated by applying the benefit formula
of the CMS Energy Supplemental Executive Retirement Plan to all compensation
earned from the NU system and to all service rendered to the Company and CMS
Energy.  If Mr. Kenyon retires with at least three years of service with the
Company, he will be deemed to have 2 extra years of service for purpose of
his special retirement benefit.  If after achieving three years of service he
voluntarily terminates employment following a "substantial change in
responsibilities resulting from a material change in the business of Northeast
Utilities", he will be deemed to have an additional year of service for purpose
of his special retirement benefit, and if he retires with at least 3 years of
service with the Company, he will receive a lump sum payment of $500,000.

     In addition, Mr. Forsgren's Employment Agreement provides for supplemental
pension benefits based on crediting up to 10 years additional service and
providing payments equal to 25 percent of salary for up to 15 years following
retirement, reduced by four percentage points for each year that his age is
less than 65 years at retirement.

     As of December 31, 2000, the executive officers named in the Summary
Compensation Table had the following years of credited service for purposes
of calculating target benefits under the Supplemental Plan (or in the case of
Messrs. Morris and Kenyon, for purposes of calculating the special retirement
benefits under their respective Employment Agreements):  Mr. Morris - 22, Mr.
Kenyon - 6, Mr. Forsgren - 4, Mr. MacKenzie - 35, Mrs. Grise - 20, and Mr.
Feigenbaum - 15.  In addition, Mr. Forsgren had 9 years of service for purposes
of his supplemental pension benefit and would have 25 years of service for such
purpose if he were to retire at age 65.  Assuming that retirement were to occur
at age 65 for these officers, retirement would occur with 33, 13, 15, 47, 36
and 29 years of credited service, respectively.

COMPENSATION OF DIRECTORS

     During 2000, each Trustee who was not an employee of NU or its
subsidiaries was compensated at an annual rate of $20,000 cash plus 500 common
shares of NU, and received $1,000 for each meeting attended of the Board or its
Committees.  A non-employee Trustee who participates in a meeting of the Board
or any of its Committees by conference telephone receives $675 per meeting.
Also, a non-employee Trustee who is asked by either the Board of Trustees or
the Chairman of the Board to perform extra services in the interest of the NU
system may receive additional compensation of $1,000 per day plus necessary
expenses.  The Chairs of the Audit, the Compensation, the Corporate Affairs,
the Corporate Governance and the Nuclear Committees were compensated at an
additional annual rate of $3,500.  In addition to the above compensation,
Dr. Kennan is paid at the annual rate of $30,000 for the extra services
performed as Lead Trustee.  The Chair of the Nuclear Committee receives an
additional retainer at the rate of $25,000 per year.

     Under the terms of the Incentive Plan adopted by shareholders at the 1998
Annual Meeting, each non-employee Trustee is eligible for stock-based grants.
During 2000 each such Trustee was granted nonqualified options to purchase
2,500 common shares of NU.  Receipt of shares acquired on exercise of these
options may be deferred pursuant to the terms of the Northeast Utilities
Deferred Compensation Plan for Executives.

     In February 2000, each non-employee Trustee was granted nonqualified
options to purchase 2,500 common shares.

     Prior to the beginning of each calendar year, each non-employee Trustee
may irrevocably elect to have all or any portion of the annual retainer fee
paid in the form of common shares of NU.  Pursuant to the Northeast Utilities
Deferred Compensation Plan for Trustees, each Trustee may also irrevocably
elect to defer receipt of some or all cash and/or share compensation.

     During 2000 each non-employee Director of PSNH and WMECO was compensated
at an annual rate of $10,000 cash, and received $500 for each meeting attended
of the Board of Directors or, in the case of PSNH, its committees.  A non-
employee Director who participates in a meeting of the Board of Directors or
any of its committees by conference telephone receives $300 per meeting.
Also, committee chairs were compensated at an additional annual rate of $1,500.

EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT ARRANGEMENTS

     NUSCO has entered into employment agreements (the Officer Agreements)
with each of the named executive officers.  The Officer Agreements are also
binding on NU and on each majority-owned subsidiary of NU.

     Each Officer Agreement obligates the officer to perform such duties as
may be directed by the NUSCO Board of Directors or the NU Board of Trustees,
protect the Company's confidential information, and refrain, while employed
by the Company and for a period of time thereafter, from competing with the
Company in a specified geographic area.  Each Officer Agreement provides that
the officer's base salary will not be reduced below certain levels without
the consent of the officer, and that the officer will participate in
specified benefits under the Supplemental Executive Retirement Plan or other
supplemental retirement programs (see Pension Benefits, above) and/or in
certain executive incentive programs at specified incentive opportunity
levels.

     Each Officer Agreement provides for a specified employment term and for
automatic one-year extensions of the employment term unless at least six
months' notice of non-renewal is given by either party.  The employment term
may also be ended by the Company for "cause", as defined, at any time (in
which case no supplemental retirement benefit, if any, shall be due), or by
the officer on thirty days' prior written notice for any reason.  Absent
"cause", the Company may remove the officer from his or her position on 60
days' prior written notice, but in the event the officer is so removed and
signs a release of all claims against the Company, the officer will receive
one or two years' base salary and annual incentive payments, specified
employee welfare and pension benefits, and vesting of stock appreciation
rights, options and restricted stock.

     Under the terms of an Officer Agreement, upon any termination of
employment following a change of control, as defined, between (a) the earlier
of the date shareholders approve a change of control transaction or a change
of control transaction occurs and (b) the earlier of the date, if any, on
which the Board of Trustees abandons the transaction or the date 2 years
following the change of control, if the officer signs a release of all claims
against the Company, the officer will be entitled to certain payments
including a multiple (not to exceed four) of annual base salary, annual
incentive payments, specified employee welfare and pension benefits, and
vesting of stock appreciation rights, options and restricted stock.  Certain
of the change in control provisions may be modified by the Board of Trustees
prior to a change in control, on at least two years' notice to the affected
officer(s).

     Besides the terms described above, the Officer Agreements of Messrs.
Morris, Kenyon and Forsgren provide for a specified salary, cash, restricted
stock and/or stock options upon employment, special incentive programs and/or
special retirement benefits.  See Pension Benefits, above, for further
description of these provisions.

     The descriptions of the various agreements set forth above are for
purpose of disclosure in accordance with the proxy and other disclosure rules
of the SEC and shall not be controlling on any party; the actual terms of the
agreements themselves determine the rights and obligations of the parties.

SHARE PERFORMANCE CHART

     The following chart compares the cumulative total return on an investment
in NU common shares with the cumulative total return of the S&P 500 Stock
Index and the S&P Electric Companies Index over the last five fiscal years,
in accordance with the rules of the SEC:

(Assumes $100 invested on January 1, 1996, in NU common shares, S&P 500 Index
and S&P Electric Companies Index with all dividends reinvested.)

                    Year Ended December 31, 2000

         NU Common*     S&P Electric Companies     S&P 500
         ----------     ----------------------     -------

1996        59.00                100.00            123.00
1997        55.00                126.00            164.00
1998        75.00                146.00            211.00
1999        97.00                117.00            255.00
2000       116.00                203.00            232.00

*Total return of NU common shares assumes reinvestment of all dividends
 on payment date.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

NU.

     The following table provides, as of December 31, 2000, information with
respect to persons who are known to NU to beneficially own more than five
percent of the common shares of NU.  NU has no other class of voting
securities.

 Name and Address                   Amount and Nature of     Percent of
of Beneficial Owner                 Beneficial Ownership        Class
- -------------------                 --------------------     ----------

Barrow, Hanley, Mewhinney               11,274,868 (1)          7.58%
  & Strauss, Inc.
One McKinney Plaza
3232 McKinney Avenue, 15th Floor
Dallas, TX

Capital Research and                    7,525,000 (2)           5.06%
  Management Company
333 South Hope Street
Los Angeles, California 90071

- -----------------------

(1)  According to a Statement on Schedule 13G dated February 12, 2001, Barrow,
     Hanley, Mewhinney & Strauss, Inc. holds 11,274,868 common shares of NU.
     According to the Schedule 13G, Barrow, Hanley, Mewhinney & Strauss, Inc.
     has sole voting power for 7,238,468 shares, shared voting power for
     4,036,400 shares and sole dispositive power for 11,274,868 shares.

(2)  According to an Amendment to Schedule 13G dated February 9, 2001, Capital
     Research and Management Company holds 10,938,200 common shares of NU.
     According to the Amendment, Capital Research and Management Company has
     sole voting power for zero shares, shared voting power for zero shares,
     sole dispositive power for 10,938,200 shares and shared dispositive power
     for zero shares.  The Schedule 13G states that beneficial ownership is
     disclaimed pursuant to Rule 13d-4.

     The following table provides information as of February 28, 2001, as to
the beneficial ownership of the common shares of NU by each Trustee and nominee
for Trustee, each of the 5 highest paid executive officers of NU and its
subsidiaries, and all Trustees, nominees for Trustee and executive officers as
a group.  Unless otherwise noted, each Trustee, nominee and executive officer
has sole voting and investment power with respect to the listed shares.

                                Amount and Nature of         Percent
       Name                     Beneficial Ownership       of Class (1)
       ----                     --------------------       ------------

Cotton M. Cleveland                   15,169 (2)
Sanford Cloud, Jr.                    10,913 (3)
William F. Conway                     14,280 (2)(4)
E. Gail de Planque                    12,256 (2)
John H. Forsgren                     115,014 (5)
Raymond L. Golden                     13,210 (6)
Cheryl W. Grise                       51,396 (7)
Elizabeth T. Kennan                   13,600 (2)
Bruce D. Kenyon                      109,458 (8)
Hugh C. MacKenzie                     18,360 (9)
Michael G. Morris                    621,767 (10)
Emery G. Olcott                       17,751 (3)
William J. Pape II                     9,203 (2)(11)
Robert E. Patricelli                  17,877 (2)
John F. Swope                         15,814 (2)
John F. Turner                         9,705 (2)(12)

All Trustees and Executive Officers
as a Group (18 persons)            1,147,925 (13)

- ----------------------

 (1) As of February 28, 2001, the Trustees and executive officers of NU, as a
     group, beneficially owned less than one percent of the NU common shares
     outstanding.

 (2) Includes 8,750 shares that could be acquired by the beneficial owner
     pursuant to currently exercisable options.

 (3) Includes 3,750 shares that could be acquired by the beneficial owner
     pursuant to currently exercisable options.

 (4) Includes 5,530 shares held jointly by Mr. Conway and his wife, who share
     voting and investment power.

 (5) Includes 2,738 restricted shares, as to which Mr. Forsgren has sole
     voting power but no dispositive power.  Includes 107,087 shares that
     could be acquired by Mr. Forsgren pursuant to currently exercisable
     options.

 (6) Includes 6,250 shares that could be acquired by Mr. Golden pursuant to
     currently exercisable options.

 (7) Includes 1,643 restricted shares, as to which Mrs. Grise has sole voting
     power, but no dispositive power.  Includes 33,724 shares that could be
     acquired by Mrs. Grise pursuant to currently exercisable options.
     Includes 265 shares held by Mrs. Grise's husband as custodian for her
     children, with whom she shares voting and dispositive power.

 (8) Includes 1,734 restricted shares, as to which Mr. Kenyon has sole voting
     power but no dispositive power.  Includes 41,772 shares that could be
     acquired by Mr. Kenyon pursuant to currently exercisable options.

 (9) Mr. MacKenzie retired effective January 1, 2001.  Beneficial ownership
     is given as of December 31, 2000, and includes 3,285 restricted shares,
     as to which Mr. MacKenzie had sole voting power but no dispositive
     power, and 22,067 shares that could be acquired by Mr. MacKenzie
     pursuant to then exercisable options.  Mr. MacKenzie's restricted stock
     and 28,141 unvested options vested upon his retirement.

(10) Includes 7,779 restricted shares, as to which Mr. Morris has sole voting
     power but no dispositive power.  Includes 573,476 shares that could be
     acquired by Mr. Morris pursuant to currently exercisable options.
     Includes 13,499 shares held jointly by Mr. Morris and his wife, who
     share voting and investment power.

(11) Includes 5,176 shares as to which Mr. Pape shares voting and dispositive
     power.  Includes 1,250 shares that could be acquired by Mr. Pape pursuant
     to currently exercisable options.  In addition, Mr. Pape shares beneficial
     ownership of 800 shares of CL&P 4.50% Preferred Series 1956.

(12) Includes 955 shares held jointly by Mr. Turner and his wife, who share
     voting and investment power.

(13) Includes 2,053 restricted shares held by executive officers other than
     those named in the table above as to which they have sole voting power
     but no dispositive power.  Includes 70,623 shares that could be acquired
     by them pursuant to currently exercisable options.

CL&P, PSNH, WMECO, and NAEC.

     NU owns 100% of the outstanding common stock of registrants CL&P, PSNH,
WMECO, and NAEC.  As of February 28, 2001, the Directors and Executive Officers
of CL&P, PSNH, WMECO, and NAEC beneficially owned the number of shares of each
class of equity securities of NU listed below.  No equity securities of CL&P,
PSNH, WMECO, or NAEC are owned by the Directors and Executive Officers of CL&P,
PSNH, WMECO, and NAEC.  Unless otherwise noted, each Director and Executive
Officer of CL&P, PSNH, WMECO, and NAEC has sole voting and investment power
with respect to the listed shares.

Title of                                  Amount and Nature of     Percent of
  Class             Name                  Beneficial Ownership      Class (1)

NU Common    David H. Boguslawski              23,246 (2)
NU Common    James E. Byrne                      None
NU Common    John C. Collins                     None
NU Common    William A. DiProfio                5,326 (3)
NU Common    Ted C. Feigenbaum                 38,459 (4)
NU Common    John H. Forsgren                 115,014 (5)
NU Common    George R. Gram II                  6,634 (6)
NU Common    Cheryl W. Grise                   51,396 (7)
NU Common    Bruce D. Kenyon                  109,458 (8)
NU Common    Kerry J. Kuhlman                  14,509 (9)
NU Common    Gerald Letendre                     None
NU Common    Gary A. Long                      13,078 (10)
NU Common    Hugh C. MacKenzie                 18,360 (11)
NU Common    Paul J. McDonald                     500
NU Common    Michael G. Morris                621,767 (12)
NU Common    Jane E. Newman                      None
NU Common    Melinda M. Phelps                   None
NU Common    Rodney O. Powell                   8,288 (13)

Amount beneficially owned by Directors and Executive Officers as a group:

                                    Amount and Nature of
Company      Number of Persons      Beneficial Ownership

CL&P                 8                  969,352 (14)
PSNH                11                  974,142 (14)
WMECO               22                  976,073 (14)
NAEC                 7                  948,054

 (1) As of February 28, 2001, there were 148,780,800 common shares of NU
     outstanding.  The percentage of such shares beneficially owned by any
     Director or Executive Officer, and by all Directors and Executive
     Officers of CL&P, PSNH, WMECO, and NAEC as a group, does not exceed one
     percent.

 (2) Includes 730 restricted shares, as to which Mr. Boguslawski has sole
     voting power but no dispositive power.  Includes 15,512 shares that
     could be acquired by Mr. Boguslawski pursuant to currently exercisable
     options.

 (3) Mr. DiProfio retired effective February 1, 2001.  Beneficial ownership
     is given as of January 31, 2001, and includes 879 shares that could be
     acquired by Mr. DiProfio pursuant to then exercisable options.  1,295
     unvested options vested upon Mr. DiProfio's retirement.

 (4) Includes 639 restricted shares, as to which Mr. Feigenbaum has sole
     voting power but no dispositive power.  Includes 19,153 shares that
     could be acquired by Mr. Feigenbaum pursuant to currently exercisable
     options.

 (5) Includes 2,738 restricted shares, as to which Mr. Forsgren has sole
     voting power but no dispositive power.  Includes 107,087 shares that
     could be acquired by Mr. Forsgren pursuant to currently exercisable
     options.

 (6) Includes 5,283 shares that could be acquired by Mr. Gram pursuant to
     currently exercisable options.

 (7) Includes 1,643 restricted shares, as to which Mrs. Grise has sole voting
     power, but no dispositive power.  Includes 33,724 shares that could be
     acquired by Mrs. Grise pursuant to currently exercisable options.
     Includes 265 shares held by Mrs. Grise's husband as custodian for her
     children, with whom she shares voting and dispositive power.

 (8) Includes 1,734 restricted shares, as to which Mr. Kenyon has sole voting
     power but no dispositive power.  Includes 41,772 shares that could be
     acquired by Mr. Kenyon pursuant to currently exercisable options.

 (9) Includes 342 restricted shares, as to which Ms. Kuhlman has sole voting
     power but no dispositive power.  Includes 8,395 shares that could be
     acquired by Ms. Kuhlman pursuant to currently exercisable options.

(10) Includes 319 restricted shares, as to which Mr. Long has sole voting
     power but no dispositive power.  Includes 7,590 shares that could be
     acquired by Mr. Long pursuant to currently exercisable options.

(11) Mr. MacKenzie retired effective January 1, 2001.  Beneficial ownership
     is given as of December 31, 2000, and includes 3,285 restricted shares,
     as to which Mr. MacKenzie had sole voting power but no dispositive power,
     and 22,067 shares that could be acquired by Mr. MacKenzie pursuant to then
     exercisable options.  Mr. MacKenzie's restricted stock and 28,141 unvested
     options vested upon his retirement.

(12) Includes 7,779 restricted shares, as to which Mr. Morris has sole voting
     power but no dispositive power.  Includes 573,476 shares that could be
     acquired by Mr. Morris pursuant to currently exercisable options.
     Includes 13,499 shares held jointly by Mr. Morris and his wife, who
     share voting and investment power.

(13) Includes 249 restricted shares, as to which Mr. Powell has sole voting
     power but no dispositive power.  Includes 6,750 shares that could be
     acquired by Mr. Powell pursuant to currently exercisable options.

(14) Includes 684 restricted shares held by an executive officer other than
     those named in the table above as to which such officer has sole voting
     power but no dispositive power.  Includes 16,174 shares that could be
     acquired by such officer pursuant to currently exercisable options.

CHANGES IN CONTROL

See Item 1 - Business - Mergers and Acquisitions - Consolidated Edison, Inc.
Merger on pages 3-4.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The law firm of Sulloway and Hollis provided legal services to NU, PSNH
and NAEC during 2000.  John B. Garvey, who is the husband of Cotton M.
Cleveland, a Trustee of NU, is a member of the firm.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)  1.  Financial Statements:

         The Report of Independent Public Accountants and financial statements
         of CL&P, PSNH, WMECO, and NAEC are hereby incorporated by reference
         and made a part of this report (see "Item 8. Financial Statements and
         Supplementary Data").

         Report of Independent Public Accountants
         on Schedules                                                  S-1

         Consent of Independent Public Accountants                     S-2

     2.  Schedules:

         Financial Statement Schedules for NU (Parent),
         NU and Subsidiaries, CL&P and Subsidiaries,
         PSNH, and WMECO and Subsidiary are listed in
         the Index to Financial Statements Schedules                  S-3

     3.  Exhibits Index                                               E-1

(b)  Reports on Form 8-K:

     NU filed a current report on Form 8-K dated February 29, 2000, disclosing:

     o  The 1999 financial statements for NU consolidated and notes thereto
        and management's discussion and analysis of financial condition and
        results of operations relating to the 1999 financial statements.

     NU filed a current report on Form 8-K dated March 1, 2000, disclosing:

     o  The completion of the merger with Yankee.

     NU, CL&P and WMECO filed current reports on Form 8-K dated March 14,
     2000, disclosing:

     o  The transfer of approximately 1,289 MW of hydroelectric and pumped
        storage generation assets in Connecticut and Massachusetts to NGC.

     NU filed a current report on Form 8-K dated March 29, 2000, disclosing:

     o  The supplement to the joint proxy statement/prospectus for the
        special meeting of shareholders related to the Con Edison merger.

     NU filed a current report on Form 8-K dated September 27, 2000,
     disclosing:

     o  The Utility Operations Management Analysis Unit of the DPUC recommended
        that the DPUC approve the results of the recently completed auction of
        the Millstone nuclear units.

     NU filed a current report on Form 8-K dated October 24, 2000, disclosing:

     o  Con Edison issued a press release on October 23, 2000, regarding the
        DPUC's decision on October 19, 2000, which approved the proposed merger
        between NU and Con Edison, subject to a number of conditions.

     NU filed a current report on Form 8-K dated October 24, 2000, disclosing:

     o  NU's earnings press release for the third quarter of 2000.

     NU filed a current report on Form 8-K dated October 31, 2000, disclosing:

     o  NU's and Con Edison's presentation dated October 31, 2000, entitled
        "The Northeast's Energy Company."

     NU filed a current report on Form 8-K dated January 23, 2001, disclosing:

     o  NU's earnings press release for the fourth quarter and full year 2000.

     NU filed a current report on Form 8-K dated February 28, 2001, disclosing:

     o  NU's news release formally seeking Con Edison's assurance of intent
        to close merger.

     NU filed a current report on Form 8-K dated March 5, 2001, disclosing:

     o  NU declares Con Edison in breach of merger agreement.  NU to sue Con
        Edison to recover value of merger for NU shareholders.

     NU filed a current report on Form 8-K dated March 12, 2001, disclosing:

     o  NU filed suit in the U.S. District Court for the Southern District
        seeking for itself and its shareholders in excess of $1 billion in
        damages arising from Con Edison's breach of the merger agreement.

     NU filed a current report on Form 8-K dated March 22, 2001, disclosing:

     o  NU's news release announcing revised 2000 earnings and confirming
        2001 projected earnings.



                                NORTHEAST UTILITIES

                                    SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

                                        NORTHEAST UTILITIES
                                        -------------------
                                            (Registrant)



Date:  March 16, 2001                   By /s/ Michael G. Morris
                                           ----------------------------
                                               Michael G. Morris
                                               Chairman of the Board,
                                               President and
                                               Chief Executive Officer


     Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.


Date               Title                           Signature
- ----               -----                           ---------

March 16, 2001     Chairman of the Board,         /s/ Michael G. Morris
                   President and                  --------------------------
                   Chief Executive Officer            Michael G. Morris
                   and a Trustee


March 16, 2001     Executive Vice                 /s/ John H. Forsgren
                   President and Chief            --------------------------
                   Financial Officer                  John H. Forsgren
                   and a Trustee


March 16, 2001     Vice President and             /s/ John J. Roman
                   Controller                     --------------------------
                                                      John J. Roman


March 16, 2001     Trustee                        /s/ Cotton M. Cleveland
                                                  --------------------------
                                                      Cotton M. Cleveland


March 16, 2001     Trustee                        /s/ Sanford Cloud, Jr.
                                                  --------------------------
                                                      Sanford Cloud, Jr.


March 16, 2001     Trustee                        /s/ William F. Conway
                                                  --------------------------
                                                      William F. Conway


March 16, 2001     Trustee                        /s/ E. Gail de Planque
                                                  --------------------------
                                                      E. Gail de Planque


March 16, 2001     Trustee                        /s/ Raymond L. Golden
                                                  --------------------------
                                                      Raymond L. Golden


March 16, 2001     Trustee                        /s/ Elizabeth T. Kennan
                                                  --------------------------
                                                      Elizabeth T. Kennan


March 16, 2001     Trustee                        /s/ Emery G. Olcott
                                                  --------------------------
                                                      Emery G. Olcott


March 16, 2001     Trustee                        /s/ William J. Pape II
                                                  --------------------------
                                                      William J. Pape II


March 16, 2001     Trustee                        /s/ Robert E. Patricelli
                                                  --------------------------
                                                      Robert E. Patricelli


March 16, 2001     Trustee                        /s/ John F. Swope
                                                  --------------------------
                                                      John F. Swope


March 16, 2001     Trustee                        /s/ John F. Turner
                                                  --------------------------
                                                      John F. Turner



                      THE CONNECTICUT LIGHT AND POWER COMPANY

                                     SIGNATURES


     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.


                                        THE CONNECTICUT LIGHT AND POWER COMPANY
                                        ---------------------------------------
                                                     (Registrant)


Date:  March 16, 2001                   By /s/ Michael G. Morris
                                           ------------------------------------
                                               Michael G. Morris
                                               Chief Executive Officer

     Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.

Date               Title                          Signature
- ----               -----                          ---------

March 16, 2001     Treasurer                      /s/ Randy A. Shoop
                                                  -----------------------------
                                                      Randy A. Shoop


March 16, 2001     Controller                     /s/ John P. Stack
                                                  -----------------------------
                                                      John P. Stack


March 16, 2001     Director                       /s/ David H. Boguslawski
                                                  -----------------------------
                                                      David H. Boguslawski


March 16, 2001     Director                       /s/ Rodney O. Powell
                                                  -----------------------------
                                                      Rodney O. Powell



                      PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

                                     SIGNATURES


     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

                                        PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
                                        ---------------------------------------
                                                      (Registrant)


Date:  March 16, 2001                   By /s/ Michael G. Morris
                                           ------------------------------------
                                               Michael G. Morris
                                               Chairman and Chief
                                               Executive Officer


     Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.


Date               Title                          Signature
- ----               -----                          ---------

March 16, 2001     Chairman and Chief             /s/ Michael G. Morris
                   Executive Officer              -----------------------------
                   and a Director                     Michael G. Morris


March 16, 2001     President and Chief            /s/ Gary A. Long
                   Operating Officer and          -----------------------------
                   a Director                         Gary A. Long


March 16, 2001     Vice President and             /s/ David R. McHale
                   Treasurer                      -----------------------------
                                                      David R. McHale


March 16, 2001     Vice President                 /s/ John J. Roman
                   and Controller                 -----------------------------
                                                      John J. Roman


March 16, 2001     Director                       /s/ David H. Boguslawski
                                                  -----------------------------
                                                      David H. Boguslawski


March 16, 2001     Director                       /s/ John C. Collins
                                                  -----------------------------
                                                      John C. Collins


March 16, 2001     Director                       /s/ John H. Forsgren
                                                  -----------------------------
                                                      John H. Forsgren


March 16, 2001     Director                       /s/ Gerald Letendre
                                                  -----------------------------
                                                      Gerald Letendre


March 16, 2001     Director                       /s/ Jane E. Newman
                                                  -----------------------------
                                                      Jane E. Newman



                          WESTERN MASSACHUSETTS ELECTRIC COMPANY

                                        SIGNATURES


     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

                                        WESTERN MASSACHUSETTS ELECTRIC COMPANY
                                        --------------------------------------
                                                      (Registrant)



Date:  March 16, 2001                   By /s/ Michael G. Morris
                                           ----------------------------------
                                               Michael G. Morris
                                               Chairman and Chief
                                               Executive Officer


     Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.


Date               Title                          Signature
- ----               -----                          ---------

March 16, 2001     Chairman and Chief             /s/ Michael G. Morris
                   Executive Officer              -----------------------------
                   and a Director                     Michael G. Morris


March 16, 2001     President and                  /s/ Kerry J. Kuhlman
                   Chief Operating                -----------------------------
                   Officer and a Director             Kerry J. Kuhlman



March 16, 2001     Vice President                 /s/ David R. McHale
                   and Treasurer                  -----------------------------
                                                      David R. McHale


March 16, 2001     Vice President                 /s/ John J. Roman
                   and Controller                 -----------------------------
                                                      John J. Roman


March 16, 2001     Director                       /s/ David H. Boguslawski
                                                  -----------------------------
                                                      David H. Boguslawski


March 16, 2001     Director                       /s/ James E. Byrne
                                                  -----------------------------
                                                      James E. Byrne


March 16, 2001     Director                       /s/ John H. Forsgren
                                                  -----------------------------
                                                      John H. Forsgren


March 16, 2001     Director                       /s/ Paul J. McDonald
                                                  -----------------------------
                                                      Paul J. McDonald


March 16, 2001     Director                       /s/ Melinda M. Phelps
                                                  -----------------------------
                                                      Melinda M. Phelps



                            NORTH ATLANTIC ENERGY CORPORATION

                                        SIGNATURES


     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.


                                        NORTH ATLANTIC ENERGY CORPORATION
                                        ---------------------------------
                                                  (Registrant)


Date:  March 16, 2001                   By /s/ Bruce D. Kenyon
                                           ------------------------------------
                                               Bruce D. Kenyon
                                               President and Chief
                                               Executive Officer

     Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.

Date               Title                          Signature
- ----               -----                          ---------

March 16, 2001     President and Chief            /s/ Bruce D. Kenyon
                   Executive Officer              ------------------------------
                   and a Director                     Bruce D. Kenyon


March 16, 2001     Vice President and             /s/ David R. McHale
                   Treasurer of Northeast         -----------------------------
                   Utilities Service                  David R. McHale
                   Company as Agent for
                   North Atlantic Energy
                   Corporation


March 16, 2001     Vice President and             /s/ John J. Roman
                   and Controller of              -----------------------------
                   Northeast Utilities                John J. Roman
                   Service Company as
                   Agent for North Atlantic
                   Energy Corporation


March 16, 2001     Director                       /s/ Ted C. Feigenbaum
                                                  -----------------------------
                                                      Ted C. Feigenbaum


March 16, 2001     Director                       /s/ George R. Gram
                                                  ----------------------------
                                                      George R. Gram




           REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES
           -----------------------------------------------------


We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements included in Northeast Utilities'
annual report on Form 10-K and The Connecticut Light and Power Company's,
Western Massachusetts Electric Company's, Public Service Company of New
Hampshire's, and North Atlantic Energy Corporation's annual reports,
incorporated by reference in this Form 10-K, and have issued our reports
thereon dated January 23, 2001 (except with respect to the matters discussed
in Note 15, Note 15, Note 14, Note 14, and Note 11 for Northeast Utilities,
The Connecticut Light and Power Company, Western Massachusetts Electric
Company, Public Service Company of New Hampshire, and North Atlantic Energy
Corporation, respectively, as to which the date is March 13, 2001).  Our
audit was made for the purpose of forming an opinion on the basic financial
statements taken as a whole.  The schedules listed in the accompanying Index
to Financial Statements Schedules are the responsibility of the companies'
management and are presented for purposes of complying with the Securities
and Exchange Commission's rules and are not a part of the basic financial
statements.  These schedules have been subjected to the auditing procedures
applied in the audit of the basic financial statements and, in our opinion,
fairly state in all material respects the financial data required to be set
forth therein in relation to the basic financial statements taken as a whole.



                                         /s/ Arthur Andersen LLP
                                             Arthur Andersen LLP

Hartford, Connecticut
January 23, 2001




                   CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
                   -----------------------------------------


As independent public accountants, we hereby consent to the incorporation of
our reports dated January 23, 2001 (except with respect to the matters
discussed in Note 15 for Northeast Utilities and The Connecticut Light and
Power Company, Note 14 for Western Massachusetts Electric Company and Public
Service Company of New Hampshire, and Note 11 for North Atlantic Energy
Corporation, as to which the date is March 13, 2001), included (or
incorporated by reference) in this Form 10-K into the Company's previously
filed Registration Statements No. 33-55279 of The Connecticut Light and Power
Company, No. 33-56537 of CL&P Capital, LP and No. 33-34622, No. 33-44814, No.
33-63023, No. 33-40156, No. 333-52413, No. 333-52415, and No. 333-85613 of
Northeast Utilities.  It should be noted that we have not audited any
financial statements of the Company subsequent to December 31, 2000 or
performed any audit procedures subsequent to the date of our report.



                                         /s/ Arthur Andersen LLP
                                             Arthur Andersen LLP

Hartford, Connecticut
March 27, 2001



                       INDEX TO FINANCIAL STATEMENTS SCHEDULES

Schedule

I.    Financial Information of Registrant:
        Northeast Utilities (Parent) Balance
        Sheets 2000 and 1999                                           S-4

      Northeast Utilities (Parent) Statements
      of Income 2000, 1999, and 1998                                   S-5

      Northeast Utilities (Parent) Statements
      of Cash Flows 2000, 1999, and 1998                               S-6

II.   Valuation and Qualifying Accounts and Reserves
      2000, 1999, and 1998:

      Northeast Utilities and Subsidiaries                          S-7 - S-9
      The Connecticut Light and Power Company
        and Subsidiaries                                           S-10 - S-12
      Public Service Company of New Hampshire                      S-13 - S-15
      Western Massachusetts Electric Company
        and Subsidiary                                             S-16 - S-18


     All other schedules of the companies' for which provision is made in the
applicable regulations of the SEC are not required under the related
instructions or are not applicable, and therefore have been omitted.




                                     SCHEDULE I
                            NORTHEAST UTILITIES (PARENT)
                        FINANCIAL INFORMATION OF REGISTRANT
                                  BALANCE SHEETS
                           AT DECEMBER  31, 2000 AND 1999
                               (Thousands of Dollars)





<TABLE>
<CAPTION>

                                                                  2000           1999
                                                               ----------     ----------
<S>                                                            <C>            <C>
ASSETS
- ------
Other Property and Investments:
  Investments in subsidiary companies, at equity............  $2,687,804     $2,252,175
  Investments in transmission companies, at equity..........      15,011         16,460
  Other, at cost............................................          14             54
                                                              -----------    -----------
                                                               2,702,829      2,268,689
                                                              -----------    -----------
Current Assets:
  Cash......................................................       1,058           -
  Notes receivable from affiliated companies................      94,400         45,300
  Notes and accounts receivable.............................         868            625
  Receivables from affiliated companies.....................       3,908          8,351
  Taxes receivable..........................................        -               418
  Prepayments...............................................       3,744          1,192
                                                              -----------    -----------
                                                                 103,978         55,886
                                                              -----------    -----------
Deferred Charges:
  Unamortized debt expense..................................          13              6
  Other.....................................................         321            122
  Deferred Yankee Energy System, Inc. acquisition expenses..        -             3,427
                                                              -----------    -----------
                                                                     334          3,555
                                                              -----------    -----------

       Total Assets.........................................  $2,807,141     $2,328,130
                                                              ===========    ===========

CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
  Common Shareholders' Equity:
    Common shares, $5 par value - authorized
    225,000,000 shares; 148,781,861 shares issued and
    143,820,405 shares outstanding in 2000 and
    137,393,829 shares issued and
    131,870,284 outstanding in 1999.........................  $  693,345     $  636,405
  Capital surplus, paid in..................................     927,059        776,290
  Temporary equity from stock forward.......................     215,000        215,000
  Deferred contribution plan - employee stock ownership plan    (114,463)      (127,725)
  Retained earnings.........................................     495,873        581,817
  Accumulated other comprehensive income....................       1,769          1,524
                                                              -----------    -----------
    Total common shareholders' equity.......................   2,218,583      2,083,311
  Long-term debt............................................     117,000        138,000
                                                              -----------    -----------
    Total capitalization....................................   2,335,583      2,221,311
                                                              -----------    -----------
Current Liabilities:
  Long-term debt - current portion..........................      21,000         20,000
  Notes payable to banks....................................     436,000         65,000
  Accounts payable..........................................         966          7,258
  Accounts payable to affiliated companies..................          18          1,201
  Accrued taxes.............................................       1,135           -
  Accrued interest..........................................       6,961          1,705
  Accrued Con Edison/Northeast Utilities merger fees........          20          6,143
                                                              -----------    -----------
                                                                 466,100        101,307
                                                              -----------    -----------
Accumulated deferred income taxes...........................       5,026          5,302
Other deferred credits......................................         432            210
                                                              -----------    -----------
                                                                   5,458          5,512
                                                              -----------    -----------
    Total Capitalization and Liabilities                      $2,807,141     $2,328,130
                                                              ===========    ===========
</TABLE>





                                      SCHEDULE I
                             NORTHEAST UTILITIES (PARENT)
                         FINANCIAL INFORMATION OF REGISTRANT
                                STATEMENTS OF INCOME
                    YEARS ENDED DECEMBER 31, 2000, 1999, AND 1998
                   (Thousands of Dollars Except Share Information)



                                        2000           1999           1998
                                   -------------  -------------  -------------


Operating Revenues................ $       -      $       -      $       -
                                   -------------  -------------  -------------
Operating Expenses:
  Other...........................       15,335         19,126          7,674
  Federal income taxes............        2,708         (4,849)         1,569
                                   -------------  -------------  -------------
   Total operating expenses.......       18,043         14,277          9,243
                                   -------------  -------------  -------------
Operating Loss....................      (18,043)       (14,277)        (9,243)
                                   -------------  -------------  -------------
Other Income/(Loss):
  Equity in earnings/(loss)
   of subsidiaries................       23,553         56,812       (145,874)
  Equity in earnings of
   transmission companies.........        2,553          2,608          2,903
  Other, net......................        9,134          2,628         21,995
  Income taxes....................        2,036          2,057           -
                                   -------------  -------------  -------------
    Other income/(loss), net......       37,276         64,105       (120,976)
                                   -------------  -------------  -------------
    Income/(loss) before interest
     charges......................       19,233         49,828       (130,219)
                                   -------------  -------------  -------------
Interest Charges..................       47,819         15,612         16,534
                                   -------------  -------------  -------------
(Loss)/Earnings for Common Shares. $    (28,586)  $     34,216   $   (146,753)
                                   =============  =============  =============

Basic and Fully Diluted (Loss)/
  Earnings Per Common Share....... $      (0.20)  $       0.26   $      (1.12)
                                   =============  =============  =============

Basic Common Shares
 Outstanding (average)............  141,549,860    131,415,126    130,549,760
                                   =============  =============  =============

Fully Diluted Common Shares
 Outstanding (average)............  141,967,216    132,031,573    130,549,760
                                   =============  =============  =============


<TABLE>
                                                SCHEDULE I
                                       NORTHEAST UTILITIES (PARENT)
                                   FINANCIAL INFORMATION OF REGISTRANT
                                         STATEMENTS OF CASH FLOWS
                                YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
                                         (Thousands of Dollars)

<CAPTION>
                                                                  2000          1999          1998
                                                             ------------ -------------- --------------
<S>                                                              <S>           <S>            <C>
Operating Activities:
  Net (loss)/income........................................  $   (28,586) $      34,216  $    (146,753)
  Adjustments to reconcile to net cash
   provided by operating activities:
    Equity in earnings of subsidiary companies.............      (23,553)       (56,812)       145,874
    Cash dividends received from subsidiary companies......      183,016         66,000         47,000
    Deferred income taxes..................................         (276)            74            777
    Other sources of cash..................................        3,276         16,655         20,926
    Changes in working capital:
      Receivables..........................................        4,200         (7,220)           (84)
      Accounts payable.....................................       (7,475)         5,863            523
      Other working capital (excludes cash)................       (1,866)        12,191        (15,981)
                                                             ------------ -------------- --------------
Net cash flows provided by operating activities............      128,736         70,967         52,282
                                                             ------------ -------------- --------------

Investing Activities:
  NU system Money Pool.....................................      (49,100)       (10,900)          (200)
  Investment in subsidiaries...............................     (117,631)       (99,462)       (40,029)
  Other investment activities, net.........................        1,489          1,245          2,278
  Payment for the purchase of Yankee Energy System, Inc....     (260,347)           -              -
                                                             ------------ -------------- --------------
Net cash flows used in investing activities................     (425,589)      (109,117)       (37,951)
                                                             ------------ -------------- --------------

Financing Activities:
  Issuance of common shares................................        4,269          5,318          2,659
  Net increase in short-term debt..........................      371,000         65,000            -
  Reacquisitions and retirements of long-term debt.........      (20,000)       (19,000)       (17,000)
  Cash dividends on common shares..........................      (57,358)       (13,168)           -
                                                             ------------ -------------- --------------
Net cash flows provided by/(used in) financing activities..      297,911         38,150        (14,341)
                                                             ------------ -------------- --------------

Net increase/(decrease) in cash for the period.............        1,058            -              (10)
Cash - beginning of period.................................            -            -               10
                                                             ------------ -------------- --------------
Cash - end of period.......................................  $     1,058  $         -    $         -
                                                             ============ ============== ==============

Supplemental Cash Flow Information:
Cash paid during the year for:
  Interest, net of amounts capitalized.....................  $    39,099  $      15,724  $      16,610
                                                             ============ ============== ==============
  Income taxes.............................................  $     1,430  $      28,982  $      16,929
                                                             ============ ============== ==============
</TABLE>



<TABLE>
                                     NORTHEAST UTILITIES AND SUBSIDIARIES                         SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 2000
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $ 4,895      $26,740     $   130 (c)  $19,265 (a)     $12,500
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $44,995      $22,573     $37,680 (c)  $25,967 (b)     $79,281
                                             =======      =======     =======      =======         =======

(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.
(c) Amounts represent activity related to the acquisition of Yankee on March 1, 2000.
</TABLE>

<TABLE>
                                     NORTHEAST UTILITIES AND SUBSIDIARIES                         SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 1999
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $ 2,417      $ 8,026     $  -         $ 5,548 (a)     $ 4,895
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $40,438      $18,597     $  -         $14,040 (b)     $44,995
                                             =======      =======     =======      =======         =======

(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.

</TABLE>



<TABLE>
                                     NORTHEAST UTILITIES AND SUBSIDIARIES                         SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 1998
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $ 2,052      $ 3,042     $  -         $ 2,677 (a)     $ 2,417
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $34,437      $12,427     $  -         $ 6,426 (b)     $40,438
                                             =======      =======     =======      =======         =======


(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
     employee medical expenses, and expenses in connection therewith.

 </TABLE>



<TABLE>
                           THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES               SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 2000
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $   300      $ 9,270     $  -         $ 9,270 (a)     $   300
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $16,069      $ 7,488     $  -         $ 9,897 (b)     $13,660
                                             =======      =======     =======      =======         =======



(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.

 </TABLE>


<TABLE>
                           THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES               SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 1999
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $   300      $   290     $  -         $   290 (a)     $   300
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $16,656      $ 5,422     $  -         $ 6,009 (b)     $16,069
                                             =======      =======     =======      =======         =======


(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.

 </TABLE>



<TABLE>
                           THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES               SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 1998
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $   300      $   183     $  -         $   183 (a)     $   300
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $14,962      $ 5,612     $  -         $ 3,918 (b)     $16,656
                                             =======      =======     =======      =======         =======



(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.

 </TABLE>


<TABLE>
                                   PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE                        SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 2000
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $ 1,359      $ 2,220     $  -         $ 1,710 (a)     $ 1,869
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $11,405      $ 9,855     $  -         $ 9,610 (b)     $11,650
                                             =======      =======     =======      =======         =======



(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.

 </TABLE>


<TABLE>
                                   PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE                        SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 1999
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $ 2,041      $ 1,590     $  -         $ 2,272 (a)     $ 1,359
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $ 9,906      $ 7,268     $  -         $ 5,769 (b)     $11,405
                                             =======      =======     =======      =======         =======



(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.

</TABLE>



<TABLE>
                                   PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE                        SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 1998
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $ 1,702      $ 2,726     $  -         $ 2,387 (a)     $ 2,041
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $ 7,788      $ 4,136     $  -         $ 2,018 (b)     $ 9,906
                                             =======      =======     =======      =======         =======



(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.

</TABLE>


<TABLE>
                            WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY                 SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 2000
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $ 1,640      $ 2,416     $  -         $ 2,170 (a)     $ 1,886
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $ 7,188      $ 1,130     $  -         $ 1,558 (b)     $ 6,760
                                             =======      =======     =======      =======         =======



(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.

</TABLE>



<TABLE>
                            WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY                 SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 1999
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $    50      $ 4,564     $  -         $ 2,974 (a)     $ 1,640
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $ 5,960      $ 3,085     $  -         $ 1,857 (b)     $ 7,188
                                             =======      =======     =======      =======         =======



(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.

</TABLE>


<TABLE>
                            WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY                 SCHEDULE II
                                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                         YEAR ENDED DECEMBER 31, 1998
                                            (Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Column A                                     Column B          Column C             Column D       Column E

                                                               Additions
                                                         ----------------------
                                                             (1)         (2)

                                                                      Charged to
                                            Balance at   Charged to     other                      Balance
                                            beginning    costs and     accounts-   Deductions-     at end
Description                                 of period     expenses     describe      describe     of period
- -------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>         <C>          <C>             <C>
RESERVES DEDUCTED FROM ASSETS
 TO WHICH THEY APPLY:

    Reserves for uncollectible accounts      $    50      $   106     $  -         $   106 (a)     $    50
                                             =======      =======     =======      =======         =======

RESERVES NOT APPLIED AGAINST ASSETS:

    Operating reserves                       $ 5,503      $   816     $  -         $   359 (b)     $ 5,960
                                             =======      =======     =======      =======         =======



(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
    employee medical expenses, and expenses in connection therewith.

</TABLE>



                                 EXHIBIT INDEX


     Each document described below is incorporated by reference to the files
of the SEC, unless the reference to the document is marked as follows:

     *  - Filed with the 2000 Annual Report on Form 10-K for NU and herein
     incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324
     into the 2000 Annual Reports on Form 10-K for CL&P, PSNH, WMECO, and NAEC.

     #  - Filed with the 2000 Annual Report on Form 10-K for NU and herein
     incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324
     into the 2000 Annual Report on Form 10-K for CL&P.

     @  - Filed with the 2000 Annual Report on Form 10-K for NU and herein
     incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324
     into the 2000 Annual Report on Form 10-K for PSNH.

     ** - Filed with the 2000 Annual Report on Form 10-K for NU and herein
     incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324
     into the 2000 Annual Report on Form 10-K for WMECO.

     ## - Filed with the 2000 Annual Report on Form 10-K for NU and herein
     incorporated by reference from the 2000 Form 10-K, File No. 1-5324 into
     the 2000 Annual Report on Form 10-K for NAEC.

Exhibit
Number                        Description

   2   Plan of acquisition, reorganization, arrangement, liquidation or
       succession

       2.1   Agreement and Plan of Merger (Exhibit 1 in NU's Current Report
             on Form 8-K dated June 14, 1999, File No. 1-5324)

       2.2   Agreement and Plan of Merger (Exhibit 1 to NU's Current Report
             on Form 8-K dated October 13, 1999, File No. 1-5324)

   3   Articles of Incorporation and By-Laws

       3.1   Northeast Utilities

             3.1.1    Declaration of Trust of NU, as amended through May 24,
                      1988. (Exhibit 3.1.1, 1988 NU Form 10-K, File No. 1-5324)

       3.2   The Connecticut Light and Power Company

             3.2.1    Certificate of Incorporation of CL&P, restated to
                      March 22, 1994.  (Exhibit 3.2.1, 1993 NU Form 10-K,
                      File No. 1-5324)

             3.2.2    Certificate of Amendment to Certificate of Incorporation
                      of CL&P, dated December 26, 1996. (Exhibit 3.2.2, 1996 NU
                      Form 10-K, File No. 1-5324)

             3.2.3    Certificate of Amendment to Certificate of Incorporation
                      of CL&P, dated April 27, 1998. (Exhibit 3.2.3, 1998 NU
                      Form 10-K, File No. 1-5324)

             3.2.4    By-laws of CL&P, as amended to January 1, 1997.
                      (Exhibit 3.2.3, 1996 NU Form 10-K, File No. 1-5324)

       3.3   Public Service Company of New Hampshire

             3.3.1    Articles of Incorporation, as amended to May 16, 1991.
                      (Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324)

             3.3.2    By-laws of PSNH, as amended to November 1, 1993.
                      (Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324)

       3.4   Western Massachusetts Electric Company

             3.4.1    Articles of Organization of WMECO, restated to
                      February 23, 1995.  (Exhibit 3.4.1, 1994 NU Form 10-K,
                      File No. 1-5324)

             3.4.2    By-laws of WMECO, as amended to April 1, 1999.
                      (Exhibit 3.1, 1999 NU Form 10-Q for the Quarter Ended
                       June 30, 1999, File No. 1-5324)

             3.4.3    By-laws of WMECO, as further amended to May 1, 2000.
                      (Exhibit 3.1, 2000 NU Form 10-Q for the Quarter Ended
                      June 30, 2000, File No. 1-5324)

       3.5   North Atlantic Energy Corporation

             3.5.1   Articles of Incorporation of NAEC dated September 20,
                     1991.  (Exhibit 3.5.1, 1993 NU Form 10-K, File No. 1-5324)

             3.5.2   Articles of Amendment dated October 16, 1991 and June 2,
                     1992, to Articles of Incorporation of NAEC.  (Exhibit
                     3.5.2, 1993 NU Form 10-K, File No. 1-5324)

             3.5.3   By-laws of NAEC, as amended to November 8, 1993.  (Exhibit
                     3.5.3, 1993 NU Form 10-K, File No. 1-5324)

             3.5.4   By-laws of NAEC, as amended to June 1, 2000.  (Exhibit
                     3.1, 2000 NU Form 10-Q for the Quarter Ended September 30,
                     2000, File No. 1-5324)

   4   Instruments defining the rights of security holders, including
       indentures

       4.1   Northeast Utilities

             4.1.1   Indenture dated as of December 1, 1991, between Northeast
                     Utilities and IBJ Schroder Bank & Trust Company, with
                     respect to the issuance of Debt Securities.  (Exhibit
                     4.1.1, 1991 NU Form 10-K, File No. 1-5324)

             4.1.2   First Supplemental Indenture dated as of December 1,
                     1991, between Northeast Utilities and IBJ Schroder Bank &
                     Trust Company, with respect to the issuance of Series A
                     Notes.  (Exhibit 4.1.2, 1991 NU Form 10-K, File No.
                     1-5324)

             4.1.3   Second Supplemental Indenture dated as of March 1, 1992,
                     between Northeast Utilities and IBJ Schroder Bank & Trust
                     Company with respect to the issuance of 8.38% Amortizing
                     Notes.  (Exhibit 4.1.3, 1992 NU Form 10-K, File No.
                     1-5324)

             4.1.4   Credit Agreement among NU, CL&P, WMECO and the Co-Agents
                     and Banks named therein, dated as of November 17, 2000,
                     (includes Open End Mortgages), (Exhibit No. 2 on 35-CERT
                     filed November 27, 2000, File No. 70-8875)

            *4.1.5   Term Loan Agreement among NU and the Banks named therein,
                     dated as of March 1, 2000.

                    *4.1.5.1   First Amendment to Term Loan Agreement dated
                               as of December 15, 2000.

             4.1.6   Indenture between NU and The Bank of New York, as Trustee,
                     dated as of February 28, 2001, relating to Senior Notes
                     (Exhibit A-1 to 35-CERT filed March 9, 2001, File No.
                     70-9535)

                     4.1.6.1   First Supplemental Indenture to the Indenture,
                               dated as of February 28, 2001, between NU and
                               The Bank of New York, as Trustee, relating to
                               Floating Rate Notes Due 2003 (Exhibit A-2 to
                               35-CERT filed March 9, 2001, File No. 70-9535)

       4.2   The Connecticut Light and Power Company

             4.2.1   Indenture of Mortgage and Deed of Trust between CL&P and
                     Bankers Trust Company, Trustee, dated as of May 1, 1921.
                     (Composite including all twenty-four amendments to May 1,
                     1967.)  (Exhibit 4.1.1, 1989 NU Form 10-K, File No.
                     1-5324)

                     Supplemental Indentures to the Composite May 1, 1921,
                     Indenture of Mortgage and Deed of Trust between CL&P and
                     Bankers Trust Company, dated as of:

             4.2.2   December 1, 1969.  (Exhibit 4.2.2, 1998 NU Form 10-K,
                     File No. 1-5324)

             4.2.3   June 30, 1982.  (Exhibit 4.33, File No. 2-79235)

             4.2.4   December 1, 1989.  (Exhibit 4.1.26, 1989 NU Form 10-K,
                     File No. 1-5324)

             4.2.5   July 1, 1992.  (Exhibit 4.31, File No. 33-59430)

             4.2.6   July 1, 1993.  (Exhibit A.10(b),  File No. 70-8249)

             4.2.7   July 1, 1993.  (Exhibit A.10(b),  File No. 70-8249)

             4.2.8   December 1, 1993.  (Exhibit 4.2.14, 1993 NU Form 10-K,
                     File No. 1-5324)

             4.2.9   February 1, 1994.  (Exhibit 4.2.16, 1993 NU Form 10-K,
                     File No. 1-5324)

             4.2.10  June 1, 1994.  (Exhibit 4.2.15, 1994 NU Form 10-K,
                     File No. 1-5324)

             4.2.11  October 1, 1994.  (Exhibit 4.2.16, 1994 NU Form 10-K,
                     File No. 1-5324)

             4.2.12  June 1, 1996.  (Exhibit 4.2.16, 1996 NU Form 10-K,
                     File No. 1-5324)

             4.2.13  January 1, 1997.  (Exhibit 4.2.17, 1996 NU Form 10-K,
                     File No. 1-5324)

             4.2.14  May 1, 1997.  (Exhibit 4.19, File No. 333-30911)

             4.2.15  June 1, 1997.  (Exhibit 4.20, File No. 333-30911)

             4.2.16  June 1, 1997.  (Exhibit 4.2.17, 1997 NU Form 10-K, File
                     No. 1-5324)

             4.2.17  May 1, 1998.  (Exhibit 4.2.17, 1998 NU Form 10-K, File
                     No. 1-5324)

             4.2.18  May 1, 1998.  (Exhibit 4.2.18, 1998 NU Form 10-K, File
                     No. 1-5324)

             4.2.19  Financing Agreement between Industrial Development
                     Authority of the State of New Hampshire and CL&P
                     (Pollution Control Bonds, 1986 Series) dated as of
                     December 1, 1986.  (Exhibit C.1.47, 1986 NU Form U5S,
                     File No. 30-246)

             4.2.20  Financing Agreement between Industrial Development
                     Authority of the State of New Hampshire and CL&P
                     (Pollution Control Bonds, 1988 Series) dated as of
                     October 1, 1988.  (Exhibit C.1.55, 1988 NU Form U5S,
                     File No. 30-246)

             4.2.21  Loan and Trust Agreement among Business Finance Authority
                     of the State of New Hampshire, CL&P and the Trustee
                     (Pollution Control Bonds, 1992 Series A) dated as of
                     December 1, 1992. (Exhibit C.2.33, 1992 NU Form U5S,
                     File No. 30-246)

             4.2.22  Loan Agreement between Connecticut Development Authority
                     and CL&P (Pollution Control Bonds - Series A, Tax Exempt
                     Refunding) dated as of September 1, 1993.  (Exhibit
                     4.2.21, 1993 NU Form 10-K, File No. 1-5324)

             4.2.23  Loan Agreement between Connecticut Development Authority
                     and CL&P (Pollution Control Bonds - Series B, Tax Exempt
                     Refunding) dated as of September 1, 1993.  (Exhibit
                     4.2.22, 1993 NU Form 10-K, File No. 1-5324)

             4.2.24  Amended and Restated Loan Agreement between Connecticut
                     Development Authority and CL&P (Pollution Control Revenue
                     Bond - 1996A Series) dated as of May 1, 1996, and Amended
                     and Restated as of January 1, 1997.  (Exhibit 4.2.24, 1996
                     NU Form 10-K, File No. 1-5324)

                     4.2.24.1   Amended and Restated Indenture of Trust between
                                Connecticut Development Authority and the
                                Trustee (CL&P Pollution Control Revenue Bond-
                                1996A Series), dated as of May 1, 1996, and
                                Amended and Restated as of January 1, 1997.
                                (Exhibit 4.2.24.1, 1996 NU Form 10-K, File
                                No. 1-5324)

                    #4.2.24.2   Standby Bond Purchase Agreement among CL&P,
                                Bank of New York as Purchasing Agent and the
                                Banks Named therein, dated October 24, 2000.

                     4.2.24.3   AMBAC Municipal Bond Insurance Policy issued
                                by the Connecticut Development Authority (CL&P
                                Pollution Control Revenue Bond-1996A Series),
                                effective January 23, 1997. (Exhibit 4.2.24.3,
                                1996 NU Form 10-K, File No. 1-5324)

             4.2.25  Amended and Restated Limited Partnership Agreement (CL&P
                     LP) among CL&P, NUSCO, and the persons who became limited
                     partners of CL&P LP in accordance with the provisions
                     thereof dated as of January 23, 1995 (MIPS).  (Exhibit
                     A.1 (Execution Copy), File No. 70-8451)

             4.2.26  Indenture between CL&P and Bankers Trust Company, Trustee
                     (Series A Subordinated Debentures), dated as of January 1,
                     1995 (MIPS).  (Exhibit B.1 (Execution Copy), File No.
                     70-8451)

             4.2.27  Payment and Guaranty Agreement of CL&P dated as of
                     January 23, 1995 (MIPS).  (Exhibit B.3 (Execution Copy),
                     File No. 70-8451)

       4.3   Public Service Company of New Hampshire

             4.3.1   First Mortgage Indenture dated as of August 15, 1978,
                     between PSNH and First Fidelity Bank, National
                     Association, New Jersey, now First Union National Bank,
                     Trustee, (Composite including all amendments to May 16,
                     1991).  (Exhibit 4.4.1, 1992 NU Form 10-K, File No.
                     1-5324)

                     4.3.1.1   Tenth Supplemental Indenture dated as of May 1,
                               1991, between PSNH and First Fidelity Bank,
                               National Association, now First Union National
                               Bank. (Exhibit 4.1, PSNH Current Report on
                               Form 8-K dated February 10, 1992, File No.
                               1-6392)

             4.3.3   Series A (Tax Exempt New Issue) PCRB Loan and Trust
                     Agreement dated as of May 1, 1991.  (Exhibit 4.2, PSNH
                     Current Report on Form 8-K dated February 10, 1992,
                     File No. 1-6392)

             4.3.4   Series B (Tax Exempt Refunding) PCRB Loan and Trust
                     Agreement dated as of May 1, 1991.  (Exhibit 4.3, PSNH
                     Current Report on Form 8-K dated February 10, 1992,
                     File No. 1-6392)

             4.3.5   Series C (Tax Exempt Refunding) PCRB Loan and Trust
                     Agreement dated as of May 1, 1991.  (Exhibit 4.4, PSNH
                     Current Report on Form 8-K dated February 10, 1992,
                     File No. 1-6392)

             4.3.6   Series D (Tax Exempt Refunding) Amended and Restated PCRB
                     Loan and Trust Agreement dated as of April 1, 1999.
                     (Exhibit 4.3.6, 1999 NU Form 10-K, File No. 1-5324)

             4.3.7   Series E (Tax Exempt Refunding) Amended and Restated PCRB
                     Loan and Trust Agreement dated as of April 14, 1999.
                     (Exhibit 4.3.7, 1999 NU Form 10-K, File No. 1-5324)

       4.4   Western Massachusetts Electric Company

             4.4.1   First Mortgage Indenture and Deed of Trust between WMECO
                     and Old Colony Trust Company, Trustee, dated as of
                     August 1, 1954.  (Exhibit 4.4.1, 1993 NU Form 10-K,
                     File No. 1-5324)

                     Supplemental Indentures thereto dated as of:

             4.4.2   October 1, 1954.  (Exhibit 4.4.2, 1998 NU Form 10-K,
                     File No. 1-5324)

             4.4.3   March 1, 1967.  (Exhibit 4.4.3, 1997 NU Form 10-K,
                     File No. 1-5324)

             4.4.4   July 1, 1973.  (Exhibit 2.10, File No. 2-68808)

             4.4.5   December 1, 1992. (Exhibit 4.15, File No. 33-55772)

             4.4.6   January 1, 1993. (Exhibit 4.5.13, 1992 NU Form 10-K,
                     File No. 1-5324)

             4.4.7   March 1, 1994. (Exhibit 4.4.12, 1993 NU Form 10-K,
                     File No. 1-5324)

             4.4.8   May 1, 1997. (Exhibit 4.11, File No. 33-51185)

             4.4.9   July 1, 1997.  (Exhibit 4.4.10, 1997 NU Form 10-K,
                     File No. 1-5324)

             4.4.10  May 1, 1998. (Exhibit 4.4.10, 1998 NU Form 10-K, File
                     No. 1-5324)

             4.4.11  May 1, 1998. (Exhibit 4.4.11, 1998 NU Form 10-K, File
                     No. 1-5324)

             4.4.12  Loan Agreement between Connecticut Development Authority
                     and WMECO, (Pollution Control Bonds - Series A, Tax Exempt
                     Refunding) dated as of September 1, 1993.  (Exhibit
                     4.4.13, 1993 NU Form 10-K, File No. 1-5324)

       4.5   North Atlantic Energy Corporation

             4.5.1   First Mortgage Indenture and Deed of Trust between NAEC
                     and United States Trust Company of New York, Trustee,
                     dated as of June 1, 1992.  (Exhibit 4.6.1, 1992 NU Form
                     10-K, File No. 1-5324)

             4.5.2   Term Credit Agreement dated as of November 9, 1995.
                     (Exhibit 4.5.2, 1995 NU Form 10-K, File No. 1-5324)

  10   Material Contracts

       10.1  Stockholder Agreement dated as of July 1, 1964, among the
             stockholders of CYAPC.  (Exhibit 10.1, 1994 NU Form 10-K, File
             No. 1-5324)

       10.2  Form of Power Contract dated as of July 1, 1964, between CYAPC
             and each of CL&P, HELCO, PSNH, and WMECO.  (Exhibit 10.2, 1994 NU
             Form 10-K, File No. 1-5324)

             10.2.1  Form of Additional Power Contract dated as of April 30,
                     1984, between CYAPC and each of CL&P, PSNH and WMECO.
                     (Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324)

             10.2.2  Form of 1987 Supplementary Power Contract dated as of
                     April 1, 1987, between CYAPC and each of CL&P, PSNH and
                     WMECO.  (Exhibit 10.2.6, 1987 NU Form 10-K, File No.
                     1-5324)

       10.3  Capital Funds Agreement dated as of September 1, 1964, between
             CYAPC and CL&P, HELCO, PSNH, and WMECO.  (Exhibit 10.3, 1994 NU
             Form 10-K, File No. 1-5324)

       10.4  Stockholder Agreement dated December 10, 1958, between YAEC and
             CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.4, 1993 NU Form 10-K,
             File No. 1-5324)

       10.5  Form of Amendment No. 3, dated as of April 1, 1985, to Power
             Contract between YAEC and each of CL&P, PSNH and WMECO, including
             a composite restatement of original Power Contract dated June 30,
             1959, and Amendment No. 1 dated April 1, 1975, and Amendment No. 2
             dated October 1, 1980.  (Exhibit 10.5, 1988 NU Form 10-K, File No.
             1-5324.)

             10.5.1  Form of Amendment No. 4 to Power Contract, dated May 6,
                     1988, between YAEC and each of CL&P, PSNH and WMECO.
                     (Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324)

             10.5.2  Form of Amendment No. 5 to Power Contract, dated June 26,
                     1989, between YAEC and each of CL&P, PSNH and WMECO.
                     (Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324)

             10.5.3  Form of Amendment No. 6 to Power Contract, dated July 1,
                     1989, between YAEC and each of CL&P, PSNH and WMECO.
                     (Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324)

             10.5.4  Form of Amendment No. 7 to Power Contract, dated
                     February 1, 1992, between YAEC and each of CL&P, PSNH
                     and WMECO. (Exhibit 10.5.4, 1993 NU Form 10-K, File
                     No. 1-5324)

      10.6   Stockholder Agreement dated as of May 20, 1968, among stockholders
             of MYAPC.  (Exhibit 10.6, 1997 NU Form 10-K, File No. 1-5324)

      10.7   Form of Power Contract dated as of May 20, 1968, between MYAPC
             and each of CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.7, 1997
             Form 10-K, File No. 1-5324)

             10.7.1  Form of Amendment No. 1 to Power Contract dated as of
                     March 1, 1983, between MYAPC and each of CL&P, PSNH and
                     WMECO.  (Exhibit 10.7.1, 1993 NU Form 10-K, File No.
                     1-5324)

             10.7.2  Form of Amendment No. 2 to Power Contract dated as of
                     January 1, 1984, between MYAPC and each of CL&P, PSNH
                     and  WMECO.  (Exhibit 10.7.2, 1993 NU Form 10-K, File
                     No. 1-5324)

             10.7.3  Form of Amendment No. 3 to Power Contract dated as of
                     October 1, 1984, between MYAPC and each of CL&P, PSNH and
                     WMECO.  (Exhibit No. 10.7.3, 1994 NU Form 10-K, File
                     No. 1-5324)

             10.7.4  Form of Additional Power Contract dated as of February 1,
                     1984, between MYAPC and each of CL&P, PSNH and WMECO.
                     (Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324)

      10.8   Capital Funds Agreement dated as of May 20, 1968, between MYAPC
             and CL&P, PSNH, HELCO, and WMECO. (Exhibit 10.8, 1997 NU Form
             10-K, File No. 1-5324)

             10.8.1  Amendment No. 1 to Capital Funds Agreement, dated as of
                     August 1, 1985, between MYAPC, CL&P, PSNH and WMECO.
                     (Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324)

      10.9   Sponsor Agreement dated as of August 1, 1968, among the sponsors
             of VYNPC. (Exhibit 10.9, 1997 NU Form 10-K, File No. 1-5324)

      10.10  Form of Power Contract dated as of February 1, 1968, between VYNPC
             and each of CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.10, 1997 NU
             Form 10-K, File No. 1-5324)

             10.10.1   Form of Amendment to Power Contract dated as of June 1,
                       1972, between VYNPC and each of CL&P, HELCO, PSNH and
                       WMECO.  (Exhibit 5.22, File No. 2-47038)

             10.10.2   Form of Second Amendment to Power Contract dated as of
                       April 15, 1983, between VYNPC and each of CL&P, PSNH
                       and WMECO.  (Exhibit 10.10.2, 1993 NU Form 10-K,
                       File No. 1-5324)

             10.10.3   Form of Third Amendment to Power Contract dated as of
                       April 24, 1985, between VYNPC and each of CL&P, PSNH and
                       WMECO.  (Exhibit No. 10.10.3, 1994 NU Form 10-K, File
                       No. 1-5324)

             10.10.4   Form of Fourth Amendment to Power Contract dated as of
                       June 1, 1985, between VYNPC and each of CL&P, PSNH and
                       WMECO.  (Exhibit No. 10.10.4, 1996 NU Form 10-K, File
                       No. 1-5324)

             10.10.5   Form of Fifth Amendment to Power Contract dated as of
                       May 6, 1988, between VYNPC and each of CL&P, PSNH and
                       WMECO.  (Exhibit 10.10.5, 1990 NU Form 10-K, File No.
                       1-5324)

             10.10.6   Form of Sixth Amendment to Power Contract dated as of
                       May 6, 1988, between VYNPC and each of CL&P, PSNH and
                       WMECO.  (Exhibit 10.10.6, 1990 NU Form 10-K, File No.
                       1-5324)

             10.10.7   Form of Seventh Amendment to Power Contract dated as of
                       June 15, 1989, between VYNPC and each of CL&P, PSNH and
                       WMECO.  (Exhibit 10.10.7, 1990 NU Form 10-K, File No.
                       1-5324)

             10.10.8   Form of Eighth Amendment to Power Contract dated as of
                       December 1, 1989, between VYNPC and each of CL&P, PSNH
                       and WMECO.  (Exhibit 10.10.8, 1990 NU Form 10-K, File
                       No. 1-5324)

             10.10.9   Form of Additional Power Contract dated as of
                       February 1, 1984, between VYNPC and each of CL&P, PSNH
                       and WMECO.  (Exhibit 10.10.9, 1993 NU Form 10-K, File
                       No. 1-5324)

      10.11  Capital Funds Agreement dated as of February 1, 1968, between
             VYNPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.11, 1997 NU
             Form 10-K, File No. 1-5324)

             10.11.1   Form of First Amendment to Capital Funds Agreement dated
                       as of March 12, 1968, between VYNPC and CL&P, HELCO,
                       PSNH, and WMECO. (Exhibit 10.11.1, 1997 NU Form 10-K,
                       File No. 1-5324)

             10.11.2   Form of Second Amendment to Capital Funds Agreement
                       dated as of September 1, 1993, between VYNPC and CL&P,
                       HELCO, PSNH, and WMECO. (Exhibit 10.11.2, 1993 NU Form
                       10-K, File No. 1-5324)

      10.12  PSA for the Millstone Power Station dated as of August 7, 2000,
             by and among CL&P and WMECO as Sellers and Dominion as Buyer.
             (Exhibit 10.1, 2000 NU Form 10-Q for the Quarter ended June 30,
             2000, File No. 1-5324)

      10.13  Amended and Restated Millstone Plant Agreement dated as of
             December 1, 1984, by and among CL&P, WMECO and NNECO.  (Exhibit
             10.12, 1994 NU Form 10-K, File No. 1-5324)

      10.14  Sharing Agreement dated as of September 1, 1973, with respect to
             1979 Connecticut nuclear generating unit (Millstone 3). (Exhibit
             6.43, File No. 2-50142)

             10.14.1   Amendment dated August 1, 1974, to Sharing Agreement -
                       1979 Connecticut Nuclear Unit.  (Exhibit 5.45, File No.
                       2-52392)

             10.14.2   Amendment dated December 15, 1975, to Sharing Agreement
                       - 1979 Connecticut Nuclear Unit.  (Exhibit 7.47, File
                       No. 2-60806)

             10.14.3   Amendment dated April 1, 1986, to Sharing Agreement -
                       1979 Connecticut Nuclear Unit.  (Exhibit 10.17.3, 1990
                       NU Form 10-K, File No. 1-5324)

      10.15  Agreement dated July 19, 1990, among NAESCO and Seabrook Joint
             owners with respect to operation of Seabrook. (Exhibit 10.53, 1990
             NU Form 10-K, File No. 1-5324)

      10.16  Sharing Agreement between CL&P, WMECO, HP&E, HWP, and PSNH dated
             as of June 1, 1992.  (Exhibit 10.17, 1992 NU Form 10-K, File No.
             1-5324)

      10.17  Rate Agreement by and between NUSCO, on behalf of NU, and the
             Governor of the State of New Hampshire and the New Hampshire
             Attorney General dated as of November 22, 1989. (Exhibit 10.44,
             1989 NU Form 10-K, File No. 1-5324)

             10.17.1   First Amendment to Rate Agreement dated as of
                       December 5, 1989.  (Exhibit 10.16.1, 1995 NU Form 10-K,
                       File No. 1-5324)

             10.17.2   Second Amendment to Rate Agreement dated as of
                       December 12, 1989.  (Exhibit 10.16.2, 1995 NU Form 10-K,
                       File No. 1-5324)

             10.17.3   Third Amendment to Rate Agreement dated as of
                       December 3, 1993.  (Exhibit 10.16.3, 1995 NU Form 10-K,
                       File No. 1-5324)

             10.17.4   Fourth Amendment to Rate Agreement dated as of
                       September 21, 1994.  (Exhibit 10.16.4, 1995 NU Form 10-K,
                       File No. 1-5324)

             10.17.5   Fifth Amendment to Rate Agreement dated as of
                       September 9, 1994.  (Exhibit 10.16.5, 1995 NU Form 10-K,
                       File No. 1-5324)

      10.18  Agreement to Settle PSNH Restructuring (Exhibit 10.2, 1999 NU Form
             10-Q for the Quarter Ended June 30, 1999, File No. 1-5324)

      10.19  Merger Settlement Agreement between NU, Con Edison and NHPUC dated
             as of December 6, 2000. (Exhibit O.1, to NU's U-1 Application,
             File No. 70-9711)

      10.20  Form of Seabrook Power Contract between PSNH and NAEC, as amended
             and restated.  (Exhibit 10.45, 1992 NU Form 10-K, File No. 1-5324)

      10.21  Agreement (composite) for joint ownership, construction and
             operation of New Hampshire nuclear unit, as amended through the
             November 1, 1990 twenty-third amendment.  (Exhibit No. 10.17, 1994
             NU Form 10-K, File No. 1-5324)

             10.21.1   Memorandum of Understanding dated November 7, 1988,
                       between PSNH and Massachusetts Municipal Wholesale
                       Electric Company (Exhibit 10.17, PSNH 1989 Form 10-K,
                       File No. 1-6392)

             10.21.2   Agreement of Settlement among Joint Owners dated as of
                       January 13, 1989.  (Exhibit 10.13.21, 1988 NU Form 10-K,
                       File No. 1-5324)

                       10.21.2.1  Supplement to Settlement Agreement, dated as
                                  of February 7, 1989, between PSNH and CMP.
                                  (Exhibit 10.18.1, PSNH 1989 Form 10-K, File
                                  No. 1-6392)

      10.22  Amended and Restated Agreement for Seabrook Project Disbursing
             Agent dated as of November 1, 1990.  (Exhibit 10.4.7, File
             No. 33-35312)

             10.22.1   Form of First Amendment to Exhibit 10.22. (Exhibit
                       10.4.8, File No. 33-35312)

             10.22.2   Form (Composite) of Second Amendment to Exhibit 10.22.
                       (Exhibit 10.18.2, 1993 NU Form 10-K, File No. 1-5324)

      10.23  Agreement dated November 1, 1974, for Joint Ownership,
             Construction and Operation of William F. Wyman Unit No. 4 among
             PSNH, CMP and other utilities.  (Exhibit 5.16, File No. 2-52900)

             10.23.1   Amendment to Exhibit 10.23 dated June 30, 1975. (Exhibit
                       5.48, File No. 2-55458)

             10.23.2   Amendment to Exhibit 10.23 dated as of August 16, 1976.
                       (Exhibit 5.19, File No. 2-58251)

             10.23.3   Amendment to Exhibit 10.23 dated as of December 31,
                       1978.  (Exhibit 5.10.3, File No. 2-64294)

      10.24  Form of Service Contract dated as of July 1, 1966, between each
             of NU, CL&P and WMECO and the Service Company.  (Exhibit 10.20,
             1993 NU Form 10-K, File No. 1-5324)

             10.24.1   Service Contract dated as of June 5, 1992, between PSNH
                       and the Service Company.  (Exhibit 10.12.4, 1992 NU Form
                       10-K, File No. 1-5324)

             10.24.2   Service Contract dated as of June 5, 1992, between NAEC
                       and the Service Company.  (Exhibit 10.12.5, 1992 NU Form
                       10-K, File No. 1-5324)

             10.24.3   Form of Service Agreement dated as of June 29, 1992,
                       between PSNH and NAESCO, and the First Amendment
                       thereto.  (Exhibits B.7 and B.7.1, File No. 70-7787)

             10.24.4   Form of Annual Renewal of Service Contract.  (Exhibit
                       10.20.3, 1993 NU Form 10-K, File No. 1-5324)

      10.25  Memorandum of Understanding between CL&P, HELCO, HP&E, HWP, and
             WMECO dated as of June 1, 1970, with respect to pooling of
             generation and transmission.  (Exhibit 13.32, File No. 2-38177)

             10.25.1   Amendment to Memorandum of Understanding between CL&P,
                       HELCO, HP&E, HWP, and WMECO dated as of February 2,
                       1982, with respect to pooling of generation and
                       transmission.  (Exhibit 10.21.1, 1993 NU Form 10-K,
                       File No. 1-5324)

             10.25.2   Amendment to Memorandum of Understanding between CL&P,
                       HELCO, HP&E, HWP, and WMECO dated as of January 1,
                       1984, with respect to pooling of generation and
                       transmission.  (Exhibit 10.21.2, 1994 NU Form 10-K,
                       File No. 1-5324)

             10.25.3   Second Amendment to Memorandum of Understanding between
                       CL&P, HELCO, HP&E, HWP, and WMECO dated as of June 8,
                       1999, with respect to pooling of generation and
                       transmission. (Exhibit 10.23.3, 1999 NU Form 10-K,
                       File No. 1-5324)

     *10.26  Restated NEPOOL Power Pool Agreement (restated by the sixty-ninth
             Agreement dated as of December 31, 2000, and includes the Restated
             NEPOOL Open Access Transmission Tariff

             10.26.1   Form of Interim ISO Agreement (Attachment to Thirty-
                       third Amendment to Exhibit 10.26 dated as of
                       December 31, 1996).  (Exhibit 10.23.6, 1996 NU Form
                       10-K, File No. 1-5324)

      10.27  Agreements among New England Utilities with respect to the Hydro-
             Quebec interconnection projects.  (See Exhibits 10(u) and 10(v);
             10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K
             of New England Electric System, File No. 1-3446.)

      10.28  Trust Agreement dated February 11, 1992, between State Street Bank
             and Trust Company of Connecticut, as Trustor, and Bankers Trust
             Company, as Trustee, and CL&P and WMECO, with respect to Niantic
             Bay Fuel Trust. (Exhibit 10.23, 1991 NU Form 10-K, File No.
             1-5324)

             10.28.1   Nuclear Fuel Lease Agreement dated as of February 11,
                       1992, between Bankers Trust Company, Trustee, as Lessor,
                       and CL&P and WMECO, as Lessees.  (Exhibit 10.23.1, 1991
                       NU Form 10-K, File No. 1-5324)

             10.28.2   Modification and Amendment to Nuclear Fuel Lease
                       Agreement dated as of May 17, 1999, between Bankers
                       Trust Company, Trustee, as Lessor, and CL&P and WMECO,
                       as Lessees. (Exhibit 10.26.2, 1999 NU Form 10-K,
                       File No. 1-5324)

      10.29  Simulator Financing Lease Agreement, dated as of May 2, 1985, by
             and between The Prudential Insurance Company of America and NNECO.
             (Exhibit No. 10.26, 1994 NU Form 10-K, File No. 1-5324)

      10.30  Lease dated as of April 14, 1992, between The Rocky River Realty
             Company (RRR) and NUSCO with respect to the Berlin, Connecticut
             headquarters (office lease).  (Exhibit 10.29, 1992 NU Form 10-K,
             File No. 1-5324)

             10.30.1   Lease dated as of April 14, 1992, between RRR and NUSCO
                       with respect to the Berlin, Connecticut headquarters
                       (project lease).  (Exhibit 10.29.1, 1992 NU Form 10-K,
                       File No. 1-5324)

      10.31  Lease and Agreement, dated as of December 15, 1988, by and between
             WMECO and Bank of New England, N.A., with BNE Realty Leasing
             Corporation of North Carolina.  (Exhibit 10.63, 1988 NU Form 10-K,
             File No. 1-5324.)

      10.32  Note Agreement dated April 14, 1992, by and between RRR and
             Purchasers named therein (Connecticut General Life Insurance
             Company, Life Insurance Company of North America, INA Life
             Insurance Company of New York, Life Insurance Company of Georgia),
             with respect to RRR's sale of $15 million of guaranteed senior
             secured notes due 2007 and $28 million of guaranteed senior
             secured notes due 2017.  (Exhibit 10.52, 1992 NU Form 10-K,
             File No. 1-5324)

             10.32.1   Amendment to Note Agreement, dated September 26, 1997.
                       (Exhibit 10.31.1, 1997 NU Form 10-K, File No. 1-5324)

             10.32.2   Note Guaranty dated April 14, 1992, by Northeast
                       Utilities pursuant to Note Agreement dated April 14,
                       1992, between RRR and Note Purchasers, for the benefit
                       of The Connecticut National Bank as Trustee, the
                       Purchasers and the owners of the notes.  (Exhibit
                       10.52.1, 1992 NU Form 10-K, File No. 1-5324)

                       10.32.2.1  Extension of Note Guaranty, dated
                                  September 26, 1997.  (Exhibit 10.31.2.1,
                                  1997 NU Form 10-K, File No. 1-5324)

             10.32.3   Assignment of Leases, Rents and Profits, Security
                       Agreement and Negative Pledge, dated as of April 14,
                       1992, among RRR, NUSCO and The Connecticut National Bank
                       as Trustee, securing notes sold by RRR pursuant to
                       April 14, 1992, Note Agreement. (Exhibit 10.52.2,
                       1997 NU Form 10-K, File No. 1-5324)

                       10.32.3.1  Modification of and Confirmation of
                                  Assignment of Leases, Rents and
                                  Profits, Security Agreement and Negative
                                  Pledge, dated as of September 26, 1997.
                                  (Exhibit 10.31.3.1, 1997 NU Form 10-K,
                                  File No. 1-5324)

             10.32.4   Purchase and Sale Agreement, dated July 28, 1997, by
                       and between RRR and the Sellers and Purchasers named
                       therein. (Exhibit 10.31.4, 1997 NU Form 10-K, File
                       No. 1-5324)

             10.32.5   Purchase and Sale Agreement, dated September 26, 1997,
                       by and between RRR and the Purchaser named therein.
                       (Exhibit 10.31.5, 1992 NU Form 10-K, File No. 1-5324)

      10.33  Master Trust Agreement dated as of September 2, 1986, between
             CL&P and WMECO and Colonial Bank as Trustee, with respect to
             reserve funds for Millstone 1 decommissioning costs.  (Exhibit No.
             10.32, 1996 NU Form 10-K, File No. 1-5324)

             10.33.1   Notice of Appointment of Mellon Bank, N.A. as Successor
                       Trustee, dated November 20, 1990, and Acceptance of
                       Appointment.  (Exhibit 10.41.1, 1992 NU Form 10-K, File
                       No. 1-5324)

      10.34  Master Trust Agreement dated as of September 2, 1986, between CL&P
             and WMECO and Colonial Bank as Trustee, with respect to reserve
             funds for Millstone 2 decommissioning costs. (Exhibit No. 10.33,
             1996 NU Form 10-K, File No. 1-5324)

             10.34.1   Notice of Appointment of Mellon Bank, N.A. as Successor
                       Trustee, dated November 20, 1990, and Acceptance of
                       Appointment.  (Exhibit 10.42.1, 1992 NU Form 10-K, File
                       No. 1-5324)

      10.35  Master Trust Agreement dated as of April 23, 1986, between CL&P
             and WMECO and Colonial Bank as Trustee, with respect to reserve
             funds for Millstone 3 decommissioning costs. (Exhibit No. 10.34,
             1996 NU Form 10-K, File No. 1-5324)

             10.35.1   Notice of Appointment of Mellon Bank, N.A. as Successor
                       Trustee, dated November 20, 1990, and Acceptance of
                       Appointment.  (Exhibit 10.43.1, 1992 NU Form 10-K,
                       File No. 1-5324)

      10.36  Rights Agreement dated as of February 23, 1999, between Northeast
             Utilities and NUSCO, as Rights Agent (Exhibit 1 to NU's
             Registration Statement on Form 8-A, filed on 4/12/99, File No.
             001-05324).

             10.36.1   Amendment to Rights Agreement (Exhibit 3 to NU's Current
                       Report on Form 8-K dated October 13, 1999, File No.
                       1-5324).

      10.37  NU Executive Incentive Plan, effective as of January 1, 1991.
             (Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324)

             10.37.1  NU Incentive Plan, effective as of January 1, 1998.
                      (Exhibit 10.35.1, 1998 NU Form 10-K, File No. 1-5324)

                      10.37.1.1  Amendment to Exhibit 10.37.1, effective as of
                                 February 23, 1999. (Exhibit 10.35.1.1, 1998 NU
                                 Form 10-K, File No. 1-5324)

      10.38  Supplemental Executive Retirement Plan for Officers of NU system
             companies, Amended and Restated effective as of January 1, 1992.
             (Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30,
             1992, File No. 1-5324)

             10.38.1   Amendment 1 to Exhibit 10.38, effective as of August 1,
                       1993.  (Exhibit 10.35.1, 1993 NU Form 10-K, File No.
                       1-5324)

             10.38.2  Amendment 2 to Exhibit 10.38, effective as of January 1,
                      1994.  (Exhibit 10.35.2, 1993 NU Form 10-K, File No.
                      1-5324)

             10.38.3  Amendment 3 to Exhibit 10.38, effective as of January 1,
                      1996.  (Exhibit 10.36.3, 1995 NU Form 10-K, File No.
                      1-5324)

      10.39  Special Severance Program for Officers of NU system companies, as
             adopted on July 15, 1998.  (Exhibit 10.37, 1998 NU Form 10-K,
             File No. 1-5324)

             10.39.1  Amendment to Exhibit 10.39, effective as of February 23,
                      1999.  (Exhibit 10.37.1, 1998 NU Form 10-K, File No.
                      1-5324)

             10.39.2  Amendment to Exhibit 10.39, effective as of September 14,
                      1999.  (Exhibit 10.3, 1999 NU Form 10-Q for the Quarter
                      Ended September 30, 1999, File No. 1-5324)

      10.40  Loan Agreement dated as of December 2, 1991, by and between NU
             and Mellon Bank, N.A., as Trustee, with respect to NU's loan of
             $175 million to an ESOP Trust.  (Exhibit 10.46, 1991 NU Form 10-K,
             File No. 1-5324)

             10.40.1  First Amendment to Exhibit 10.40 dated February 7, 1992.
                      (Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324)

             10.40.2  Loan Agreement dated as of March 19, 1992 by and between
                      NU and Mellon Bank, N.A., as Trustee, with respect to
                      NU's loan of $75 million to the ESOP Trust.  (Exhibit
                      10.49.1, 1992 NU Form 10-K, File No. 1-5324)

             10.40.3  Second Amendment to Exhibit 10.40 dated April 9, 1992.
                      (Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324)

      10.41  Employment Agreement with Michael G. Morris. (Exhibit 10.39, 1997
             NU Form 10-K, File No. 1-5324)

             10.40.1  Amendment to Exhibit 10.41, dated as of February 23,
                      1999. (Exhibit 10.39.1, 1998 NU Form 10-K, File No.
                      1-5324)

      10.42  Transition and Retirement Agreement with Bernard M. Fox.
             (Exhibit 10.39, 1996 NU Form 10-K, File No. 1-5324)

      10.43  Employment Agreement with Bruce D. Kenyon.  (Exhibit 10.40, 1996
             NU Form 10-K, File No. 1-5324)

             10.43.1  Amendment to Exhibit 10.43, dated as of January 13, 1998.
                      (Exhibit 10.41.1, 1998 NU Form 10-K, File No. 1-5324)

             10.43.2  Amendment to Exhibit 10.43, dated as of February 23, 1999.
                      (Exhibit 10.41.2, 1998 NU Form 10-K, File No. 1-5324)

             10.43.3  Amendment to Exhibit 10.43, dated as of March 21, 1999.
                      (Exhibit 10.1, 1999 NU Form 10-Q for the Quarter Ended
                      March 31,1999, File No. 1-5324)

             10.43.4  Amendment to Exhibit 10.43, dated as of May 14, 2000.
                      (Exhibit 10.3, 2000 NU Form 10-Q for the Quarter Ended
                      June 30, 2000, File No. 1-5324)

      10.44  Employment Agreement with John H. Forsgren.  (Exhibit 10.41, 1996
             NU Form 10-K, File No. 1-5324)

             10.44.1  Amendment to Exhibit 10.44, dated as of January 13, 1998.
                      (Exhibit 10.42.1, 1998 NU Form 10-K, File No. 1-5324)

             10.44.2  Amendment to Exhibit 10.44, dated as of February 23,
                      1999.  (Exhibit 10.42.2, 1998 NU Form 10-K, File No.
                      1-5324)

             10.44.3  Amendment to Exhibit 10.44, dated as of May 10, 1999.
                      (Exhibit 10.1, 1999 NU Form 10-Q for the Quarter Ended
                      March 31, 1999, File No. 1-5324)

             10.44.4  Amendment to Exhibit 10.44, dated as of September 14,
                      1999.  (Exhibit 10.4, 1999 NU Form 10-Q for the Quarter
                      Ended September 30, 1999, File No. 1-5324)

      10.45  Employment Agreement with Hugh C. MacKenzie.  (Exhibit 10.42,
             1996 NU Form 10-K, File No. 1-5324)

             10.45.1  Amendment to Exhibit 10.45, dated as of January 13,
                      1998.  (Exhibit 10.43.1, 1998 NU Form 10-K, File
                      No. 1-5324)

             10.45.2  Amendment to Exhibit 10.45, dated as of February 23,
                      1999.  (Exhibit 10.43.2, 1998 NU Form 10-K, File No.
                      1-5324)

         #@**10.45.3  Separation Agreement with Hugh C. MacKenzie, dated
                      as of December 20, 2000.

      10.46  Employment Agreement with Cheryl W. Grise.  (Exhibit 10.44,
             1998 NU Form 10-K, File No. 1-5324)

             10.46.1  Amendment to Exhibit 10.46, dated as of January 13, 1998.
                     (Exhibit 10.44.1, 1998 NU Form 10-K, File No. 1-5324)

             10.46.2  Amendment to Exhibit 10.46, dated as of February 23,
                      1999.  (Exhibit 10.44.2, 1998 NU Form 10-K, File No.
                      1-5324)

             10.46.3  Amendment to Exhibit 10.46, dated as of September 14,
                      1999.  (Exhibit 10.5, 1999 NU Form 10-Q for the Quarter
                      Ended September 30, 1999, File No. 1-5324)

      10.47  Northeast Utilities Deferred Compensation Plan for Trustees,
             Amended and Restated December 13, 1994.  (Exhibit 10.39, 1995 NU
             Form 10-K, File No. 1-5324)

      10.48  Deferred Compensation Plan for Officers of Northeast Utilities
             System Companies adopted September 23, 1986. (Exhibit 10.40, 1995
             NU Form 10-K, File No. 1-5324)

      10.49  Northeast Utilities Deferred Compensation Plan for Executives,
             adopted January 13, 1998.  (Exhibit A.5, File No. 70-09185)

      10.50  Reciprocal Support Agreement Among NNECO, NAESCO, CYAPC, YAEC,
             and NUSCO dated January 1, 1996.  (Exhibit 10.41, 1995 NU Form
             10-K, File No. 1-5324)

      10.51  Receivables Purchase and Sale Agreement (CL&P and CL&P Receivables
             Corporation [CRC]), dated as of September 30, 1997. (Exhibit
             10.49, 1997 NU Form 10-K, File No. 1-5324)

             10.51.1  Amendment to Exhibit 10.51 dated September 29, 1998.
                      (Exhibit 10.49.1, 1998 NU Form 10-K, File No. 1-5324)

             10.51.2  Amendment to Exhibit 10.51 dated September 28, 1999.
                      (Exhibit C.10.3, 1999 NU Form U5S, File No. 30-246)

            #10.51.3  Amendment to Exhibit 10.51 dated September 27, 2000.

             10.51.4  Purchase and Contribution Agreement (CL&P and CRC),
                      dated as of September 30, 1997.  (Exhibit 10.49.1,
                      1997 NU Form 10-K, File No. 1-5324)

     *10.52  Confirmation Agreement between Credit Suisse First Boston and
             NU, dated as of January 2, 2001.

      10.53  Confirmation Agreement between Bank One and NU, dated as of
             December 9, 1999.  (Exhibit 10.56, 1999 NU Form 10-K, File
             No. 1-5324)

            *10.53.1  First Amendment to Confirmation Agreement, dated as
                      of January 1, 2001.

     *10.54  Credit Agreement dated as of March 9, 2000, among NGC as
             Borrower and the Initial Lenders Named Therein as Initial Lenders
             and Citibank, N.A. as Administrative and Collateral Agent and
             Depository Bank.

            *10.54.1  Amendment No. 1 to Exhibit 10.54, dated as of July 27,
                      2000.

            *10.54.2  Amendment No. 2 to Exhibit 10.54, dated as of
                      November 22, 2000.

     *10.55  Tranche B Mortgage dated as of March 9, 2000, among NGC and
             Citibank, N.A.

      10.56  Indenture of Mortgage and Deed of Trust dated July 1, 1989,
             between Yankee and the Connecticut National Bank, as Trustee
             (Exhibit 4.7, 1990 Yankee Form 10-K, File No. 0-10721)

      10.57  Credit Agreement dated as of February 2, 1995, by and among
             Yankee and the Bank of New York as Agent (Exhibit 10.18, 1995
             Yankee Form 10-K, File No. 0-10721)

  13  Annual Report to Security Holders (Each of the Annual Reports is filed
      only with the Form 10-K of that respective registrant.)

      13.1   Annual Report of CL&P.

      13.2   Annual Report of WMECO.

      13.3   Annual Report of PSNH.

      13.4   Annual Report of NAEC.

 *21  Subsidiaries of the Registrant.




                     MANAGEMENT'S DISCUSSION AND ANALYSIS


                             FINANCIAL CONDITION


OVERVIEW

Northeast Utilities (NU or the company) reported year end 2000 earnings before
extraordinary items of $205.3 million, or $1.45 per share on a fully diluted
basis, compared with earnings of $34.2 million, or $0.26 per share, in 1999
and a loss of $146.8 million, or $1.12 per share in 1998.  Because of
extraordinary charges totaling $233.9 million after-tax, NU reported a net loss
of $28.6 million, or $0.20 per share, on a fully diluted basis, for the year.
These extraordinary charges are associated with the impacts of industry
restructuring and the discontinuation of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation."  The most significant write-off occurred at Public Service Company
of New Hampshire (PSNH) during the fourth quarter as a result of the "Agreement
to Settle PSNH Restructuring" (Settlement Agreement) with the State of
New Hampshire.

Increases in competitive energy subsidiaries' sales pushed total NU revenues to
a record $5.9 billion in 2000, up 31 percent from $4.47 billion in 1999.
Revenues were $3.77 billion in 1998.  The growth in competitive energy
subsidiaries' revenues more than offset a 5 percent retail rate decrease on
January 1, 2000, for customers of The Connecticut Light and Power Company
(CL&P) and a 5 percent rate reduction on October 1, 2000, for PSNH retail
customers.  Regulated retail electric sales increased by 0.8 percent in 2000,
as compared to 1999, primarily due to economic growth in NU's service
territories.  However, retail electric sales would have increased 1.9 percent
had it not been for mild summer temperatures.

Many areas of the Northeast Utilities system (NU system) contributed to the
better operating performance in 2000.  The most significant improvement
occurred at CL&P, NU's largest operating subsidiary.  CL&P's earnings totaled
$148.1 million in 2000, compared with a loss of $13.6 million in 1999 and
$195.7 million in 1998.  The 2000 results represented CL&P's first annual
profit since 1995.  CL&P benefited from the return to service of the Millstone
2 unit in May 1999 and the strong performance of the Millstone 2 and 3 units
in 2000.  Millstone 2 operated at a capacity factor of 82 percent in 2000,
while Millstone 3 operated at a capacity factor of virtually 100 percent in
2000.  However, management projects that CL&P's earnings will decline in 2001
as a result of the expected sale of CL&P's share of the Millstone units, other
rate adjustments and the pending resolution of the over-earnings docket.
Although CL&P's earnings are expected to decline, its return on equity is not
expected to be compromised.

NU's competitive energy subsidiaries achieved a significant improvement in
operating results in 2000 over 1999.  The competitive energy subsidiaries
contributed $13.6 million before extraordinary charges in 2000 toward NU's
consolidated earnings, compared with a net loss of $37 million in 1999.
During 2000, the Holyoke Water Power Company (HWP) recorded an extraordinary
charge of $19.7 million after-tax, or $0.14 per share, as a result of the
discontinuation of SFAS No. 71 for certain hydroelectric generation assets.

Absent the extraordinary charge, PSNH earned $67.6 million in 2000, compared
with $84.2 million in 1999 and $91.7 million in 1998.  North Atlantic Energy
Corporation (NAEC) earned $32.5 million in 2000, compared with $29.6 million
in 1999 and $29.5 million in 1998.  Operating earnings at PSNH and NAEC are
expected to decline significantly after the first quarter of 2001, as a result
of the retail rate reductions and capital redeployment that will accompany the
introduction of industry restructuring in New Hampshire.

Similar to CL&P, Western Massachusetts Electric Company (WMECO) also
experienced a significant improvement in operating results in 2000, primarily
as a result of the return to service of Millstone 2 and the absence of
restructuring charges.  In 2000, WMECO earned $35.3 million, compared with
$2.9 million in 1999 and a loss of $9.6 million in 1998.

NU projects earnings will be between $1.40 per share and $1.60 per share during
2001, not including significant nonrecurring gains and losses.

CONSOLIDATED EDISON, INC. MERGER

In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the
approvals needed to complete the merger announced in October 1999.
Shareholders from both companies approved the merger in April 2000, and all
state regulatory approvals were granted by the end of the year.  Additionally,
the Federal Energy Regulatory Commission (FERC) approved the merger in May
2000, the Nuclear Regulatory Commission approved the transaction in August
2000, and the United States Department of Justice approved the merger in
February 2001.  Necessary approval from the Securities and Exchange Commission
(SEC) was expected to be received in mid-March 2001.

On February 28, 2001, NU's Board of Trustees requested that Con Edison provide
reasonable assurance, in writing, that it intended to comply with the terms of
the definitive merger agreement between the two companies.  This included
assurances that Con Edison would consummate the pending merger at the price
set forth in the agreement promptly following the receipt of SEC approval.
The original request for assurance was to be received by March 2, 2001, however
that date was later extended to March 5, 2001.  On March 5, 2001, Con Edison
advised NU that it was not willing to close the merger on the agreed terms.
NU notified Con Edison that it was treating its refusal to proceed on the terms
set forth in the merger agreement as a repudiation and breach of the merger
agreement, and that NU would file suit to obtain the benefits of the
transaction as negotiated for NU shareholders.  On March 6, 2001, Con Edison
filed suit in the U.S. District Court for the Southern District of New York
(Southern District), seeking declaratory judgment that NU failed to satisfy
conditions precedent under the merger agreement.  On March 12, 2001, NU
filed suit against Con Edison in the Southern District seeking damages in
excess of $1 billion arising from Con Edison's breach of the merger
agreement.  NU cannot predict the outcome of this matter nor its effect on NU.

Under the terms of the proposed transaction, had it proceeded to closing, NU
shareholders would have received a base price of $25 per share, in a
combination of cash and Con Edison common stock, plus $0.0034 per share per
day, or approximately $0.10 per share per month, for each day that the merger
did not close after August 5, 2000.  Additionally, NU shareholders would have
received another $1 per share as a result of a recommendation by the
Connecticut Department of Public Utility Control's (DPUC) Utility Operations
Management Analysis Unit that the DPUC accept the results of the Millstone
auction that were announced on August 7, 2000.  The DPUC approved the sale in
January 2001.  The $25 per share base price, the $0.0034 per share per day
compensation and the additional $1 per share resulting from the Millstone
auction would have been subject to the collar mechanism described in the
merger proxy statement dated February 29, 2000, to the extent NU shareholders
received Con Edison stock.  Assuming that Con Edison's stock price had averaged
between $36 and $46 per share during the applicable pricing period, as defined,
NU shareholders would have received approximately $26.84 per share, were the
merger to have closed on April 10, 2001.

YANKEE ENERGY SYSTEM, INC. MERGER

On March 1, 2000, NU completed its acquisition of Yankee Energy System, Inc.
(Yankee), the parent company of Connecticut's largest natural gas distribution
company.  Under the terms of the merger, NU issued approximately 11.1 million
NU common shares and paid $261.4 million of cash to Yankee's shareholders.
As expected, the transaction was dilutive for NU earnings per share in 2000,
in part because the merger was closed at the end of the winter heating season
and near the end of Yankee's strongest earnings period.  Yankee lost $0.7
million during the 10 months of 2000 it has been part of the NU system.
Substantially better financial results are anticipated in 2001 during which
Yankee's operations will include the months of January and February.
Yankee anticipates filing a rate case in the second quarter of 2001.

On August 9, 2000, Yankee Gas Services Company (Yankee Gas) was ordered by the
DPUC to file a rate application.  This review of Yankee Gas' rates is required
under Connecticut law because four years have passed since its last rate
review.  In accordance with the most recent schedule approved by the DPUC,
Yankee Gas filed a cost of service study on February 14, 2001, which reflected
a historical test year ending September 30, 2000.  Yankee Gas has asked the
DPUC to approve a schedule that would call for Yankee Gas to file a letter of
intent in May 2001, and its full filing in July 2001.

LIQUIDITY

NU's net cash flows provided by operating activities declined slightly to
$578.4 million in 2000 compared with $614.2 million in 1999 and $663.3
million in 1998.  Industry restructuring in Connecticut which required
retail rate cuts reduced cash flows from operating activities.  Industry
restructuring resulted in a reduction of depreciation and amortization
expense of $382.8 million for the year, as compared to 1999.  Changes in
working capital, primarily a decrease in accrued taxes and an increase in
prepayments and other, also decreased cash flows from operating activities.
The increase in prepayments and other is primarily due to increases in
prepaid property taxes.  In addition, an increase in prepaid pension, which
is a component of other sources and uses, contributed to the decrease in
cash flows from operating activities.  Those factors were partially offset
by a $162.5 million increase in income after interest charges for the year
ended December 31, 2000, compared with the same period in 1999.  Cash flows
from operations, however, was more than adequate to meet the payment of the
NU system's common and preferred dividends ($71.6 million) and investments
in electric and other utility plant, nuclear fuel and nuclear
decommissioning trusts ($453.6 million).  The level of common dividends
totaled $57.4 million in 2000, as compared to $13.2 million paid in 1999
and no cash dividends in 1998.  This increase was a result of NU paying a
$0.10 per share quarterly common dividend for all of 2000, as compared to
only the fourth quarter of 1999.  The level of preferred dividends
decreased to $14.2 million in 2000, compared with $22.8 million in 1999 and
$26.4 million in 1998, reflecting NU's ongoing effort to reduce preferred
stock outstanding.  The NU system companies currently forecast construction
expenditures ranging from $395 million to $420 million for the year 2001.

The transfer of 1,289 megawatts (MW) of hydroelectric generation assets to
Northeast Generation Company (NGC), an affiliated company, from CL&P and WMECO
in March 2000, produced a significant source of cash for CL&P and WMECO.  NGC
financed the transfer with a short-term credit agreement collateralized by
the generation assets transferred and an equity infusion from NU.  CL&P and
WMECO used this cash to retire long-term debt,  preferred stock and to return
equity capital to the parent company.  Consolidated financing activities for
2000 included $812.3 million for the retirement of long-term debt and
preferred stock, compared with $864 million for 1999.

Aside from the NGC borrowings, the largest new financing for the NU system in
2000 was the borrowing of $263 million to finance the cash portion of the
Yankee acquisition.  NU refinanced that borrowing on February 28, 2001, when
it issued $263 million of two-year variable-rate notes.  Based on the initial
rate of those notes, NU expects to save more than $1 million annually as a
result of the refinancing.

The NU system also renewed a series of other borrowing facilities over the
course of 2000.  In November 2000, NU parent increased its revolving credit
agreement to $400 million from $350 million, primarily to meet Select Energy
Inc.'s (Select Energy) increased working capital needs to support a rapidly
growing level of business.  NU parent provides credit assurance in the form
of guarantees, letters of credit, performance guarantees, and other assurances
for the financial performance obligations of certain of its competitive energy
subsidiaries, particularly Select Energy.  Also in November 2000, CL&P and
WMECO reduced their revolving credit agreement to $350 million from $500
million to reflect lower borrowing needs post-restructuring, NAEC renewed its
$200 million term credit agreement for 364 days, and Yankee Gas renewed a
$60 million revolving credit agreement.  All of those facilities were renewed
with more favorable terms as a result of the NU system's improving credit
profile.  In April 2000, Moody's Investors Service (Moody's) upgraded its
credit ratings for NU, PSNH and NAEC, and in October 2000, Fitch IBCA (Fitch)
upgraded its credit ratings for PSNH and NAEC.  In January 2001, Moody's and
Standard and Poor's upgraded their credit ratings for NU, CL&P, PSNH, WMECO,
and NAEC, primarily as a result of the New Hampshire Supreme Court's decision
to uphold that state's restructuring plan, the anticipated sale of the
Millstone units and NU's general financial recovery.  In February 2001, Fitch
upgraded its credit ratings for NU, CL&P and WMECO.  These upgrades return
NU's unsecured debt to investment grade ratings for the first time in five
years and will save the NU system in excess of $4.7 million annually in
financing costs.

For further information regarding the NU system's borrowing facilities, see
Note 2, "Short-Term Debt," to the consolidated financial statements.

PSNH terminated its $75 million revolving credit agreement in April 1999 and
continues to fund its operations and capital program with cash on hand and
operating cash flows.  In August and September 2000, PSNH repaid $109.2 million
of variable-rate taxable pollution control bonds from cash on hand.  PSNH also
paid a $50 million common dividend to NU on October 2, 2000, PSNH's first
common dividend to NU since February 1997.  Despite those cash outflows,
PSNH maintained $115.1 million of cash on hand as of December 31, 2000.

On January 2, 2001, NU modified its forward share purchase arrangements for
approximately 10 million NU common shares.  To initially effect these
arrangements, the financial institutions (counterparties) purchased
approximately 10 million NU common shares on the open market in December 1999
and January 2000, in a total aggregate amount of $215 million at an average
price of $21.26.  The counterparties maintain ownership of the shares until
the transactions are settled.  NU will continue to accrue charges on the total
aggregate amount at LIBOR plus an agreed upon percentage per annum until the
transactions are settled.  These transactions can be settled in cash or NU
common shares at the company's discretion.  NU expects to repurchase the shares
from the counterparties in the first half of 2001 with proceeds from
restructuring.  However, if prior to the settlement date, NU's share price
falls below $18.06 per share, NU may be required to provide the counterparties
with additional collateral.  This amount has been classified as temporary
equity from stock forward on NU's consolidated balance sheets at
December 31, 2000 and 1999.

For further information regarding the forward share purchase arrangements,
see Note 1C, "Summary of Significant Accounting Policies - New Accounting
Standards," to the consolidated financial statements.

In 2001, NU expects to reduce the capitalization of its regulated electric
operating companies significantly as a result of continued asset sales and
securitization of stranded costs.  CL&P, PSNH and WMECO expect to receive
gross proceeds of $843.2 million, $26 million and $196.2 million,
respectively, as a result of the sale of their ownership interests in the
Millstone units to Dominion Resources, Inc. (Dominion).  This sale is
expected to close as early as the end of March 2001.  The cash proceeds are
expected to be used to repay subsidiary debt and capital lease obligations
and to return equity capital to the parent company.

By the end of 2002, PSNH expects to complete the auction of approximately
1,200 MW of fossil and hydroelectric generation assets, as well as CL&P's
and NAEC's share of the Seabrook Station nuclear unit (Seabrook).  PSNH's
restructuring settlement was predicated upon receiving approximately $400
million of net proceeds from those sales.  Cash proceeds will be used to
retire debt and to return equity capital to the parent company.

In November 2000, the DPUC approved CL&P's request to securitize an amount
not to exceed $1.55 billion of approved, eligible stranded costs, primarily
related to above-market purchased-power contracts and generation-related
regulatory assets.  CL&P plans to use approximately $400 million of those
proceeds to reduce debt with the remaining proceeds to be used to buydown
and buyout above-market purchased-power contracts and to return equity
capital to the parent company.  However, the Office of Consumer Counsel
(OCC) has appealed the securitization order to the Connecticut Superior
Court.  On March 1, 2001, CL&P and the OCC entered into an agreement to
settle this issue.  Under the agreement, pending DPUC approval, the OCC
agreed to withdraw its appeal of the securitization order and not take any
action that would affect the timing and amount of securitization financing
to be undertaken.  The DPUC approved the agreement on March 12, 2001.  The
OCC withdrew is appeal on March 16, 2001.  Securitization for CL&P is
expected to take place by the end of the first quarter 2001.

In September 2000, the New Hampshire Public Utilities Commission (NHPUC)
approved a comprehensive restructuring settlement that allows PSNH to
securitize up to $670 million of stranded costs.  In January 2001, the New
Hampshire Supreme Court upheld this restructuring order on appeal.  However,
one of the appellants indicated publicly it would request a review of the
New Hampshire Supreme Court decision by the United States Supreme Court.
Such a request must be filed by May 1, 2001.  Management believes that such
an appeal would have a low probability of success, but cannot determine what
effect it might have on the timing of the issuance of securitization bonds
and the implementation of customer choice in New Hampshire.  PSNH currently
expects to work with the State of New Hampshire to issue securitization bonds
early in the second quarter of 2001.  Cash proceeds would be combined with
cash on hand and used primarily to buydown the power contract between PSNH
and NAEC, retire debt at the two companies of approximately $300 million and
to return equity capital to the parent company from PSNH and NAEC of another
$375 million.

During February 2001, the Massachusetts Department of Telecommunications and
Energy (DTE) approved the securitization of $155 million of stranded costs
by WMECO.   A significant portion of those proceeds will be used to buyout
a purchased-power contract with the remainder used to retire WMECO's debt
and to return equity capital to the parent company.  Securitization for WMECO
is expected to take place early in the second quarter of 2001.

Should NU's regulated companies successfully complete the aforementioned asset
sales and securitization transactions, between 1999 and 2002, these regulated
companies would receive in excess of $5 billion of cash, including
approximately $1.4 billion previously received related to the sale and transfer
of CL&P's and WMECO's fossil and hydroelectric generation assets during 1999
and 2000.  In total, management currently expects these operating subsidiaries
to use these proceeds in four primary ways.  More than $2 billion would be used
to repay debt and preferred stock; more than $1 billion to buyout and buydown
high-cost purchased-power contracts; approximately $600 million to pay taxes
on gains from the sales of generation assets, and; approximately $1.2 billion
would be returned to NU from these operating companies.  Of that $1.2 billion,
CL&P and WMECO repurchased $390 million of their common stock from NU in
March 2000, the proceeds of which were immediately invested in NGC.  NU will
also use another $215 million of these proceeds to settle the aforementioned
forward share purchase arrangement.

RESTRUCTURING

As a result of industry restructuring, CL&P and WMECO stopped supplying power
directly to customers in 2000.  Instead, CL&P and WMECO became energy delivery
companies, delivering electricity to customers that is produced by other
companies and sometimes bought by customers through intermediaries.  In 2000,
customers in both states had the option of choosing alternative power suppliers
or relying on CL&P and WMECO to acquire the power for them through standard
offer service.

In 1999, under the oversight of the DPUC, CL&P secured four-year fixed-price
contracts with three suppliers to provide power to customers who choose
standard offer service.  CL&P is fully recovering from retail customers the
cost of buying power from these three standard offer suppliers and expects to
continue recovery through the expiration of the contracts on December 31, 2003.
As of January 1, 2000, Select Energy, an affiliated company, became responsible
for 50 percent of CL&P's standard offer load for the entire standard offer
period, or approximately 2,000 MW annually at peak.  Two other unaffiliated
suppliers became responsible for the balance of CL&P's standard offer load
also for the entire standard offer period.

CL&P and WMECO continue to generate power through either direct ownership of
generating plants, such as Millstone 2 and 3 and Seabrook, or through
purchased-power contracts.  CL&P and WMECO sold the capacity associated with
Millstone 2 and 3 and Seabrook to Select Energy and five unaffiliated
companies.  These contracts will expire on December 31, 2001.  The revenues
generated from these contracts are expected to recover CL&P's and WMECO's share
of the nuclear operating costs through the divestiture of the Millstone units.

In 2000, WMECO supplied power to standard offer customers at a rate of slightly
more than $0.045 per kilowatt-hour.  As a result of new one-year standard offer
supply contracts signed in December 2000, that rate will increase significantly
in 2001 to approximately $0.073 per kilowatt-hour.  In January 2001, the DTE
approved an average overall rate increase of approximately 17.4 percent for
WMECO standard offer customers, allowing WMECO to fully recover these increased
power procurement costs.  A higher rate was also approved for customers who
take default service from WMECO.  Under the new standard offer contracts,
three unaffiliated companies provide up to 630 MW of power to WMECO's standard
offer customers and one unaffiliated company serves WMECO's default load of up
to 70 MW through December 31, 2001.  WMECO renegotiates its standard offer
supply contracts on an annual basis.

Because of delays in implementing restructuring in New Hampshire, PSNH remained
a vertically integrated utility in 2000 with a fuel and purchased-power
adjustment charge.  For the first nine months following restructuring, PSNH
will meet the load requirements of those customers who do not choose an
alternative supplier (Transition Service or standard offer service) through its
own generation assets and purchased-power obligations.  Because PSNH's
generation assets are heavily weighted toward coal and nuclear generation, PSNH
is somewhat insulated from rising oil and natural gas prices.  Following that
initial nine-month period, PSNH expects to sell its generation assets and
acquire power for up to two years from third-party suppliers for customers who
remain on transition service.  Under the restructuring statute and the
conforming Settlement Agreement, PSNH will utilize its own generation
capability to provide Transition Service and Default Service for the Initial
Transition Service Period (ITSP, the first nine months after competition day).
At the conclusion of the ITSP, PSNH will be required to contract for Transition
Service for the remaining 24-month Transition Service period with third party
suppliers through a competitive bidding process administered by the NHPUC.
As part of its negotiation with state legislature, PSNH has agreed to expense
the first $7 million of costs for the first 12-month period following the ITSP,
if the cost of acquiring Transition Service exceeds the rate charged to
customers.  PSNH will be permitted to defer and recover, as unsecuritized
stranded costs, all Transition Service costs in excess of the initial
$7 million.

Provisions for Transition Service are but one element of Settlement Agreement
which during 2000 was approved by the New Hampshire House and Senate, signed
into law by the Governor of New Hampshire and approved by the NHPUC.  Other
provisions allow for issuing rate reduction bonds to securitize stranded costs;
implementing a rate decrease of approximately 15.5 percent, 5 percent of which
was implemented on a temporary basis on October 1, 2000; an after-tax write-off
of stranded costs in excess of $200 million, which was recorded in the fourth
quarter; selling NAEC's share of Seabrook no later than December 31, 2003, and;
fixing PSNH's delivery rates at $0.028 per kilowatt-hour for the first 33
months after the Settlement Agreement takes effect.  PSNH and NAEC will also
terminate the Seabrook Power Contracts upon the sale of Seabrook.
Restructuring is expected to take effect the first day of the month after PSNH
issues rate reduction bonds, which is anticipated to be May 1, 2001.

For further information regarding commitments and contingencies related to
restructuring, see Note 6A, "Commitments and Contingencies - Restructuring," to
the consolidated financial statements.

REGIONAL TRANSMISSION ORGANIZATION

Pursuant to FERC Order 888 (issued in April 1996), the NU system companies
operate their transmission system under an open access, nondiscriminatory
transmission tariff.

In December 1999, the FERC issued an order calling on all transmission owners
to voluntarily join Regional Transmission Organizations (RTOs) in order to
boost competition in electric markets.  In general, each of these organizations
would be an independent operator over all transmission facilities, and would
perform, among other functions, tariff administration, construction planning
and reliability management for the particular regional transmission system.
NU's active voting interest in such an organization would be limited to 5
percent under the proposal.

The NU system companies and other parties have appealed this order.  Of primary
concern to NU is the ratemaking authority granted to RTOs and its impact on the
ability of transmission owners to earn appropriate returns on their
transmission investment under the organizational structure and the minimum
functions proposed in the order.  The NU system companies were required to
participate in a collaborative process established by the FERC beginning in
March of 2000.  On January 16, 2001, NU along with the Independent System
Operator and five other New England transmission owning utilities filed a
proposal to establish a New England RTO.

COMPETITIVE ENERGY SUBSIDIARIES

NU's competitive energy subsidiaries engage in a variety of energy-related
activities, primarily in the competitive energy retail and wholesale commodity,
marketing and services fields.  In addition, these subsidiaries own and manage
1,521 MW of capacity, as well as provide services to the electric generation
market and large commercial and industrial customers in the Northeast.

NU's competitive energy subsidiaries contributed $13.6 million before
extraordinary items in 2000 towards NU's consolidated earnings, compared with a
net loss of $37 million in 1999.  In July 1999, NGC was announced as one of the
winning bidders of certain CL&P and WMECO hydroelectric generation assets.
Management expected this transaction to close by January 1, 2000.  The
transaction actually closed on March 14, 2000.  This transaction has allowed
the competitive energy subsidiaries to better balance their energy purchase and
supply commitments, improving profitability.  Since January 1, 2000, these
assets have been managed by the competitive energy subsidiaries and earnings of
$6.9 million have been included in the contributed earnings reported above of
$13.6 million.  As a result of the delayed closing, however, the $6.9 million
was recorded by CL&P and WMECO for the period from January 1, 2000 to March 14,
2000.  Unconsolidated revenues for the competitive energy subsidiaries were
$1.9 billion in 2000, compared with $648.9 million in 1999.  CL&P's standard
offer purchases from Select Energy, represented $651.9 million of total
competitive energy subsidiaries' revenues in 2000, which is eliminated in
consolidation.

NUCLEAR PLANT PERFORMANCE AND DIVESTITURE

Millstone:  The Millstone units completed one of their best years ever in 2000.
Millstone 2 operated at a capacity factor of 82 percent in  2000 and completed
a refueling outage in early June more than four days ahead of schedule.  The
40-day, 21-hour outage set a world record for a refueling that included a full
generator rewind.  Millstone 3 operated at virtually a 100 percent capacity
factor in 2000 and ran for 585 consecutive days before beginning a scheduled
refueling outage on February 3, 2001.  Millstone 3 is expected to return to
service by the end of the first quarter of 2001.  Along with the higher output,
NU benefited from lower costs.  NU's share of the nonfuel operation and
maintenance (O&M) expenses associated with Millstone 2 and 3 totaled $193.6
million in 2000, compared with $269.4 million in 1999.

On August 7, 2000, CL&P, WMECO and certain other joint owners reached an
agreement to sell substantially all of the Millstone units, located in
Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including
approximately $105 million for nuclear fuel.  Dominion has also agreed to
assume responsibility for decommissioning the three units and NU will transfer
to Dominion all funds in the Millstone decommissioning trust.  Additionally,
NU is obligated to top-off the decommissioning trust if its value does not
equal an agreed upon amount at closing.  That amount is pursuant to the
purchase and sale agreement (PSA) with Dominion, subject to adjustment for
delays in the closing of the sale and Millstone 1 not meeting the "cold and
dark" condition specified in the PSA.

If the transaction is consummated as proposed, CL&P and WMECO would receive
gross proceeds of approximately $843.2 million and $196.2 million on a pretax
basis for their respective ownership interests.  The proceeds from the sale of
these interests will be used to reduce the companies' stranded costs under
restructuring and the cash proceeds will be used to repay subsidiary debt and
capital lease obligations and to return equity capital to the parent company.
PSNH will receive $26 million on a pretax basis, which will be reflected as a
gain in accordance with the Settlement Agreement.

In preparation for the divestiture of the Millstone units, it was discovered
that two full-length irradiated fuel rods are missing.  The company believes
that the two rods remain stored in the Millstone 1 spent fuel pool or were
shipped in a shielded cask to a facility licensed to accept radioactive
material.  The company's investigation into the location of the two rods is
ongoing.  NU is responsible for any potential liabilities, which are not
determinable at this time, related to these missing fuel rods.

In connection with the prior settlement of Millstone 3 joint owner claims, if
the aforementioned transaction is consummated as proposed, the NU system will
record a pretax gain in excess of $150 million.

NU currently expects to close on the sale of Millstone as early as the end of
March 2001.  In anticipation of the sale of Millstone, in December 2000, NU
announced a voluntary separation program designed to reduce generation-related
support staff in 2001.  NU will reflect this program's cost in the first
quarter of 2001.

Seabrook:  Seabrook operated at a capacity factor of 78 percent in 2000.  The
unit began a scheduled refueling outage on October 21, 2000.  The outage was
extended by approximately two months as a result of the need to repair
extensive problems with a back-up diesel generator.  Seabrook returned to
service on January 29, 2001.

On December 15, 2000, NU filed its divestiture plan for Seabrook with the
NHPUC and the DPUC.  NU hopes to complete the sale in 2002.

In October 2000, NU reached an agreement with an unaffiliated joint owner, who
owns approximately 15 percent of Seabrook, to auction its share of the plant
with NU's share.  As part of the agreement, if the unaffiliated joint owner's
share of the proceeds from the sale of Seabrook is less than $87.2 million,
NU will provide up to $17.4 million to compensate for any shortfall.  NU also
will share in the benefits if the proceeds from the sale of that share of
Seabrook exceeds $87.2 million.  Additionally, under the agreement, NU will
top-off certain decommissioning obligations above a defined level.

Yankee Companies:  In 1999, the Vermont Yankee Nuclear Power Corporation
(VYNPC) agreed to sell its nuclear generating unit for $22 million to an
unaffiliated company.  Among other commitments, the acquiring company agreed
to assume the obligation to decommission the unit after it is taken out of
service, and the owners of VYNPC (including CL&P, WMECO and PSNH) agreed to
fund their shares of the decommissioning costs up to a negotiated amount.
Subsequent to the time that the agreement was executed, the original proposed
acquiring company increased its purchase price and three other unaffiliated
companies have indicated their interest in buying VYNPC's generating unit on
terms that have not been disclosed.  On February 14, 2001, the Vermont Public
Service Board dismissed the acquiring company's petition for approval and
VYNPC agreed to work with the Vermont regulators to develop an auction process
for the sale of the unit.  At present, CL&P, WMECO and PSNH expect that the
unit will be sold, but the identity of the owner and the terms of sale,
including price, future decommissioning obligations and future power purchase
obligations, are not known.

NUCLEAR DECOMMISSIONING

In connection with the aforementioned sale of the Millstone units, Dominion has
agreed to assume responsibility for decommissioning the Millstone units.

For further information regarding nuclear decommissioning, see Note 7, "Nuclear
Decommissioning and Plant Closure Costs," to the consolidated financial
statements.

SPENT NUCLEAR FUEL DISPOSAL COSTS

The United States Department of Energy (DOE) originally was scheduled to begin
accepting delivery of spent nuclear fuel in 1998.  However, delays in
confirming the suitability of a permanent storage site continually have
postponed plans for the DOE's long-term storage and disposal site.  Extended
delays or a default by the DOE could lead to consideration of costly
alternatives.  NU has the primary responsibility for the interim storage of
its spent nuclear fuel prior to divestiture of its nuclear units.

For further information regarding spent nuclear fuel disposal costs, see
Note 6D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs,"
to the consolidated financial statements.

COMPETITIVE ENERGY SUBSIDIARIES' MARKET AND OTHER RISKS

NU's competitive energy subsidiaries, as major providers of electricity and
natural gas, have certain market risks inherent in their business activities.
The competitive energy subsidiaries enter into contracts of varying length of
time to buy and sell energy commodities, primarily electricity, natural gas
and oil.  Market risk represents the risk of loss that may impact the
companies' financial statements due to adverse changes in commodity market
prices.  Through December 31, 2000, the competitive energy subsidiaries
increased their volume of electricity and gas marketing activities,
increasing these risks.

The competitive energy subsidiaries manage its portfolio of contracts and
assets to maximize value and minimize associated risks.  The length of
contracts to buy and sell energy vary in duration from daily/hourly to several
years.  At any point in time, the portfolio may be long (purchases exceeds
sales) or short (sales exceeds purchases).  Portfolio and risk management
disciplines are used to manage exposures to market risks.  Policies and
procedures have been established to manage these risks.  At market spot prices
in effect at December 31, 2000, the portfolio had a negative mark to market.
There is significant volatility in the energy commodities market and for
certain of the energy products and contracts there has been limited liquidity.
Management does not believe the ultimate settlement through physical delivery
of its energy portfolio will result in realization of this negative mark to
market.  The servicing of CL&P's standard offer load is a significant risk
for Select Energy, as this contract is for a 4-year period, ending December 31,
2003, at fixed prices.  Approximately 26 percent of the 2000 competitive
energy revenues came from this contract.  This risk is partially mitigated by
Select Energy entering into purchase contracts with other energy providers
to supply a portion of the standard offer requirement, including its contracts
with NGC, the purchase of 850 MW of output from the Millstone and Seabrook
units through 2001 and other resources in the energy marketplace.  Although
there can be no assurance that it will be able to do so, management believes
that Select Energy will be able to source its remaining load requirement at
reasonable prices.  If Select Energy is unable to source its remaining load
requirement at prices below the standard offer contract price as a result
of energy price increases, Select Energy's earnings would be adversely
impacted.  For further information see Note 8, "Market Risk and Risk Management
Instruments," to the consolidated financial statements.

OTHER MATTERS

Derivative Instruments and Market Risk:  Select Energy engages in the trading
of commodity derivatives which are accounted for using the mark-to-market
method under Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy
Trading and Risk Management Activities."  All other nontrading transactions
are recognized where settled.  For further information regarding these topics,
see Note 8, "Market Risk and Risk Management Instruments," to the consolidated
financial statements.

Environmental Matters:  NU is subject to environmental laws and regulations
structured to mitigate or remove the effect of past operations and to improve
or maintain the quality of the environment.  For further information regarding
environmental matters, see Note 6C, "Commitments and Contingencies -
Environmental Matters," to the consolidated financial statements.

Other Commitments and Contingencies:  For further information regarding other
commitments and contingencies, see Note 6, "Commitments and Contingencies," to
the consolidated financial statements.

Forward Looking Statements:  This discussion and analysis includes forward
looking statements, which are statements of future expectations and not facts
including, but not limited to, statements regarding future earnings,
refinancings, the use of proceeds from restructuring, and the recovery of
operating costs.  Words such as estimates, expects, anticipates, intends,
plans, and similar expressions identify forward looking statements.  Actual
results or outcomes could differ materially as a result of further actions by
state and federal regulatory bodies, competition and industry restructuring,
changes in economic conditions, changes in historical weather patterns,
changes in laws, developments in legal or public policy doctrines,
technological developments, and other presently unknown or unforeseen factors.

RESULTS OF OPERATIONS

The components of significant income statement variances for the past two years
are provided in the table below.

                                          Income Statement Variances
                                             (Millions of Dollars)

                               2000 over/(under) 1999   1999 over/(under) 1998
                               -----------------------------------------------
                                  Amount    Percent        Amount    Percent
                                  ------    -------        ------    -------


Operating Revenues                $1,405       31%          $704        19%

Operating Expenses:
Fuel, purchased and net
  interchange power                1,423       75            428        29
Other operation                       (6)      (1)            53         7
Maintenance                          (85)     (25)           (58)      (15)
Depreciation                         (62)     (21)           (31)       (9)
Amortization of regulatory
  assets, net                       (321)     (54)           393        (a)
Federal and state income taxes        49       27             99        (a)
Taxes other than income taxes        (22)      (9)             9         4
Gain on sale of utility plant        309      100           (309)        -
                                  ------      ---           ----       ---
Total operating expenses           1,285       31            584        16
                                  ------      ---           ----       ---

Operating income                     120       35            120        53
                                  ------      ---           ----       ---

Other Income:
Equity in earnings of regional
  nuclear generating and
  transmission companies              10       (a)            (7)      (59)
Nuclear related costs                 53       75             72        50
Other, net                            29       95            (19)       (a)
Other income taxes                   (14)     (17)             6         8
                                  ------      ---           ----       ---
Net other income                      78       (a)            52        69
Interest charges, net                 36       14             (5)       (2)
Preferred dividends of
  subsidiaries                        (9)     (38)            (4)      (14)
                                  ------      ---           ----       ---
Income before extraordinary line     171       (a)           181        (a)
                                  ------      ---           ----       ---
Extraordinary loss                  (234)      (a)            -          -
                                  ------      ---           ----       ---
Net (loss)/income                 $  (63)      (a)          $181        (a)
                                  ======      ===           ====       ===
(a) Percent greater than 100.


OPERATING REVENUES

Total revenues increased by $1,405 million or 31 percent in 2000, primarily due
to higher revenues from the competitive energy subsidiaries ($1,246 million of
which $669 million represents sales to other NU affiliates which are eliminated
in consolidation), the acquisition of Yankee  ($262 million) and higher
regulated wholesale revenues ($727 million of which $281 million represents
sales to other NU affiliates which are eliminated in consolidation), partially
offset by lower regulated retail revenues ($26 million).  The competitive
energy companies' increase is primarily due to higher revenues from Select
Energy as a result of new contracts for energy sales and services.  The
regulated wholesale revenue increase is primarily due to higher PSNH energy
sales and higher CL&P and WMECO revenue from the sale of the output from
Millstone 2 and 3.  The regulated retail decrease is primarily due to retail
rate reductions for CL&P and PSNH ($108 and $8 million, respectively),
partially offset by the impact of Millstone 2 being returned to CL&P's rate
base ($33 million), higher retail sales ($18 million), higher fuel revenues
for PSNH ($15 million) and higher retail revenue attributed to lower price
discounts in 2000 and changing customer mix ($24 million).  Regulated retail
kilowatt-hour sales increased by 0.8 percent in 2000.

Total revenues increased by $704 million or 19 percent in 1999, primarily due
to higher revenues from the competitive energy subsidiaries ($552 million),
higher regulated wholesale revenue ($107 million) and higher regulated retail
revenue ($45 million).  The competitive energy companies' increase is primarily
due to higher revenues from Select Energy as a result of new contracts for
energy sales.  The regulated wholesale revenue increase is primarily due to
higher energy sales and related capacity and transmission revenues.  The
regulated retail increase is primarily due to higher retail sales ($99 million)
and the impact of Millstone 2 and 3 being returned to CL&P's rate base
($13 million).  These retail increases were partially offset by retail rate
reductions for CL&P and WMECO ($55 and $12 million, respectively).  Regulated
retail kilowatt-hour sales increased by 3.8 percent.

FUEL, PURCHASED AND NET INTERCHANGE POWER

Fuel, purchased and net interchange power expense increased in 2000, primarily
due to higher purchased energy and capacity costs as a result of higher sales
for Select Energy ($1,053 million of which $660 million represents purchases
from NU other affiliates which are eliminated in consolidation), Yankee
expenses ($135 million) and higher purchased power for regulated subsidiaries
($235 million).

Fuel, purchased and net interchange power expense increased in 1999, primarily
due to higher purchased energy and capacity costs as a result of higher sales
for Select Energy ($521 million), regulated wholesale ($86 million) and
regulated retail ($36 million), partially offset by lower replacement power
costs due to the return to service of Millstone 2 and 3 ($215 million).

OTHER OPERATION AND MAINTENANCE

Other O&M expenses decreased $91 million in 2000, primarily due to lower
spending at the nuclear units due to better performance ($75 million), lower
expenses due to the sale of certain CL&P and WMECO fossil generation assets
($74 million), lower corporate support ($38 million), the decommissioning
status of Millstone 1 ($17 million), lower environmental-related costs ($12
million), and higher 1999 expenses associated with the Con Edison merger
($12 million), partially offset by the addition of Yankee ($60 million),
higher O&M expenses for the competitive energy businesses ($54 million),
primarily due to the business expansion, and higher distribution expenses
($29 million), including increased conservation program expenses.

Other O&M expenses decreased in 1999, primarily due to lower costs at the
Millstone units ($125 million), partially offset by the recognition of
environmental insurance proceeds in 1998 and additional environmental reserves
in 1999 ($30 million), higher transmission and power exchange expenses ($35
million), higher spending at Seabrook ($10 million) as a result of the
refueling outage, higher expenditures for HEC Inc. and the competitive energy
businesses ($32 million), and expenses associated with the Con Edison merger
($12 million) in 1999.

DEPRECIATION

Depreciation decreased in 2000, primarily due to the effect of discontinuing
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," for
the portion of the generation business for CL&P and WMECO and the resulting
reclassification of depreciable nuclear plant balances to regulatory assets
($84 million) and the sale of certain CL&P and WMECO fossil and hydroelectric
generation assets, partially offset by the addition of Yankee ($23 million).

Depreciation decreased in 1999, primarily due to the retirement of Millstone 1.

AMORTIZATION OF REGULATORY ASSETS, NET

Amortization of regulatory assets, net decreased in 2000, primarily due to the
amortization in 1999 as a result of the gain on the sale of fossil and
hydroelectric generation assets for CL&P and WMECO ($309 million) and changes
in amortization levels as a result of industry restructuring ($95 million).
These decreases were partially offset by higher amortization associated with
the reclassified nuclear plant balances ($84 million).

Amortization of regulatory assets, net increased in 1999, primarily due to the
increased amortization associated with the gain on the sale of CL&P's and
WMECO's fossil and hydroelectric generation assets ($309 million), the
amortization of CL&P's and WMECO's Millstone 1 remaining investment ($56
million) and the amortization of stranded nuclear plant balances reclassified
as regulatory assets ($23 million).

FEDERAL AND STATE INCOME TAXES

The consolidated statement of income taxes provides a reconciliation of actual
and expected tax expense.  The tax effect of temporary differences is accounted
for in accordance with the rate-making treatment of the applicable regulatory
commission.  In past years, this rate-making treatment has required the company
to provide the customers with a portion of the tax benefits associated with
accelerated tax depreciation in the year it is generated (flow-through
depreciation).  As these flow-through differences turn around, higher tax
expense is recorded.

Federal and state income tax expense increased approximately $63 million in
2000.  Significant variances responsible for this increase include higher
pretax earnings ($90 million) and lower adjustments to the tax valuation
allowance ($21 million).  Reduction in flow-through depreciation and
amortization ($51 million) partially offset the overall change.

Federal and state income tax expense increased approximately $93 million in
1999, primarily due to the significant increase in book pretax earnings.
Significant variances of other items include a $10 million increase in
flow-through depreciation turnaround and $4.6 million of nontax deductible
merger-related expenditures, offset by the elimination of a $23 million
deferred tax asset valuation reserve.

TAXES OTHER THAN INCOME TAXES

Taxes other than income taxes decreased in 2000, primarily due to lower
Connecticut gross earnings taxes ($12 million) and lower payroll taxes
($7 million).

Other income taxes increased in 1999, primarily due to higher local property
taxes ($3 million) and higher gross earnings taxes ($2 million).

GAIN ON SALE OF UTILITY PLANT

CL&P and WMECO recorded gains on the sale of their fossil and hydroelectric
generation assets in 1999.  A corresponding amount of amortization expense was
recorded.

EQUITY IN EARNINGS OF REGIONAL NUCLEAR GENERATING AND TRANSMISSION COMPANIES

Equity in earnings of regional nuclear generating and transmission companies
increased in 2000, primarily due to higher earnings from the Connecticut Yankee
Atomic Power Company (CYAPC) as a result of a rate settlement.

Equity in earnings of regional nuclear generating and transmission companies
decreased in 1999, primarily due to lower earnings from CYAPC.

NUCLEAR RELATED COSTS

Nuclear related costs in 2000 are comprised of a CL&P/WMECO settlement of
Millstone 3 joint owner litigation, net of insurance proceeds ($11 million),
and CL&P/WMECO regulatory settlements ($6 million).  In comparison, 1999 is
comprised of one-time charges related to the CL&P write-off of Connecticut
Municipal Electric Energy Cooperative (CMEEC) nuclear costs ($20 million),
the CL&P write-off of capital projects as a result of the Connecticut standard
offer decision ($11 million), the CL&P/WMECO settlement of Millstone 3 joint
owner litigation, net of insurance proceeds ($27 million), and WMECO return
disallowances on Millstone 1 plant ($13 million).  Recoverable costs in 1998
are comprised of the write-off of the Millstone 1 entitlement formerly held by
CMEEC ($28 million) and the write-off of unrecoverable Millstone 1 costs as a
result of the February 1999 CL&P rate decision ($115 million).

OTHER, NET

Other, net increased in 2000, primarily due to a one-time gain related to
Mode 1 Communications, Inc.'s investment in NEON Communications, Inc. ($17
million) and the loss in 1999 on the CL&P assignment of market-based contracts
to Select Energy ($15 million).

Other income/(loss), net decreased in 1999, primarily due to the PSNH
settlement with the New Hampshire Electric Cooperative ($6 million) and the
loss on the CL&P assignment of market-based contracts to Select Energy
($15 million).

INTEREST CHARGES, NET

Interest charges, net increased in 2000, primarily due to higher short-term
borrowings associated with the NGC asset transfer and the Yankee merger,
partially offset by lower long-term debt as a result of reacquisitions and
retirements.

Interest charges, net decreased in 1999, primarily due to lower long-term
debt as a result of reacquisitions and retirements.

PREFERRED DIVIDENDS

Preferred dividends decreased in 1999 and 2000, primarily due to lower
preferred stock outstanding.

EXTRAORDINARY LOSS

The extraordinary loss is primarily due to an after-tax write-off by PSNH
of approximately $225 million of stranded costs under an industry
restructuring settlement with the state of New Hampshire, combined with
other positive effects on PSNH from the discontinuance of SFAS No. 71 ($11
million) and a loss associated with the pending sale of certain HWP assets
($20 million).




                                   COMPANY REPORT


The accompanying consolidated financial statements of Northeast Utilities and
subsidiaries and other sections of this annual report were prepared by the
company.  These financial statements, which were audited by Arthur Andersen
LLP, were prepared in accordance with accounting principles generally accepted
in the United States using estimates and judgments, where required, and giving
consideration to materiality.

The company has endeavored to establish a control environment that encourages
the maintenance of high standards of conduct in all of its business activities.
The company maintains a system of internal controls over financial reporting,
which is designed to provide reasonable assurance to the company's management
and Board of Trustees regarding the preparation of reliable, published
financial statements.  The system is supported by an organization of trained
management personnel, policies and procedures, and a comprehensive program of
internal audits.  Through established programs, the company regularly
communicates to its management employees their internal control
responsibilities and policies prohibiting conflicts of interest.

The Audit Committee of the Board of Trustees is composed entirely of
independent trustees.  The Audit Committee meets periodically with management,
the internal auditors and the independent auditors to review the activities
of each and to discuss audit matters, financial reporting and the adequacy
of internal controls.

Because of inherent limitations in any system of internal controls, errors or
irregularities may occur and not be detected.  The company believes, however,
that its system of internal accounting controls and control environment provide
reasonable assurance that its assets are safeguarded from loss or unauthorized
use and that its financial records, which are the basis for the preparation
of all financial statements, are reliable.



                        REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
                        ----------------------------------------


To the Board of Trustees and
Shareholders of Northeast Utilities:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Northeast Utilities (a Massachusetts trust) and
subsidiaries as of December 31, 2000 and 1999, and the related consolidated
statements of income, comprehensive income, shareholders' equity, cash flows,
and income taxes for each of the three years in the period ended December 31,
2000.  These financial statements are the responsibility of the company's
management.  Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.  We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Northeast Utilities and
subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.


/s/ ARTHUR ANDERSEN LLP
    ARTHUR ANDERSEN LLP


Hartford, Connecticut
January 23, 2001 (except with
respect to the matters discussed
in Note 15, as to which the
date is March 13, 2001)




NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
                                                         For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)         2000          1999          1998
- ---------------------------------------------------------------------------------------------
<S>                                                  <C>           <C>           <C>
Operating Revenues................................. $  5,876,620  $  4,471,251  $  3,767,714
                                                    ------------- ------------- -------------
Operating Expenses:
Operation -
    Fuel, purchased and net interchange power......    3,321,226     1,898,314     1,470,200
    Other..........................................      850,192       855,917       803,419
Maintenance........................................      255,884       340,419       399,165
Depreciation.......................................      239,798       302,305       332,807
Amortization of regulatory assets, net.............      276,139       596,437       203,132
Federal and state income taxes.....................      230,031       180,883        82,332
Taxes other than income taxes......................      238,587       261,353       251,932
Gain on sale of utility plant......................         -         (308,914)         -
                                                    ------------- ------------- -------------
      Total operating expenses.....................    5,411,857     4,126,714     3,542,987
                                                    ------------- ------------- -------------
Operating Income...................................      464,763       344,537       224,727
                                                    ------------- ------------- -------------
Other Income/(Loss):
Equity in earnings of regional nuclear
     generating and transmission companies.........       14,586         5,034        12,420
Nuclear related costs .............................      (17,907)      (71,066)     (143,239)
Other, net.........................................       (1,689)      (30,855)      (12,225)
Minority interest in loss of subsidiary............       (9,300)       (9,300)       (9,300)
Income taxes.......................................       68,306        82,272        76,393
                                                    ------------- ------------- -------------
      Other income/(loss), net.....................       53,996       (23,915)      (75,951)
                                                    ------------- ------------- -------------
      Income before interest charges...............      518,759       320,622       148,776
                                                    ------------- ------------- -------------
Interest Charges:
Interest on long-term debt.........................      200,697       258,093       273,824
Other interest, net................................       98,605         5,558        (4,735)
                                                    ------------- ------------- -------------
      Interest charges, net........................      299,302       263,651       269,089
                                                    ------------- ------------- -------------
      Income/(loss) after interest charges.........      219,457        56,971      (120,313)

Preferred Dividends of Subsidiaries................       14,162        22,755        26,440
                                                    ------------- ------------- -------------
Income/(Loss) before extraordinary loss............      205,295        34,216      (146,753)

Extraordinary loss, net of tax benefit
   of $169,562.....................................     (233,881)         -             -
                                                    ------------- ------------- -------------
Net (Loss)/Income.................................. $    (28,586) $     34,216  $   (146,753)
                                                    ============= ============= =============
Basic and Fully Diluted (Loss)/Earnings Per
 Common Share:
   Income/(loss) before extraordinary loss......... $       1.45  $       0.26  $      (1.12)
   Extraordinary loss, net of tax benefit..........        (1.65)          -             -
                                                    ------------- ------------- -------------
Basic (Loss)/Earnings Per Common Share............. $      (0.20) $       0.26  $      (1.12)
                                                    ============= ============= =============

Basic Common Shares Outstanding (average)..........  141,549,860   131,415,126   130,549,760
                                                    ============= ============= =============
Fully Diluted Common Shares Outstanding (average)..  141,967,216   132,031,573   130,549,760
                                                    ============= ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
                                                         For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars)                                   2000          1999          1998
- ---------------------------------------------------------------------------------------------
<S>                                                      <C>            <C>         <C>
Net (Loss)/Income.................................. $    (28,586) $     34,216  $   (146,753)
                                                    ------------- ------------- -------------
Other comprehensive income, net of tax:
Foreign currency translation adjustments...........         -                1          -
Unrealized gains on securities.....................          245           118         2,019
Minimum pension liability adjustments..............         -             -             (613)
                                                    ------------- ------------- -------------
    Other comprehensive income, net of tax.........          245           119         1,406
                                                    ------------- ------------- -------------
Comprehensive (Loss)/Income........................ $    (28,341) $     34,335  $   (145,347)
                                                    ============= ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
                                                                   At December 31,
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)                                           2000           1999
- ----------------------------------------------------------------------------------------
<S>                                                            <C>            <C>
ASSETS
- ------
Utility Plant, at cost:
  Electric................................................  $  9,370,176   $  9,185,272
  Gas and other...........................................       861,727        226,002
                                                            -------------  -------------
                                                              10,231,903      9,411,274
     Less: Accumulated provision for depreciation.........     7,041,279      6,088,310
                                                            -------------  -------------
                                                               3,190,624      3,322,964
  Unamortized PSNH acquisition costs......................          -           324,437
  Construction work in progress...........................       228,330        177,504
  Nuclear fuel, net.......................................       128,261        122,529
                                                            -------------  -------------
     Total net utility plant..............................     3,547,215      3,947,434
                                                            -------------  -------------

Other Property and Investments:
  Nuclear decommissioning trusts, at market...............       740,058        711,910
  Investments in regional nuclear generating
    companies, at equity..................................        62,477         81,503
  Other, at cost..........................................       137,291         94,768
                                                            -------------  -------------
                                                                 939,826        888,181
                                                            -------------  -------------

Current Assets:
  Cash and cash equivalents...............................       200,017        255,154
  Investments in securitizable assets.....................        98,146        107,620
  Receivables, less accumulated provision for
    uncollectible accounts of $12,500 in 2000 and
    $4,895 in 1999........................................       472,863        310,190
  Unbilled revenues.......................................       121,090         75,728
  Fuel, materials and supplies, at average cost...........       163,711        172,973
  Recoverable energy costs, net - current portion.........          -            73,721
  Prepayments and other...................................        94,528         75,225
                                                            -------------  -------------
                                                               1,150,355      1,070,611
                                                            -------------  -------------

Deferred Charges:
  Regulatory assets.......................................     3,910,801      3,642,439
  Unamortized debt expense................................        33,475         39,192
  Goodwill and other purchased intangible assets..........       324,389         23,542
  Prepaid pensions........................................       139,546            669
  Other ..................................................       171,542         75,984
                                                            -------------  -------------
                                                               4,579,753      3,781,826
                                                            -------------  -------------

Total Assets..............................................  $ 10,217,149   $  9,688,052
                                                            =============  =============
</TABLE>
The accompanying notes are an integral part of these financial statements.



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
                                                                   At December 31,
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)                                           2000           1999
- ----------------------------------------------------------------------------------------
<S>                                                            <C>           <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
  Common shares, $5 par value - authorized 225,000,000
    shares; 148,781,861 shares issued and 143,820,405
    shares outstanding in 2000 and 137,393,829 shares
    issued and 131,870,284 shares outstanding in 1999.....  $    693,345   $    636,405
  Capital surplus, paid in................................       927,059        776,290
  Temporary equity from stock forward.....................       215,000        215,000
  Deferred contribution plan - employee stock
    ownership plan........................................      (114,463)      (127,725)
  Retained earnings.......................................       495,873        581,817
  Accumulated other comprehensive income..................         1,769          1,524
                                                            -------------  -------------
     Total common shareholders' equity....................     2,218,583      2,083,311
Preferred stock not subject to mandatory redemption.......       136,200        136,200
Preferred stock subject to mandatory redemption...........        15,000        121,289
Long-term debt............................................     2,029,593      2,372,341
                                                            -------------  -------------
     Total capitalization.................................     4,399,376      4,713,141
                                                            -------------  -------------

Minority Interest in Consolidated Subsidiary..............       100,000        100,000
                                                            -------------  -------------

Obligations Under Capital Leases..........................        47,234         62,824
                                                            -------------  -------------

Current Liabilities:
  Notes payable to banks..................................     1,309,977        278,000
  Long-term debt and preferred stock - current portion....       340,041        503,315
  Obligations under capital leases - current portion......       112,645        118,469
  Accounts payable........................................       538,983        347,321
  Accrued taxes...........................................        54,088        158,684
  Accrued interest........................................        41,131         37,904
  Other...................................................       144,931        126,768
                                                            -------------  -------------
                                                               2,541,796      1,570,461
                                                            -------------  -------------

Deferred Credits and Other Long-term Liabilities:
  Accumulated deferred income taxes.......................     1,585,494      1,688,114
  Accumulated deferred investment tax credits.............       153,155        140,407
  Decommissioning obligation - Millstone 1................       692,560        702,351
  Deferred contractual obligations........................       244,608        358,387
  Other...................................................       452,926        352,367
                                                            -------------  -------------
                                                               3,128,743      3,241,626
                                                            -------------  -------------
Commitments and Contingencies (Note 6)

Total Capitalization and Liabilities......................  $ 10,217,149   $  9,688,052
                                                            =============  =============
</TABLE>
The accompanying notes are an integral part of these financial statements.



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
                                                                         Accum-
                                                     Deferred            ulated
                                           Capital   Contribu-           Other
                                  Common   Surplus,    tion    Retained  Compre-
                                  Shares   Paid In     Plan-   Earnings  hensive
(Thousands of Dollars)             (a)       (a)       ESOP       (b)    Income   Total
- ------------------------------------------------------------------------------------------
<S>                              <C>      <C>        <C>       <C>       <C>    <C>
Balance as of
 January 1, 1998................$684,211 $  932,494 $(154,141)$ 707,522 $   (1)$2,170,085
- ------------------------------------------------------------------------------------------
  Net loss for 1998.............                               (146,753)         (146,753)
  Issuance of 189,094 common
    shares, $5 par value........     945      1,714                                 2,659
  Allocation of benefits-ESOP...             (4,769)   13,522                       8,753
  Unearned stock compensation...               (537)                                 (537)
  Capital stock expenses, net...              3,560                                 3,560
  Gain on equity investment.....              8,140                                 8,140
  Gain on repurchase of
    preferred stock.............                 59                                    59
  Other comprehensive income....                                         1,406      1,406
- ------------------------------------------------------------------------------------------
Balance as of
  December 31, 1998............. 685,156    940,661  (140,619)  560,769  1,405  2,047,372
- ------------------------------------------------------------------------------------------
  Net income for 1999...........                                 34,216            34,216
  Cash dividends on common
    shares-$0.10 per share......                                (13,168)          (13,168)
  Issuance of 362,565 common
    shares, $5 par value........   1,813      3,505                                 5,318
  Allocation of benefits-ESOP...             (3,053)   12,894                       9,841
  Unearned stock compensation...             (1,194)                               (1,194)
  Capital stock expenses, net...                807                                   807
  Other comprehensive income....                                           119        119
- ------------------------------------------------------------------------------------------
Balance as of
  December 31, 1999............. 686,969    940,726  (127,725)  581,817  1,524  2,083,311
- ------------------------------------------------------------------------------------------
  Net loss for 2000.............                                (28,586)          (28,586)
  Cash dividends on common
    shares-$0.40 per share......                                (57,358)          (57,358)
  Issuance of 11,388,032 common
    shares, $5 par value........  56,940    164,443                               221,383
  Common share repurchase
    transaction fee.............            (13,786)                              (13,786)
  Allocation of benefits-ESOP...             (1,617)   13,262                      11,645
  Redemption of
    preferred stock.............               (749)                                 (749)
  Capital stock expenses, net...              2,478                                 2,478
  Other comprehensive income....                                           245        245
- ------------------------------------------------------------------------------------------
Balance as of
  December 31, 2000.............$743,909 $1,091,495 $(114,463)$ 495,873 $1,769 $2,218,583
- ------------------------------------------------------------------------------------------

(a) In conjunction with NU's forward share purchase arrangement, 10,112,879 shares or
    $50.6 million and $164.4 million, respectively, have been reclassified from
    Common Shares and Capital Surplus, Paid In, at December 31, 2000 and 1999, to
    Temporary Equity from Stock Forward.

(b) Certain consolidated subsidiaries have dividend restrictions imposed by their
    long-term debt agreements.  These restrictions also limit the amount of retained
    earnings available for NU common dividends.  At December 31, 2000, retained earnings
    available for payment of dividends totaled $180.1 million.  Pursuant to certain
    credit agreements, NU may not declare or make distributions in an amount not to
    exceed $60 million for any twelve month period.
</TABLE>

The accompanying notes are an integral part of these financial statements.




NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
                                                                For the Years Ended December 31,
- ------------------------------------------------------------------------------------------------
(Thousands of Dollars)                                              2000       1999       1998
- ------------------------------------------------------------------------------------------------
<S>                                                             <C>        <C>        <C>
Operating Activities:
  Income/(loss) after interest charges......................... $ 219,457  $  56,971  $(120,313)
  Adjustments to reconcile to net cash
   provided by operating activities:
    Depreciation...............................................   239,798    302,305    332,807
    Deferred income taxes and investment tax credits, net......   (16,117)  (183,356)    23,502
    Amortization of regulatory assets, net.....................   276,139    596,437    203,132
    Net (deferral)/amortization of recoverable energy costs....   (30,603)    44,526     38,356
    Nuclear related costs......................................    17,907     71,066    143,239
    Gain on sale of utility plant..............................      -      (308,914)      -
    Net other sources/(uses) of cash...........................   (88,549)   (79,232)    53,346
  Changes in working capital:
    Receivables and unbilled revenues, net.....................  (104,868)  (106,566)   (27,553)
    Fuel, materials and supplies...............................    12,450     29,688     10,060
    Accounts payable...........................................   171,148      8,709    (64,258)
    Accrued taxes..............................................  (128,107)   107,929      4,739
    Investments in securitizable assets........................     9,474     74,498     48,787
    Other working capital (excludes cash)......................       254        157     17,424
                                                                ---------- ---------- ----------
Net cash flows provided by operating activities................   578,383    614,218    663,268
                                                                ---------- ---------- ----------
Investing Activities:
  Investments in plant:
    Electric, gas and other utility plant......................  (352,736)  (287,081)  (217,009)
    Nuclear fuel...............................................   (61,286)   (42,471)   (17,026)
                                                                ---------- ---------- ----------
  Net cash flows used for investments in plant.................  (414,022)  (329,552)  (234,035)
  Investments in nuclear decommissioning trusts................   (39,550)   (74,231)   (75,551)
  Investment in competitive energy assets......................      -       (23,542)      -
  Net proceeds from the sale of utility plant..................      -       565,436       -
  Other investment activities, net.............................   (28,478)    13,084     14,342
  Payment for the purchase of Yankee, net of cash acquired.....  (260,347)      -          -
                                                                ---------- ---------- ----------
Net cash flows (used in)/provided by investing activities......  (742,397)   151,195   (295,244)
                                                                ---------- ---------- ----------
Financing Activities:
  Issuance of common shares....................................     4,269      5,318      2,659
  Issuance of long-term debt...................................    26,477        200        275
  Net increase/(decrease) in short-term debt...................   961,977    248,000    (20,000)
  Reacquisitions and retirements of long-term debt.............  (685,555)  (817,759)  (269,555)
  Reacquisitions and retirements of preferred stock............  (126,771)   (46,250)   (62,211)
  Cash dividends on preferred stock............................   (14,162)   (22,755)   (26,440)
  Cash dividends on common shares..............................   (57,358)   (13,168)      -
                                                                ---------- ---------- ----------
Net cash flows provided by/(used in) financing activities......   108,877   (646,414)  (375,272)
                                                                ---------- ---------- ----------
Net (decrease)/increase in cash and cash equivalents...........   (55,137)   118,999     (7,248)
Cash and cash equivalents - beginning of period................   255,154    136,155    143,403
                                                                ---------- ---------- ----------
Cash and cash equivalents - end of period...................... $ 200,017  $ 255,154  $ 136,155
                                                                ========== ========== ==========
Supplemental schedule of noncash investing and financing activities:

In conjuction with the Yankee acquisition on March 1, 2000, common stock was issued
and debt was assumed as follows:
  Fair value of assets acquired, net of liabilites assumed      $ 712,484
  Cash paid                                                      (261,370)
  NU common stock issued                                         (217,114)
                                                                ----------
                                                                $ 234,000
                                                                ==========
Supplemental Cash Flow Information:
Cash paid during the year for:
  Interest, net of amounts capitalized......................... $ 269,735  $ 266,823  $ 238,990
                                                                ========== ========== ==========
  Income taxes................................................. $ 253,383  $  86,183  $  19,454
                                                                ========== ========== ==========
Increase in obligations:
  Niantic Bay Fuel Trust and other capital leases.............. $   8,067  $   5,865  $  12,583
                                                                ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.


<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------
                                                                                            At December 31,
- ----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)                                                                     2000         1999
- ----------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>          <C>
Common Shareholders' Equity (a)                                                         $2,218,583   $2,083,311
Cumulative Preferred Stock of Subsidiaries:
   $25 par value - authorized 36,600,000 shares at December 31, 2000 and 1999;
      1,630,722 shares outstanding in 2000 and 2,720,000 shares outstanding in 1999
   $50 par value - authorized 9,000,000 shares at December 31, 2000 and 1999;
      2,324,000 shares outstanding in 2000 and 4,314,774 shares outstanding in 1999
   $100 par value - authorized 1,000,000 shares at December 31, 2000 and 1999;
      200,000 shares outstanding in 2000 and 1999
</TABLE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------
                                              Current          Current
                                            Redemption         Shares
Dividend Rates                              Prices (b)       Outstanding
- ----------------------------------------------------------------------------------------------------------------
<S>                                      <C>                  <C>                          <C>          <C>
Not Subject to Mandatory Redemption:
 $50 par value - $1.90 to $3.28          $50.50 to $54.00     2,234,000                    116,200      116,200
$100 par value - $7.72                   $103.51                200,000                     20,000       20,000
                                                                                         ---------    ---------
Total Preferred Stock Not Subject to Mandatory Redemption                                  136,200      136,200
                                                                                         ---------    ---------
Subject to Mandatory Redemption:  (c)
$25 par value - $1.90 to $2.65           $25.00 to $25.26     1,630,722                     40,768       68,000
$50 par value - $2.65 to $3.615                  -                 -                          -          99,539
                                                                                         ---------    ---------
Total Preferred Stock Subject to Mandatory Redemption                                       40,768      167,539
Less:  Preferred Stock to be Redeemed Within One Year                                       25,768       46,250
                                                                                         ---------    ---------
Preferred Stock Subject to Mandatory Redemption, Net                                        15,000      121,289
                                                                                         ---------    ---------

</TABLE>
<TABLE>
Long-Term Debt:  (d)
<CAPTION>
First Mortgage Bonds -
Maturity                Interest Rates
- ----------------------------------------------------------------------------------------------------------------
<S>                     <C>                                                              <C>           <C>
  2000                  5.75% to 6.875%...................................                    -         159,000
  2001                  7.375% to 7.875%..................................                 220,000      220,000
  2002                  7.75% to 9.05%....................................                 375,000      489,150
  2005                  6.75%.............................................                  20,000         -
  2009-2012             6.20% to 7.19%....................................                  80,000         -
  2019-2024             7.375% to 10.07%..................................                 313,050       325,000
                                                                                       -----------    ----------
       Total First Mortgage Bonds.........................................               1,008,050     1,193,150
                                                                                       -----------    ----------
Other Long-Term Debt -
Pollution Control Notes and Other Notes - (e)
  2000                  Adjustable Rate and 7.67%.........................                    -          206,011
  2003-2006             6.24% to 8.58%....................................                 139,600       158,000
  2013-2018             Adjustable Rate and 5.90%.........................                  33,400        33,400
  2020                  Adjustable Rate...................................                  15,300        15,300
  2021-2022             Adjustable Rate and 5.85% to 7.65%................                 443,285       552,485
  2028                  5.85% to 5.95%....................................                 369,300       369,300
  2031                  Adjustable Rate...................................                  62,000        62,000
                                                                                        ----------    ----------
       Total Pollution Control Notes and Other Notes......................               1,062,885     1,396,496
Fees and interest due for spent nuclear fuel disposal costs...............                 240,303       226,463
Other.....................................................................                  38,978        15,346
                                                                                        ----------    ----------
Total Other Long-Term Debt................................................               1,342,166     1,638,305
                                                                                        ----------    ----------
Unamortized premium and discount, net.....................................                  (6,350)       (2,049)
                                                                                        ----------    ----------
Total Long-Term Debt......................................................               2,343,866     2,829,406
Less:  Amounts due within one year........................................                 314,273       457,065
                                                                                        ----------    ----------
Long-Term Debt, Net.......................................................               2,029,593     2,372,341
                                                                                        ----------    ----------
Total Capitalization......................................................              $4,399,376    $4,713,141
                                                                                        ==========    ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.



              NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION


(a) On January 2, 2001, NU modified its forward share purchase arrangements
for approximately 10 million NU common shares.  To initially effect these
arrangements, the financial institutions (counterparties) purchased
approximately 10 million NU common shares on the open market in December 1999
and January 2000, in a total aggregate amount of $215 million, at an average
price of $21.26.  The counterparties maintain ownership of the shares until
the transactions are settled.  NU will continue to accrue charges on the total
aggregate amount at LIBOR plus an agreed upon percentage per annum, until the
transactions are settled.  These transactions can be settled in cash or NU
common shares at the company's discretion.  NU expects to repurchase the shares
from the counterparties in the first half of 2001 with the proceeds from
restructuring.  This amount has been classified as temporary equity from stock
forward on NU's consolidated balance sheets at December 31, 2000 and 1999.

(b) Each of these series is subject to certain refunding limitations for the
first five years after issuance.  For preferred stock subject to mandatory
redemption, redemption prices reduce in future years.

(c) The minimum sinking fund requirements of the series subject each year
to mandatory redemption aggregate $25.8 million in 2001 and $1.5 million in
2002, 2003, 2004, and 2005.  In case of default on sinking fund payments,
no payments may be made on any junior stock by way of dividends or
otherwise (other than in shares of junior stock) so long as the default
continues.  If a subsidiary is in arrears in the payment of dividends on
any outstanding shares of preferred stock, the subsidiary is prohibited
from redeeming or purchasing less than all of the outstanding preferred
stock.

(d) Long-term debt maturities and cash sinking fund requirements, excluding
fees and interest due for spent nuclear fuel disposal costs, on debt
outstanding at December 31, 2000, for the years 2001 through 2005 are $314.3
million, $331.5 million, $26.6 million, $26.4 million, and $48.5 million,
respectively.

Essentially all utility plant of CL&P, PSNH, WMECO, and NAEC, is subject to the
liens of each company's respective first mortgage bond indenture.  NAEC's first
mortgage bonds are also secured by payments made to NAEC by PSNH under the
terms of two life-of-unit, full cost recovery contracts.

CL&P and WMECO have secured $369.3 million of pollution control notes with
second mortgage liens on Millstone 1, junior to the liens of their respective
first mortgage bond indentures.

CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with
bond insurance secured by the first mortgage bonds and a liquidity facility.

Concurrent with the issuance of PSNH's Series A and B first mortgage bonds,
PSNH entered into financing arrangements with the Business Finance Authority
(BFA) of the state of New Hampshire.  Pursuant to these arrangements, the BFA
issued five series of PCRBs and loaned the proceeds to PSNH.  At December 31,
2000 and 1999, $407.3 million and $516.5 million, respectively, of the PCRBs
were outstanding.  PSNH's obligation to repay each series of PCRBs is secured
by the first mortgage bonds.  Each such series of first mortgage bonds contains
similar terms and provisions as the applicable series of PCRBs.  For financial
reporting purposes, these bonds would not be considered outstanding unless PSNH
failed to meet its obligations under the PCRBs.

(e) The average effective interest rates on the variable-rate pollution control
notes ranged from 3.2 percent to 6.8 percent for 2000 and 2.2 percent to 6.1
percent for 1999.

<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME TAXES
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------
                                                                           For the Years Ended December 31,
- ----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)                                                       2000          1999          1998
- ----------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>           <C>           <C>
The components of the federal and state income tax
  provisions charged to operations are:
Current income taxes:
   Federal......................................................         $ 154,790     $ 248,012     $ (13,660)
   State........................................................            23,052        33,955        (3,903)
                                                                         ---------     ---------     ---------
Total current...................................................           177,842       281,967       (17,563)
                                                                         ---------     ---------     ---------
Deferred income taxes, net:
  Federal.......................................................             7,297      (134,773)       51,913
  State.........................................................            (5,529)      (28,789)      (12,948)
                                                                         ---------     ---------     ---------
Total deferred..................................................             1,768      (163,562)       38,965
                                                                         ---------     ---------     ---------
Investment tax credits, net.....................................           (17,885)      (19,794)      (15,463)
                                                                         ---------     ---------     ---------
Total income tax expense........................................         $ 161,725     $  98,611     $   5,939
                                                                         =========     =========     =========
The components of total income tax expense are
  classified as follows:
    Income taxes charged to operating expenses..................         $ 230,031     $ 180,883     $  82,332
    Other income taxes..........................................           (68,306)      (82,272)      (76,393)
                                                                         ---------     ---------     ---------
Total income tax expense........................................         $ 161,725     $  98,611     $   5,939
                                                                         =========     =========     =========

Deferred income taxes are comprised of the tax effects of
  temporary differences as follows:
   Deferred tax asset associated with net operating losses......         $   1,563     $  14,801     $  69,212
   Depreciation, leased nuclear fuel, settlement
    credits and disposal costs..................................             9,514        (4,580)       16,217
   Regulatory deferral..........................................           (34,486)      (27,297)      (38,287)
   Regulatory disallowance......................................              -          (30,719)      (18,080)
   Sale of fossil and hydroelectric generation assets...........              -         (125,807)         -
   Pension......................................................            25,751         8,936        10,950
   Other........................................................              (574)        1,104        (1,047)
                                                                         ---------     ---------     ---------
Deferred income taxes, net......................................         $   1,768     $(163,562)    $  38,965
                                                                         =========     =========     =========
A reconciliation between income tax expense and the
  expected tax expense at 35 percent of pretax income:
Expected federal income tax.....................................         $ 133,413     $  54,454     $ (40,031)
Tax effect of differences:
   Depreciation.................................................             7,775        24,583        25,793
   Amortization of regulatory assets............................            11,942        45,825        30,740
   Amortization of PSNH acquisition costs.......................             9,946         9,946        17,301
   Investment tax credit amortization...........................           (17,885)      (19,794)      (15,463)
   State income taxes, net of federal benefit...................            11,390         3,358       (10,953)
   Nondeductible penalties......................................                38            17         3,589
   Adjustment for prior years' taxes............................              -           (2,796)       (7,338)
   Employee stock ownership plan................................              (999)        1,166        (1,670)
   Dividends received deduction.................................            (8,618)       (1,314)       (3,218)
   Adjustment to tax asset valuation allowance..................            (2,136)      (23,129)        7,000
   Merger-related expenditures..................................             5,829         4,597           -
   Deferred intercompany gain...................................             5,038           786           630
   Other, net...................................................             5,992           912          (441)
                                                                         ---------     ---------     ---------
Total income tax expense                                                 $ 161,725     $  98,611     $   5,939
                                                                         =========     =========     =========
</TABLE>
The accompanying notes are in integral part of these financial statements.



                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.   ABOUT NORTHEAST UTILITIES

Northeast Utilities (NU or the company) is the parent company of the Northeast
Utilities system (NU system).  Through its regulated utilities and competitive
energy subsidiaries, the NU system serves in excess of 30 percent of New
England's electric needs and is one of the 25 largest electric utility systems
in the country as measured by revenues.  The NU system's regulated utilities
furnish franchised retail electric service in Connecticut, New Hampshire and
western Massachusetts through three wholly owned subsidiaries:  The Connecticut
Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH)
and Western Massachusetts Electric Company (WMECO).  Another wholly owned
subsidiary, North Atlantic Energy Corporation (NAEC), sells all of its
entitlement to the capacity and output of the Seabrook Station nuclear unit
(Seabrook) to PSNH under the terms of two life-of-unit, full cost recovery
contracts (Seabrook Power Contracts).  A fifth wholly owned subsidiary, Holyoke
Water Power Company (HWP), also is engaged in the production and distribution
of electric power.

On March 1, 2000, NU completed its acquisition of Yankee Energy System, Inc.
(Yankee), the parent company of Yankee Gas Services Company (Yankee Gas),
Connecticut's largest natural gas distribution system.

NU is registered with the Securities and Exchange Commission (SEC) as a holding
company under the Public Utility Holding Company Act of 1935 (1935 Act), and
the NU system is subject to the provisions of the 1935 Act.  Arrangements among
the NU system companies, outside agencies and other utilities covering inter-
connections, interchange of electric power and sales of utility property are
subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or
the SEC.  The operating subsidiaries are subject to further regulation for
rates, accounting and other matters by the FERC and/or applicable state
regulatory commissions.

NU Enterprises, Inc. is a wholly owned subsidiary of NU and acts as the holding
company for certain of NU's competitive energy subsidiaries.  Northeast
Generation Company (NGC) was formed to acquire and manage generation
facilities.  Northeast Generation Services Company and its subsidiaries (NGS)
was formed to maintain and service any fossil or hydroelectric facility that is
acquired or contracted with for these services.  HEC Inc. and its subsidiaries
(HEC), Mode 1 Communications, Inc. (Mode 1), Select Energy, Inc. (Select
Energy), and Select Energy Portland Pipeline, Inc. engage in a variety of
energy-related and telecommunications activities, as applicable, primarily in
the competitive energy retail and wholesale commodity, marketing and services
fields.

Several wholly owned subsidiaries of NU provide support services for the
NU system companies and, in some cases, for other New England utilities.
Northeast Utilities Service Company provides centralized accounting,
administrative, information resources, engineering, financial, legal,
operational, planning, purchasing, and other services to the NU system
companies.  Northeast Nuclear Energy Company acts as agent for the NU system
companies and other New England utilities in operating the Millstone nuclear
units.  North Atlantic Energy Service Corporation has operational
responsibility for Seabrook.  Three other subsidiaries construct, acquire or
lease some of the property and facilities used by the NU system companies.

B.   PRESENTATION

The consolidated financial statements of the NU system include the accounts of
all subsidiaries.  Intercompany transactions have been eliminated in
consolidation.

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during
the reporting period.  Actual results could differ from those estimates.

Certain reclassifications of prior years' data have been made to conform with
the current year's presentation.

C.   NEW ACCOUNTING STANDARDS

Derivative Instruments:  Effective January 1, 2001, NU adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. SFAS No. 133 requires that
derivative instruments be recorded as an asset or liability measured at its
fair value and that changes in the fair value of derivative instruments be
recognized currently in earnings unless specific hedge accounting criteria
are met.

In order to implement SFAS No. 133 by January 1, 2001, NU established a cross-
functional project team to identify all derivative instruments, measure the
fair value of those derivative instruments, designate and document various
hedge relationships, and evaluate the effectiveness of those hedge
relationships.  NU has completed the process of identifying all derivative
instruments and has established appropriate fair value measurements of those
derivative instruments in place at January 1, 2001.  In addition, for those
derivative instruments which are hedging an identified risk, NU has designated
and documented all hedging relationships anew.

NU believes that the majority of its nontrading energy and capacity contracts,
purchased-power agreements, power sale agreements, and gas and electric retail
contracts, qualify for the "normal purchases and sales" exception of the new
standard, and therefore are not required to be recognized at fair value.
However, NU believes that its electric, oil and gas swap contracts, interest
rate swap agreements, and gas and oil futures are derivatives and will be
recorded on its consolidated balance sheets at fair value on January 1, 2001.
NU believes that certain of these contracts meet specific hedge accounting
criteria; accordingly, changes in the fair value of these contracts will be
recorded in other comprehensive income on the consolidated balance sheets.
For those contracts that do not meet the hedging requirements, the changes in
fair value of those contracts will be recognized currently in earnings.  As
explained within Note 8 commodity derivatives that are utilized for trading
purposes, are accounted for using the mark-to-market method, under Emerging
Issues Task Force (EITF) Issue No. 98-10, "Accounting for Energy Trading and
Risk Management Activities."

Management will record the effects of SFAS No. 133 in the first quarter of 2001
through a cumulative effect of a change in accounting principle and estimates
that the effect will be to reduce pretax earnings by approximately $37.4
million and increase shareholders' equity by $21.7 million.  These estimates
do not include certain long-term energy and capacity contracts which management
believes represent "normal purchases and sales."  The accounting for these
types of contracts is currently being evaluated by the Financial Accounting
Standards Board (FASB).  Further guidance from the FASB may change management's
conclusions regarding these contracts and require them to be accounted for as
derivatives.

Transfers of Financial Assets: In September 2000, the FASB issued SFAS No. 140,
"Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities - a Replacement of FASB Statement No. 125."  SFAS No. 140
revises the criteria for accounting for securitizations, other financial asset
transfers and collateral and introduces new disclosures, but otherwise carries
forward most of the provisions of SFAS No. 125, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities," without
amendment.  SFAS No. 140 is effective for transfers and servicing of financial
assets and extinguishments of liabilities occurring after March 31, 2001, and
is effective for recognition and reclassification of collateral and for
disclosures relating to securitization transactions and collateral for fiscal
years ending after December 15, 2000.  The adoption of the disclosure
requirements under SFAS No. 140 did not have a material impact on NU's
consolidated financial statements.

Revenue Recognition:  In December 1999, the SEC issued Staff Accounting
Bulletin (SAB) No. 101, "Revenue Recognition."  The adoption of SAB No. 101,
as amended, did not have a material impact on NU's consolidated financial
statements.

Forward Share Purchase Arrangement:  EITF Issue No. 00-19, "Accounting for
Derivative Financial Instruments Indexed to, and Potentially Settled in, a
Company's Own Stock," requires that all contracts be initially measured at fair
value and subsequently accounted for based on the current classification and
the assumed or required settlement method.  As NU's forward share purchase
arrangements can be settled in cash or NU common shares at the company's
discretion, this amount was classified as temporary equity from stock forward
on the consolidated balance sheets at December 31, 2000 and 1999.

On January 2, 2001, these arrangements were modified.  As a result of applying
the revised guidance under EITF Issue No. 00-19, the aforementioned forward
share purchase transactions no longer meet the temporary equity criteria and
will be classified as an asset or liability in the first quarter of 2001.
The difference between the fair value and contract value will be included in
earnings.  NU expects to repurchase the shares from the counterparties in the
first half of 2001 with the proceeds from restructuring.

D.   INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT

Regional Nuclear Generating Companies:  CL&P, PSNH and WMECO own common stock
in four regional nuclear companies (Yankee Companies).  The NU system's
ownership interests in the Yankee Companies at December 31, 2000 and 1999,
which are accounted for on the equity method due to the NU system companies'
ability to exercise significant influence over their operating and financial
policies are 49 percent of the Connecticut Yankee Atomic Power Company (CYAPC),
38.5 percent of the Yankee Atomic Electric Company (YAEC), 20 percent of the
Maine Yankee Atomic Power Company (MYAPC), and 16 percent of the Vermont Yankee
Nuclear Power Corporation (VYNPC).  The NU system's total equity investment in
the Yankee Companies at December 31, 2000 and 1999, is $62.5 million and $81.5
million, respectively.  Each Yankee Company owns a single nuclear generating
unit.  However, VYNPC is the only unit still in operation at December 31, 2000.

Millstone:  CL&P and WMECO together own 100 percent of both Millstone 1, a
660 megawatt (MW) nuclear unit, which is currently in decommissioning status,
and Millstone 2, an 870 MW nuclear generating unit.  CL&P, PSNH and WMECO
together have a 68.02 percent joint ownership interest in Millstone 3, a
1,154 MW nuclear generating unit.  On August 7, 2000, CL&P, WMECO and certain
other joint owners reached an agreement to sell substantially all of the
Millstone units to Dominion Resources, Inc. (Dominion) for approximately $1.3
billion, including approximately $105 million for nuclear fuel.  NU currently
expects to close on the sale of Millstone as early as the end of March 2001.

Seabrook:  CL&P and NAEC together have a 40.04 percent joint ownership interest
in Seabrook, a 1,148 MW nuclear generating unit.  NAEC sells all of its share
of the power generated by Seabrook to PSNH under the Seabrook Power Contracts.
CL&P and NAEC expect to auction their joint ownership interests in Seabrook in
2001 with a closing on the sale expected in 2002.

Plant-in-service and the accumulated provision for depreciation for the NU
system's share of Millstone 2 and 3 and Seabrook are as follows:

- -------------------------------------------------------------------------------
                                                          At December 31,
- -------------------------------------------------------------------------------
(Millions of Dollars)                                     2000        1999
- -------------------------------------------------------------------------------
Plant-in-service
Millstone 2                                            $  962.0     $  952.1
Millstone 3                                             2,427.2      2,414.9
Seabrook                                                  909.3        901.9
Accumulated provision for depreciation
Millstone 2                                            $  953.6     $  910.0
Millstone 3                                             2,214.3      2,220.5
Seabrook                                                  821.3        318.8
- -------------------------------------------------------------------------------

Hydro-Quebec:  NU has a 22.66 percent equity ownership interest, totaling $15
million and $16.5 million at December 31, 2000 and 1999, respectively, in two
companies that transmit electricity imported from the Hydro-Quebec system in
Canada.

E.   DEPRECIATION

The provision for depreciation is calculated using the straight-line method
based on the estimated remaining useful lives of depreciable utility plant-
in-service, adjusted for salvage value and removal costs, as approved by the
appropriate regulatory agency where applicable.  Except for major facilities,
depreciation rates are applied to the average plant-in-service during the
period.  Major facilities are depreciated from the time they are placed in
service.  When plant is retired from service, the original cost of the plant,
including costs of removal less salvage, is charged to the accumulated
provision for depreciation.  The costs of closure and removal of nonnuclear
facilities are accrued over the life of the plant as a component of
depreciation.  The depreciation rates for the several classes of electric
plant-in-service are equivalent to a composite rate of 3.1 percent in 2000
and 3.3 percent in 1999 and 1998.

As a result of discontinuing the application of SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation," for CL&P's and WMECO's generation
businesses in 1999, including CL&P's ownership interest in Seabrook, NU
recorded a charge to accumulated depreciation for the nuclear plant in excess
of the estimated fair market value at the time in the amount of $2 billion and
a corresponding regulatory asset was created.  Also, in 2000, HWP discontinued
SFAS No. 71 and recorded a charge to accumulated depreciation for the plant in
excess of fair value for certain hydroelectric generation assets, which was
recorded as an extraordinary loss.

F.   REVENUES

Regulated utility revenues are based on authorized rates applied to each
customer's use of electricity.  In general, rates can be changed only through
a formal proceeding before the appropriate regulatory commission.  Regulatory
commissions also have authority over the terms and conditions of nontraditional
rate-making arrangements.  At the end of each accounting period, CL&P, PSNH,
WMECO, Select Energy, and Yankee Gas accrue a revenue estimate for the amount
of energy delivered but unbilled.

Revenues for NU's competitive energy subsidiaries, primarily Select Energy, are
recognized when the energy is delivered.

G.   PSNH ACQUISITION COSTS

PSNH acquisition costs represent the aggregate value placed by the 1989 rate
agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in
excess of the net book value of PSNH's non-Seabrook assets, plus the
$700 million value assigned to Seabrook by the Rate Agreement as part of the
bankruptcy resolution on June 5, 1992.  The Rate Agreement provided for the
recovery through rates, with a return, of the PSNH acquisition costs.  In
connection with the "Agreement to Settle PSNH Restructuring" (Settlement
Agreement) approximately $219.4 million was written off and the balance of
$76.6 million has been reclassified as a regulatory asset.

H.   REGULATORY ACCOUNTING AND ASSETS

The accounting policies of the NU system operating companies and the
accompanying consolidated financial statements conform to accounting
principles generally accepted in the United States applicable to rate-regulated
enterprises and historically reflect the effects of the rate-making process in
accordance with SFAS No. 71.  As a result of final restructuring orders issued
in 1999, CL&P and WMECO discontinued the application of SFAS No. 71 for the
generation portion of their businesses.  During the fourth quarter of 2000,
the Settlement Agreement became probable of implementation, therefore, PSNH
discontinued the application of SFAS No. 71 for the generation portion of its
business.

CL&P's, WMECO's and PSNH's transmission and distribution business will continue
to be cost-based and management believes the application of SFAS No. 71
continues to be appropriate.  Management continues to believe it is probable
that the NU system operating companies will recover their investments in long-
lived assets, including regulatory assets through charges to their transmission
and distribution customers generally over periods of 7 to 26 years, subject to
certain adjustments.  The majority for CL&P and WMECO will be recovered through
a transition charge over a 12-year period.  PSNH will recover securitized
assets over a 12-year period.  Nuclear decommissioning and IPP costs will be
recovered over the period PSNH is responsible for those costs.  The third type
of PSNH stranded costs are nonsecuritized regulatory assets (type three
regulatory assets).  Any type three regulatory assets not collected by the
recovery end date will be written off.  Based on current projections, PSNH
expects to fully recovery all of its type three regulatory assets by the
recovery end date stipulated in the Settlement Agreement.  In addition, all
material regulatory assets are earning a return.  The components of the NU
system companies' regulatory assets are as follows:

- -------------------------------------------------------------------------------
                                                          At December 31,
- -------------------------------------------------------------------------------
(Millions of Dollars)                                     2000        1999
- -------------------------------------------------------------------------------
Recoverable nuclear costs                               $2,565.8    $2,210.8
Income taxes, net                                          504.7       636.6
Unrecovered contractual obligations                        255.8       349.2
Recoverable energy costs, net                              332.5       228.2
Other                                                      252.0       217.6
- -------------------------------------------------------------------------------
Totals                                                  $3,910.8    $3,642.4
- -------------------------------------------------------------------------------

As a result of discontinuing the application of SFAS No. 71 in 1999 for CL&P's
and WMECO's generation businesses, CL&P and WMECO reclassified nuclear plant
in excess of its estimated fair market value from plant to regulatory assets.
As of December 31, 2000 and 1999, both the CL&P unamortized balance ($1.35
billion and $1.38 billion, respectively) and the WMECO unamortized balance
($286.9 million and $316.1 million, respectively) are classified as recoverable
nuclear costs.  Also included in that regulatory asset component for 2000 and
1999 are $449.2 million and $514.7 million, respectively, which includes
Millstone 1 recoverable nuclear costs relating to the recoverable portion of
the undepreciated plant and related assets ($90.8 million and $145.7 million,
respectively) and the decommissioning and closure obligation ($358.4 million
and $369 million, respectively).

As a result of discontinuing the application of SFAS No. 71 in 2000 for PSNH's
generation business, PSNH recorded an after-tax charge of $214.2 million in the
fourth quarter of 2000.  In addition, a regulatory asset was created for the
Seabrook over market generation in the amount of $484.7 million, which is
classified as recoverable nuclear costs.  It is anticipated this regulatory
asset will be securitized.

I.   INCOME TAXES

The tax effect of temporary differences (differences between the periods in
which transactions affect income in the financial statements and the periods
in which they affect the determination of taxable income) is accounted for
in accordance with the rate-making treatment of the applicable regulatory
commissions.

The tax effect of temporary differences, including timing differences accrued
under previously approved accounting standards, that give rise to the
accumulated deferred tax obligation is as follows:

- -------------------------------------------------------------------------------
(Millions of Dollars)                                     2000        1999
- -------------------------------------------------------------------------------
Accelerated depreciation and other
  plant-related differences                             $1,364.9    $1,388.0
Regulatory assets - income tax
  gross-up                                                 189.1       241.2
Other                                                       31.5        58.9
- -------------------------------------------------------------------------------
Totals                                                  $1,585.5    $1,688.1
- -------------------------------------------------------------------------------

J.   UNRECOVERED CONTRACTUAL OBLIGATIONS

Under the terms of contracts with the Yankee Companies, the shareholder-
sponsored companies are responsible for their proportionate share of the
remaining costs of the units, including decommissioning.  As management
expects that the NU system companies will be allowed to recover these costs
from their customers, the NU system companies have recorded regulatory assets,
with corresponding obligations, on their respective balance sheets.

K.   RECOVERABLE ENERGY COSTS

Energy Policy Act of 1992:  Under the Energy Policy Act of 1992 (Energy Act),
CL&P, PSNH, WMECO, and NAEC are assessed for their proportionate shares of
the costs of decontaminating and decommissioning uranium enrichment plants
owned by the United States Department of Energy (DOE) (D&D Assessment).  The
Energy Act requires that regulators treat D&D Assessments as a reasonable and
necessary current cost of fuel, to be fully recovered in rates like any other
fuel cost.  CL&P, PSNH, WMECO, and NAEC are currently recovering these costs
through rates.  As of December 31, 2000 and 1999, the NU system's total D&D
Assessment deferrals were $34.5 million and $38.4 million, respectively.

CL&P:  Through December 31, 1999, CL&P had an energy adjustment clause under
which fuel prices above or below base-rate levels were charged to or credited
to customers.  Coincident with the start of restructuring, the energy
adjustment clause was terminated.  Energy costs deferred and not yet collected
under the energy adjustment clause amounted to $61.1 million and $62.6 million
at December 31, 2000 and 1999, respectively.  This balance is recorded as a
generation-related stranded cost and will be recovered through a transition
charge mechanism pending final Connecticut Department of Public Utility Control
(DPUC) approval.

PSNH:  The Rate Agreement includes a fuel and purchased-power adjustment clause
(FPPAC) permitting PSNH to pass through to retail customers, for a 10-year
period that began in May 1991, the retail portion of differences between the
fuel and purchased-power costs assumed in the Rate Agreement and PSNH's actual
costs, which include the costs related to the Seabrook Power Contracts and the
Clean Air Act Amendment.  The cost components of the FPPAC are subject to a
prudence review by the New Hampshire Public Utilities Commission (NHPUC).  At
December 31, 2000 and 1999, PSNH had $230.1 million and $120.5 million,
respectively, of recoverable energy costs deferred under the FPPAC.  Under the
Settlement Agreement, the FPPAC will be recovered as a type three regulatory
asset through a transition charge.

L.   CASH AND CASH EQUIVALENTS

Cash and cash equivalents includes cash on hand and short-term cash investments
which are highly liquid in nature and have original maturities of three months
or less.

2.   SHORT-TERM DEBT

Limits:  The amount of short-term borrowings that may be incurred by NU and the
NU system operating companies is subject to periodic approval by either the SEC
under the 1935 Act or by the respective state regulators.  Currently, SEC
authorization allows NU, CL&P, WMECO, and Yankee Gas to incur total short-term
borrowings up to a maximum of $400 million, $375 million, $250 million, and
$100 million, respectively.  In addition, the charters of CL&P and WMECO
contain preferred stock provisions restricting the amount of unsecured debt
those companies may incur.  As of December 31, 2000, CL&P's and WMECO's
charters permit CL&P and WMECO to incur $245 million and $94 million,
respectively, of additional unsecured debt.  PSNH and NAEC are authorized by
the NHPUC to incur short-term borrowings up to a maximum of $71.3 million and
$260 million, respectively.

Credit Agreements:

NGC:  In March 2000, CL&P and WMECO transferred 1,289 MW of hydroelectric
generation assets in Connecticut and Massachusetts to NGC, an affiliated
company, for approximately $865.5 million.  To finance the transfer, on
March 9, 2000, NGC entered into a new short-term credit agreement with a total
commitment amount of $865.5 million, collateralized by the generation assets
transferred.  Under the short-term credit agreement, $435.5 million of the
commitment matured on March 14, 2000, and was repaid.  This credit agreement,
with an original maturity date of December 29, 2000, was extended for a
minimum of six months.  NGC expects to replace the short-term credit agreement
with up to $440 million of permanent financing in the first half of 2001.
At December 31, 2000, there were $402.4 million in borrowings under the
credit agreement.

Yankee Merger:  To finance the cash portion of the Yankee merger, on March 1,
2000, NU entered into an unsecured term loan agreement for $266 million.
The term loan agreement will expire on February 28, 2001.  NU expects to
replace this financing with permanent, long-term financing prior to its
maturity date.  At December 31, 2000, there were $263 million in borrowings
under the term loan agreement.

CL&P and WMECO:  On November 17, 2000, CL&P and WMECO entered into a 364-day
revolving credit facility for $350 million, replacing the previous $500 million
facility which was to expire on November 17, 2000.  CL&P and WMECO may draw up
to $200 million and $150 million, respectively, under the facility which, until
the nuclear divestiture, is secured by second mortgages on Millstone 2 and 3.
Once CL&P and WMECO receive the proceeds from securitization, the $350 million
revolving credit facility will be reduced to $250 million, with a $150 million
limit for CL&P and a $100 million limit for WMECO.  Unless extended, the credit
facility will expire on November 16, 2001.  At December 31, 2000 and 1999,
there were $225 million and $213 million, respectively, in borrowings under
these facilities.

NAEC:  On November 9, 2000, NAEC entered into an unsecured 364-day term credit
agreement for $200 million, replacing a $225 million term loan which was to
expire on November 9, 2000.  The proceeds from the term credit agreement were
used to repay the $200 million outstanding under the previous term loan.
Additionally, the interest rate swaps and collar related to the previous term
loan expired and were not replaced.  The term credit agreement also contains
two mandatory prepayment provisions; the first is a 50 percent mandatory
principal repayment of amounts outstanding to $100 million within two days of
the buydown of the Seabrook Power Contracts and the second is 100 percent
prepayment within two days of the sale of Seabrook.  Any amounts prepaid can
not be reborrowed.  Unless extended, the term credit agreement will expire on
November 8, 2001.  At December 31, 2000 and 1999, there were $200 million in
borrowings under the credit agreement and previous term loan.

NU Parent:  To continue to support the working capital needs of NU and its
competitive energy subsidiaries, NU replaced its $350 million 364-day unsecured
revolving credit facility which was to expire on November 17, 2000, with a
364-day unsecured revolving credit facility on November 17, 2000.  This
facility provides a total commitment of $400 million which is available subject
to two overlapping sub-limits.  First, subject to the notional amount of any
letters of credit outstanding, amounts up to $300 million are available for
advances.  Second, subject to the advances outstanding, letters of credit may
be issued in notional amounts up to $200 million.  Unless extended, this credit
facility will expire on November 16, 2001.  At December 31, 2000 and 1999,
there were $173 million and $65 million, respectively, in borrowings under the
new and previous facilities.  With regard to credit support, NU had $40 million
and $29 million, respectively, in letters of credit issued under the new and
previous agreements at December 31, 2000 and 1999.

Yankee Gas:  Yankee Gas has arranged a $60 million unsecured revolving credit
facility.  On November 17, 2000, the expiration date of this facility was
extended to November 16, 2001.  At December 31, 2000, there were $46.6 million
in borrowings under this credit facility.

NU provides credit assurance in the form of guarantees, letters of credit and
other assurances for the financial performance obligations of certain of its
competitive energy subsidiaries.  NU currently has authorization from the SEC
to provide up to $500 million of such assurances.  As of December 31, 2000 and
1999, NU had provided approximately $284 million and $190 million,
respectively, of such credit assurances.

Under the aforementioned credit agreements, the respective borrowers may borrow
at fixed or variable rates plus an applicable margin based upon certain debt
ratings, as rated by the lower of Standard and Poor's or Moody's Investors
Service.  The weighted average interest rate on the NU system companies' notes
payable to banks outstanding on December 31, 2000 and 1999, was 8.85 percent
and 7.93 percent, respectively.  Maturities of short-term debt obligations were
for periods of three months or less.

These credit agreements provide that the parties to these agreements must
comply with certain financial and nonfinancial covenants as are customarily
included in such agreements, including, but not limited to, common equity
ratios, interest coverage ratios, cash flow ratios, and dividend payment
restrictions.  The parties to the credit agreements currently are and expect
to remain in compliance with these covenants.

3.   LEASES

CL&P and WMECO finance their nuclear fuel for Millstone 2 and their respective
shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust
(NBFT) capital lease agreement.  This capital lease agreement has an expiration
date of June 1, 2040.  At December 31, 2000 and 1999, the present value of the
capital lease obligation to the NBFT was $139.2 million and $157 million,
respectively.  In connection with the planned nuclear divestiture the NBFT
capital lease agreement will be terminated, the nuclear fuel will be
transferred to Dominion and the related $180 million Series G Intermediate Term
Note Agreement will be extinguished with the divestiture proceeds.

CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel
consumed in the reactors based on a units-of-production method at rates which
reflect estimated kilowatt-hours of energy provided plus financing costs
associated with the fuel in the reactors.  Upon permanent discharge from the
reactors, ownership of the nuclear fuel transfers to CL&P and WMECO.

The NU system companies also have entered into lease agreements, some of which
are capital leases, for the use of data processing and office equipment,
vehicles, nuclear control room simulators, and office space.  The provisions
of these lease agreements generally provide for renewal options.

Capital lease rental payments charged to operating expense were $50.1 million
in 2000, $20.8 million in 1999 and $31 million in 1998.  Interest included in
capital lease rental payments was $11.6 million in 2000, $13.7 million in 1999
and $18.3 million in 1998.  Operating lease rental payments charged to expense
were $10.1 million in 2000, $7.5 million in 1999 and $15.7 million in 1998.

Future minimum rental payments, excluding annual nuclear fuel lease payments
and executory costs, such as property taxes, state use taxes, insurance, and
maintenance, under long-term noncancelable leases, as of December 31, 2000
are as follows:

- ------------------------------------------------------------------------------
(Millions of Dollars)
- ------------------------------------------------------------------------------
Year                                    Capital Leases     Operating Leases
- ------------------------------------------------------------------------------
2001                                       $  4.9              $ 25.0
2002                                          3.2                20.0
2003                                          3.2                15.0
2004                                          3.0                11.5
2005                                          2.8                 9.4
After 2005                                   27.7                23.2
- ------------------------------------------------------------------------------
Future minimum lease payments                44.8
Less amount representing interest            24.1               104.1
- ------------------------------------------------------------------------------
Present value of future minimum
  lease payments for other than
  nuclear fuel                               20.7
Present value of future nuclear
  fuel lease payments                       139.2
- ------------------------------------------------------------------------------
Present value of future minimum
  lease payments                           $159.9
- ------------------------------------------------------------------------------
4.   EMPLOYEE BENEFITS

A.   PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

The NU system companies, participate in a uniform noncontributory defined
benefit retirement plan covering substantially all regular NU system employees.
Benefits are based on years of service and the employees' highest eligible
compensation during 60 consecutive months of employment.  The total pension
credit, part of which was credited to utility plant, was $97.9 million in
2000, $33.7 million in 1999 and $44.1 million in 1998.

Currently, the NU system companies' policy is to annually fund an amount at
least equal to that which will satisfy the requirements of the Employee
Retirement Income Security Act and Internal Revenue Code.

The NU system companies also provide certain health care benefits, primarily
medical and dental, and life insurance benefits through a benefit plan to
retired employees.  These benefits are available for employees retiring from
the NU system who have met specified service requirements.  For current
employees and certain retirees, the total benefit is limited to two times
the 1993 per retiree health care cost.  These costs are charged to expense
over the estimated work life of the employee.  The NU system companies annually
fund postretirement costs through external trusts with amounts that have been
rate-recovered and which also are tax deductible.

Pension and trust assets are invested primarily in domestic and international
equity securities and bonds.

In December 2000, NU announced the details of a voluntary separation program
designed to reduce NU's generation-related support staff in 2001.  NU will
reflect the program's costs in first quarter 2001 results.

The following table represents information on the plans' benefit obligation,
fair value of plan assets, and the respective plans' funded status:

- -------------------------------------------------------------------------------
                                                At December 31,
- -------------------------------------------------------------------------------
                                   Pension Benefits     Postretirement Benefits
- -------------------------------------------------------------------------------
(Millions of Dollars)             2000         1999         2000         1999
- -------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation
  at beginning of year......... $(1,516.6)  $(1,479.2)    $(306.8)    $(305.2)
Yankee merger..................     (66.7)         -        (26.9)         -
Service cost...................     (41.2)      (43.7)       (7.6)       (7.6)
Interest cost..................    (118.5)     (106.3)      (25.5)      (21.8)
Employee contribution..........        -           -         (0.1)         -
Plan amendment.................        -        (79.6)         -           -
Actuarial (loss)/gain..........     (39.4)      133.8       (13.6)       (1.3)
Benefits paid..................     109.5        78.3        27.5        28.9
Settlements and other..........       2.0       (19.9)        0.7         0.2
- -------------------------------------------------------------------------------
Benefit obligation
  at end of year............... $(1,670.9)  $(1,516.6)    $(352.3)    $(306.8)
- -------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets
  at beginning of year......... $ 2,330.2   $ 2,098.0     $ 170.7     $ 151.2
Yankee merger..................     107.5          -         16.1          -
Actual return on plan assets...      (8.8)      310.5         8.6        18.7
Employer contribution..........        -          -          29.6        29.7
Employee contribution..........        -          -           0.1          -
Benefits paid..................    (109.5)      (78.3)      (27.5)      (28.9)
- -------------------------------------------------------------------------------
Fair value of plan assets
  at end of year............... $ 2,319.4   $ 2,330.2     $ 197.6     $ 170.7
- -------------------------------------------------------------------------------
Funded status at December 31... $   648.5   $   813.6     $(154.7)    $(136.1)
Unrecognized transition
  (asset)/obligation...........      (5.8)       (7.4)      180.9       196.6
Unrecognized prior
  service cost.................      90.9        99.2         -           -
Unrecognized net gain..........    (594.1)     (904.7)      (35.5)      (60.4)
- -------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost. $   139.5   $     0.7     $  (9.3)    $   0.1
- -------------------------------------------------------------------------------

The following actuarial assumptions were used in calculating the plans' year
end funded status:

- -------------------------------------------------------------------------------
                                               At December 31,
- -------------------------------------------------------------------------------
                                   Pension Benefits     Postretirement Benefits
- -------------------------------------------------------------------------------
                                     2000    1999           2000      1999
- -------------------------------------------------------------------------------
Discount rate.....................   7.50%   7.75%          7.50%     7.75%
Compensation/progression rate.....   4.50    4.75           4.50      4.75
Health care cost trend rate (a)...   N/A     N/A            5.26      5.57
- -------------------------------------------------------------------------------

(a) The annual per capita cost of covered health care benefits was assumed to
    decrease to 4.91 percent by 2001.

The components of net periodic benefit (credit)/cost are:

- -------------------------------------------------------------------------------
                                    For the Years Ended December 31,
- -------------------------------------------------------------------------------
                                                          Postretirement
                               Pension Benefits              Benefits
- -------------------------------------------------------------------------------
(Millions of Dollars)     2000      1999      1998     2000   1999     1998
- -------------------------------------------------------------------------------
Service cost.........    $ 41.2   $ 43.7    $ 37.4    $ 7.6   $ 7.6   $ 6.6
Interest cost........     118.5    106.3      96.8     25.5    21.8    20.9
Expected return
  on plan assets.....    (205.1)  (175.5)   (153.2)   (15.3)  (11.7)   (9.9)
Amortization of
  unrecognized net
  transition (asset)/
  obligation.........      (1.4)    (1.5)     (1.5)    15.1    15.1    15.1
Amortization of prior
  service cost.......       7.9      7.9       2.1       -       -       -
Amortization of
  actuarial gain.....     (52.4)   (33.5)    (25.7)      -       -       -
Other amortization,
  net................        -        -         -      (4.3)   (3.1)   (3.8)
  Settlements and
  other..............      (6.6)    18.9        -        -       -       -
- -------------------------------------------------------------------------------
Net periodic benefit
 (credit)/cost.......    $(97.9)  $(33.7)   $(44.1)   $28.6   $29.7   $28.9
- -------------------------------------------------------------------------------

For calculating pension and postretirement benefit costs, the following
assumptions were used:

- -------------------------------------------------------------------------------
                                     For the Years Ended December 31,
- -------------------------------------------------------------------------------
                                                           Postretirement
                                 Pension Benefits              Benefits
- -------------------------------------------------------------------------------
                           2000      1999      1998     2000    1999     1998
- -------------------------------------------------------------------------------
Discount rate........      7.75%     7.00%     7.25%    7.75%   7.00%    7.25%
Expected long-term
  rate of return.....      9.50      9.50      9.50      N/A     N/A      N/A
Compensation/
 progression rate....      4.75      4.25      4.25     4.75    4.25     4.25
Long-term rate
  of return -
  Health assets,
    net of tax.......       N/A       N/A       N/A     7.50    7.50     7.75
  Life assets........       N/A       N/A       N/A     9.50    9.50     9.50
- -------------------------------------------------------------------------------

Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans.  The effect of changing the assumed health
care cost trend rate by one percentage point in each year would have the
following effects:

- -------------------------------------------------------------------------------
                                            One Percentage     One Percentage
(Millions of Dollars)                       Point Increase     Point Decrease
- -------------------------------------------------------------------------------
Effect on total service and
  interest cost components                      $ 1.6              $ (1.6)
Effect on postretirement
  benefit obligation                            $17.9              $(16.6)
- -------------------------------------------------------------------------------

The trust holding the health plan assets is subject to federal income taxes.

B.   401(k) SAVINGS PLAN

NU maintains a 401(k) Savings Plan for substantially all NU system  employees.
This savings plan provides for employee contributions up to specified limits.
NU matches employee contributions up to a maximum of 3 percent of eligible
compensation with cash and NU stock.  The matching contributions made by NU
were $13.6 million in 2000, $13.8 million in 1999 and $13.2 million in 1998.

C.     ESOP

NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating
shares to employees participating in the NU system's 401(k) Savings Plan.
Under this arrangement, NU issued unsecured notes during 1991 and 1992 totaling
$250 million, the proceeds of which were lent to the ESOP trust for the
purchase of 10.8 million newly issued NU common shares (ESOP Shares).  The
ESOP trust is obligated to make principal and interest payments on the ESOP
notes at the same rate that ESOP Shares are allocated to employees.  NU makes
annual contributions to the ESOP equal to the ESOP's debt service, less
dividends received by the ESOP.  All dividends received by the ESOP on
unallocated shares are used to pay debt service and are not considered
dividends for financial reporting purposes.  During the fourth quarter of
1999 through December 31, 2000, NU paid a 10 cent per share quarterly dividend.

In 2000 and 1999, the ESOP trust issued 572,863 and 556,978 of NU common
shares, respectively, to satisfy 401(k) Savings Plan obligations to employees.
As of December 31, 2000 and 1999, the total allocated ESOP shares were
5,854,699 and 5,281,836, respectively, and total unallocated ESOP shares were
4,945,486 and 5,518,349, respectively.  The fair market value of unallocated
ESOP shares as of December 31, 2000 and 1999, was $119.9 million and $113.5
million, respectively.

D.   STOCK-BASED COMPENSATION

Employee Stock Purchase Plan (ESPP):  Since July 1998, the NU system maintained
an ESPP for all eligible employees.  Under the ESPP, shares of NU common stock
were purchased at 6-month intervals at 85 percent of the lower of the price on
the first or last day of each 6-month period.  Employees purchased shares
having a value not exceeding 25 percent of their compensation at the beginning
of the purchase period.  During 2000 and 1999, employees purchased 199,520 and
253,853 shares, respectively, at discounted prices ranging from $17.48 to
$18.49 in 2000, and $13.76 to $14.93 per share in 1999.  At December 31, 2000
and 1999, 1,417,156 and 1,616,676 shares remained reserved for future issuance
under the ESPP, respectively.  Effective January 1, 2001, the ESPP was
terminated.

Incentive Plans:  The NU system has long-term incentive plans authorizing
various types of share-based awards, including stock options, to be made to
eligible employees and board members.  The exercise price of stock options, as
set at the time of grant, is generally equal to the fair market value per
share at the date of grant.  Under the Northeast Utilities Incentive Plan
(Incentive Plan), the number of shares which may be utilized for awards granted
during a given calendar year may not exceed one percent of the total number of
shares of NU common stock outstanding as of the first day of that calendar
year.

Stock option transactions for 1998, 1999 and 2000, including those options
acquired in connection with the Yankee merger, are as follows:

- -------------------------------------------------------------------------------
                                              Exercise Price Per Share
                                              ------------------------

                                   Options             Range          Weighted
                                   -------             -----           Average
- -------------------------------------------------------------------------------
Outstanding December 31, 1997       500,000                $ 9.6250   $ 9.6250
Granted                             741,273     $14.8750 - $16.8125   $16.1780
Forfeited                            (7,595)               $16.3125   $16.3125
- -------------------------------------------------------------------------------
Outstanding December 31, 1998     1,233,678     $ 9.6250 - $16.8125   $13.5213
Granted                             644,123     $14.9375 - $21.1250   $15.2514
Exercised                           (19,368)    $16.3125 - $16.8125   $16.3986
Forfeited                           (32,177)    $14.9375 - $16.3125   $15.8714
- -------------------------------------------------------------------------------
Outstanding December 31, 1999     1,826,256     $ 9.6250 - $21.1250   $14.0585
Granted                             669,470     $18.4375 - $22.2500   $18.7029
Yankee merger                        10,167     $ 9.3640 - $12.6888   $10.7653
Exercised                           (43,750)    $14.9375 - $19.5000   $16.0658
Forfeited                           (28,281)    $14.9375 - $19.5000   $16.6515
- -------------------------------------------------------------------------------
Outstanding December 31, 2000     2,433,862     $ 9.3640 - $22.2500   $15.2569
- -------------------------------------------------------------------------------
Exercisable December 31, 1998       232,936     $14.8750 - $16.8125   $16.2972
Exercisable December 31, 1999       711,787     $ 9.6250 - $21.1250   $14.0102
Exercisable December 31, 2000     1,298,339     $ 9.3640 - $22.2500   $14.2021
- -------------------------------------------------------------------------------

The vesting schedule for the options granted in 1998 is one-third upon grant,
two-thirds after one year and the total award after two years.  For the options
that were granted in 1999 and for certain options that were granted in 2000,
the vesting schedule for these options is ratably over three years from the
date of grant.  Other options granted in 2000 vest 50 percent at the date of
grant and 50 percent one year from the date of grant.

Also under the Incentive Plan, the NU system awarded 91,120 of restricted
shares in 1999.  These shares have the same vesting schedule as the options
granted under the Incentive Plan.  The NU system has also made several small
grants of restricted stock and other incentive-based stock compensation.
During 2000, 1999 and 1998, $1.9 million, $2.2 million and $0.8 million,
respectively, was expensed for stock-based compensation.

Had compensation cost been determined for the ESPP and the incentive plan stock
options under the fair value method as opposed to the intrinsic value method
followed by the NU system, net (loss)/income and net (loss)/income per share
would have been as follows:

- -------------------------------------------------------------------------------
(Millions of Dollars,
except per share amounts)                       2000        1999        1998
- -------------------------------------------------------------------------------
Net (loss)/income                             $(33.9)       $29.6     $(149.1)
Basic (loss)/income per common share          $(0.24)       $0.23     $ (1.14)
Diluted (loss)/income per common share        $(0.24)       $0.22     $ (1.14)
- -------------------------------------------------------------------------------

The fair value of each stock option grant has been estimated on the date of
grant using the Black-Scholes option pricing model with the following weighted
average assumptions:

- -------------------------------------------------------------------------------
                                                2000        1999        1998
- -------------------------------------------------------------------------------
Risk-free interest rate                        6.56%       5.69%       5.82%
Expected life                                 10 years    10 years    10 years
Expected volatility                           26.15%      36.21%      35.05%
Expected dividend yield                        1.82%       1.89%       5.46%
- -------------------------------------------------------------------------------

The weighted average grant date fair values of options granted during 2000,
1999 and 1998 were $7.50, $6.79 and $3.98, respectively.  As of December 31,
2000 and 1999, the weighted average remaining contractual lives for those
options outstanding are 7.92 years and 8.47 years, respectively.

5.   SALE OF CUSTOMER RECEIVABLES

As of December 31, 2000 and 1999, CL&P had sold accounts receivable of $170
million to a third-party purchaser with limited recourse through the CL&P
Receivables Corporation (CRC), a wholly owned subsidiary of CL&P.  In addition,
at December 31, 2000 and 1999, $18.9 million and $22.5 million, respectively,
of accounts receivable were designated as collateral under the agreement with
the CRC.

Concentrations of credit risk to the purchaser under the company's agreement
with respect to the receivables are limited due to CL&P's diverse customer base
within its service territory.

6.   COMMITMENTS AND CONTINGENCIES

A.   RESTRUCTURING

Connecticut:  The 1999 restructuring orders allowed for securitization of
CL&P's nonnuclear regulatory assets and the costs to buyout or buydown the
various purchased-power contracts.  On November 8, 2000, the DPUC approved
CL&P's request to securitize an amount not to exceed $1.55 billion of approved,
eligible stranded costs, primarily related to above-market purchased-power
contracts and generation related regulatory assets.  However, the Office of
Consumer Counsel (OCC) appealed the securitization order to the Connecticut
Superior Court and it remains unclear when securitization financing can be
undertaken.

New Hampshire:  In September 2000, the NHPUC approved a comprehensive
restructuring order that would allow PSNH to securitize up to $670 million of
stranded costs.  In January 2001, the New Hampshire Supreme Court upheld this
restructuring order on appeal.  However, one of the appellants indicated
publicly it would request a review of the New Hampshire Supreme Court decision
by the United States Supreme Court.  Such a request must be filed by May 1,
2001.  Management believes that such an appeal would have a low probability of
success, but cannot determine what effect it might have on the timing of the
issuance of securitization bonds and the implementation of customer choice in
New Hampshire.  PSNH currently expects to work with the State of New Hampshire
to issue securitization bonds early in the second quarter of 2001.

In October 2000, NU reached an agreement with an unaffiliated joint owner, who
owns approximately 15 percent of Seabrook, to auction its share of the plant
with NU's share.  As part of the agreement, if the unaffiliated joint owner's
share of Seabrook sells for less than $87.2 million, NU will provide up to
$17.4 million to compensate for any shortfall.  NU also will share in the
benefits if that share of Seabrook exceeds $87.2 million.  Additionally, under
the agreement, NU will top-off certain decommissioning obligations above a
defined level.

Massachusetts:  A settlement has been reached with the Massachusetts Attorney
General finalizing a $155 million securitization plan.  WMECO expects to
receive approval of its securitization plan in February 2001.

B.   NUCLEAR GENERATION ASSETS DIVESTITURE

On August 7, 2000, CL&P, WMECO and certain other joint owners reached an
agreement to sell substantially all of the Millstone units, located in
Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including
approximately $105 million for nuclear fuel.  Dominion has also agreed to
assume responsibility for decommissioning the three units and NU will transfer
to Dominion all funds in the Millstone decommissioning trust.  Additionally,
NU is obligated to top-off the decommissioning trust if its value does not
equal a previously agreed upon level as defined.  NU expects to close on the
sale of Millstone as early as the end of March 2001.

If the transaction is consummated as proposed, CL&P and WMECO would receive
gross proceeds of approximately $843.2 million and $196.2 million on a pretax
basis for their respective ownership interests.  The proceeds from the sale of
these interests will be used to reduce the companies' stranded costs under
restructuring and the cash proceeds will be used to repay subsidiary debt and
capital lease obligations and to return equity capital to the parent company.
The DPUC approved the recovery of Millstone-related stranded costs not offset
by asset divestiture proceeds.  Pursuant to the DPUC order, CL&P will seek
recovery of Millstone post-1997 capital additions totaling $50 million.  The
OCC has appealed CL&P's ability to recover these costs.  PSNH will receive
$26 million on a pretax basis, which will be reflected as a gain in accordance
with the Settlement Agreement.

In connection with the prior settlement of Millstone 3 joint owner claims, if
the aforementioned transaction is consummated as proposed, the NU system will
record a pretax gain in excess of $150 million.  These settlements included
clauses which allowed NU to retain sale proceeds for the joint owners interests
in the units in excess of certain agreed upon amounts.

By the end of 2002, PSNH expects to complete the sale of its fossil and
hydroelectric generation assets, as well as NAEC's ownership share of Seabrook.
CL&P intends to sell its interest in Seabrook, when NAEC sells theirs.

C.   ENVIRONMENTAL MATTERS

The NU system is subject to environmental laws and regulations intended to
mitigate or remove the effect of past operations and improve or maintain the
quality of our environment.  As such, the NU system has an active environmental
auditing and training program and believes it is substantially in compliance
with the current laws and regulations.

However, the normal course of operations may involve activities and substances
that expose the NU system to potential liabilities of which management cannot
determine the outcome.  Additionally, management cannot determine the outcome
for liabilities that may be imposed for past acts, even though such past acts
may have been lawful at the time they occurred.  Management does not believe,
however, that this will have a material impact on the NU system's financial
statements.

Based upon currently available information for the estimated remediation costs
as of December 31, 2000 and 1999, including Yankee in 2000, the liability
recorded by the NU system for its estimated environmental remediation costs
amounted to $58.2 million and $24.8 million, respectively.

D.   SPENT NUCLEAR FUEL DISPOSAL COSTS

Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC must
pay the DOE for the disposal of spent nuclear fuel and high-level radioactive
waste.  The DOE is responsible for the selection and development of
repositories for, and the disposal of, spent nuclear fuel and high-level
radioactive waste.  For nuclear fuel used to generate electricity prior to
April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full
liability and payment must be made prior to the first delivery of spent fuel
to the DOE.  Until such payment is made, the outstanding balance will continue
to accrue interest at the 3-month treasury bill yield rate.  As of December 31,
2000 and 1999, fees due to the DOE for the disposal of Prior Period Fuel were
$240.3 million and $226.5 million, respectively, including interest costs of
$158.2 million and $144.3 million, respectively.

Fees for nuclear fuel burned on or after April 7, 1983, are billed currently
to customers and paid to the DOE on a quarterly basis.  NU is responsible for
fees to be paid for fuel burned until the divestiture of the Millstone and
Seabrook nuclear units.

E.   NUCLEAR INSURANCE CONTINGENCIES

Insurance policies covering the NU system's nuclear facilities have been
purchased for the primary cost of repair, replacement or decontamination of
utility property, certain extra costs incurred in obtaining replacement power
during prolonged accidental outages and the excess cost of repair, replacement
or decontamination or premature decommissioning of utility property.

The NU system is subject to retroactive assessments if losses under those
policies exceed the accumulated funds available to the insurer.  The maximum
potential assessments with respect to losses arising during the current policy
year for the primary property insurance program, the replacement power policies
and the excess property damage policies are $8.2 million, $4.1 million and
$10.2 million, respectively.  In addition, insurance has been purchased in the
aggregate amount of $200 million on an industry basis for coverage of worker
claims.

Under certain circumstances, in the event of a nuclear incident at one of the
nuclear facilities covered by the federal government's third-party liability
indemnification program, the NU system could be assessed liabilities in
proportion to its ownership interest in each of its nuclear units up to $83.9
million.  The NU system's payment of this assessment would be limited to, in
proportion to its ownership interest in each of its nuclear units, $10 million
in any one year per nuclear unit.  In addition, if the sum of all claims and
costs from any one nuclear incident exceeds the maximum amount of financial
protection, the NU system would be subject to an additional 5 percent, or $4.2
million, liability, in proportion to its ownership interests in each of its
nuclear units.  Based upon its ownership interests in the Millstone units and
in Seabrook, the NU system's maximum liability, including any additional
assessments, would be $271 million per incident, of which payments would be
limited to $30.8 million per year.  In addition, through purchased-power
contracts with VYNPC, the NU system would be responsible for up to an
additional assessment of $14.1 million per incident, of which payments would
be limited to $1.6 million per year.

NU expects to terminate its nuclear insurance upon the divestiture of its
nuclear units.

F.   LONG-TERM CONTRACTUAL ARRANGEMENTS

Yankee Companies:  Under the terms of their agreements, the NU system companies
paid their ownership (or entitlement) shares of costs, which included
depreciation, operation and maintenance (O&M) expenses, taxes, the estimated
cost of decommissioning, and a return on invested capital.  These costs were
recorded as purchased-power expenses.  The total cost of purchases under
contracts with VYNPC amounted to $24.9 million in 2000, $29.2 million in 1999
and $27.3 million in 1998.  VYNPC is in the process of selling its nuclear
unit.  Upon completion of the sale, these long-term contracts will be
terminated.

Nonutility Generators (NUGs):  CL&P, PSNH and WMECO have entered into various
arrangements for the purchase of capacity and energy from NUGs.  The total cost
of purchases under these arrangements amounted to $482.1 million in 2000,
$461.8 million in 1999 and $459.7 million in 1998.  The companies are in the
process of renegotiating the terms of these contracts through either a contract
buydown or buyout.  The companies expect any payments to the NUGs as result of
these renegotiations to be recovered from the companies' customers.

Hydro-Quebec:  Along with other New England utilities, CL&P, PSNH, WMECO, and
HWP have entered into agreements to support transmission and terminal
facilities to import electricity from the Hydro-Quebec system in Canada.  CL&P,
PSNH, WMECO, and HWP are obligated to pay, over a 30-year period ending in
2020, their proportionate shares of the annual O&M expenses and capital costs
of those facilities.

Estimated Annual Costs:   The estimated annual costs of the NU system's
significant long-term contractual arrangements, absent the effects of any
contract terminations, buydowns or buyouts are as follows:

- ------------------------------------------------------------------------------
                                   2001     2002     2003     2004     2005
- ------------------------------------------------------------------------------
                                             (Millions of Dollars)

VYNPC.............               $ 28.5    $ 28.9   $ 29.1   $ 32.0   $ 30.1
NUGs..............                480.2     489.2    500.6    487.3    496.8
Hydro-Quebec......                 27.9      27.0     26.0     25.0     24.1
- ------------------------------------------------------------------------------

Select Energy:  Select Energy maintains long-term agreements to purchase energy
in the normal course of business as part of its portfolio of resources to meet
its actual or expected sales commitments.  The aggregate amount of these
purchase contracts was $1.94 billion at December 31, 2000.

These contracts extend through 2004 as follows:

- -------------------------------------------------------------------------------
(Millions of Dollars)
- -------------------------------------------------------------------------------
Year
- -------------------------------------------------------------------------------
2001                             $1,418.3
2002                                266.2
2003                                228.5
2004                                 28.0
- -------------------------------------------------------------------------------
Total                            $1,941.0
- -------------------------------------------------------------------------------

7.   NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS

Millstone and Seabrook:  The NU system operating nuclear power plants,
Millstone 2 and 3 and Seabrook, have service lives that are expected to end
during the years 2015 through 2026, and upon retirement, must be
decommissioned.  Millstone 1's expected service life was to end in 2010,
however, in July 1998, restart activities were discontinued and decommissioning
of the unit began.  In connection with the sale of the Millstone units,
Dominion has agreed to assume responsibility for decommissioning.  Until the
divestiture, CL&P, PSNH and WMECO recover sufficient amounts through their
allowed rates related to decommissioning costs.

The estimated cost of decommissioning Millstone 2, in year end 2000 dollars,
is $430.6 million.  The NU system's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook, in year end 2000 dollars, is $440.8
million and $234.6 million, respectively.  Nuclear decommissioning costs are
accrued over the expected service lives of the units and are included in
depreciation expense and the accumulated provision for depreciation.  Nuclear
decommissioning expenses for these units amounted to $35.5 million in 2000,
$30.6 million in 1999 and $27.9 million in 1998.  Nuclear decommissioning
expenses for Millstone 1 were $23.1 million in 2000, $25.7 million in 1999
and $19.8 million in 1998.  Through December 31, 2000 and 1999, total
decommissioning expenses of $304.4 million and $260.6 million, respectively,
have been collected from customers and are reflected in the accumulated
provision for depreciation.

External decommissioning trusts have been established for the costs of
decommissioning the Millstone units.  Payments for the NU system's ownership
share of the cost of decommissioning Seabrook are paid to an independent
decommissioning financing fund managed by the state of New Hampshire.
Funding of the estimated decommissioning costs assumes after-tax earnings
on the Millstone and Seabrook decommissioning funds of 5.5 percent and
6.5 percent, respectively.

As of December 31, 2000 and 1999, $278.5 million and $239.7 million,
respectively, have been transferred to external decommissioning trusts.
Earnings on the decommissioning trusts increase the decommissioning trust
balances and the accumulated provisions for depreciation.  Unrealized gains and
losses associated with the decommissioning trusts also impact the balance of
the trusts and the accumulated provisions for depreciation.  The fair values
of the amounts in the external decommissioning trusts were $450.8 million and
$410.2 million at December 31, 2000 and 1999, respectively.  Upon divestiture,
balances in the decommissioning trusts will be transferred to the buyer.
NU is obligated to top-off the Millstone decommissioning trust if its value
does not equal an agreed upon amount at closing, pursuant to the conditions
set forth in the purchase and sale agreement.

Yankee Companies:  VYNPC owns and operates a nuclear generating unit with a
service life that is expected to end in 2012.  The NU system's ownership share
of estimated costs, in year end 2000 dollars, of decommissioning this unit is
$72.3 million.  In 1999, VYNPC agreed to sell its nuclear generating unit for
$22 million to an unaffiliated company.  Among other commitments, the acquiring
company agreed to assume the obligation to decommission the unit after it is
taken out of service, and the owners of VYNPC (including CL&P, WMECO and PSNH)
agreed to fund their shares of the decommissioning costs up to a negotiated
amount.  Subsequent to the time that agreement was executed, the original
proposed acquiring company has increased the price it agreed to pay and three
other unaffiliated companies have indicated their interest in buying VYNPC's
generating unit on terms that have not been disclosed.  At present, CL&P,
WMECO and PSNH expect that the unit will be sold, but the identity of the owner
and the terms of sale, including price, future decommissioning obligations and
future power purchase obligations, are not known.

As of December 31, 2000 and 1999, NU's remaining estimated obligation,
including decommissioning for the units owned by CYAPC, YAEC and MYAPC, which
have been shut down was $244.6 million and $358.4 million, respectively.

8.   MARKET RISK AND RISK MANAGEMENT INSTRUMENTS

Competitive Energy Subsidiaries:  Select Energy provides both firm requirement
energy services to its customers and performs energy trading and marketing
activities.  Select Energy manages its exposure to risk from existing
contractual commitments and provides risk management services to its customers
through forward contracts, futures, over-the-counter swap agreements, and
options (commodity derivatives).

Select Energy has utilized the sensitivity analysis methodology to disclose the
quantitative information for the commodity price risks.  Sensitivity analysis
provides a presentation of the potential loss of future earnings, fair values
or cash flows from market risk-sensitive instruments over a selected time
period due to one or more hypothetical changes in commodity prices, or other
similar price changes.

Commodity Price Risk - Trading Activities:  As a market participant in the
Northeast area of the United States, Select Energy conducts commodity-trading
activities in electricity and its related products, oil and natural gas and
therefore experiences net open positions.  Select Energy manages these open
positions with strict policies which limit its exposure to market risk and
require daily reporting to management of potential financial exposure.
Commodity derivatives utilized for trading purposes are accounted for using
the mark-to-market method, under EITF Issue No. 98-10, "Accounting for Energy
Trading and Risk Management Activities."  Under this methodology, these
instruments are adjusted to market value, and the unrealized gains and losses
are recognized in income in the current period in the consolidated statements
of income as operating expenses - other and in the consolidated balance sheets
as prepayments and other.  The mark-to-market position at December 31, 2000,
was a positive $13.8 million.

Under sensitivity analysis, the fair value of the portfolio is a function of
the underlying commodity, contract prices and market prices represented by
each derivative commodity contract.  For swaps, forward contracts and options,
market value reflects management's best estimates considering over-the-counter
quotations, time value and volatility factors of the underlying commitments.
Exchange-traded futures and options are subject to market, based on closing
exchange prices.

As of December 31, 2000, Select Energy has calculated the market price
resulting from a 10 percent unfavorable change in forward market prices.  That
10 percent change would result in approximately a $1 million decline in the
fair value of the Select Energy trading portfolio.  In the normal course of
business, Select Energy also faces risks that are either nonfinancial or
nonquantifiable.  Such risks principally include credit risk, which is not
reflected in the sensitivity analysis above.

Commodity Price Risk - Nontrading Activities:  Select Energy utilizes
derivative financial and commodity instruments (derivatives), including futures
and forward contracts, to reduce market risk associated with fluctuations in
the price of electricity and natural gas sold under firm commitments with
certain customers.  Select Energy also utilizes derivatives, including price
swap agreements, call and put option contracts, and futures and forward
contracts, to manage the market risk associated with a portion of its
anticipated supply requirements.

Gains or losses on derivatives associated with firm commitments are recognized
as adjustments to cost of sales or revenues when the associated transactions
affect earnings.  Gains and losses on derivatives associated with forecasted
transactions are recognized when such forecasted transactions affect earnings.
If a derivative instrument is terminated early because it is probable that a
transaction or forecasted transaction will not occur, any gain or loss as of
such date is immediately recognized in earnings.

When conducting sensitivity analysis of the change in the fair value of Select
Energy's electricity, oil and natural gas portfolio, which would result from
a hypothetical change in the future market price of electricity, oil and
natural gas, the fair value of the contracts are determined from models which
take into account estimated future market prices of electricity, oil and
natural gas, the volatility of the market prices in each period, as well as
the time value factors of the underlying commitments.  In most instances,
market prices and volatility are determined from quoted prices on the
futures exchange.

Select Energy has determined a hypothetical change in the fair value for its
nontrading electricity, natural gas and oil contracts, assuming a 10 percent
unfavorable change in forward market prices.  As of December 31, 2000, an
unfavorable 10 percent change in forward market price would have resulted in
a decrease in fair value of approximately $52 million.

The impact of a change in electricity, natural gas and oil prices on Select
Energy's nontrading contracts on December 31, 2000, is not necessarily
representative of the results that will be realized when these contracts go to
eventual physical delivery.

Select Energy also maintains natural gas service agreements with certain
customers to supply gas at fixed prices for terms extending through 2003.
Select Energy has hedged its gas supply risk under these agreements through
NYMEX contracts.  Under these contracts, the purchase price of a specified
quantity of gas is effectively fixed over the term of the gas service
agreements, which extend through 2002.  As of December 31, 2000, the NYMEX
contracts had a notional value of $18.8 million and a positive mark-to-
market position of $14.9 million.

Regulated Entities:

Interest Rate Risk - Nontrading Activities:  The company manages its interest
rate risk exposure by maintaining a mix of fixed and variable rate debt.  In
addition, Yankee has entered into an interest rate sensitive derivative.
Yankee uses swap instruments with financial institutions to exchange fixed-rate
interest obligations to a blend between fixed and variable-rate obligations
without exchanging the underlying notional amounts.  These instruments convert
fixed interest rate obligations to variable rates.  The notional amounts
parallel the underlying debt levels and are used to measure interest to be paid
or received and do not represent the exposure to credit loss.  As of
December 31, 2000, Yankee had outstanding agreements with a total notional
value of $48 million and a negative mark-to-market position of $0.8 million.

For the fair value, see Note 10 for the disclosure of NU's debt.

Commodity Price Risk - Nontrading Activities:  Yankee Gas maintains a master
swap agreement with a certain customer to supply gas at fixed prices for a
10-year term extending through 2005.  Under this master swap agreement, the
purchase price of a specified quantity of gas is effectively fixed over the
term of the gas service agreement, which extends through 2005.  As of
December 31, 2000, the commodity swap agreement had a notional value of
$17.1 million and a positive mark-to-market position of $5.4 million.

9.   MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY

CL&P Capital LP (CL&P LP), a subsidiary of CL&P, previously had issued $100
million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS),
Series A.  CL&P has the sole ownership in CL&P LP, as a general partner,
and is the guarantor of the MIPS securities.  Subsequent to the MIPS issuance,
CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1
million capital contribution, back to CL&P in the form of an unsecured
debenture.  CL&P consolidates CL&P LP for financial reporting purposes.
Upon consolidation, the unsecured debenture is eliminated, and the MIPS
securities are accounted for as a minority interest.

10.  FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value
of each of the following financial instruments:

Cash and cash equivalents:  The carrying amounts approximate fair value due to
the short-term nature of cash and cash equivalents.

Supplemental Executive Retirement Plan (SERP) Investments:  Investments held
for the benefit of the SERP are recorded at fair market value.  The investments
having a cost basis of $6.5 million and $5.8 million held for benefit of the
SERP were recorded at their fair market values at December 31, 2000 and 1999,
of $10.1 million and $9.2 million, respectively.

Nuclear decommissioning trusts:  The investments held in the NU system
companies' nuclear decommissioning trusts were marked-to-market by $117.6
million as of December 31, 2000, and $129 million as of December 31, 1999,
with corresponding offsets to the accumulated provision for depreciation.
The amounts adjusted in 2000 and in 1999 represent cumulative net unrealized
gains.  Cumulative gross unrealized holding losses were immaterial for both
2000 and 1999.

Preferred stock and long-term debt:  The fair value of the NU system's fixed-
rate securities is based upon the quoted market price for those issues or
similar issues.  Adjustable rate securities are assumed to have a fair value
equal to their carrying value.  The carrying amounts of the NU system's
financial instruments and the estimated fair values are as follows:

- -------------------------------------------------------------------------------
                                               At December 31, 2000
- -------------------------------------------------------------------------------
                                               Carrying          Fair
(Millions of Dollars)                           Amount          Value
- -------------------------------------------------------------------------------
Preferred stock not subject to
  mandatory redemption...............         $  136.2         $ 159.9

Preferred stock subject to
  mandatory redemption...............             40.8            42.0

Long-term debt -
  First mortgage bonds...............          1,008.1         1,012.5
  Other long-term debt...............          1,342.2         1,290.6

MIPS..................................           100.0           100.5
- -------------------------------------------------------------------------------

- -------------------------------------------------------------------------------
                                               At December 31, 1999
- -------------------------------------------------------------------------------
                                               Carrying          Fair
(Millions of Dollars)                           Amount          Value
- -------------------------------------------------------------------------------
Preferred stock not subject to
  mandatory redemption...............         $  136.2         $ 164.0

Preferred stock subject to
  mandatory redemption...............            167.5           166.8

Long-term debt -
  First mortgage bonds...............          1,193.2         1,209.5
  Other long-term debt...............          1,638.3         1,593.1

MIPS..................................           100.0            97.3
- -------------------------------------------------------------------------------

11.  OTHER COMPREHENSIVE INCOME

The accumulated balance for each other comprehensive income item is as follows:

- -------------------------------------------------------------------------------
                                                        Current
                                       December 31,     Period     December 31,
(Thousands of Dollars)                     1999         Change         2000
- -------------------------------------------------------------------------------
Foreign currency translation
  adjustments.......................      $ -           $ -          $   -
Unrealized gains on securities......       2,137         245          2,382
Minimum pension liability
  adjustments.......................        (613)          -           (613)
- -------------------------------------------------------------------------------
Accumulated other
  comprehensive income............        $1,524        $245         $1,769
- -------------------------------------------------------------------------------

- -------------------------------------------------------------------------------
                                                        Current
                                       December 31,     Period     December 31,
(Thousands of Dollars)                     1998         Change         1999
- -------------------------------------------------------------------------------
Foreign currency translation
  adjustments.......................      $   (1)       $  1         $  -
Unrealized gains on securities......       2,019         118          2,137
Minimum pension liability
  adjustments.......................        (613)          -           (613)
- -------------------------------------------------------------------------------
Accumulated other
  comprehensive income............        $1,405        $119         $1,524
- -------------------------------------------------------------------------------

The changes in the components of other comprehensive income are reported net of
the following income tax effects:

- -------------------------------------------------------------------------------
(Thousands of Dollars)                            2000      1999      1998
- -------------------------------------------------------------------------------
Foreign currency translation adjustments         $  -      $ -       $ -
Unrealized gains on securities                    (147)     (71)     (1,222)
Minimum pension liability adjustments               -       -           398
- -------------------------------------------------------------------------------
Other comprehensive income                       $(147)    $(71)     $ (824)
- -------------------------------------------------------------------------------

12.  EARNINGS PER SHARE

Earnings per share (EPS) is computed based upon the weighted average number of
common shares outstanding during each year.  Diluted earnings per share is
computed on the basis of the weighted average number of common shares
outstanding plus the potential dilutive effect if certain securities are
converted into common stock.

The following table sets forth the components of basic and diluted EPS:

- -------------------------------------------------------------------------------
(Millions of Dollars,
except share information)                 2000          1999         1998
- -------------------------------------------------------------------------------
Income/(loss) after
  interest charges                       $219.5         $57.0      $  (120.4)
Preferred dividends
  of subsidiaries                          14.2          22.8           26.4
- -------------------------------------------------------------------------------
Income/(loss) before
  extraordinary loss                      205.3          34.2         (146.8)
Extraordinary loss,
  net of tax benefit                     (233.9)           -             -
- -------------------------------------------------------------------------------
Net (loss)/income                        $(28.6)        $34.2        $(146.8)
- -------------------------------------------------------------------------------
Basic EPS common shares
  outstanding (average)             141,549,860   131,415,126    130,549,760
Dilutive effect of
  employee stock options                417,356       616,447           -    (a)
- -------------------------------------------------------------------------------
Diluted EPS common
  shares outstanding (average)      141,967,216   132,031,573    130,549,760
- -------------------------------------------------------------------------------
Basic earnings/(loss)
  per common share:
  Income/(loss) before
    extraordinary loss                   $ 1.45         $0.26         $(1.12)
  Extraordinary loss,
    net of tax benefit                    (1.65)          -              -
- -------------------------------------------------------------------------------
  Net (loss)/income                      $(0.20)        $0.26         $(1.12)
- -------------------------------------------------------------------------------
Diluted earnings/(loss)
  per common share:
  Income/(loss) before
    extraordinary loss                   $ 1.45         $0.26         $(1.12)
  Extraordinary loss,
    net of tax benefit                    (1.65)          -              -
- -------------------------------------------------------------------------------
  Net (loss)/income                      $(0.20)        $0.26         $(1.12)
- -------------------------------------------------------------------------------

(a) The addition of dilutive potential common shares would be anti-dilutive
    for 1998 and was not included.

13.  MODE 1

On November 23, 1999, NEON Communications, Inc. (NEON) entered into agreements
with two unaffiliated companies.  Under the terms of the agreements, NEON will
provide network transport and carrier services in its service areas and that of
the two unaffiliated companies and each company will provide connectivity from
the backbone system to their respective local loops.  Additionally, each
company will manage their local distribution into their respective end-users'
locations.  NEON will also develop, operate and market the combined
telecommunications infrastructure created under the two agreements.  As the
agreements are implemented, the two unaffiliated companies will ultimately
obtain a total of approximately 4.6 million shares of NEON common stock, or
approximately 12 percent and 10 percent ownership interests, respectively.
Each unaffiliated company will also nominate one member to the NEON Board of
Directors.  Prior to the implementation of these agreements, Mode 1 had
approximately a 29 percent ownership interest in the common shares of NEON.

In conjunction with the consummation of the agreements on September 14, 2000,
a portion of the total common shares to be issued were issued to the two
unaffiliated companies.  The remainder of these shares will be issued as the
two unaffiliated companies complete certain milestones, as defined in their
respective agreements.

The issuance of these shares had the effect of decreasing Mode 1's ownership
interest in NEON's outstanding common shares to approximately 25 percent.
However, these shares were issued at an amount greater than Mode 1's
investment, resulting in a $19.8 million pretax increase to Mode 1's equity.
NU's accounting policy is to recognize the gain or loss from this type of
change in ownership interest in net income.

14.  SEGMENT INFORMATION

The NU system is organized between regulated utilities (electric and gas for
the 12 months and 10 months, respectively, ended December 31, 2000, and
electric only for the year ended December 31, 1999) and competitive energy
subsidiaries.  The regulated utilities segment represents approximately 85
percent and 86 percent of the NU system's total revenues for the year ended
December 31, 2000 and 1999, respectively, and is comprised of several business
units.

Regulated utilities revenues primarily are derived from residential, commercial
and industrial customers and are not dependent on any single customer.  The
competitive energy subsidiaries segment has two major customers, one
unaffiliated company and CL&P.  Their purchases represented approximately 15
percent and 34 percent, respectively, of total competitive energy subsidiaries'
revenues for the year ended December 31, 2000.  Purchases from the unaffiliated
company represented approximately 43 percent of total competitive energy
subsidiaries' revenues for the year ended December 31, 1999.  There were no
purchases from CL&P in 1999.

The competitive energy subsidiaries segment in the following table includes
HEC, a provider of energy management, demand-side management and related
consulting services for commercial, industrial and institutional electric
companies and electric utility companies; HWP, a company engaged in the
production and distribution of electric power; NGC, a corporation that acquires
and manages generation facilities; NGS, a corporation that maintains and
services any fossil or hydroelectric facility that is acquired or contracted
with for fossil or hydroelectric generation services, and; Select Energy, a
corporation engaged in the marketing, transportation, storage, and sale of
energy commodities, at wholesale, in designated geographical areas and in the
marketing of electricity to retail customers.

Other in the following table includes the results for Mode 1, an investor in
a fiber-optic communications network.  Mode 1 had earnings of $3.8 million
and a net loss of $4.3 million for years ended December 31, 2000 and 1999,
respectively.  See Note 13 for further information related to Mode 1's
earnings for the year ended December 31, 2000.  Other also includes the results
of the nonenergy related subsidiaries of Yankee.  Interest expense included in
Other primarily relates to the debt of NU parent.  Inter-segment eliminations
of revenues and expenses are also included in Other.

<TABLE>
- --------------------------------------------------------------------------------------------
                                       For the Year Ended December 31, 2000
- --------------------------------------------------------------------------------------------
                          Regulated Utilities      Competitive      Eliminations
(Millions of              -------------------         Energy            and
  Dollars)                 Electric      Gas       Subsidiaries        Other        Total
- --------------------------------------------------------------------------------------------
<S>                        <C>          <C>          <C>
Operating revenues         $4,738.5     $251.2       $1,894.9        $(1,008.0)   $ 5,876.6
Operating expenses         (4,311.3)    (233.7)      (1,831.7)           964.9     (5,411.8)
- --------------------------------------------------------------------------------------------
Operating income/(loss)       427.2       17.5           63.2            (43.1)       464.8
Other income/(loss)            48.2       (4.1)          (3.1)            13.0         54.0
Interest expense             (191.9)     (12.2)         (53.4)           (41.8)      (299.3)
Preferred dividends           (14.2)        -              -                -         (14.2)
- --------------------------------------------------------------------------------------------
Income/(loss) before
  extraordinary loss          269.3        1.2            6.7            (71.9)       205.3
Extraordinary loss,
  net of tax benefit         (214.2)        -           (19.7)              -        (233.9)
- --------------------------------------------------------------------------------------------
Net income/(loss)          $   55.1     $  1.2       $  (13.0)       $   (71.9)   $   (28.6)
- --------------------------------------------------------------------------------------------
Total assets               $9,620.0     $912.6       $  684.1        $  (999.6)   $10,217.1
- --------------------------------------------------------------------------------------------
</TABLE>

- -------------------------------------------------------------------------------
For the Year Ended December 31, 1999
- -------------------------------------------------------------------------------
                             Regulated    Competitive   Eliminations
                              Electric      Energy          and
(Millions of Dollars)        Utilities    Subsidiaries     Other        Total
- -------------------------------------------------------------------------------
Operating revenues           $3,846.1        $648.8       $(23.7)     $4,471.2
Operating expenses           (3,454.3)       (688.2)        15.8      (4,126.7)
- -------------------------------------------------------------------------------
Operating income/(loss)         391.8         (39.4)        (7.9)        344.5
Other (loss)/income             (43.2)          5.6         13.7         (23.9)
Interest expense               (245.5)         (3.2)       (14.9)       (263.6)
Preferred dividends             (22.8)           -            -          (22.8)
- -------------------------------------------------------------------------------
Net income/(loss)            $   80.3        $(37.0)      $ (9.1)     $   34.2
- -------------------------------------------------------------------------------
Total assets                 $9,302.6        $308.2       $ 77.3      $9,688.1
- -------------------------------------------------------------------------------

15.  SUBSEQUENT EVENTS

A.   MERGER AGREEMENT WITH CONSOLIDATED EDISON, INC.

In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the
approvals needed to complete the merger announced in October 1999.
Shareholders from both companies approved the merger in April 2000, and all
state regulatory approvals were granted by the end of the year.  Additionally,
the FERC approved the merger in May 2000, the Nuclear Regulatory Commission
approved the transaction in August 2000, and the United States Department of
Justice approved the merger in February 2001.  Necessary approval from the SEC
was expected to be received in mid-March 2001.

On February 28, 2001, NU's Board of Trustees requested that Con Edison provide
reasonable assurance, in writing, that it intended to comply with the terms
of the definitive merger agreement between the two companies.  This included
assurances that Con Edison would consummate the pending merger at the price set
forth in the agreement promptly following the receipt of SEC approval.
The original request for assurance was to be received by March 2, 2001, however
that date was later extended to March 5, 2001.  On March 5, 2001, Con Edison
advised NU that it was not willing to close the merger on the agreed terms.
NU notified Con Edison that it was treating its refusal to proceed on the terms
set forth in the merger agreement as a repudiation and breach of the merger
agreement, and that NU would file suit to obtain the benefits of the
transaction as negotiated for NU shareholders.  On March 6, 2001, Con Edison
filed suit in the U.S. District Court for the Southern District of New York
(Southern District), seeking declaratory judgment that NU failed to satisfy
conditions precedent under the merger agreement.  On March 12, 2001, NU filed
suit against Con Edison in the Southern District seeking damages in excess of
$1 billion arising from Con Edison's breach of the merger agreement.

Under the terms of the proposed transaction, had it proceeded to closing, NU
shareholders would have received a base price of $25 per share, in a
combination of cash and Con Edison common stock, plus $0.0034 per share per
day, or approximately $0.10 per share per month, for each day that the merger
did not close after August 5, 2000.  Additionally, NU shareholders would have
received another $1 per share as a result of a recommendation by the DPUC's
Utility Operations Management Analysis Unit that the DPUC accept the results
of the Millstone auction that were announced on August 7, 2000.  The DPUC
approved the sale in January 2001.  The $25 per share base price, the
$0.0034 per share per day compensation and the additional $1 per share
resulting from the Millstone auction would have been subject to the collar
mechanism described in the merger proxy statement dated February 29, 2000,
to the extent NU shareholders received Con Edison stock.  Assuming that Con
Edison's stock price had averaged between $36 and $46 per share during the
applicable pricing period, as defined, NU shareholders would have received
approximately $26.84 per share, were the merger to have closed on April 10,
2001.

B.   FERC DECISION

On March 6, 2001, the FERC issued an order on rehearing related to the
price for installed capacity (ICAP) in New England.  The FERC reinstituted
the previously approved $8.75 per kilowatt-month charge for installed
capacity, but made the price effective April 1, 2001.  In an earlier
decision in December 2000, the FERC had made the charge effective as of
August 1, 2000, but in its revised decision, the FERC substituted a $0.17
per kilowatt-month charge for the period of August 2000 through March 2001.
Because NU was a major seller of installed generating capacity during the
last five months of 2000, the FERC's revised decision with respect to the
August through March time period reduced NU's fourth quarter revenues by
$24.6 million and lowered earnings by $14.8 million, or $0.10 per share.
Although it is important that FERC understood the going forward need for a
capacity charge that approximates the cost of installing new generation in
New England, management currently plans on requesting that FERC review the
inconsistency of their decision with regard to the change in the effective
date of the $8.75 charge.

<TABLE>
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
<CAPTION>
                                                   Quarter Ended (a) (b)
                                                   ---------------------
(Thousands of Dollars,
except per share information)      March 31       June 30     September 30    December 31
                                   --------       -------     ------------    -----------
<S>                              <C>            <C>            <C>            <C>
2000
Operating Revenues               $1,382,321     $1,414,973     $1,581,947     $1,497,379
Operating Income                 $  135,409     $   99,092     $  115,761     $  114,501

Income Before Extraordinary
  Loss                           $   74,587     $   12,206     $   65,543     $   52,959
Extraordinary Loss,
  Net of Tax Benefit                      -              -              -       (233,881)
                                 ----------     ----------     ----------     ----------
Net Income/(Loss)                $   74,587     $   12,206     $   65,543     $ (180,922)
                                 ==========     ==========     ==========     ==========

Basic Earnings/(Loss) Per Common Share:
  Income Before Extraordinary
    Loss                         $     0.55     $     0.09     $     0.46     $     0.37
  Extraordinary Loss,
    Net of Tax Benefit           $        -     $        -     $        -     $    (1.63)
                                 ----------     ----------     ----------     ----------
  Net Income/(Loss)              $     0.55     $     0.09     $     0.46     $    (1.26)
                                 ==========     ==========     ==========     ==========

Diluted Earnings/(Loss) Per Common Share:
  Income Before Extraordinary
    Loss                         $     0.55     $     0.08     $     0.45     $     0.37
  Extraordinary Loss,
    Net of Tax Benefit           $        -     $        -     $        -     $    (1.63)
                                 ----------     ----------     ----------     ----------
  Net Income/(Loss)              $     0.55     $     0.08     $     0.45     $    (1.26)
                                 ==========     ==========     ==========     ==========

1999
Operating Revenues               $1,043,407     $1,038,569     $1,240,539     $1,148,736
Operating Income                 $   89,638     $   56,492     $  110,544     $   87,863
Net Income/(Loss)                $   18,444     $      228     $   31,218     $  (15,674)
Basic and Diluted Earnings/(Loss)
  Per Common Share               $     0.14     $        -     $     0.24     $    (0.12)
</TABLE>

(a)  Certain reclassifications of prior years' data have been made to conform
     with the current year's presentation.
(b)  Summation of quarterly data may not equal annual data due to rounding.


<TABLE>
CONSOLIDATED GENERATION STATISTICS (UNAUDITED)
<CAPTION>
Source of Electric
Energy: (kWh-millions)             2000       1999       1998       1997       1996
                                  ------     ------     ------     ------     ------
<S>                               <C>        <C>        <C>        <C>        <C>
Nuclear - Steam (a)               16,306     13,558      5,679      3,778      9,405
Fossil - Steam                     5,584     10,959     12,505     13,155      9,188
Hydro - Conventional                 686      1,206      1,510      1,260      1,544
Hydro - Pumped Storage               240        944        819        959      1,217
Internal Combustion                    7        262         80        184        206
Energy Used for Pumping             (343)    (1,318)    (1,130)    (1,327)    (1,668)
                                  ------     ------     ------     ------     ------
Net Generation                    22,480     25,611     19,463     18,009     19,892
Purchased and Net Interchange     56,280     43,849     24,945     24,377     22,111
Company Use and Unaccounted For   (3,100)    (2,612)    (2,566)    (2,802)    (2,473)
                                  ------     ------     ------     ------     ------
Net Energy Sold                   75,660     66,848     41,842     39,584     39,530
                                  ======     ======     ======     ======     ======
</TABLE>
(a) Includes the NU system's entitlements in regional nuclear generating
    companies, net of capacity sales and purchases.



<TABLE>
SELECTED CONSOLIDATED FINANCIAL DATA (UNAUDITED)
<CAPTION>
(Thousands of Dollars,
except percentages and
share information)             2000         1999         1998         1997         1996
                           -----------  -----------  -----------  -----------  -----------
<S>                        <C>          <C>          <C>          <C>          <C>
Balance Sheet Data:
  Net Utility Plant        $ 3,547,215  $ 3,947,434  $ 6,170,881  $ 6,463,158  $ 6,732,165
  Total Assets              10,217,149    9,688,052   10,387,381   10,414,412   10,741,748
  Total Capitalization (a)   4,739,417    5,216,456    6,030,402    6,472,504    6,659,617
  Obligations Under
    Capital Leases (a)         159,879      181,293      209,279      207,731      206,165

Income Data:
  Operating Revenues       $ 5,876,620  $ 4,471,251  $ 3,767,714  $ 3,834,806  $ 3,792,148

  Income/(Loss) Before
    Extraordinary Loss     $   205,295  $    34,216  $  (146,753) $  (129,962) $    38,929
Extraordinary Loss,
    Net of Tax Benefit        (233,881)           -            -            -            -
                           -----------  -----------  -----------  -----------  -----------
  Net (Loss)/Income        $   (28,586) $    34,216  $  (146,753) $  (129,962) $    38,929
                           ===========  ===========  ===========  ===========  ===========

Common Share Data:
  Basic and Diluted
    Earnings/(Loss)
    Per Common Share:
      Income/(Loss) Before
        Extraordinary Loss    $ 1.45        $ 0.26       $(1.12)      $(1.01)      $ 0.30
      Extraordinary Loss,
        Net of Tax Benefit     (1.65)           -            -            -            -
                               ------       ------       ------       ------       ------
      Net (Loss)/Income       $(0.20)       $ 0.26       $(1.12)      $(1.01)      $ 0.30
                              ======        ======       ======       ======       ======

  Basic Common Shares
    Outstanding
    (Average)             141,549,860  131,415,216  130,549,760  129,567,708  127,960,382
  Fully Diluted
    Common Shares
    Outstanding
    (Average)             141,967,216  132,031,573  130,549,760  129,567,708  128,073,261
  Dividends Per Share          $ 0.40       $ 0.10       $    -       $ 0.25       $ 1.38
  Market Price -
    Closing (high)             $24.25       $22.00       $17.25       $14.25       $25.25
  Market Price -
    Closing (low)              $18.25       $13.56       $11.69       $ 7.63       $ 9.50
  Market Price -
    Closing (end of year)      $24.25       $20.56       $16.00       $11.81       $13.13
  Book Value Per
    Share (end of year)        $15.43       $15.80       $15.63       $16.67       $18.02
  Rate of Return Earned
    on Average
    Common Equity (%)            (1.3)         1.6         (7.0)        (5.8)         1.6
  Market-to-Book
    Ratio (end of year)           1.6          1.3          1.0          0.7          0.7

Capitalization:
  Common Shareholders'
    Equity                         47%          40%          34%          34%          35%
  Preferred Stock (a) (b)           4            5            5            6            6
  Long-Term Debt (a)               49           55           61           60           59
                              -------      -------      -------      -------      -------
                                  100%         100%         100%         100%         100%
                              =======      =======      =======      =======      =======
</TABLE>
(a) Includes portions due within one year.
(b) Excludes $100 million of MIPS.



<TABLE>
CONSOLIDATED ELECTRIC SALES STATISTICS (UNAUDITED)
<CAPTION>
                           2000          1999          1998          1997          1996
                        ----------    ----------    ----------    ----------    ----------
<S>                    <C>           <C>           <C>           <C>           <C>
Revenues: (Thousands)
Residential            $1,469,439    $1,517,913    $1,475,363    $1,499,394    $1,501,465
Commercial              1,256,126     1,272,969     1,273,146     1,266,449     1,246,822
Industrial                566,625       560,801       568,913       560,782       565,900
Other Utilities         1,884,082       926,056       336,623       329,764       315,577
Streetlighting
  and Railroads            45,998        45,564        47,682        48,867        48,053
Non-Franchised Sales       16,932        24,659        22,479        21,476         8,360
Miscellaneous              96,666        52,357        16,429        47,446        23,513
                       ----------    ----------    ----------    ----------    ----------
Total Electric          5,335,868     4,400,319     3,740,635     3,774,178     3,709,690
Gas                       461,716          -             -             -             -
Other                      79,036        70,932        27,079        60,628        82,458
                       ----------    ----------    ----------    ----------    ----------
Total                  $5,876,620    $4,471,251    $3,767,714    $3,834,806    $3,792,148
                       ==========    ==========    ==========    ==========    ==========

Sales: (kWh - Millions)
Residential                12,940        12,912        12,162        12,099        12,241
Commercial                 13,023        12,850        12,477        12,091        12,012
Industrial                  7,130         7,050         6,948         6,801         6,820
Other Utilities            42,127        33,575         9,742         8,034         8,032
Streetlighting
  and Railroads               333           314           320           318           319
Non-Franchised Sales          107           147           193           241            50
                       ----------    ----------    ----------    ----------    ----------
Total                      75,660        66,848        41,842        39,584        39,474
                       ==========    ==========    ==========    ==========    ==========

Customers: (average)
Residential             1,576,068     1,569,932     1,555,013     1,535,134     1,532,015
Commercial                166,114       164,932       162,500       159,350       157,347
Industrial                  7,701         7,721         7,847         7,804         7,792
Other                       3,917         3,908         3,890         3,929         3,916
                       ----------    ----------    ----------    ----------    ----------
Total Electric          1,753,800     1,746,493     1,729,250     1,706,217     1,701,070
Gas                       187,000      -             -             -             -
                       ----------    ----------    ----------    ----------    ----------
Total                   1,940,800     1,746,493     1,729,250     1,706,217     1,701,070
                       ==========    ==========    ==========    ==========    ==========

Average Annual Use
  Per Residential
  Customer (kWh)            8,233         8,243         7,799         7,898         8,005
                       ==========    ==========    ==========    ==========    ==========
Average Annual Bill
  Per Residential
  Customer             $   934.94    $   969.38    $   946.80    $   978.72    $   980.19
                       ==========    ==========    ==========    ==========    ==========

Average Revenue per kWh:
Residential                 11.36 cents   11.76 cents   12.14 cents   12.39 cents   12.27 cents
Commercial                   9.65          9.91         10.20         10.47         10.38
Industrial                   7.95          7.95          8.19          8.25          8.30

</TABLE>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4.1.5
<SEQUENCE>2
<FILENAME>0002.txt
<DESCRIPTION>EXHIBIT 4.1.5
<TEXT>


                                                                  EXECUTION COPY


                               TERM LOAN AGREEMENT

                            Dated as of March 1, 2000

                                      Among

                               NORTHEAST UTILITIES
                                   as Borrower

                             THE BANKS NAMED HEREIN

                               FLEET NATIONAL BANK
                              as Syndication Agent

                              THE BANK OF NEW YORK
                             as Documentation Agent

                                       and

                       CANADIAN IMPERIAL BANK OF COMMERCE,
                                 NEW YORK AGENCY
                             as Administrative Agent

<PAGE>

                                TABLE OF CONTENTS
                                                                            Page

                                    ARTICLE I

                        DEFINITIONS AND ACCOUNTING TERMS

SECTION 1.01.    Certain Defined Terms                                        1
SECTION 1.02.    Computation of Time Periods                                 14
SECTION 1.03.    Accounting Terms; Financial Statements                      14
SECTION 1.04.    Computations of Outstandings                                14


                                   ARTICLE II

                                   COMMITMENTS

SECTION 2.01.    The Commitments                                             15
SECTION 2.02.    Fees                                                        15


                                   ARTICLE III

                                CONTRACT ADVANCES

SECTION 3.01.    Contract Advances                                           15
SECTION 3.02.    Terms Relating to the Making of Contract Advances           15
SECTION 3.03.    Making of Advances                                          16
SECTION 3.04.    Repayment of Advances                                       16
SECTION 3.05.    Interest                                                    17

                                        i
<PAGE>

                                TABLE OF CONTENTS
                                   (continued)
                                                                            Page

                                   ARTICLE IV

                                    PAYMENTS

SECTION 4.01.    Payments and Computations                                   19
SECTION 4.02.    Prepayments                                                 20
SECTION 4.03.    Yield Protection                                            21
SECTION 4.04.    Sharing of Payments, Etc.                                   24
SECTION 4.05.    Taxes                                                       25


                                    ARTICLE V

                              CONDITIONS PRECEDENT

SECTION 5.01.    Conditions Precedent to Effectiveness                       26
SECTION 5.02.    Conditions Precedent to Advances on Funding Date.           28
SECTION 5.03.    Reliance on Certificates                                    29


                                   ARTICLE VI

                         REPRESENTATIONS AND WARRANTIES

SECTION 6.01.    Representations and Warranties of the Borrower              29


                                   ARTICLE VII

                                    COVENANTS

SECTION 7.01.    Affirmative Covenants                                       33
SECTION 7.02.    Negative Covenants                                          36
SECTION 7.03.    Financial Covenants                                         41
SECTION 7.04.    Reporting Obligations                                       41

                                       ii
<PAGE>

                                TABLE OF CONTENTS
                                   (continued)
                                                                            Page

                                  ARTICLE VIII

                                    DEFAULTS

SECTION 8.01.    Events of Default                                           44
SECTION 8.02.    Remedies Upon Events of Default                             46


                                   ARTICLE IX

                            THE ADMINISTRATIVE AGENT

SECTION 9.01.    Authorization and Action                                    46
SECTION 9.02.    Administrative Agent's Reliance, Etc.                       47
SECTION 9.03.    CIBC and its Affiliates.                                    47
SECTION 9.04.    Lender Credit Decision                                      48
SECTION 9.05.    Indemnification                                             48
SECTION 9.06.    Successor Administrative Agent                              48
SECTION 9.07.    Other Agents                                                49


                                    ARTICLE X

                                  MISCELLANEOUS

SECTION 10.01.   Amendments, Etc.                                            49
SECTION 10.02.   Notices, Etc.                                               49
SECTION 10.03.   No Waiver of Remedies                                       50
SECTION 10.04.   Costs, Expenses and Indemnification                         50
SECTION 10.05.   Right of Set-off                                            51
SECTION 10.06.   Binding Effect                                              52
SECTION 10.07.   Assignments and Participation                               52
SECTION 10.08.   Confidentiality                                             55
SECTION 10.09.   Waiver of Jury Trial                                        55
SECTION 10.10.   Governing Law                                               55
SECTION 10.11.   Relation of the Parties; No Beneficiary                     56
SECTION 10.12.   Execution in Counterparts                                   56
SECTION 10.13.   Limitation of Liability                                     56

                                       iii
<PAGE>

                                TABLE OF CONTENTS
                                   (continued)
                                                                            Page

                                    SCHEDULES

Schedule I       -      Applicable Lending Offices
Schedule II      -      Pending Actions


                                    EXHIBITS

Exhibit 1.01A    -      Form of Contract Note

Exhibit 3.01     -      Form of Notice of Contract Borrowing

Exhibit 5.01A    -      Form of Opinion of Day, Berry and Howard, Counsel to the
                           Borrower

Exhibit 5.01B    -      Form of Opinion of Jeffrey C. Miller, Assistant
                            General Counsel of NUSCO

Exhibit 5.01C    -      Form of Opinion of King and Spalding, Special New York
                           Counsel to the Administrative Agent

Exhibit 10.07    -      Form of Lender Assignment

                                       iv
<PAGE>

                               TERM LOAN AGREEMENT

                            Dated as of March 1, 2000

THIS TERM LOAN AGREEMENT is made by and among:

(i)      Northeast Utilities, an unincorporated voluntary business association
         organized under the laws of the Commonwealth of Massachusetts ("NU" or
         the "Borrower");

(ii)     The financial institutions (the "Banks") listed on the signature pages
         hereof and the other Lenders (as hereinafter defined) from time to time
         party hereto;

(iii)    Fleet National Bank, as Syndication Agent hereunder;

(iv)     The Bank of New York, as Documentation Agent hereunder; and

(v)      Canadian Imperial Bank of Commerce, a Canadian chartered bank ("CIBC")
         acting through its New York Agency, as Administrative Agent for the
         Lenders hereunder.


                              PRELIMINARY STATEMENT

         The Borrower has requested the Banks to provide the credit facility
hereinafter described in the amounts and on the terms and conditions set forth
herein. The Banks have so agreed on the terms and conditions set forth herein,
and the Administrative Agent has agreed to act as agent for the Lenders on such
terms and conditions.

         Based upon the foregoing and subject to the terms and conditions set
forth in this Agreement, the parties hereto hereby agree as follows:
<PAGE>

                                    ARTICLE I

                        DEFINITIONS AND ACCOUNTING TERMS

         SECTION 1.01. CERTAIN DEFINED TERMS. As used in this Agreement, the
following terms shall have the following meanings (such meanings to be
applicable to the singular and plural forms of the terms defined):

                  "ADMINISTRATIVE AGENT" means CIBC, in its capacity as
         administrative agent hereunder, or any successor thereto as provided
         herein.

                  "ADVANCE" means a Contract Advance.

                  "AFFILIATE" means, with respect to any Person, any other
         Person directly or indirectly controlling (including, but not limited
         to, all directors and officers of such Person), controlled by, or under
         direct or indirect common control with such Person. A Person shall be
         deemed to control another entity if such Person possesses, directly or
         indirectly, the power to direct or cause the direction of the
         management and policies of such entity, whether through the ownership
         of voting securities, by contract or otherwise.

                  "AGREEMENT" means this Term Loan Agreement, as the same may be
         modified, amended and/or supplemented pursuant to the terms hereof.

                  "APPLICABLE LENDING OFFICE" means, with respect to each
         Lender:

                           (i) in the case of any Contract Advance, (A) such
                  Lender's "Eurodollar Lending Office" in the case of a
                  Eurodollar Rate Advance or (B) such Lender's "Domestic Lending
                  Office" in the case of a Base Rate Advance, in each case as
                  specified opposite such Lender's name on Schedule I hereto or
                  in the Lender Assignment pursuant to which it became a Lender;
                  or

                           (ii) in each case, such other office of such Lender
                  as such Lender may from time to time specify in writing to the
                  Borrower and the Administrative Agent.

                  "APPLICABLE MARGIN" means, for any day during the relevant
         period indicated below for any outstanding Contract Advance, the
         percentage per annum set forth below in effect on such day during such
         period, determined on the basis of the Applicable Rating Level for the
         Borrower:

                        APPLICABLE MARGIN (PERCENTAGE %)

 APPLICABLE          EURODOLLAR                      BASE RATE
RATING LEVEL        RATE ADVANCES                    ADVANCES

                     FUNDING                         FUNDING

                     DATE  8-1-00  11-1-00 AND       DATE  8-1-00  11-1-00 AND
                           7-31-00 10-31-00                7-31-00 10-31-00
                           THEREAFTER                      THEREAFTER

                                        2
<PAGE>

Level I              2.00    1.375     1.625       1.00     .375     .625
Level II             2.00    1.625     1.875       1.00     .625     .875
Level III            2.00    1.875     2.125       1.00     .875    1.125
Level IV             2.00    2.125     2.375       1.00    1.12     1.375
Level V              2.00    2.375     2.625       1.00    1.375    1.625
Level VI             2.00    2.625     2.875       1.00    1.625    1.875

         Any change in the Applicable Margin caused by a change in the
Applicable Rating Level shall take effect at the time such change in the
Applicable Rating Level shall occur.


                  "APPLICABLE RATE" means, with respect to any Advance made to
         the Borrower, either of (i) the Base Rate from time to time applicable
         to such Advance plus the Applicable Margin, or (ii) the Eurodollar Rate
         from time to time applicable to such Advance plus the Applicable
         Margin.

                  "APPLICABLE RATING LEVEL" shall be determined at any time and
         from time to time on the basis of the ratings assigned by S and P and
         Moody's to the senior, unsecured, non-credit enhanced long-term Debt of
         the Borrower (the "RATED DEBT") in accordance with the following:


                             APPLICABLE RATING LEVEL

                              S & P                         MOODY'S

Level I                       BBB+ or higher                Baa3 or higher
Level II                      BBB                           Ba1
Level III                     BBB-                          Ba2
Level IV                      BB+                           Ba3
Level V                       BB                            B1
Level VI                      BB- or lower                  B2 or lower

         In the event that the rating assigned by S and P to the Rated Debt and
the rating assigned by Moody's to the Rated Debt do not correspond to the same
Applicable Rating Level, then the lower of the two ratings shall determine the
Applicable Rating Level. The Applicable Rating Level shall be redetermined as
and when any change in the ratings used in the determination thereof shall be
announced by S and P or Moody's, as the case may be.

                  If either Moody's or S and P shall cease to issue or maintain
         a rating on the Rated Debt, then the Applicable Rating Level shall be
         Level VI.

                  "BANKS" has the meaning assigned to that term in the caption
         to this Agreement.

                  "BASE RATE" means, for any period, a fluctuating interest rate
         per annum as shall be in effect from time to time which rate per annum
         shall at all times be equal to the higher of:

                           (a) the rate of interest announced publicly by CIBC
                  in its principal place of business in the United States from
                  time to time as CIBC's base rate for loans made in United
                  States Dollars; and

                           (b) half of one percent per annum above the Federal
                  Funds Rate in effect from time to time.

                                        3
<PAGE>

                  If the Administrative Agent shall have determined (which
         determination shall be conclusive absent manifest error) that it is
         unable to ascertain the Federal Funds Rate for any reason, including
         the inability or failure of the Administrative Agent to obtain
         sufficient quotations in accordance with the terms thereof, the Base
         Rate shall be determined without regard to clause (b) of the first
         sentence of this definition until the circumstances giving rise to such
         inability no longer exist. Any change in the Base Rate due to a change
         in the Administrative Agent's base rate or the Federal Funds Rate shall
         be effective on the effective date of such change in the Administrative
         Agent's base rate or the Federal Funds Rate, respectively.

                  "BASE RATE ADVANCE" means a Contract Advance in respect of
         which the Borrower has selected in accordance with Article III hereof,
         or this Agreement provides for, interest to be computed on the basis of
         the Base Rate.

                  "BORROWER" has the meaning assigned to that term in the
         caption to this Agreement.

                  "BORROWING" means a Contract Borrowing.

                  "BUSINESS DAY" means a day of the year on which banks are not
         required or authorized to close in New York City and, if the applicable
         Business Day relates to any Eurodollar Rate Advances, on which dealings
         are carried on in the London interbank market.

                  "CHANGE OF CONTROL" means (a) any Person or "group" (within
         the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of
         1934, as amended), other than Consolidated Edison, Inc., shall either
         (1) acquire beneficial ownership of more than 50 percent of any
         outstanding class of common stock of NU having ordinary voting power in
         the election of directors of NU or (2) obtain the power (whether or not
         exercised) to elect a majority of NU's directors or (b) except as a
         result of the acquisition of NU by Consolidated Edison, Inc., the Board
         of Directors of NU shall not consist of a majority of Continuing
         Directors. For purposes of this definition, the term "Continuing
         Directors" means directors of NU on the Closing Date and each other
         director of NU, if such other director's nomination for election to the
         Board of Directors of NU is recommended by a majority of the then
         Continuing Directors.

                  "CIBC" means Canadian Imperial Bank of Commerce, a Canadian
         chartered bank, acting through its New York Agency.

                  "CL & P" means The Connecticut Light and Power Company, a
         corporation organized under the laws of the State of Connecticut.

                  "CL & P INDENTURE" has the meaning assigned to that term in
         Section 7.02(a)(ii) hereof.

                  "CLOSING DATE" has the meaning assigned to that term in
         Section 5.01 hereof.

                  "COMMITMENT" means, for each Lender, the aggregate amount set
         forth opposite such Lender's name on the signature pages hereof or, if
         such Lender has entered into one or more Lender Assignments, set forth
         for such Lender in the Register maintained by the Administrative Agent
         pursuant to Section 10.07(c). "COMMITMENTS" shall refer to the
         aggregate of the Lenders' Commitments hereunder.

                  "COMMITMENT FEE" has the meaning assigned to that term in
         Section 2.02(a) hereof.

                                        4
<PAGE>

                  "COMMON EQUITY" means, at any date for the Borrower, an amount
         equal to the sum of the aggregate of the par value of, or stated
         capital represented by, the outstanding common shares of the Borrower
         and its Subsidiaries and the surplus, paid-in, earned and other
         capital, if any, of the Borrower and its Subsidiaries, in each case as
         determined on a consolidated basis in accordance with generally
         accepted accounting principles.

                  "CONFIDENTIAL INFORMATION" has the meaning assigned to that
         term in Section 10.08 hereof.

                  "CONSOLIDATED INTEREST EXPENSE" means, for any period, the
         aggregate amount of any interest required to be paid during such period
         by the Borrower and its Subsidiaries on Debt (including the current
         portion thereof) (as determined on a consolidated basis in accordance
         with generally accepted accounting principles), excluding interest
         required to be paid on the stranded cost recovery bonds of any
         Subsidiary of the Borrower.

                  "CONSOLIDATED OPERATING INCOME" means, for any period (as
         determined on a consolidated basis in accordance with generally
         accepted accounting principles), the Borrower's and its Subsidiaries'
         operating income for such period, adjusted as follows:

                  (i)      increased by the amount of income taxes accrued less
                           the amount of income taxes paid by the Borrower and
                           its Subsidiaries during such period, if and to the
                           extent deducted in the computation of the Borrower's
                           and/or its Subsidiaries' consolidated operating
                           income for such period;

                  (ii)     increased by the amount of any depreciation and
                           amortization deducted in the computation of the
                           Borrower's and/or its Subsidiaries' consolidated
                           operating income for such period;

                  (iii)    decreased by the amount of any capital expenditures
                           paid by the Borrower and/or its Subsidiaries to the
                           extent not deducted in the computation of the
                           Borrower's and its Subsidiaries' consolidated
                           operating income for such period;

                  (iv)     decreased by the amount of revenues accrued by the
                           Borrower and/or its Subsidiaries related to the
                           interest and principal on stranded cost recovery
                           bonds issued by Subsidiaries of the Borrower, and
                           increased by the amount of operating expenses accrued
                           by the Borrower and/or its Subsidiaries related to
                           the interest and principal on stranded cost recovery
                           bonds issued by Subsidiaries of the Borrower, in each
                           case to the extent included in the computation of the
                           Borrower's and/or its Subsidiaries' consolidated
                           operating income for such period;

                  (v)      decreased by the proceeds of stranded cost recovery
                           bonds issued by Subsidiaries of the Borrower to the
                           extent included in the computation of the Borrower's
                           and/or its Subsidiaries' consolidated operating
                           income for such period; and

                                        5
<PAGE>

                  (vi)     decreased by the proceeds (including Extraordinary
                           Proceeds of the Borrower and/or its Subsidiaries) of
                           asset sales done outside the ordinary course of
                           business to the extent included in the computation of
                           the Borrower's and/or its Subsidiaries' consolidated
                           operating income for such period; and

                  (vii)    increased or decreased, as the case may be, by the
                           amount of income taxes paid or refunded on gains or
                           losses related to the sale of assets or purchased
                           power contracts done outside the ordinary course of
                           business to the extent included in the computation of
                           the Borrower's and/or its Subsidiaries consolidated
                           operating income for such period.

                  "CONTRACT ADVANCE" means an advance by a Lender to the
         Borrower pursuant to Article III hereof, and refers to a Eurodollar
         Rate Advance or a Base Rate Advance (each of which shall be a "TYPE" of
         Contract Advance). For purposes of this Agreement, all Contract
         Advances of a Lender (or portions thereof) of the same Type and
         Interest Period, if any, made or converted on the same day to the
         Borrower shall be deemed to be a single Advance by such Lender until
         repaid.

                  "CONTRACT BORROWING" means a borrowing consisting of one or
         more Contract Advances of the same Type and Interest Period, if any,
         made, continued or converted on the same Business Day. A Contract
         Borrowing may be referred to herein as being a "TYPE" of Contract
         Borrowing, corresponding to the Type of Contract Advances comprising
         such Borrowing, whether such Advances were made on the Funding Date or
         were continued or converted as Advances of a certain Type and for a
         certain Interest Period. For purposes of this Agreement, all Contract
         Advances of the same Type and Interest Period, if any, made, continued
         or converted on the same day to the Borrower shall be deemed a single
         Contract Borrowing hereunder until repaid.

                  "CONTRACT NOTE" means a promissory note of the Borrower
         payable to the order of a Lender, in substantially the form of Exhibit
         1.01A hereto, evidencing the aggregate indebtedness of the Borrower to
         such Lender resulting from the Contract Advances made by such Lender to
         the Borrower.

                  "DEBT" means, for any Person, without duplication, (i)
         indebtedness of such Person for borrowed money, including but not
         limited to obligations of such Person evidenced by bonds, debentures,
         notes or other similar instruments (excluding stranded cost recovery
         bonds which are non-recourse to such Person), (ii) obligations of such
         Person to pay the deferred purchase price of property or services
         (excluding any obligation of such Person to the United States
         Department of Energy or its successor with respect to disposition of
         spent nuclear fuel burned prior to April 3, 1983), (iii) obligations of
         such Person as lessee under leases which shall have been or should be,
         in accordance with generally accepted accounting principles, recorded
         as capital leases, (iv) obligations under direct or indirect guaranties
         in respect of, and obligations (contingent or otherwise) to purchase or
         otherwise acquire, or otherwise to assure a creditor against loss in
         respect of, indebtedness or obligations of others of the kinds referred
         to in clauses (i) through (iii), above, including

                                        6
<PAGE>

         all Parent Support Obligations, (v) letters of credit, guaranties and
         other forms of credit enhancement issued to support power sales and
         trading activities, and (vi) liabilities in respect of unfunded vested
         benefits under ERISA Plans.

                  "DISCLOSURE DOCUMENTS" means for the Borrower and each
         Principal Subsidiary: (i) such Person's Annual Report on Form 10-K for
         the fiscal year ended December 31, 1998; (ii) its Quarterly Reports on
         Form 10-Q for the fiscal quarters ended March 31, June 30, and
         September 30, 1999; and (iii) each Current Report on Form 8-K of such
         Person filed after September 30, 1999 and on or prior to February 29,
         2000.

                  "ERISA" means the Employee Retirement Income Security Act of
         1974, as amended from time to time.

                  "ERISA AFFILIATE" means, with respect to any Person, any trade
         or business (whether or not incorporated) which is a "commonly
         controlled entity" of such Person within the meaning of the regulations
         under Section 414 of the Internal Revenue Code of 1986, as amended from
         time to time.

                  "ERISA MULTIEMPLOYER PLAN" means a "multiemployer plan"
         subject to Title IV of ERISA.

                  "ERISA PLAN" means an employee benefit plan (other than a
         ERISA Multiemployer Plan) maintained for employees of the Borrower or
         any ERISA Affiliate of the Borrower and covered by Title IV of ERISA.

                  "ERISA PLAN TERMINATION EVENT" means (i) a Reportable Event
         described in Section 4043 of ERISA and the regulations issued
         thereunder (other than a Reportable Event not subject to the provision
         for 30-day notice to the PBGC under such regulations) with respect to
         an ERISA Plan or an ERISA Multiemployer Plan, or (ii) the withdrawal of
         the Borrower or any of its ERISA Affiliates from an ERISA Plan or an
         ERISA Multiemployer Plan during a plan year in which it was a
         "substantial employer" as defined in Section 4001(a)(2) of ERISA, or
         (iii) the filing of a notice of intent to terminate an ERISA Plan or an
         ERISA Multiemployer Plan or the treatment of an ERISA Plan or an ERISA
         Multiemployer Plan under Section 4041 of ERISA, or (iv) the institution
         of proceedings to terminate an ERISA Plan or an ERISA Multiemployer
         Plan by the PBGC, or (v) any other event or condition which might
         constitute grounds under Section 4042 of ERISA for the termination of,
         or the appointment of a trustee to administer, any ERISA Plan or ERISA
         Multiemployer Plan.

                  "EUROCURRENCY LIABILITIES" has the meaning assigned to that
         term in Regulation D of the Board of Governors of the Federal Reserve
         System, as in effect from time to time.

                  "EURODOLLAR RATE" means, for each Interest Period for each
         Eurodollar Rate Advance comprising part of the same Borrowing, an
         interest rate per annum equal to (i) the rate for deposits in U.S.
         Dollars for a period equal to such Interest Period appearing on Page
         3750 of the Telerate Service at approximately 11:00 a.m. (London time)
         two

                                        7
<PAGE>

         Business Days before the first day of such Interest Period, or (ii) if
         for any reason such rate is not available, the average (rounded upward
         to the nearest whole multiple of 1 dash 16 of 1 percent per annum, if
         such average is not such a multiple) of the rates per annum at which
         deposits in U.S. dollars are offered by the principal office of each of
         the Reference Banks in London, England to prime banks in the London
         inter-bank market at 11:00 a.m. (London time) two Business Days before
         the first day of such Interest Period in the amount of 1,000,000
         dollars and for a period equal to such Interest Period. If determined
         pursuant to clause (ii), above, the Eurodollar Rate for the Interest
         Period for each Eurodollar Rate Advance comprising part of the same
         Borrowing shall be determined by the Administrative Agent on the basis
         of applicable rates furnished to and received by the Administrative
         Agent from the Reference Banks two Business Days before the first day
         of such Interest Period, subject, however, to the provisions of
         Sections 3.05(d) and 4.03(g).

                  "EURODOLLAR RATE ADVANCE" means a Contract Advance in respect
         of which the Borrower has selected in accordance with Article III
         hereof, or this Agreement provides for, interest to be computed on the
         basis of the Eurodollar Rate.

                  "EURODOLLAR RESERVE PERCENTAGE" of any Lender or its
         subparticipant, for each Interest Period for each Eurodollar Rate
         Advance, means the reserve percentage applicable during such Interest
         Period (or if more than one such percentage shall be so applicable, the
         daily average of such percentages for those days in such Interest
         Period during which any such percentage shall be so applicable) under
         Regulation D or other regulations issued from time to time by the Board
         of Governors of the Federal Reserve System (or any successor) for
         determining the maximum reserve requirement (including, without
         limitation, any emergency, supplemental or other marginal reserve
         requirement, without benefit of or credit for proration, exemptions or
         offsets) for such Lender or its subparticipant with respect to
         liabilities or assets consisting of or including Eurocurrency
         Liabilities having a term equal to such Interest Period.

                  "EVENT OF DEFAULT" has the meaning specified in Section 8.01
         hereof.

                  "EXTRAORDINARY PROCEEDS" shall mean, for any Person for any
         period, net proceeds received by such Person during such period from
         (i) issuances of securitization bonds sold by such Person or any of its
         Subsidiaries plus (ii) sales of assets by such Person or any of its
         Subsidiaries not in the ordinary course of business plus (iii) the sale
         or disposition (by way of merger, sale of capital stock, sale of assets
         or otherwise) of any Subsidiary of such Person. For purposes of the
         foregoing, all cash received by such Person from, or as a result of the
         sale or disposition of, a Subsidiary shall be deemed to constitute
         "Extraordinary Proceeds" up to the amount of proceeds received by, or
         as a result of the sale or disposition of, such Subsidiary from such
         issuances and sales during the relevant period, net of underwriting
         discounts and commissions, costs of sale and other, similar transaction
         costs.

                  "FEDERAL FUNDS RATE" means, for any period, a fluctuating
         interest rate per annum equal to, for each day during such period, the
         weighted average of the rates on overnight Federal funds transactions
         with members of the Federal Reserve System arranged by

                                        8
<PAGE>

         Federal funds brokers, as published on the next succeeding Business Day
         by the Federal Reserve Bank of New York, or, if such rate is not so
         published for any day which is a Business Day, the average of the
         quotations for such day on such transactions received by the
         Administrative Agent from three Federal funds brokers of recognized
         standing selected by it.

                  "FEE LETTER" means that certain Fee Letter dated February 18,
         2000 between NU and CIBC.

                  "FERC" means the Federal Energy Regulatory Commission.

                  "FINANCIAL STATEMENTS" means, with respect to the Borrower and
         each Principal Subsidiary, (i) the audited consolidated balance sheet
         of such Person as at December 31, 1998, (ii) the unaudited consolidated
         balance sheet of such Person as at September 30, 1999, (iii) the
         audited consolidated statements of income and cash flows of such Person
         for the Fiscal Year ended December 31, 1998 and (iv) the unaudited
         consolidated statements of income and cash flows of such Person for the
         9-month period ended September 30, 1999, in each case as included in
         such Person's Annual Report on Form 10-K for the Fiscal Year ended
         December 31, 1998 or Quarterly Report on Form 10-Q for the Fiscal
         Quarter ended September 30, 1999.

                  "FIRST MORTGAGE BONDS" means any bond, however designated,
         entitled to the benefits of a First Mortgage Indenture.

                  "FIRST MORTGAGE INDENTURE" means, with respect to CL and P,
         the CL and P Indenture or any successor thereto or replacement thereof;
         and with respect to WMECO, the WMECO Indenture or any successor thereto
         or replacement thereof.

                  "FISCAL QUARTER" means a period of three calendar months
         ending on the last day of March, June, September or December, as the
         case may be.

                  "FISCAL YEAR" means a period of twelve calendar months ending
         on the last day of December.

                  "FIXED CHARGES" shall mean, for any period, the sum of the
         following amounts: (a) dividends paid by NU to common and preferred
         stockholders during such period; (b) interest expense for NU for such
         period; and (c) income taxes paid by NU during such period.

                  "FUNDING DATE" has the meaning assigned to that term in
         Section 2.01 hereof.

                  "GOVERNMENTAL APPROVAL" means any authorization, consent,
         approval, license, permit, certificate, exemption of, or filing or
         registration with, any governmental authority or other legal or
         regulatory body (including, without limitation, the Securities and
         Exchange Commission, the FERC, the Nuclear Regulatory Commission, the
         Connecticut Department of Public Utility Control and the Massachusetts
         Department of Telecommunications and Energy, required in connection
         with either (i) the execution,

                                        9
<PAGE>

         delivery or performance of any Loan Document, (ii) the nature of the
         Borrower's or any Subsidiary's business as conducted or the nature of
         the property owned or leased by it or (iii) the acquisition by the
         Borrower of YES.

                  "HAZARDOUS SUBSTANCE" means any waste, substance or material
         identified as hazardous, dangerous or toxic by any office, agency,
         department, commission, board, bureau or instrumentality of the United
         States of America or of the State or locality in which the same is
         located having or exercising jurisdiction over such waste, substance or
         material.

                  "HWP" means Holyoke Water Power Company, a corporation
         organized under the laws of the Commonwealth of Massachusetts.

                  "INDEMNIFIED PERSON" has the meaning assigned to that term in
         Section 10.04(b) hereof.

                  "INTEREST PERIOD" has the meaning assigned to that term in
         Section 3.05(a) hereof.

                  "LENDER ASSIGNMENT" means an assignment and acceptance entered
         into by a Lender and an assignee, and accepted by the Administrative
         Agent, in substantially the form of Exhibit 10.07 hereto.

                  "LENDERS" means the financial institutions listed on the
         signature pages hereof, and each assignee that shall become a party
         hereto pursuant to Section 10.07.

                  "LIEN" means, with respect to any asset or property, any
         mortgage, lien, pledge, charge, security interest or encumbrance of any
         kind in respect of such asset or property. For the purposes of this
         Agreement, a Person or any of its Subsidiaries shall be deemed to own
         subject to a Lien any asset which it has acquired or holds subject to
         the interest of a vendor or lessor under any conditional sale
         agreement, capital lease or other title retention agreement relating to
         such asset.

                  "LOAN DOCUMENTS" means this Agreement and the Notes.

                  "MAJORITY LENDERS" means on any date of determination, Lenders
         who, collectively, on such date (i) have Percentages in the aggregate
         of at least 66-2/3 percent and (ii) if the Advances shall have been
         made on the Funding Date, hold at least 66-2/3 percent of the then
         aggregate Outstanding Credits of the Lenders. Determination of those
         Lenders satisfying the criteria specified above for action by the
         Majority Lenders shall be made by the Administrative Agent and shall be
         conclusive and binding on all parties absent manifest error.

                  "MOODY'S" means Moody's Investors Service, Inc., or any
         successor thereto.

                  "NAEC" means North Atlantic Energy Corporation, a corporation
         organized under the laws of the State of New Hampshire.

                                       10
<PAGE>

                  "NAMED DEBT" means Debt of HWP under (i) the Reimbursement and
         Security Agreement (1988 Series), dated as of November 3, 1999, between
         HWP and The Toronto-Dominion Bank and (ii) the Reimbursement and
         Security Agreement (1990 Series), dated as of November 3, 1999, between
         HWP and The Toronto-Dominion Bank.

                  "NGC EQUITY CONTRIBUTION" shall mean the proposed equity
         investment by the Borrower of up to $475,000,000 in Northeast
         Generation Company.

                  "NOTE" means a Contract Note, as may be amended, supplemented
         or otherwise modified from time to time.

                  "NOTICE OF CONTRACT BORROWING" has the meaning assigned to
         that term in Section 3.01 hereof.

                  "NU" has the meaning assigned to that term in the caption to
         this Agreement.

                  "NU SYSTEM MONEY POOL" means the money pool described in the
         application/declaration, as amended, of NU and certain of its
         Subsidiaries, filed with the Securities and Exchange Commission in File
         No. 70-8875, as amended from time to time.

                  "NUSCO" means Northeast Utilities Service Company, a
         Connecticut corporation.

                  "OPERATING CASH FLOW" shall mean, for any period, the sum of
         the following amounts: (1) dividends paid to the Borrower by a
         Subsidiary thereof during such period; (2) consulting and management
         fees paid to the Borrower for such period; (3) tax sharing payments
         made to the Borrower during such period; (4) interest and other
         distributions paid to the Borrower during such period with respect to
         cash (e.g., NU System Money Pool) and other permitted investments of
         the Borrower; and (5) other cash payments made to the Borrower by its
         Subsidiaries other than (A) returns of invested capital, (B) payments
         of the principal on Debt of any such Subsidiary to the Borrower (to the
         extent permitted hereunder) and (C) Extraordinary Proceeds. If at any
         time there shall exist an event or condition which permits any holder
         to accelerate the maturity date of any Debt of, or terminate its
         commitment to extend credit to any Subsidiary, then the contributions
         of such Subsidiary to Operating Cash Flow for any period ending at or
         prior to such time shall be eliminated and Operating Cash Flow shall be
         calculated after giving effect to such elimination.

                  "OUTSTANDING CREDITS" mean, on any date of determination, an
         amount equal to the aggregate principal amount of all Contract Advances
         outstanding on such date. The "Outstanding Credits" of a Lender on any
         date of determination shall be an amount equal to the outstanding
         Advances made by such Lender.

                  "PARENT SUPPORT OBLIGATION" means, without duplication, any
         obligation of the Borrower under direct or indirect guaranties in
         respect of, and obligations (contingent or otherwise) to purchase or
         otherwise acquire, or otherwise to assure a creditor against loss in
         respect of, indebtedness or obligations of others of the kinds referred
         to in clauses (i)

                                       11
<PAGE>

         through (iii) of the definition of "Debt", including any reimbursement
         obligation in respect of a letter of credit, any recourse obligation in
         respect of a surety or similar bond or other, similar obligation of the
         Borrower other than a construction completion or similar performance
         guaranty as permitted hereunder issued on behalf of HEC Inc. The amount
         of each Parent Support Obligation shall be computed in good faith in
         accordance with the Borrower's then applicable mark-to-market and other
         risk management methods.

                  "PBGC" means the Pension Benefit Guaranty Corporation (or any
         successor entity) established under ERISA.

                  "PERCENTAGE" means, in respect of any Lender on any date of
         determination, the percentage obtained by dividing such Lender's
         Commitment on such day (or, if the Commitments shall have been
         terminated, the aggregate principal amount of outstanding Advances held
         by such Lender on such day) by the total of the Commitments (or
         outstanding Advances, as applicable) on such day, and multiplying the
         quotient so obtained by 100%.

                  "PERMITTED INVESTMENTS" means (i) securities issued or
         directly and fully guaranteed or insured by the United States or any
         agency or instrumentality thereof (provided that the full faith and
         credit of the United States is pledged in support thereof) having
         maturities of not more than six (6) months from the date of acquisition
         by such Person; (ii) time deposits and certificates of deposit, with
         maturities of not more than six (6) months from the date of acquisition
         by such Person, of any international commercial bank of recognized
         standing having capital and surplus in excess of $500,000,000 and
         having a rating on its commercial paper of at least A-1 or the
         equivalent thereof by S&P or at least P-1 or the equivalent thereof by
         Moody's; (iii) commercial paper issued by any Person, which commercial
         paper is rated at least A-1 or the equivalent thereof by S&P or at
         least P-1 or the equivalent thereof by Moody's and matures not more
         than six (6) months after the date of acquisition by such Person; (iv)
         investments in money market funds substantially all the assets of which
         are comprised of securities of the types described in clauses (i) and
         (ii) above and (v) United States Securities and Exchange Commission
         registered money market mutual funds conforming to Rule 2a-7 of the
         Investment Company Act of 1940 in effect in the United States, that
         invest primarily in direct obligations issued by the United States
         Treasury and repurchase obligations backed by those obligations, and
         rated in the highest category by S&P and Moody's.

                  "PERSON" means an individual, partnership, corporation
         (including a business trust), limited liability company, joint stock
         company, trust, unincorporated association, joint venture or other
         entity, or a government or any political subdivision or agency thereof.

                  "PRINCIPAL SUBSIDIARY" shall mean YES, CL&P, WMECO, PSNH, HWP,
         NAEC, Select Energy, Inc., HEC Inc., Northeast Generation Company, Mode
         One Communications, Inc., and any other Subsidiary, whether owned
         directly or indirectly by the Borrower, which, with respect to the
         Borrower and its Subsidiaries taken as a whole,

                                       12
<PAGE>

         represents at least ten percent (10%) of such Borrower's consolidated
         assets or such Borrower's consolidated net income (or loss).

                  "PSNH" means Public Service Company of New Hampshire, a
         corporation duly organized under the laws of the State of New
         Hampshire.

                  "RECIPIENT" has the meaning assigned to that term in Section
         10.08 hereof.

                  "REFERENCE BANKS" means CIBC, Fleet Bank, N.A. and The Bank of
         New York, and any other bank or financial institution designated by the
         Borrower and the Administrative Agent with the approval of the Majority
         Lenders to act as a Reference Bank hereunder.

                  "REGULATORY ASSET" means, with respect to CL&P or WMECO, an
         intangible asset established by statute, regulation or regulatory order
         or similar action of a utility regulatory agency having jurisdiction
         over CL&P or WMECO, as the case may be, and included in the rate base
         of CL&P or WMECO, as the case may be, with the intention that such
         asset be amortized by rates over time.

                  "RESTRICTED PAYMENT" shall mean any dividend, payment or other
         distribution of assets, properties, cash, rights, obligations or
         securities on account of any share of any class of capital stock of NU
         (other than as a result of a stock split and dividends payable solely
         in equity securities of NU), or the purchase, redemption, retirement or
         other acquisition for value of any shares of any class of capital stock
         of NU or any warrants, rights, or options to acquire any such shares,
         now or hereafter outstanding.

                  "REVOLVING CREDIT AGREEMENT" means the Credit Agreement, dated
         as of November 19, 1999, among the Borrower, the lenders from time to
         time parties thereto and Union Bank of California, N.A., as
         Administrative Agent.

                  "S&P" means Standard and Poor's Ratings Services, a division
         of The McGraw-Hill Companies, Inc., or any successor thereto.

                  "SUBSIDIARY" shall mean, with respect to any Person (the
         "PARENT"), any corporation, association or other business entity of
         which securities or other ownership interests representing 50% or more
         of the ordinary voting power are, at the time as of which any
         determination is being made, owned or controlled by the Parent or one
         or more Subsidiaries of the Parent or by the Parent and one or more
         Subsidiaries of the Parent.

                  "TERMINATION DATE" means the earliest to occur of (i) February
         28, 2001, (ii) the date of termination of the Commitments pursuant to
         Section 8.02 or (iii) the date of acceleration of all amounts payable
         hereunder and under the Notes pursuant to Section 8.02.

                  "TOTAL CAPITALIZATION" means, at any date, the sum of (i) the
         aggregate principal amount of all long-term and short-term Debt
         (including the current portion thereof) of the Borrower and its
         Subsidiaries, (ii) the aggregate of the par value of, or stated capital

                                       13
<PAGE>

         represented by, the outstanding shares of all classes of common and
         preferred shares of the Borrower and its Subsidiaries and (iii) the
         consolidated surplus of the Borrower and its Subsidiaries, paid-in,
         earned and other capital, if any, in each case as determined on a
         consolidated basis in accordance with generally accepted accounting
         principles consistent with those applied in the preparation of the
         Borrower's Financial Statements.

                  "TOTAL COMMITMENT" means $266,000,000, or such lesser amount
         from time to time as shall equal the sum of the Commitments.

                  "TYPE" has the meaning assigned to such term (i) in the
         definition of "Contract Advance" when used in such context and (ii) in
         the definition of "Contract Borrowing" when used in such context.

                  "UNMATURED DEFAULT" means the occurrence and continuance of an
         event which, with the giving of notice or lapse of time or both, would
         constitute an Event of Default.

                  "WMECO" means Western Massachusetts Electric Company, a
         corporation organized under the laws of the Commonwealth of
         Massachusetts.

                  "WMECO INDENTURE" has the meaning assigned to that term in
         Section 7.02(a)(iii) hereof.

                  "YEAR 2000 ISSUE" means the failure of computer software,
         hardware and firmware systems and equipment containing computer chips
         to properly receive, transmit, process, manipulate, store, retrieve,
         re-transmit or in any other way utilize data and information due to the
         occurrence of the year 2000 or the inclusion of dates on or after
         January 1, 2000.

                  "YES" means Yankee Energy System Inc.

         SECTION 1.02. COMPUTATION OF TIME PERIODS. In the computation of
periods of time under this Agreement, any period of a specified number of days
or months shall be computed by including the first day or month occurring during
such period and excluding the last such day or month. In the case of a period of
time "from" a specified date "to" or "until" a later specified date, the word
"from" means "from and including" and the words "to" and "until" each means "to
but excluding".

         SECTION 1.03. ACCOUNTING TERMS; FINANCIAL STATEMENTS. All accounting
terms not specifically defined herein shall be construed in accordance with
generally accepted accounting principles applied on a basis consistent with the
application employed in the preparation of the Financial Statements. All
references contained herein to the Borrower's or a Principal Subsidiary's Annual
Report on Form 10-K in respect of a Fiscal Year or Quarterly Report on Form 10-Q
in respect of a Fiscal Quarter shall be deemed to include any exhibits and
schedules thereto, including without limitation in the case of any Annual Report
on Form 10-K, any "Annual Report" of the Borrower or such Principal Subsidiary
referred to therein.

                                       14
<PAGE>

         SECTION 1.04. COMPUTATIONS OF OUTSTANDINGS. Whenever reference is made
in this Agreement to the principal amount of Outstanding Credits under this
Agreement on any date, such reference shall refer to the aggregate principal
amount of all Outstanding Credits on such date after giving effect to (i) all
Advances to be made on such date and the application of the proceeds thereof and
(ii) any repayment or prepayment of Advances on such date by the Borrower.


                                   ARTICLE II


                                   COMMITMENTS

         SECTION 2.01. THE COMMITMENTS. Each Lender severally agrees, on the
terms and conditions hereinafter set forth, to make a single Advance to the
Borrower on any Business Day (the "FUNDING DATE") during the period from the
Closing Date until March 15, 2000, in an amount not to exceed such Lender's
Commitment. If the Funding Date shall not have occurred on or prior to March 15,
2000, the Commitments shall terminate.

         SECTION 2.02. FEES. The Borrower agrees to pay to the Administrative
Agent for the account of each Bank a commitment fee (the "COMMITMENT FEE") on
the amount of such Bank's Commitment at a rate per annum equal to one-half of
one percent (0.5%) for the period from the date of this Agreement to (but
excluding) the Funding Date or the earlier termination of the Commitments. The
Commitment Fee payable by the Borrower shall be calculated and accrued daily and
shall be payable on the Funding Date, or, if earlier, the date on which the
Commitments are terminated.

         (b) The Borrower further agrees to pay the fees specified in the Fee
Letter to the parties entitled thereto.


                                   ARTICLE III


                                CONTRACT ADVANCES

         SECTION 3.01. CONTRACT ADVANCES. Subject to Section 2.01, more than one
Contract Borrowing may be made on the same Business Day. Each Contract Borrowing
shall consist of Contract Advances of the same Type and Interest Period made to
the Borrower on the Funding Date, or thereafter continued or converted as
Advances of the same Type and for the same Interest Period on the same Business
Day, by the Lenders ratably according to their respective Commitments. The
Contract Borrowing to be made on the Funding Date shall be made on notice in
substantially the form of Exhibit 3.01 hereto (the "NOTICE OF CONTRACT
BORROWING"), delivered by the Borrower to the Administrative Agent, by hand or
facsimile, not later than 11:00 a.m. (New York City time) (i) in the case of
Eurodollar Rate Advances, on the third Business Day

                                       15
<PAGE>

prior to the Funding Date and (ii) in the case of Base Rate Advances, on the
Funding Date. Upon receipt of the Notice of Contract Borrowing, the
Administrative Agent shall notify the Lenders thereof promptly on the day so
received. The Notice of Contract Borrowing shall specify therein the requested
(A) Funding Date, (B) principal amount and Type of Advances comprising such
Borrowing and (C) initial Interest Period for such Advances. The Borrowing to be
made on the Funding Date shall be subject to the satisfaction of the conditions
precedent thereto as set forth in Article V hereof.

         SECTION 3.02. TERMS RELATING TO THE MAKING OF CONTRACT ADVANCES.

         (a) Notwithstanding anything in Section 3.01 above to the contrary:

                  (i)   at no time shall more than six different Contract
         Borrowings be outstanding hereunder; and

                  (ii) each Contract Borrowing hereunder which is to be
         comprised of Base Rate or Eurodollar Rate Advances shall be in an
         aggregate principal amount of not less than $5,000,000 or an integral
         multiple of $1,000,000 in excess thereof.

         (b) The Notice of Borrowing shall be irrevocable and binding on the
Borrower.

         SECTION 3.03. MAKING OF ADVANCES.

         (a) Each Lender shall, before 1:00 p.m. (New York City time) on the
Funding Date, make available for the account of its Applicable Lending Office to
the Administrative Agent at the Administrative Agent's address referred to in
Section 10.02, in same day funds, such Lender's portion of the Borrowing to be
made on such date. Contract Advances shall be made by the Lenders ratably in
accordance with their several Commitments. After the Administrative Agent's
receipt of such funds and upon fulfillment of the applicable conditions set
forth in Article V, the Administrative Agent will make such funds available to
the Borrower at the Administrative Agent's aforesaid address.

         (b) Unless the Administrative Agent shall have received notice from a
Lender prior to the time of the Borrowing to be made on the Funding Date that
such Lender will not make available to the Administrative Agent such Lender's
ratable portion of such Borrowing, the Administrative Agent may assume that such
Lender has made such portion available to the Administrative Agent on the
Funding Date in accordance with subsection (a) of this Section 3.03, and the
Administrative Agent may, in reliance upon such assumption, make available to
the Borrower a corresponding amount on such date. If and to the extent that any
such Lender (a "NON-PERFORMING LENDER") shall not have so made such ratable
portion available to the Administrative Agent, the non-performing Lender and the
Borrower severally agree to repay to the Administrative Agent forthwith on
demand such corresponding amount together with interest thereon, for each day
from the date such amount is made available to the Borrower until the date such
amount is repaid to the Administrative Agent, at (i) in the case of the
Borrower, the interest rate applicable at the time to Advances comprising such
Borrowing and (ii) in the case of such

                                       16
<PAGE>

Lender, the Federal Funds Rate. Nothing herein shall in any way limit, waive or
otherwise reduce any claims that any party hereto may have against any
non-performing Lender.

         (c) The failure of any Lender to make the Advance to be made by it as
part of the Borrowing on the Funding Date shall not relieve any other Lender of
its obligation, if any, hereunder to make its Advance on the Funding Date, but
no Lender shall be responsible for the failure of any other Lender to make the
Advance to be made by such other Lender on the Funding Date.

         SECTION 3.04. REPAYMENT OF ADVANCES. The Borrower shall repay the
principal amount of each Advance made to it hereunder on the Termination Date.

         SECTION 3.05. INTEREST.

         (a) INTEREST PERIODS.

                  (i) The period commencing on the date of each Advance and
         ending on the last day of the period selected by the Borrower with
         respect to such Advance pursuant to the provisions of this Section 3.05
         is referred to herein as an "INTEREST PERIOD". The duration of each
         Interest Period shall be (i) in the case of any Eurodollar Rate
         Advance, one, two, three or (subject to availability) more months, and
         (ii) in the case of any Base Rate Advance, the period of time beginning
         on the date of the making of, or the conversion of an outstanding
         Advance into, such Advance and ending on the last day of March, June,
         September or December next following the date on which such Advance was
         made; provided, however, that no Interest Period may be selected by the
         Borrower if such Interest Period would end after the Termination Date.

                  (ii) Subject to the terms and conditions of this Agreement,
         the initial Interest Period for the Advances made to the Borrower on
         the Funding Date shall be determined by the Borrower as set forth in
         its Notice of Contract Borrowing. The Borrower may elect to continue or
         convert (A) the Advances made on the Funding Date and (B) thereafter,
         one or more Advances of any Type and having the same Interest Period,
         to one or more Advances of the same or any other Type and having the
         same or a different Interest Period, on the following terms and subject
         to the following conditions:

                           (A) Each continuation or conversion shall be made as
                  to all Advances comprising a single Borrowing upon written
                  notice given by the Borrower to the Administrative Agent not
                  later than 11:00 a.m. (New York City time) on the third
                  Business Day prior to the date of the proposed continuation of
                  or conversion, in the case of a continuation or conversion to
                  a Eurodollar Rate Advance, or on the day of the proposed
                  continuation of or conversion to a Base Rate Advance. The
                  Administrative Agent shall notify each Lender of the contents
                  of such notice promptly after receipt thereof. Each such
                  notice shall specify therein the following information: (1)
                  the date of such proposed continuation or conversion (which in
                  the case of Eurodollar Rate Advances shall be the last day of
                  the Interest Period then applicable to such Advances to be
                  continued or converted), (2) the Type of,


                                       17
<PAGE>

                  and Interest Period applicable to the Advances proposed to be
                  continued or converted, (3) the aggregate principal amount of
                  Advances proposed to be continued or converted, and (4) the
                  Type of Advances to which such Advances are proposed to be
                  continued or converted and the Interest Period to be
                  applicable thereto.

                           (B) During the continuance of an Unmatured Default,
                  the right of the Borrower to continue or convert Advances to
                  Eurodollar Rate Advances shall be suspended, and all
                  Eurodollar Rate Advances then outstanding shall be converted
                  to Base Rate Advances on the last day of the Interest Period
                  then in effect, if, on such day, an Unmatured Default shall be
                  continuing.

                           (C) During the continuance of an Event of Default,
                  the right of the Borrower to continue or convert Advances to
                  Eurodollar Rate Advances shall be suspended, and upon the
                  occurrence of an Event of Default, all Eurodollar Rate
                  Advances then outstanding shall immediately, without further
                  act by the Borrower, be converted to Base Rate Advances.

                           (D) If no notice of continuation or conversion is
                  received by the Administrative Agent as provided in paragraph
                  (A), above, with respect to any outstanding Advances on or
                  before the third Business Day prior to the last day of the
                  Interest Period then in effect for such Advances, the
                  Administrative Agent shall treat such absence of notice as a
                  deemed notice of continuation or conversion providing for such
                  Advances to be continued as or converted to Base Rate Advances
                  with an Interest Period of three months commencing on the last
                  day of such Interest Period.

         (b) INTEREST RATES. The Borrower shall pay interest on the unpaid
principal amount of each Advance owing by the Borrower from the date of such
Advance until such principal amount shall be paid in full, at the Applicable
Rate for such Advance (except as otherwise provided in this subsection (b)),
payable as follows:

                  (i) EURODOLLAR RATE ADVANCES. If such Advance is a Eurodollar
         Rate Advance, interest thereon shall be payable on the last day of the
         Interest Period applicable thereto and on the Termination Date;
         provided that during the continuance of any Event of Default, such
         Advance shall bear interest at a rate per annum equal at all times to
         2% per annum above the Applicable Rate for such Advance for such
         Interest Period.

                  (ii) BASE RATE ADVANCES. If such Advance is a Base Rate
         Advance, interest thereon shall be payable quarterly on the last day of
         each March, June, September and December and on the date such Base Rate
         Advance shall be paid in full; provided that during the continuance of
         any Event of Default, such Advance shall bear interest at a rate per
         annum equal at all times to 2% per annum above the Applicable Rate for
         such Advance for such Interest Period.

                                       18
<PAGE>

         (c) OTHER AMOUNTS. Any other amounts payable hereunder that are not
paid when due shall (to the fullest extent permitted by law) bear interest, from
the date when due until paid in full, at a rate per annum equal at all times to
2.0% per annum above the Applicable Rate in effect from time to time for Base
Rate Advances, payable on demand.

         (d) INTEREST RATE DETERMINATIONS. The Administrative Agent shall give
prompt notice to the Borrower and the Lenders of the Applicable Rate determined
from time to time by the Administrative Agent for each Contract Advance. Each
Reference Bank agrees to furnish to the Administrative Agent timely information
for the purpose of determining the Eurodollar Rate for any Interest Period. If
any one Reference Bank shall not furnish such timely information, the
Administrative Agent shall determine such interest rate on the basis of the
timely information furnished by the other two Reference Banks.

         (e) MAXIMUM INTEREST RATE. Notwithstanding anything herein to the
contrary:

                  (i) If at any time the effective interest rate on any
         Eurodollar Rate Advance or Base Rate Advance for any Interest Period
         (including any additional interest payable upon the occurrence of an
         Event of Default) exceeds 4.00% plus the Eurodollar Rate as determined
         (or as it would have been determined) as of the first day of the then
         applicable Interest Period for such Eurodollar Rate Advance or Base
         Rate Advance (the "MAXIMUM RATE"), such rate of interest shall be
         reduced to the Maximum Rate.

                  (ii) If the amount of interest payable for the account of any
         Lender in respect of any Interest Period is reduced pursuant to
         subparagraph (i), above, and the amount of interest payable for such
         Lender's account in respect of any subsequent Interest Period would be
         less than the amount of interest computed at the Maximum Rate, then the
         amount of interest payable for such Lender's account in respect of such
         subsequent Interest Period shall, to the extent permitted by applicable
         law, be automatically increased to the amount of interest that would be
         payable for such Interest Period if such interest were computed at the
         Maximum Rate; provided that at no time shall the aggregate amount by
         which interest paid for the account of any Lender is increased pursuant
         to this subparagraph (ii) exceed the aggregate amount by which interest
         paid for its account has theretofore been reduced pursuant to
         subparagraph (i), above.

                                       19
<PAGE>

                                   ARTICLE IV


                                    PAYMENTS

         SECTION 4.01. PAYMENTS AND COMPUTATIONS.

         (a) The Borrower shall make each payment hereunder and under the Notes
not later than 12:00 noon (New York City time) on the day when due in U.S.
Dollars to the Administrative Agent at its address referred to in Section 10.02
hereof, in same day funds. The Administrative Agent will promptly thereafter
cause to be distributed like funds relating to the payment of principal,
interest, fees or other amounts payable to the Lenders, to the respective
Lenders to whom the same are payable, for the account of their respective
Applicable Lending Offices, in each case to be applied in accordance with the
terms of this Agreement. Upon its acceptance of a Lender Assignment and
recording of the information contained therein in the Register pursuant to
Section 10.07, from and after the effective date specified in such Lender
Assignment, the Administrative Agent shall make all payments hereunder and under
the Notes in respect of the interest assigned thereby to the Lender assignee
thereunder, and the parties to such Lender Assignment shall make all appropriate
adjustments in such payments for periods prior to such effective date directly
between themselves.

         (b) The Borrower hereby authorizes the Administrative Agent and each
Lender, if and to the extent payment owed by the Borrower to the Administrative
Agent or such Lender, as the case may be, is not made when due hereunder (or, in
the case of a Lender, under the Note held by such Lender), to charge from time
to time against any or all of the Borrower's accounts with the Administrative
Agent or such Lender, as the case may be, any amount so due.

         (c) All computations of interest based on the Base Rate (except when
determined on the basis of the Federal Funds Rate) shall be made on the basis of
a year of 365 or 366 days, as the case may be. All computations of interest and
other amounts payable pursuant to Section 4.03 shall be made by the Lender
claiming such interest or other amount on the basis of a year of 360 days. All
other computations of interest, including computations of interest based on the
Eurodollar Rate, the Base Rate (when and if determined on the basis of the
Federal Funds Rate), and all computations of fees and other amounts payable
hereunder, shall be made on the basis of a year of 360 days. In each such case,
such computation shall be made for the actual number of days (including the
first day but excluding the last day) occurring in the period for which such
interest, fees or other amounts are payable. Each such determination by the
Administrative Agent or a Lender shall be conclusive and binding for all
purposes, absent manifest error.

         (d) Whenever any payment under any Loan Document shall be stated to be
due, or the last day of an Interest Period hereunder shall be stated to occur,
on a day other than a Business Day, such payment shall be made, and the last day
of such Interest Period shall occur, on the next succeeding Business Day, and
such extension of time shall in such case be included in the computation of
payment of interest and fees hereunder; provided, however, that if such
extension would cause payment of interest on or principal of Eurodollar Rate
Advances to be made, or the last day of an Interest Period for a Eurodollar Rate
Advance to occur, in the next following

                                       20
<PAGE>

calendar month, such payment shall be made on the next preceding Business Day
and such reduction of time shall in such case be included in the computation of
payment of interest hereunder.

         (e) Unless the Administrative Agent shall have received notice from the
Borrower prior to the date on which any payment is due to the Lenders hereunder
that the Borrower will not make such payment in full, the Administrative Agent
may assume that the Borrower has made such payment in full to the Administrative
Agent on such date and the Administrative Agent may, in reliance upon such
assumption, cause to be distributed to each Lender on such due date an amount
equal to the amount then due such Lender. If and to the extent the Borrower
shall not have so made such payment in full to the Administrative Agent, such
Lender shall repay to the Administrative Agent forthwith on demand such amount
distributed to such Lender, together with interest thereon, for each day from
the date such amount is distributed to such Lender until the date such Lender
repays such amount to the Administrative Agent, at the Federal Funds Rate.

         SECTION 4.02. PREPAYMENTS.

         (a) The Borrower shall not have any right to prepay any Contract
Advances except in accordance with subsection (b) below.

         (b) The Borrower may, (i) in the case of Eurodollar Rate Advances, upon
at least three Business Day's written notice to the Administrative Agent (such
notice being irrevocable) and (ii) in the case of Base Rate Advances, upon
notice not later than 11:00 a.m. on the date of the proposed prepayment to the
Administrative Agent (such notice being irrevocable), stating the proposed date
and aggregate principal amount of the prepayment, and if such notice is given,
the Borrower shall, prepay Contract Advances comprising part of the same
Borrowing, in whole or ratably in part, together with accrued interest to the
date of such prepayment on the principal amount prepaid and any amounts owing in
connection therewith pursuant to Section 4.03(d); provided, however, that each
partial prepayment shall be in an aggregate principal amount not less than
$5,000,000 or an integral multiple of $1,000,000 in excess thereof. Once
prepaid, Advances may not be reborrowed.

         SECTION 4.03. YIELD PROTECTION.

         (a) CHANGE IN CIRCUMSTANCES. Notwithstanding any other provision
herein, if after the date hereof; the adoption of or any change in applicable
law or regulation or in the interpretation or administration thereof by any
governmental authority charged with the interpretation or administration thereof
(whether or not having the force of law) shall (i) change the basis of taxation
of payments to any Lender of the principal of or interest on any Eurodollar Rate
Advance made by such Lender or any fees or other amounts payable hereunder
(other than changes in respect of taxes imposed on the overall net income of
such Lender, or its Applicable Lending Office, by the jurisdiction in which such
Lender has its principal office or in which such Applicable Lending Office is
located or by any political subdivision or taxing authority therein), or (ii)
shall impose, modify or deem applicable any reserve, special deposit or similar
requirement against commitments or assets of, deposits with or for the account
of, or credit extended by, such Lender, or (iii) shall impose on such Lender any
other condition affecting this Agreement or Eurodollar

                                       21
<PAGE>

Rate Advances, and the result of any of the foregoing shall be (A) to increase
the cost to such Lender of issuing, maintaining or participating in this
Agreement or of agreeing to make, making or maintaining any Advance or (B) to
reduce the amount of any sum received or receivable by such Lender hereunder
(whether of principal, interest or otherwise), then the Borrower will pay to
such Lender, upon demand, such additional amount or amounts as will compensate
such Lender for such additional costs incurred or reduction suffered.

         (b) CAPITAL. If any Lender shall have determined that any change after
the date hereof in any law, rule, regulation or guideline adopted pursuant to or
arising out of the July 1988 report of the Basle Committee on Banking
Regulations and Supervisory Practices entitled "International Convergence of
Capital Measurement and Capital Standards", or the adoption after the date
hereof of any law, rule, regulation or guideline regarding capital adequacy, or
any change in any of the foregoing or in the interpretation or administration of
any of the foregoing by any governmental authority, central bank or comparable
agency charged with the interpretation or administration thereof, or compliance
by any Lender (or any Applicable Lending Office of such Lender), or any holding
company of any such entity, with any request or directive regarding capital
adequacy (whether or not having the force of law) of any such authority, central
bank or comparable agency, has or would have the effect (i) of reducing the rate
of return on such entity's capital or on the capital of such entity's holding
company, if any, as a consequence of this Agreement, any Commitment hereunder or
the portion of the Advances made by such entity pursuant hereto to a level below
that which such entity or such entity's holding company could have achieved, but
for such applicability, adoption, change or compliance (taking into
consideration such entity's policies and the policies of such entity's holding
company with respect to capital adequacy), or (ii) of increasing or otherwise
determining the amount of capital required or expected to be maintained by such
entity or such entity's holding company based upon the existence of this
Agreement, any Commitment hereunder, the portion of the Advance made by such
entity pursuant hereto and other similar such credits, participations,
commitments, agreements or assets, then from time to time the Borrower shall pay
to such Lender, upon demand, such additional amount or amounts as will
compensate such entity or such entity's holding company for any such reduction
or allocable capital cost suffered.

         (c) EURODOLLAR RESERVES. The Borrower shall pay to each Lender upon
demand, so long as such Lender shall be required under regulations of the Board
of Governors of the Federal Reserve System to maintain reserves with respect to
liabilities or assets consisting of or including Eurocurrency Liabilities,
additional interest on the unpaid principal amount of each Eurodollar Rate
Advance of such Lender to the Borrower, from the date of such Advance until such
principal amount is paid in full, at an interest rate per annum equal at all
times to the remainder obtained by subtracting (i) the Eurodollar Rate for the
Interest Period for such Advance from (ii) the rate obtained by dividing such
Eurodollar Rate by a percentage equal to 100% minus the Eurodollar Reserve
Percentage of such Lender for such Interest Period. Such additional interest
shall be determined by such Lender and notified to the Borrower and the
Administrative Agent.

         (d) BREAKAGE INDEMNITY. The Borrower shall indemnify each Lender
against any loss, cost or reasonable expense which such Lender may sustain or
incur as a consequence of (i) any failure by the Borrower to fulfill on the
Funding Date or the date of any continuation or conversion of Advances hereunder
the applicable conditions precedent set forth in Articles III and

                                       22
<PAGE>

V, (ii) any failure by the Borrower to borrow or continue any, or convert any
outstanding Advance into a, Eurodollar Rate Advance hereunder after the Notice
of Contract Borrowing has been delivered pursuant to Section 3.01 hereof or
after delivery of a notice of continuation or conversion pursuant to Section
3.05(a)(ii) hereof, (iii) any payment, prepayment, continuation or conversion of
a Eurodollar Rate Advance required or permitted by any other provision of this
Agreement or otherwise made or deemed made on a date other than the last day of
the Interest Period applicable thereto, (iv) any default in payment or
prepayment of the principal amount of any Eurodollar Rate Advance made to the
Borrower or any part thereof or interest accrued thereon, as and when due and
payable (at the due date thereof, by irrevocable notice of prepayment or
otherwise) or (v) the occurrence of any Event of Default, including, in each
such case, any loss or reasonable expense sustained or incurred or to be
sustained or incurred in liquidating or employing deposits from third parties
acquired to effect or maintain such Advance or any part thereof as a Eurodollar
Rate Advance. Such loss, cost or reasonable expense shall include an amount
equal to the excess, if any, as reasonably determined by such Lender, of (A) its
cost of obtaining the funds for the Eurodollar Rate Advance being paid, prepaid,
converted, continued or not borrowed or continued for the period from the date
of such payment, prepayment, conversion, continuation or failure to borrow or
continue to the last day of the Interest Period for such Advance (or, in the
case of a failure to borrow or continue, the Interest Period for such Advance
which would have commenced on the date of such failure) over (B) the amount of
interest (as reasonably determined by such Lender) that would be realized by
such Lender in reemploying the funds so paid, prepaid, converted, continued or
not borrowed or continued for such period or Interest Period, as the case may
be. For purposes of this subsection (d), it shall be presumed that in the case
of any Eurodollar Rate Advance, each Lender shall have funded each such Advance
with a fixed-rate instrument bearing the rates and maturities designated in the
determination of the Applicable Rate for such Advance.

(e) NOTICES. A certificate of any Lender setting forth such entity's claim for
compensation hereunder and the amount necessary to compensate such entity or its
holding company pursuant to subsections (a) through (d) of this Section 4.03
shall be submitted to the Borrower and the Administrative Agent and shall be
conclusive and binding for all purposes, absent manifest error. The Borrower
shall pay such Lender directly the amount shown as due on any such certificate
within 10 days after its receipt of the same. The failure of any entity to
provide such notice or to make demand for payment under this Section 4.03 shall
not constitute a waiver of such entity's rights hereunder; provided that such
entity shall not be entitled to demand payment pursuant to subsections (a)
through (d) of this Section 4.03 in respect of any loss, cost, expense,
reduction or reserve, if such demand is made more than one year following the
later of such entity's incurrence or sufferance thereof or such entity's actual
knowledge of the event giving rise to such entity's rights pursuant to such
subsections. Each Lender shall use reasonable efforts to ensure the accuracy and
validity of any claim made by it hereunder, but the foregoing shall not obligate
any such entity to assert any possible invalidity or inapplicability of the law,
rule, regulation, guideline or other change or condition which shall have
occurred or been imposed.

(f) CHANGE IN LEGALITY. Notwithstanding any other provision herein, if the
adoption of or any change in any law or regulation or in the interpretation or
administration thereof by any governmental authority charged with the
administration or interpretation thereof shall make it unlawful for any Lender
to make or maintain any Eurodollar Rate Advance or to give effect to its

                                       23
<PAGE>

obligations as contemplated hereby with respect to any Eurodollar Rate Advance,
then, by written notice to the Borrower and the Administrative Agent, such
Lender may:

                  (i) declare that Eurodollar Rate Advances will not thereafter
         be made by such Lender hereunder, whereupon the right of the Borrower
         to select Eurodollar Rate Advances for any Borrowing or conversion
         shall be forthwith suspended until such Lender shall withdraw such
         notice as provided hereinbelow or shall cease to be a Lender hereunder
         pursuant to Section 10.07(g) hereof; and

                  (ii) require that all outstanding Eurodollar Rate Advances be
         converted to Base Rate Advances, in which event all Eurodollar Rate
         Advances shall be automatically converted to Base Rate Advances as of
         the effective date of such notice as provided herein below.

         Upon receipt of any such notice, the Administrative Agent shall
promptly notify the other Lenders. Promptly upon becoming aware that the
circumstances that caused such Lender to deliver such notice no longer exist,
such Lender shall deliver notice thereof to the Borrower and the Administrative
Agent withdrawing such prior notice (but the failure to do so shall impose no
liability upon such Lender). Promptly upon receipt of such withdrawing notice
from such Lender (or upon such Lender assigning all of its Commitments, Advances
and other rights and obligations under the Loan Documents in accordance with
Section 10.07(g)), the Administrative Agent shall deliver notice thereof to the
Borrower and the Lenders and such suspension shall terminate. Prior to any
Lender giving notice to the Borrower under this subsection (f), such Lender
shall use reasonable efforts to change the jurisdiction of its Applicable
Lending Office, if such change would avoid such unlawfulness and would not, in
the sole determination of such Lender, be otherwise disadvantageous to such
Lender. Any notice to the Borrower by any Lender shall be effective as to each
Eurodollar Rate Advance on the last day of the Interest Period currently
applicable to such Eurodollar Rate Advance; provided that if such notice shall
state that the maintenance of such Advance until such last day would be
unlawful, such notice shall be effective on the date of receipt by the Borrower
and the Administrative Agent.

         (g) MARKET RATE DISRUPTIONS. If (i) fewer than two Reference Banks
furnish timely information to the Administrative Agent for determining the
Eurodollar Rate for Eurodollar Rate Advances in connection with any proposed
Borrowing or (ii) if the Majority Lenders shall notify the Administrative Agent
that the Eurodollar Rate will not adequately reflect the cost to such Majority
Lenders of making, funding or maintaining their respective Eurodollar Rate
Advances, the right of the Borrower to select or receive Eurodollar Rate
Advances for any Borrowing shall be forthwith suspended until the Administrative
Agent shall notify the Borrower and the Lenders that the circumstances causing
such suspension no longer exist, and until such notification from the
Administrative Agent, each requested Borrowing of Eurodollar Rate Advances
hereunder shall be deemed to be a request for Base Rate Advances.

         (h) RIGHTS OF PARTICIPANTS. Any participant in a Lender's interests
hereunder may assert any claim for yield protection under Section 4.03 that it
could have asserted if it were a Lender hereunder. If such a claim is asserted
by any such participant, it shall be entitled to receive such compensation from
the Borrower as a Lender would receive in like circumstances; provided,

                                       24
<PAGE>

however, that with respect to any such claim, the Borrower shall have no greater
liability to the Lender and its participant, in the aggregate, than it would
have had to the Lender alone had no such participation interest been created.

         SECTION 4.04. SHARING OF PAYMENTS, ETC. If any Lender shall obtain any
payment (whether voluntary, involuntary, through the exercise of any right of
set-off, or otherwise, but excluding any proceeds received by assignments or
sales of participation in accordance with Section 10.07 hereof to a Person that
is not an Affiliate of the Borrower) on account of the Advances owing to it
(other than pursuant to Section 4.03 hereof) in excess of its ratable share of
payments on account of the Advances obtained by all the Lenders, such Lender
shall forthwith purchase from the other Lenders such participation in the
Advances owing to them as shall be necessary to cause such purchasing Lender to
share the excess payment ratably with each of them; provided, however, that if
all or any portion of such excess payment is thereafter recovered from such
purchasing Lender, such purchase from each Lender shall be rescinded and such
Lender shall repay to the purchasing Lender the purchase price to the extent of
such recovery together with an amount equal to such Lender's ratable share
(according to the proportion of (i) the amount of such Lender's required
repayment to (ii) the total amount so recovered from the purchasing Lender) of
any interest or other amount paid or payable by the purchasing Lender in respect
of the total amount so recovered. The Borrower agrees that any Lender so
purchasing a participation from another Lender pursuant to this Section 4.04
may, to the fullest extent permitted by law, exercise all its rights of payment
(including the right of set-off) with respect to such participation as fully as
if such Lender were the direct creditor of the Borrower in the amount of such
participation. Notwithstanding the foregoing, if any Lender shall obtain any
such excess payment involuntarily, such Lender may, in lieu of purchasing
participation from the other Lenders in accordance with this Section 4.04, on
the date of receipt of such excess payment, return such excess payment to the
Administrative Agent for distribution in accordance with Section 4.01(a).

         SECTION 4.05. TAXES.

         (a) All payments by or on behalf of the Borrower under any Loan
Document shall be made in accordance with Section 4.01, free and clear of and
without deduction for all present or future taxes, levies, imposts, deductions,
charges or withholdings, and all liabilities with respect thereto, excluding, in
the case of each Lender and the Administrative Agent, taxes imposed on its
overall net income, and franchise taxes imposed on it, by the jurisdiction under
the laws of which such Lender or the Administrative Agent (as the case may be)
is organized or any political subdivision thereof and, in the case of each
Lender, taxes imposed on its overall net income, and franchise taxes imposed on
it, by the jurisdiction of such Lender's Applicable Lending Office or any
political subdivision thereof (all such non-excluded taxes, levies, imposts,
deductions, charges, withholdings and liabilities being hereinafter referred to
as "TAXES"). If the Borrower shall be required by law to deduct any Taxes from
or in respect of any sum payable under any Loan Document to any Lender or the
Administrative Agent, (i) the sum payable shall be increased as may be necessary
so that after making all required deductions (including deductions applicable to
additional sums payable under this Section 4.05) such Lender or the
Administrative Agent (as the case may be) receives an amount equal to the sum it
would have received had no such deductions been made, (ii) the Borrower shall
make such deductions and (iii) the Borrower shall

                                       25
<PAGE>

pay the full amount deducted to the relevant taxation authority or other
authority in accordance with applicable law.

         (b) In addition, the Borrower agrees to pay any present or future stamp
or documentary taxes or any other excise or property taxes, charges or similar
levies that arise from any payment made by the Borrower under any Loan Document
or from the execution, delivery or registration of, or otherwise with respect
to, any Loan Document (hereinafter referred to as "OTHER TAXES").

         (c) The Borrower hereby indemnifies each Lender and the Administrative
Agent for the full amount of Taxes and Other Taxes (including, without
limitation, any Taxes and any Other Taxes imposed by any jurisdiction on amounts
payable under this Section 4.05) paid by such Lender or the Administrative Agent
(as the case may be) and any liability (including penalties, interest and
expenses) arising therefrom or with respect thereto, whether or not such Taxes
or Other Taxes were correctly or legally asserted. A claim for such
indemnification shall be set forth in a certificate of such Lender or the
Administrative Agent (as the case may be) setting forth in reasonable detail the
amount necessary to indemnify such Person pursuant to this subsection (c) and
shall be submitted to the Borrower and the Administrative Agent and shall be
conclusive and binding for all purposes, absent manifest error. The Borrower
shall pay such Lender or the Administrative Agent (as the case may be) directly
the amount shown as due on any such certificate within 30 days after the receipt
of same. If any Taxes or Other Taxes for which a Lender or the Administrative
Agent has received payments from the Borrower hereunder shall be finally
determined to have been incorrectly or illegally asserted and are refunded to
such Lender or the Administrative Agent, such Lender or the Administrative
Agent, as the case may be, shall promptly forward to the Borrower any such
refunded amount. The Borrower's, the Administrative Agent's and each Lender's
obligations under this Section 4.05 shall survive the payment in full of the
Outstanding Credits.

         (d) Within 30 days after the date of any payment of Taxes, the Borrower
will furnish to the Administrative Agent, at its address referred to in Section
10.02, the original or a certified copy of a receipt evidencing payment thereof.

         (e) Each Lender that is not incorporated under the laws of the United
States of America or any state thereof shall, on or prior to the date it becomes
a Lender hereunder, deliver to the Borrower and the Administrative Agent such
certificates, documents or other evidence, as required by the Internal Revenue
Code of 1986, as amended from time to time (the "CODE"), or treasury regulations
issued pursuant thereto, including Internal Revenue Service Form 4224, Form
1001, Form W-8 BEN or Form W-8 ECI and any other certificate or statement of
exemption required by Treasury Regulation Section 1.1441-1(a) or Section
1.1441-6(c) or any subsequent version thereof, properly completed and duly
executed by such Lender establishing that it is (i) not subject to withholding
under the Code or (ii) totally exempt from United States of America tax under a
provision of an applicable tax treaty. Each Lender shall promptly notify the
Borrower and the Administrative Agent of any change in its Applicable Lending
Office and shall deliver to the Borrower and the Administrative Agent together
with such notice such certificates, documents or other evidence referred to in
the immediately preceding sentence. Each Lender will use good faith efforts to
apprise the Borrower and the Administrative Agent as promptly as practicable of
any impending change in its tax status that would give rise to any obligation by
the

                                       26
<PAGE>

Borrower to pay any additional amounts pursuant to this Section 4.05. Unless the
Borrower and the Administrative Agent have received forms or other documents
satisfactory to them indicating that payments under the Loan Documents are not
subject to United States of America withholding tax or are subject to such tax
at a rate reduced by an applicable tax treaty, the Borrower or the
Administrative Agent shall withhold taxes from such payments at the applicable
statutory rate in the case of payments to or for any Lender organized under the
laws of a jurisdiction outside the United States of America. Each Lender
represents and warrants that each such form supplied by it to the Administrative
Agent and the Borrower pursuant to this Section 4.05, and not superseded by
another form supplied by it, is or will be, as the case may be, complete and
accurate.

         (f) Any Lender claiming any additional amounts payable pursuant to this
Section 4.05 shall use reasonable efforts (consistent with legal and regulatory
restrictions) to file any certificate or document requested by the Borrower or
to change the jurisdiction of its Applicable Lending Office if the making of
such a filing or change would avoid the need for or reduce the amount of any
such additional amounts which may thereafter accrue and would not, in the sole
determination of such Lender, be otherwise disadvantageous to such Lender.


                                    ARTICLE V


                              CONDITIONS PRECEDENT

         SECTION 5.01. CONDITIONS PRECEDENT TO EFFECTIVENESS. The obligations of
the Lenders to make Advances to the Borrower on the Funding Date shall not
become effective until the date (the "CLOSING DATE") on which each of the
following conditions is satisfied:

         (a) The Administrative Agent shall have received on or before the
Closing Date the following, each dated the Closing Date, in form and substance
satisfactory to the Administrative Agent and in sufficient copies for each
Lender (except for the Notes):

                  (i) Counterparts of this Agreement, duly executed by the
         Borrower.

                  (ii) Contract Notes of the Borrower, duly made to the order of
         each Lender in the amount of such Lender's Commitment.

                  (iii) A certificate of the Secretary or Assistant Secretary of
         the Borrower certifying:

                           (A) the names and true signatures of the officers of
                  the Borrower authorized to sign the Loan Documents;

                           (B) that attached thereto are true and correct copies
                  of: (1) the Declaration of Trust of the Borrower, together
                  with all amendments thereto, as in effect on such date; (2)
                  the resolutions of the Borrower's Board of Trustees

                                       27
<PAGE>

                  approving the execution, delivery and performance by the
                  Borrower of the Loan Documents, the Borrowings hereunder and
                  the consummation by the Borrower of the acquisition of YES;
                  (3) all documents evidencing other necessary corporate or
                  other similar action, if any, with respect to the execution,
                  delivery and performance of the Loan Documents by the Borrower
                  and the consummation by the Borrower of the acquisition of
                  YES; and (4) true and correct copies of all Governmental
                  Approvals referred to in clauses (i) and (iii) of the
                  definition of "Governmental Approval" required to be obtained
                  by the Borrower in connection with the execution, delivery and
                  performance by the Borrower of the Loan Documents (including
                  the order of the Securities and Exchange Commission) and the
                  acquisition by the Borrower of YES; and

                           (C) that the resolutions referred to in the foregoing
                  clause (B)(2) have not been modified, revoked or rescinded and
                  are in full force and effect on such date.

                  (iv) A certificate signed by the Treasurer or Assistant
         Treasurer of the Borrower, certifying as to:

                           (A) the delivery to each of the Lenders, prior to the
                  Closing Date, of true, correct and complete copies (other than
                  exhibits thereto) of all of the Disclosure Documents; and

                           (B) the absence of any material adverse change in the
                  financial condition, operations, properties or prospects of
                  the Borrower or the Borrower and its Principal Subsidiaries,
                  taken as a whole, since September 30, 1999, except as
                  disclosed in the Disclosure Documents.

                  (v) A certificate of a duly authorized officer of the Borrower
         certifying that (i) the representations and warranties of the Borrower
         contained in Section 6.01 are correct, in all material respects, on and
         as of the Closing Date, (ii) no event has occurred and is continuing
         which constitutes an Event of Default or Unmatured Default, and (iii)
         attached thereto is the merger agreement with respect to the
         acquisition of YES and all amendments and supplements, if any, thereto.

                  (vi) Such financial, business and other information regarding
         the Borrower and its Principal Subsidiaries, as any Lender shall have
         reasonably requested.

                  (vii) Favorable opinions of:

                           (A) Day, Berry & Howard, counsel to the Borrower, in
                  substantially the form of Exhibit 5.01A hereto and as to such
                  other matters as any Lender may reasonably request;

                           (B) Jeffrey C. Miller, Assistant General Counsel of
                  NUSCO, in substantially the form of Exhibit 5.01B hereto; and
                  as to such other matters as any Lender may reasonably request;
                  and

                                       28
<PAGE>

                           (C) King & Spalding, special New York counsel to the
                  Administrative Agent, in substantially the form of Exhibit
                  5.01C hereto and as to such other matters as any Lender may
                  reasonably request.

         (b) The representations and warranties of the Borrower contained in
Section 6.01 shall be correct in all material respects on and as of the Closing
Date, and no event shall have occurred and be continuing which constitutes an
Event of Default or Unmatured Default.

         (c) All fees and other amounts payable pursuant to the Fee Letter shall
have been paid (to the extent then due and payable).

         (d) The Borrower shall have entered into a definitive merger agreement
with respect to the acquisition of YES; the Administrative Agent shall have
reviewed and shall be satisfied with all of the material terms thereof; no
default or failure in the satisfaction of a condition shall have occurred and be
continuing under such agreement that could reasonably be expected to threaten or
materially delay the consummation of such acquisition; and, from and after the
date hereof, the Borrower shall not have agreed to any modification of such
material terms if the effect thereof would be to increase the purchase price of
the shares of YES to be acquired thereunder or, without the consent of the
Administrative Agent, if the effect of such modification would be to decrease
the aggregate value of such shares.

         (e) The Administrative Agent shall have received such other approvals,
opinions and documents as the Majority Lenders, through the Administrative
Agent, shall have reasonably requested as to the legality, validity, binding
effect or enforceability of this Agreement and the Notes or the financial
condition, operations, properties or prospects of the Borrower and its Principal
Subsidiaries.

         SECTION 5.02. CONDITIONS PRECEDENT TO ADVANCES ON FUNDING DATE. The
obligation of any Lender to make an Advance on the Funding Date shall be subject
to the conditions precedent that, on such date and after giving effect to the
Advances to be made thereon:

         (a) the following statements shall be true (and each of the giving of
the Notice of Contract Borrowing with respect to such Advances and the
acceptance of the proceeds of such Advances by the Borrower shall constitute a
representation and warranty by the Borrower that on the Funding Date such
statements are true):

                  (i) the representations and warranties of the Borrower
         contained in Section 6.01 of this Agreement are correct, in all
         material respects, on and as of the Funding Date, before and after
         giving effect to the Advances to be made thereon and to the application
         of the proceeds therefrom, as though made on and as of such date; and

                  (ii) no Event of Default or Unmatured Default has occurred and
         is continuing on or as of the Funding Date or would result from the
         Advances to be made thereon or from the application of the proceeds
         thereof; and

                                       29
<PAGE>

         (b) the Borrower shall have furnished to the Administrative Agent such
other approvals, opinions or documents as any Lender may reasonably request
through the Administrative Agent as to the legality, validity, binding effect or
enforceability of any Loan Document.

         SECTION 5.03. RELIANCE ON CERTIFICATES. The Lenders and the
Administrative Agent shall be entitled to rely conclusively upon the
certificates delivered from time to time by officers of the Borrower as to the
names, incumbency, authority and signatures of the respective persons named
therein until such time as the Administrative Agent may receive a replacement
certificate, in form acceptable to the Administrative Agent, from an officer of
the Borrower identified to the Administrative Agent as having authority to
deliver such certificate, setting forth the names and true signatures of the
officers and other representatives of the Borrower thereafter authorized to act
on behalf of the Borrower and, in all cases, the Lenders and the Administrative
Agent may rely on the information set forth in any such certificate.


                                   ARTICLE VI


                         REPRESENTATIONS AND WARRANTIES

         SECTION 6.01. REPRESENTATIONS AND WARRANTIES OF THE BORROWER. The
Borrower represents and warrants as follows:

                  (a) The Borrower is a voluntary association organized under a
         Declaration of Trust, and each of its Principal Subsidiaries is a
         corporation, in each case duly organized, validly existing and in good
         standing under the laws of the jurisdiction of its organization, has
         the requisite corporate power (or in the case of the Borrower, power
         under its Declaration of Trust) and authority to own its property and
         assets and to carry on its business as now conducted and is qualified
         to do business in every jurisdiction where, because of the nature of
         its business or property, such qualification is required, except where
         the failure so to qualify would not have a material adverse effect on
         the financial condition, properties, prospects or operations of the
         Borrower or of the Borrower and its Principal Subsidiaries taken as a
         whole. The Borrower has the requisite power to execute, deliver and
         perform its obligations under the Loan Documents, to borrow hereunder
         and to execute and deliver its respective Notes, and to consummate the
         acquisition of YES.

                  (b) The execution, delivery and performance of the Loan
         Documents by the Borrower, and the consummation by the Borrower of the
         acquisition of YES, are within the Borrower's powers under its
         Declaration or Trust, have been duly authorized by all necessary action
         under its Declaration of Trust and applicable law, and do not and will
         not contravene (i) the Borrower's Declaration of Trust or any law or
         legal restriction or (ii) any contractual restriction binding on or
         affecting the Borrower or its properties or its Principal Subsidiaries
         or their respective properties.

                  (c) Except as disclosed in the Disclosure Documents, none of
         the Borrower or any of its Principal Subsidiaries is in violation of
         any law or in default with respect to any

                                       30
<PAGE>

         judgment, writ, injunction, decree, rule or regulation (including any
         of the foregoing relating to environmental laws and regulations) of any
         court or governmental agency or instrumentality where such violation or
         default would reasonably be expected to have a material adverse effect
         on the financial condition, properties, prospects or operations of the
         Borrower or of the Borrower and its Principal Subsidiaries, taken as a
         whole.

                  (d) There has been no material adverse development with
         respect to (i) the proceedings of CL&P or WMECO to divest its
         generating assets, or (ii) any orders, plans or authorizations for
         recovery of the stranded assets of CL&P or WMECO, where any such
         development results, or would reasonably be expected to result, in a
         material adverse effect on the financial condition, properties,
         prospects or operations of the Borrower or of the Borrower and its
         Principal Subsidiaries, taken as a whole, other than as described in
         the Disclosure Documents.

                  (e) All Governmental Approvals referred to in clauses (i) and
         (iii) of the definition of "Governmental Approvals" have been duly
         obtained or made, and all applicable periods of time for review,
         rehearing or appeal with respect thereto have expired, except as
         described below. If the period for appeal of the order of the
         Securities and Exchange Commission approving the transactions
         contemplated hereby (including the acquisition by the Borrower of YES)
         has not expired, the filing of an appeal of such order will not affect
         the validity of said transactions, unless such order has been otherwise
         stayed or any of the parties hereto has actual knowledge that any of
         such transactions constitutes a violation of the Public Utility Holding
         Company Act of 1935 or any rule or regulation thereunder. No such stay
         exists and the Borrower has no reason to believe that any of such
         transactions constitutes any such violation. The Borrower and each
         Subsidiary thereof has obtained or made all Governmental Approvals
         referred to in clause (ii) of the definition of "Governmental
         Approvals", except (A) those which are not yet required but which are
         obtainable in the ordinary course of business as and when required, (B)
         those the absence of which would not materially adversely affect the
         financial condition, properties, prospects or operations of the
         Borrower or of the Borrower and its Principal Subsidiaries, taken as a
         whole, and (C) those which the Borrower or any such Subsidiary, as the
         case may be, is diligently attempting in good faith to obtain, renew or
         extend, or the requirement for which the Borrower or any such
         Subsidiary, as the case may be, is contesting in good faith by
         appropriate proceedings or by other appropriate means, in each case
         described in the foregoing clause (C), except as is disclosed in the
         Disclosure Documents, such attempt or contest, and any delay resulting
         therefrom, is not reasonably expected to have a material adverse effect
         on the financial condition, properties, prospects or operations of the
         Borrower or of the Borrower and its Principal Subsidiaries, taken as a
         whole, or to magnify to any significant degree any such material
         adverse effect that would reasonably be expected to result from the
         absence of such Governmental Approval.

                  (f) The Loan Documents are legal, valid and binding
         obligations of the Borrower enforceable against the Borrower in
         accordance with their respective terms; subject to the qualification,
         however, that the enforcement of the rights and remedies herein and
         therein is subject to bankruptcy and other similar laws of general
         application affecting rights and

                                       31
<PAGE>

         remedies of creditors and the application of general principles of
         equity (regardless of whether considered in a proceeding in equity or
         at law).

                  (g) The Financial Statements, copies of which have been
         provided to the Administrative Agent and each of the Lenders, fairly
         present in all material respects the consolidated financial condition
         and results of operations of the Borrower and each of its Principal
         Subsidiaries at and for the period ended on the dates thereof, and have
         been prepared in accordance with generally accepted accounting
         principles consistently applied. Since September 30, 1999, there has
         been no material adverse change in the consolidated financial
         condition, operations, properties or prospects of the Borrower or of
         the Borrower and its Principal Subsidiaries, taken as a whole, except
         as disclosed in the Disclosure Documents.

                  (h) There is no pending or known threatened action or
         proceeding (including, without limitation, any action or proceeding
         relating to any environmental protection laws or regulations) affecting
         the Borrower, any Principal Subsidiary thereof or any of their
         respective properties, before any court, governmental agency or
         arbitrator (i) which affects or purports to affect the legality,
         validity or enforceability of any Loan Document or of the consummation
         by the Borrower of the acquisition of YES or (ii) as to which there is
         a reasonable possibility of an adverse determination and which, if
         adversely determined, would materially adversely affect (A) the
         financial condition, properties, prospects or operations of the
         Borrower or of the Borrower and its Principal Subsidiaries, taken as a
         whole, or (B) the timing, cost or worth to the Borrower of the
         consummation of the acquisition of YES, except, for purposes of this
         clause (ii) only, such as is described in the Disclosure Documents or
         in Schedule II hereto.

                  (i) No ERISA Plan Termination Event has occurred nor is
         reasonably expected to occur with respect to any ERISA Plan which would
         materially adversely affect the financial condition, properties,
         prospects or operations of the Borrower or of the Borrower and its
         Principal Subsidiaries, taken as a whole, except as disclosed to the
         Lenders and consented to by the Majority Lenders in writing. Since the
         date of the most recent Schedule B (Actuarial Information) to the
         annual report of each such ERISA Plan (Form 5500 Series), there has
         been no material adverse change in the funding status of the ERISA
         Plans referred to therein, and no "prohibited transaction" has occurred
         with respect thereto that, singly or in the aggregate with all other
         "prohibited transactions" and after giving effect to all likely
         consequences thereof, would be reasonably expected to have a material
         adverse effect on the financial condition, properties, prospects or
         operations of the Borrower or of the Borrower and its Principal
         Subsidiaries, taken as a whole. Neither the Borrower nor any of its
         ERISA Affiliates has incurred nor reasonably expects to incur any
         material withdrawal liability under ERISA to any ERISA Multiemployer
         Plan, except as disclosed to and consented by the Majority Lenders in
         writing.

                  (j) The Borrower and each Principal Subsidiary thereof has
         good and marketable title (or, in the case of personal property, valid
         title) or valid leasehold interests in its assets, except for (i) minor
         defects in title that do not materially interfere with the ability of

                                       32
<PAGE>

         the Borrower or such Principal Subsidiary to conduct its business as
         now conducted and (ii) other defects that, either individually or in
         the aggregate, do not materially adversely affect the financial
         condition, properties, prospects or operations of the Borrower or of
         the Borrower and its Principal Subsidiaries, taken as a whole. All such
         assets and properties are free and clear of any Lien, other than Liens
         permitted under Section 7.02(a) hereof. No Liens exist on the stock of
         CL&P, WMECO or PSNH.

                  (k) All outstanding shares of capital stock having ordinary
         voting power for the election of directors of each Principal Subsidiary
         have been validly issued and are fully paid and nonassessable and are
         owned beneficially by NU, free and clear of any Lien. NU is a "holding
         company" (as defined in the Public Utility Holding Company Act of 1935,
         as amended).

                  (l) The Borrower and each of its Principal Subsidiaries has
         filed all tax returns (Federal, state and local) required to be filed
         and paid taxes shown thereon to be due, including interest and
         penalties, or, to the extent the Borrower or such Principal Subsidiary
         is contesting in good faith an assertion of liability based on such
         returns, has provided adequate reserves in accordance with generally
         accepted accounting principles for payment thereof.

                  (m) No exhibit, schedule, report or other written information
         provided by or on behalf of the Borrower or its agents to the
         Administrative Agent or the Lenders in connection with the negotiation,
         execution and closing of the Loan Documents (including, without
         limitation, the Financial Statements) knowingly contained when made any
         material misstatement of fact or knowingly omitted to state any
         material fact necessary to make the statements contained therein not
         misleading in light of the circumstances under which they were made.
         Except as has been disclosed to the Administrative Agent and each
         Lender, nothing has come to the attention of the responsible officers
         of the Borrower that would indicate that any of such assumptions, to
         the extent material to such projections, has ceased to be reasonable in
         light of subsequent developments or events.

                  (n) All proceeds of the Advances shall be used to finance the
         acquisition by the Borrower of YES. No proceeds of any Advance will be
         used in violation of, or in any manner that would result in a violation
         by any party hereto of, Regulation T, U or X promulgated by the Board
         of Governors of the Federal Reserve System or any successor
         regulations. After giving effect to the acquisition of YES, the
         aggregate value of all of the shares of YES acquired by the Borrower,
         together with the aggregate value of all other Margin Stock (as defined
         in Regulation U) owned of record or beneficially by the Borrower and
         its consolidated subsidiaries will not exceed 25% of the total
         consolidated assets of the Borrower and its consolidated Subsidiaries.
         Neither the Borrower nor any Subsidiary thereof (A) is an "investment
         company" within the meaning ascribed to that term in the Investment
         Company Act of 1940 or (B) is engaged in the business of extending
         credit for the purpose of buying or carrying Margin Stock.

                  (o) The Borrower and each Principal Subsidiary thereof has
         obtained the insurance specified in Section 7.01(c) hereof and the same
         is in full force and effect.

                                       33
<PAGE>

                  (p) The Borrower and each Principal Subsidiary thereof has
         substantially completed reprogramming and/or remediation required as a
         result of the potential Year 2000 Issue to permit the proper
         functioning in all material respects of its computer software, hardware
         and firmware systems and equipment containing computer chips and the
         proper processing in all material respects of data, and the testing of
         such reprogramming or remediation (as the case may be). The Borrower
         has completed review of the reasonably foreseeable consequences of the
         potential Year 2000 Issue to the Borrower and each of its Principal
         Subsidiaries (including, without limitation, reprogramming errors and
         the failure of systems or equipment supplied by others) and such
         consequences are not reasonably expected to result in an Event of
         Default, an Unmatured Default or a material adverse effect on the
         financial condition, properties, prospects or operations of the
         Borrower or of the Borrower and its Principal Subsidiaries, taken as a
         whole.


                                   ARTICLE VII


                                    COVENANTS

         SECTION 7.01. AFFIRMATIVE COVENANTS. On and after the Closing Date, so
long as any Note shall remain unpaid or any Lender shall have any Commitment
hereunder, the Borrower shall, unless the Majority Lenders shall otherwise
consent in writing:

                  (a) USE OF PROCEEDS. Apply the proceeds of each Advance solely
         as specified in Section 6.01(n) hereof.

                  (b) PAYMENT OF TAXES, ETC. Pay and discharge, and cause each
         of its Principal Subsidiaries to pay and discharge, before the same
         shall become delinquent, all taxes, assessments and governmental
         charges, royalties or levies imposed upon it or upon its property
         except to the extent the Borrower or such Principal Subsidiary is
         contesting the same in good faith by appropriate proceedings and has
         set aside adequate reserves in accordance with generally accepted
         accounting principles for the payment thereof.

                  (c) MAINTENANCE OF INSURANCE. Maintain or cause to be
         maintained, and cause each of its Principal Subsidiaries to maintain or
         cause to be maintained, insurance (including appropriate plans of
         self-insurance) covering the Borrower, the Principal Subsidiaries and
         their respective properties, in effect at all times in such amounts and
         covering such risks as may be required by law and, in addition, as is
         usually carried by companies engaged in similar businesses and owning
         similar properties as the Borrower and such Principal Subsidiaries.

                  (d) PRESERVATION OF EXISTENCE, ETC.; DISAGGREGATION.

                           (i) Except as permitted by Section 7.02(b) hereof,
                  preserve and maintain, and cause each of its Principal
                  Subsidiaries to preserve and maintain, its existence,

                                       34
<PAGE>

                  corporate or otherwise, material rights (statutory and
                  otherwise) and franchises except where the failure to maintain
                  and preserve such rights and franchises would not materially
                  adversely affect the financial condition, properties,
                  prospects or operations of the Borrower or of the Borrower and
                  its Principal Subsidiaries, taken as a whole.

                           (ii) In furtherance of the foregoing, and
                  notwithstanding Section 7.02(b), the Borrower agrees that it
                  will not, and will cause each of its Principal Subsidiaries
                  not to, except in accordance with one or more restructuring
                  plans approved by the appropriate regulatory authorities,
                  sell, transfer or otherwise dispose of (by lease or otherwise,
                  and whether in one or a series of related transactions) any
                  portion of its generation, transmission or distribution assets
                  in excess of 10% of the net utility plant assets of the
                  Borrower and its Principal Subsidiaries, taken as a whole, in
                  each case as determined on a cumulative basis from the date of
                  this Agreement through the Termination Date by reference to
                  the published balance sheets of the Borrower and its Principal
                  Subsidiaries.

                  (e) COMPLIANCE WITH LAWS, ETC. Comply, and cause each of its
         Principal Subsidiaries to comply, in all material respects with the
         requirements of all applicable laws, rules, regulations and orders of
         any governmental authority, including, without limitation, any such
         laws, rules, regulations and orders issued by the Securities and
         Exchange Commission or relating to zoning, environmental protection,
         use and disposal of Hazardous Substances, land use, construction and
         building restrictions, ERISA and employee safety and health matters
         relating to business operations, except to the extent (i) that the
         Borrower or any such Principal Subsidiary is contesting the same in
         good faith by appropriate proceedings or (ii) that any such
         non-compliance, and the enforcement or correction thereof, would not
         materially adversely affect the financial condition, properties,
         prospects or operations of the Borrower or of the Borrower and its
         Principal Subsidiaries, taken as a whole.

                  (f) INSPECTION RIGHTS. At any time and from time to time upon
         reasonable notice, permit, and cause each of its Principal Subsidiaries
         to permit, the Administrative Agent, the Lenders and their respective
         agents and representatives to examine and make copies of and abstracts
         from the records and books of account of, and the properties of, the
         Borrower and each Principal Subsidiary and to discuss the affairs,
         finances and accounts of the Borrower and each Principal Subsidiary (i)
         with the Borrower, each Principal Subsidiary and their respective
         officers and directors and (ii) with the consent of the Borrower and/or
         its Principal Subsidiaries, as the case may be (which consent shall not
         be unreasonably withheld or delayed), with the accountants of the
         Borrower or any such Principal Subsidiary.

                  (g) KEEPING OF BOOKS. Keep, and cause each Principal
         Subsidiary to keep, proper records and books of account, in which full
         and correct entries shall be made of all financial transactions of the
         Borrower and each Principal Subsidiary and the assets and business of
         the Borrower and each Principal Subsidiary, in accordance with
         generally accepted accounting practices consistently applied.

                                       35
<PAGE>

                  (h) CONDUCT OF BUSINESS. Except as permitted by Section
         7.02(b) but subject in all respects to Section 7.01(d)(ii), conduct,
         and cause each Principal Subsidiary to conduct, its primary business in
         substantially the same manner and in substantially the same fields as
         such business is conducted on the Closing Date.

                  (i) MAINTENANCE OF PROPERTIES, ETC. (i) As to properties of
         the type described in Section 6.01(j) hereof, maintain, and cause each
         Principal Subsidiary to maintain, title of the quality described
         therein and preserve, maintain, develop, and operate, and cause each
         Principal Subsidiary to preserve, maintain, develop and operate, in
         substantial conformity with all laws, material contractual obligations
         and prudent practices prevailing in the industry, all of its properties
         which are used or useful in the conduct of its businesses in good
         working order and condition, ordinary wear and tear excepted, except
         (A) as permitted by Section 7.02(b), but subject nevertheless to
         Section 7.01(d)(ii), (B) as disclosed in the Disclosure Documents or
         otherwise in writing to the Administrative Agent and the Lenders on or
         prior to the date hereof, and (C) to the extent such non-conformity
         would not materially adversely affect the financial condition,
         properties, prospects or operations of the Borrower or of the Borrower
         and its Principal Subsidiaries, taken as a whole; provided, however,
         that neither the Borrower nor any Principal Subsidiary will be
         prevented from discontinuing the operation and maintenance of any such
         properties if such discontinuance is, in the judgment of the Borrower
         or such Principal Subsidiary, desirable in the operation or maintenance
         of its business and would not materially adversely affect the financial
         condition, properties, prospects or operations of the Borrower or of
         the Borrower and its Principal Subsidiaries, taken as a whole.

                  (j) GOVERNMENTAL APPROVALS. Duly obtain, and cause each
         Principal Subsidiary to duly obtain, on or prior to such date as the
         same may become legally required, and thereafter maintain, and cause
         each Principal Subsidiary to maintain, in effect at all times, all
         Governmental Approvals on its part to be obtained, except in the case
         of those Governmental Approvals referred to in clause (ii) of the
         definition of "Governmental Approvals", (i) those the absence of which
         would not materially adversely affect the financial condition,
         properties, prospects or operations of the Borrower or of the Borrower
         and its Principal Subsidiaries, taken as a whole, and (ii) those which
         the Borrower or such Principal Subsidiary is diligently attempting in
         good faith to obtain, renew or extend, or the requirement for which the
         Borrower or such Principal Subsidiary is contesting in good faith by
         appropriate proceedings or by other appropriate means; provided,
         however, that the exception afforded by clause (ii), above, shall be
         available only if and for so long as such attempt or contest, and any
         delay resulting therefrom, does not have a material adverse effect on
         the financial condition, properties, prospects or operations of the
         Borrower or of the Borrower and its Principal Subsidiaries, taken as a
         whole, and does not magnify to any significant degree any such material
         adverse effect that would reasonably be expected to result from the
         absence of such Governmental Approval.

                  (k) FURTHER ASSURANCES. Promptly execute and deliver all
         further instruments and documents, and take all further action, that
         may be necessary or that any Lender

                                       36
<PAGE>

         through the Administrative Agent may reasonably request in order to
         fully give effect to the interests and properties purported to be
         covered by the Loan Documents.

         SECTION 7.02. NEGATIVE COVENANTS. On and after the Closing Date, and so
long as any Note shall remain unpaid or any Lender shall have any Commitment
hereunder, the Borrower shall not, or permit any Principal Subsidiary to,
without the written consent of the Majority Lenders:

         (a) LIENS, ETC. Create incur, assume or suffer to exist any Lien upon
any of its properties or assets (including the stock of its Subsidiaries),
whether now owned or hereafter acquired, except:

                  (i)     any Liens existing on the Closing Date;

                  (ii) in the case of CL&P, Liens created by the Indenture of
         Mortgage and Deed of Trust dated as of May 1, 1921, from CL&P to
         Bankers Trust Company, as trustee, as previously and hereafter amended
         and supplemented (the "CL&P INDENTURE");

                  (iii) in the case of WMECO, Liens created by the First
         Mortgage Indenture and Deed of Trust dated as of August 1, 1954, from
         WMECO to State Street Bank and Trust Company, as successor trustee, as
         previously and hereafter amended and supplemented (the "WMECO
         INDENTURE");

                  (iv) in the case of PSNH, Liens created by the General and
         Refunding Mortgage Indenture, dated as of August 15, 1978, between PSNH
         and New England Merchants National Bank, as trustee, and to which First
         Union National Bank is successor trustee, as previously and hereafter
         amended and supplemented (the "PSNH INDENTURE");

                  (v) in the case of NAEC, Liens created by the First Mortgage
         Indenture and Deed of Trust, dated as of June 1, 1992, between NAEC and
         United States Trust Company of New York, as trustee, as previously and
         hereafter amended and supplemented (the "NAEC INDENTURE");

                  (vi) Liens on the interests of CL&P and WMECO in (A) the
         Millstone Unit No. 1 created by (1) the Open-End Mortgage and Trust
         Agreement dated as of October 1, 1986, as previously and hereafter
         amended, made by CL&P in favor of State Street Bank and Trust Company,
         as successor trustee, and (2) the Open-End Mortgage and Trust Agreement
         dated as of October 1, 1986, as previously and hereafter amended, made
         by WMECO in favor of State Street Bank and Trust Company, as successor
         trustee, to the extent of the Debt from time to time secured by such
         Open-End Mortgages and Trust Agreements, and (B) Millstone Unit No. 2
         and Millstone Unit No. 3 created by (1) the Open-End Mortgage, dated as
         of November 19, 1999, made by CL&P in favor of Citibank, N.A., as
         collateral agent, and (2) the Open-End Mortgage, dated as of November
         19, 1999, made by WMECO in favor of Citibank, N.A., as collateral
         agent, to the extent of the Debt secured by such Open-End Mortgages;

                                       37
<PAGE>

                  (vii) "Permitted Liens" or "Permitted Encumbrances" under the
         CL&P Indenture (in the case of CL&P), the WMECO Indenture (in the case
         of WMECO), the PSNH Indenture (in the case of PSNH) or the NAEC
         Indenture (in the case of NAEC), in each case as such terms are defined
         on the date hereof, to the extent such Liens do not secure Debt of the
         Borrower or any Principal Subsidiary;

                  (viii) any purchase money Lien or construction mortgage on
         assets hereafter acquired or constructed by the Borrower or any
         Principal Subsidiary and any Lien on any assets existing at the time of
         acquisition thereof by the Borrower or such Principal Subsidiary or
         created within 180 days from the date of completion of such acquisition
         or construction; provided that such Lien shall at all times be confined
         solely to the assets so acquired or constructed and any additions
         thereto;

                  (ix) any existing Liens on assets now owned by the Borrower or
         any Principal Subsidiary and Liens existing on assets of a corporation
         or other going concern when it is merged into or with the Borrower or
         such Principal Subsidiary or when substantially all of its assets are
         acquired by the Borrower or such Principal Subsidiary; provided that
         such Liens shall at all times be confined solely to such assets, or if
         such assets constitute a utility system, additions to or substitutions
         for such assets;

                  (x) Liens resulting from legal proceedings being contested in
         good faith by appropriate legal or administrative proceedings by the
         Borrower or any Principal Subsidiary, and as to which the Borrower or
         such Principal Subsidiary, to the extent required by generally accepted
         accounting principles applied on a consistent basis, shall have set
         aside on its books adequate reserves;

                  (xi)    Liens created in favor of the other contracting party
         in connection with advance or progress payments;

                  (xii) any Liens in favor of any state of the United States or
         any political subdivision of any such state, or any agency of any such
         state or political subdivisions, or trustee acting on behalf of holders
         of obligations issued by any of the foregoing or any financial
         institutions lending to or purchasing obligations of any of the
         foregoing, which Lien is created or assumed for the purpose of
         financing all or part of the cost of acquiring or constructing the
         property subject thereto;

                  (xiii) Liens resulting from conditional sale agreements,
         capital leases or other title retention agreements including, without
         limitation, Liens arising under leases of nuclear fuel from the Niantic
         Bay Fuel Trust;

                  (xiv) with respect to pollution control bond financings, Liens
         on funds, accounts and other similar intangibles of the Borrower or any
         Principal Subsidiary created or arising under the relevant indenture,
         pledges of the related loan agreement with the relevant issuing
         authority and pledges of the Borrower's or such Principal Subsidiary's
         interest, if any, in any bonds issued pursuant to such financings to a
         letter of credit bank or bond issuer or similar credit enhancer;

                                       38
<PAGE>

                  (xv) Liens granted on accounts receivable and Regulatory
         Assets in connection with financing transactions, whether denominated
         as sales or borrowings;

                  (xvi) Liens on the assets of, or the stock issued by,
         Northeast Generation Company or any other Subsidiary of the Borrower
         created to hold generating assets if such Liens are created to secure
         nonrecourse Debt incurred to acquire, construct or otherwise develop
         such generating assets;

                  (xvii)  Liens on assets of HWP permitted to exist by the terms
         of agreements governing the Named Debt;

                  (xviii) any other Liens incurred in the ordinary course of
         business otherwise than to secure Debt; and

                  (xix) any extension, renewal or replacement of Liens permitted
         by clauses (i), (vi) through (ix) and (xi) through (xvi); provided,
         however, that the principal amount of Debt secured thereby shall not,
         at the time of such extension, renewal or replacement, exceed the
         principal amount of Debt so secured and that such extension, renewal or
         replacement shall be limited to all or a part of the property which
         secured the Lien so extended, renewed or replaced.

         (b) MERGERS, ACQUISITIONS, SALES OF ASSETS, ETC. Merge with or into or
consolidate with or into, any Person, or purchase or otherwise acquire (whether
directly or indirectly) all or substantially all of the assets or stock of any
class of, or any partnership or joint venture interest in, any other Person, or
sell, transfer, convey, lease or otherwise dispose of all or any substantial
part of its assets; except for the following, and then only after receipt of all
necessary corporate and governmental or regulatory approvals and provided that,
before and after giving effect to any such merger, consolidation, purchase,
acquisition, sale, transfer, conveyance, lease or other disposition, no Event of
Default or Unmatured Default shall have occurred and be continuing:

                  (A) NU may merge with or into Consolidated Edison, Inc. or a
         wholly owned Subsidiary thereof;

                  (B) any purchase or acquisition of a joint venture interest in
         a mutual insurance company providing nuclear liability or nuclear
         property or replacement power insurance;

                  (C) any sale of accounts receivable on reasonable commercial
         terms (including a commercially reasonable discount) to obtain funding
         for CL&P and WMECO, as the case may be;

                  (D) any sale or purchase of generating assets or Regulatory
         Assets on an arms-length basis, subject to approval by the appropriate
         regulatory authorities;

                  (E) the sale of the Borrower's or any Principal Subsidiary's
         assets in the ordinary course of business on customary terms and
         conditions;

                                       39
<PAGE>

                  (F) the acquisition of YES for consideration in an amount not
         to exceed $495,000,000 (excluding the assumption of Debt); and

                  (G) the acquisition of substantially all of the assets of, or
         substantially all of the ownership interests in, any other Person or
         Persons, which acquisition or acquisitions are not otherwise permitted
         by this subsection (b), so long as the aggregate consideration for all
         such acquisitions (including the acquisition by HEC Inc. of the assets
         of Energy Applications Inc.) does not exceed $5,000,000.

For purposes of this subsection (b), any sale of assets by the Borrower or any
Principal Subsidiary (in one or a series of transactions) will be deemed to be a
"substantial part" of its assets if (i) the book value of such assets exceeds
7.5% of the total book value of the assets (net of Regulatory Assets) of such
Person, as reflected in the most recent financial statements of the Borrower or
such Principal Subsidiary delivered to the Administrative Agent pursuant to
Section 7.04 hereof (or, if no such financial statements have been delivered to
the Administrative Agent as of the relevant date of determination, the Financial
Statements of such Person), or (ii) the gross revenue associated with such
assets accounts for more than 7.5% of the total gross revenue of the Borrower or
such Principal Subsidiary for the four proceeding fiscal quarters, as reflected
in the most recent financial statements of the Borrower or such Principal
Subsidiary delivered to the Administrative Agent pursuant to Section 7.04 hereof
(or, if no such financial statements have been delivered to the Administrative
Agent as of the relevant date of determination, the Financial Statements of such
Person).

         (c) COMPLIANCE WITH ERISA. (i) Terminate, or permit any of its ERISA
Affiliates to terminate, any ERISA Plan so as to result in any liability of the
Borrower or any Principal Subsidiary to the PBGC in an amount greater than
$1,000,000, or (ii) permit to exist any occurrence of any Reportable Event (as
defined in Title IV of ERISA) which, alone or together with any other Reportable
Event with respect to the same or another ERISA Plan, has a reasonable
possibility of resulting in liability of the Borrower or any Principal
Subsidiary to the PBGC in an aggregate amount exceeding $1,000,000, or any other
event or condition which presents a material risk of such a termination by the
PBGC of any ERISA Plan or has a reasonable possibility of resulting in a
liability of the Borrower or any Principal Subsidiary to the PBGC or any
withdrawal liability to an ERISA Multiemployer Plan in an aggregate amount
exceeding $1,000,000.

         (c) ACCOUNTING CHANGES. Make any change in its accounting policies or
reporting practices except as required or permitted by the Securities and
Exchange Commission, the Financial Accounting Standards Board or any other
generally recognized accounting authority.

         (e) TRANSACTIONS WITH AFFILIATES. Engage in any transaction with any
Affiliate except (i) in accordance with the Public Utility Holding Company Act
of 1935, to the extent applicable thereto or (ii) on terms no less favorable to
the Borrower or the Principal Subsidiary party thereto than if the transaction
had been negotiated in good faith on an arms-length basis with a non-Affiliate
and on commercially reasonable terms or pursuant to a binding agreement in
effect on the Closing Date.

                                       40
<PAGE>

         (f) ISSUANCE OF FIRST MORTGAGE BONDS. In the case of CL&P and WMECO
only, issue any First Mortgage Bonds on or after the Closing Date, whether in
addition to First Mortgage Bonds outstanding on the Closing Date or in
replacement of First Mortgage Bonds redeemed, retired, defeased, repaid or
prepaid on or after the Closing Date.

         (g) INTERESTS IN NUCLEAR PLANTS. Acquire any nuclear plant or any
interest therein not held on the Closing Date, other than so-called "power
entitlements" acquired for use in the ordinary course of business.

         (h) DEBT. Create, incur, assume or suffer to exist, any Debt of NU, NU
Enterprises, Inc. or any Subsidiary of NU Enterprises, Inc., other than (i) Debt
under the Loan Documents; (ii) other Debt in existence on the Closing Date,
excluding any extension, renewal or replacement thereof; (iii) Debt arising
under the Revolving Credit Agreement, (iv) Debt resulting from the issuance of
debt-like instruments by NU for stock redemptions and repurchases in connection
with the acquisition of YES in an amount not to exceed $215,000,000; (v)
non-recourse Debt of the Northeast Generation Company; (vi) Parent Support
Obligations in an amount not to exceed $350,000,000 at any one time outstanding;
(vii) Debt incurred by HEC Inc. in connection with the Portsmouth Naval Shipyard
Project, and other Debt of HEC Inc. in an aggregate principal amount not to
exceed $25,000,000; and (viii) in the case of NU Enterprises, Inc. and its
Subsidiaries, Debt owing to NU, NU Enterprises, Inc. or the NU System Money
Pool.

         (i) INVESTMENTS. With respect to the Borrower only, purchase, hold or
acquire any capital stock, evidences of indebtedness or other securities
(including any option, warrant or other right to acquire any of the foregoing)
of, make or permit to exist any loans or advances to, guarantee any obligations
of, or make or permit to exist any investment or any other interest in, any
other Person, or purchase or otherwise acquire (in one transaction or a series
of transactions) any assets of any other Person constituting a business unit
(each of the foregoing, an "INVESTMENT"), except (i) the NGC Equity
Contribution; (ii) equity and debt investments in (including NU System Money
Pool advances to) Select Energy Inc. in an aggregate amount not to exceed
$100,000,000; (iii) NU System Money Pool advances (other than to Select Energy
Inc.) in an aggregate amount not to exceed $50,000,000 at any one time
outstanding; (iv) other debt and equity investments in Subsidiaries of the
Borrower (other than NU System Money Pool advances and other than in Select
Energy Inc.) in an aggregate amount not to exceed $50,000,000 from and after the
Closing Date; (v) the issuance of up to $25,000,000 in construction completion
and similar performance guaranties on behalf of HEC Inc. from and after the
Closing Date; (vi) Investments permitted by subsections (b) and (h) above; (vii)
Investments other than (A) those enumerated in clauses (i) through (vi) above
and (B) NU System Money Pool Advances, in each case, made prior to the Closing
Date; and (viii) Permitted Investments.

         (j) RESTRICTED PAYMENTS. With respect to the Borrower only, declare or
make, or agree to pay or make, directly or indirectly, any Restricted Payment,
except that the Borrower may (i) pay dividends to its common stockholders in an
aggregate amount not to exceed $53,000,000 during any 12-month period beginning
or ending on the Closing Date or any day thereafter until and including the
Termination Date, and (ii) redeem or repurchase capital stock for an aggregate
amount not in excess of $215,000,000 in connection with the acquisition of YES

                                       41
<PAGE>

         (k) FINANCING AGREEMENTS. With respect to the Borrower only, permit any
Principal Subsidiary to enter into any agreement, contract, indenture or similar
obligation, or issue any security (all of the foregoing being referred to as
"FINANCING AGREEMENTS"), that is not in effect on the Closing Date, or amend or
modify any existing Financing Agreement, if the effect of such Financing
Agreement (or amendment or modification thereof) is to impose any additional
restriction not in effect on the Closing Date on the ability of such Principal
Subsidiary to pay dividends to the Borrower; provided, that the foregoing shall
not restrict the right of Northeast Generation Company, or any other Subsidiary
of the Borrower created to hold generating assets, to enter into any such
Financing Agreement in connection with the incurrence of nonrecourse Debt to
acquire, construct or otherwise develop generating assets.

         SECTION 7.03. FINANCIAL COVENANTS. On and after the Closing Date, so
long as any Note shall remain unpaid or any Lender shall have any Commitment
hereunder, the Borrower shall, unless the Majority Lenders shall otherwise
consent in writing:

         (a) COMMON EQUITY RATIO. Maintain at all times a ratio of Common Equity
to Total Capitalization of at least 0.30:1:00.

         (b) INTEREST COVERAGE RATIO. Maintain, as of the end of each Fiscal
Quarter, with respect to the four Fiscal Quarters then ended, a ratio of
Consolidated Operating Income to Consolidated Interest Expense of at least
2.00:1:00.

         (c) CASH FLOW RATIO. Maintain, as of the end of each Fiscal Quarter
commencing with the Fiscal Quarter ending March 31, 2000, with respect to the
four Fiscal Quarters then ended (or such fewer number of quarterly periods that
shall have ended on or after March 31, 2000), a ratio of Operating Cash Flow to
Fixed Charges of at least 1.50:1.00.

         SECTION 7.04. REPORTING OBLIGATIONS. So long as any Note shall remain
unpaid or any Lender shall have any Commitment hereunder, the Borrower shall,
unless the Majority Lenders shall otherwise consent in writing, furnish or cause
to be furnished to the Administrative Agent in sufficient copies for each
Lender, the following:

                  (i) as soon as possible and in any event within ten days after
         the occurrence of each Event of Default or Unmatured Default continuing
         on the date of such statement, a statement of the Chief Financial
         Officer, Treasurer or Assistant Treasurer of the Borrower setting forth
         details of such Event of Default or Unmatured Default and the action
         which the Borrower proposes to take with respect thereto;

                  (ii) (A) as soon as available, and in any event within fifty
         (50) days after the end of each of the first three Fiscal Quarters of
         each Fiscal Year of the Borrower, a copy of the Borrower's and each of
         its Principal Subsidiary's Quarterly Reports on Form 10-Q submitted to
         the Securities and Exchange Commission with respect to such quarter,
         or, if the Borrower or Select Energy, Inc. ceases to be required to
         submit such report, consolidated and unconsolidated balance sheets of
         the Borrower or Select Energy, Inc., as the case may be, as of the end
         of such Fiscal Quarter and consolidated and unconsolidated statements
         of income and retained earnings and of cash flows of the Borrower or
         Select

                                       42
<PAGE>

         Energy, Inc., as the case may be, for the period commencing at the end
         of the previous Fiscal Year and ending with the end of such Fiscal
         Quarter, all in reasonable detail and duly certified (subject to
         year-end audit adjustments) by the Chief Financial Officer, Treasurer,
         Assistant Treasurer or Comptroller of the Borrower or Select Energy,
         Inc., as the case may be, as having been prepared in accordance with
         generally accepted accounting principles consistent with those applied
         in the preparation of the Financial Statements; and

                          (B) concurrently with the delivery of the financial
                  statements described in the foregoing clause (a), a
                  certificate of the Chief Financial Officer, Treasurer,
                  Assistant Treasurer or Comptroller of the Borrower:

                  (1) to the effect that such financial statements were prepared
in accordance with generally accepted accounting principles consistent with
those applied in the preparation of the Financial Statements,

                  (2) stating that no Event of Default or Unmatured Default has
occurred and is continuing or, if an Event of Default or Unmatured Default has
occurred and is continuing, describing the nature thereof and the action which
the Borrower proposes to take with respect thereto, and

                  (3) demonstrating the Borrower's compliance with the covenants
set forth in Section 7.03 hereof, for and as of the end of such Fiscal Quarter,
in each case such demonstrations to be in form satisfactory to the
Administrative Agent and to set forth in reasonable detail the computations used
in determining such compliance;

                  (iii) (A) as soon as available, and in any event within 105
         days after the end of each Fiscal Year of the Borrower, a copy of the
         Borrower's and each of its Principal Subsidiary's Annual Reports on
         Form 10-K submitted to the Securities and Exchange Commission with
         respect to such Fiscal Year, or, if the Borrower or Select Energy, Inc.
         ceases to be required to submit such report, a copy of the annual audit
         report for such year for the Borrower or Select Energy, Inc., as the
         case may be, including therein consolidated and unconsolidated balance
         sheets of the Borrower or Select Energy, Inc., as the case may be, as
         of the end of such Fiscal Year and consolidated and unconsolidated
         statements of income and retained earnings and of cash flows of the
         Borrower or Select Energy, Inc., as the case may be, for such Fiscal
         Year, all in reasonable detail and certified by a nationally-recognized
         independent public accountant; and

                          (B) concurrently with the delivery of the financial
                  statements described in the foregoing clause (A), a
                  certificate of the Chief Financial Officer, Treasurer,
                  Assistant Treasurer or Comptroller of the Borrower:

                  (1) to the effect that such financial statements were prepared
in accordance with generally accepted accounting principles consistent with
those applied in the preparation of the Financial Statements, and

                                       43
<PAGE>

                  (2) stating that no Event of Default or Unmatured Default has
occurred and is continuing, or if an Event of Default or Unmatured Default has
occurred and is continuing, describing the nature thereof and the action which
the Borrower proposes to take with respect thereto, and

                  (3) demonstrating the Borrower's compliance with the covenants
set forth in Section 7.03 hereof, for and as of the end of such Fiscal Year, in
each case such demonstrations to be in form satisfactory to the Administrative
Agent and to set forth in reasonable detail the computations used in determining
such compliance;

                  (iv) upon the reasonable request of the Administrative Agent,
         but not more than once per Fiscal Quarter, copies of any or all filings
         or registrations with, or notices or reports to, any regulatory
         authority by the Borrower or any Principal Subsidiary;

                  (v) promptly upon becoming aware that any of its or any of its
         Principal Subsidiaries' material businesses and operations is
         reasonably likely be affected by the Year 2000 Issue, a detailed
         description of the nature of such circumstances and the actions which
         the Borrower proposes to take with respect thereto, except where the
         effect of the Year 2000 Issue would not be reasonably likely to have a
         material adverse effect on the financial condition, properties,
         prospects or operations of the Borrower or of the Borrower and the
         Principal Subsidiaries, taken as a whole;

                  (vi) as soon as possible and in any event (A) within 30 days
         after the Chief Financial Officer, Treasurer or any Assistant Treasurer
         of the Borrower knows or has reason to know that any ERISA Plan
         Termination Event described in clause (i) of the definition of ERISA
         Plan Termination Event with respect to any ERISA Plan or ERISA
         Multiemployer Plan has occurred and (B) within 10 days after the
         Borrower knows or has reason to know that any other ERISA Plan
         Termination Event with respect to any ERISA Plan or ERISA Multiemployer
         Plan has occurred, a statement of the Chief Financial Officer,
         Treasurer or Assistant Treasurer of the Borrower describing such ERISA
         Plan Termination Event and the action, if any, which the Borrower
         proposes to take with respect thereto;

                  (vii) promptly after receipt thereof by the Borrower or any of
         its ERISA Affiliates from the PBGC, copies of each notice received by
         the Borrower or any such ERISA Affiliate of the PBGC's intention to
         terminate any ERISA Plan or ERISA Multiemployer Plan or to have a
         trustee appointed to administer any ERISA Plan or ERISA Multiemployer
         Plan;

                  (viii) promptly after receipt thereof by the Borrower or any
         of its ERISA Affiliates from an ERISA Multiemployer Plan sponsor, a
         copy of each notice received by the Borrower or any of its ERISA
         Affiliates concerning the imposition or amount of withdrawal liability
         in an aggregate principal amount of at least $10,000,000 pursuant to
         Section 4202 of ERISA in respect of which the Borrower may be liable;

                                       44
<PAGE>

                  (ix) promptly after the Borrower becomes aware of the
         commencement thereof, notice of all actions, suits, proceedings or
         other events of the type described in Section 6.01(h) hereof
         (including, without limitation, any action or proceeding relating to
         any environmental protection laws or regulations);

                  (x) promptly after the filing thereof, copies of each
         prospectus (excluding any prospectus contained in any Form S-8) and
         Current Report on Form 8-K, if any, which the Borrower or any Principal
         Subsidiary files with the Securities and Exchange Commission or any
         successor governmental authority; and

                  (xi) promptly after requested, such other information
         respecting the financial condition, operations, properties or prospects
         of the Borrower or its Subsidiaries as the Administrative Agent, or the
         Majority Lenders through the Administrative Agent, may from time to
         time reasonably request in writing.


                                  ARTICLE VIII


                                    DEFAULTS

         SECTION 8.01. EVENTS OF DEFAULT. The following events shall each
constitute an "EVENT OF Default":

                  (a) The Borrower shall fail to pay any principal of any Note
         when due or shall fail to pay any interest on any Note or fees or other
         amounts payable under the Loan Documents within two days after the same
         becomes due; or

                  (c) Any representation or warranty made by the Borrower (or
         any of its officers or agents) in any Loan Document, any certificate or
         other writing delivered pursuant hereto or thereto shall prove to have
         been incorrect in any material respect when made or deemed made; or

                  (c) The Borrower shall fail to perform or observe any term or
         covenant on its part to be performed or observed contained in Section
         7.01(d), Section 7.02, Section 7.03 or Section 7.04(i) hereof; or

                  (d) The Borrower shall fail to perform or observe any other
         term or covenant on its part to be performed or observed contained in
         any Loan Document and any such failure shall remain unremedied for a
         period of 30 days after the earlier of (i) written notice of such
         failure having been given to the Borrower by the Administrative Agent
         or (ii) the Borrower having obtained actual knowledge of such failure;
         or

                  (e) The Borrower or any Principal Subsidiary shall fail to pay
         any of its Debt when due (including any interest or premium thereon but
         excluding Debt evidenced by the Notes and excluding other Debt (except
         for Named Debt) aggregating in no event more

                                       45
<PAGE>

         than $10,000,000 in principal amount at any one time) whether by
         scheduled maturity, required prepayment, acceleration, demand or
         otherwise, and such failure shall continue after the applicable grace
         period, if any, specified in any agreement or instrument relating to
         such Debt; or any other default under any agreement or instrument
         relating to any such Debt, or any other event, shall occur and shall
         continue after the applicable grace period, if any, specified in such
         agreement or instrument, if the effect of such default or event is to
         accelerate, or to permit the acceleration of, the maturity of such
         Debt; or any such Debt shall be declared to be due and payable, or
         required to be prepaid (other than by a regularly scheduled required
         prepayment or as a result of the Borrower's or such Principal
         Subsidiary's exercise of a prepayment option) prior to the stated
         maturity thereof; or

                  (f) The Borrower or any Principal Subsidiary shall generally
         not pay its debts as such debts become due, or shall admit in writing
         its inability to pay its debts generally, or shall make an assignment
         for the benefit of creditors; or any proceeding shall be instituted by
         or against the Borrower or any Principal Subsidiary seeking to
         adjudicate it a bankrupt or insolvent, or seeking liquidation, winding
         up, reorganization, arrangement, adjustment, protection, relief, or
         composition of its debts under any law relating to bankruptcy,
         insolvency, or reorganization or relief of debtors, or seeking the
         entry of an order for relief or the appointment of a receiver, trustee,
         or other similar official for it or for any substantial part of its
         property and, in the case of a proceeding instituted against the
         Borrower or any Principal Subsidiary, the Borrower or such Principal
         Subsidiary shall consent thereto or such proceeding shall remain
         undismissed or unstayed for a period of 90 days or any of the actions
         sought in such proceeding (including without limitation the entry of an
         order for relief against the Borrower or such Principal Subsidiary or
         the appointment of a receiver, trustee, custodian or other similar
         official for the Borrower or such Principal Subsidiary or any of its
         property) shall occur; or the Borrower or any Principal Subsidiary
         shall take any corporate or other action to authorize any of the
         actions set forth above in this subsection (f); or

                  (g) Any judgments or orders for the payment of money in excess
         of $10,000,000 (or aggregating more than $10,000,000 at any one time)
         shall be rendered against the Borrower or its properties or any
         Principal Subsidiary or its properties, and either (A) enforcement
         proceedings shall have been commenced by any creditor upon such
         judgment or order and shall not have been stayed or (B) there shall be
         any period of 15 consecutive days during which a stay of enforcement of
         such judgment or order, by reason of a pending appeal or otherwise,
         shall not be in effect; or

                  (h) Any material provision of any Loan Document shall at any
         time for any reason cease to be valid and binding on the Borrower, or
         shall be determined to be invalid or unenforceable by any court,
         governmental agency or authority having jurisdiction over the Borrower,
         or the Borrower shall deny that it has any further liability or
         obligation under any Loan Document; or

                  (i) A Change of Control shall have occurred; or

                                       46
<PAGE>

                  (j) The Borrower shall cease to own at least 85% of the
         outstanding common stock of any Principal Subsidiary, free and clear of
         all Liens except for Liens permitted by Section 7.02(a) hereof; or

                  (k) Any legal restriction that is not in existence on the
         Closing Date shall materially adversely affect the ability of any
         Principal Subsidiary to pay dividends or make other distributions to
         the Borrower.

         SECTION 8.02. REMEDIES UPON EVENTS OF DEFAULT. Upon the occurrence and
during the continuance of any Event of Default, the Administrative Agent shall
at the request, or may with the consent, of the Lenders entitled to make such
request, upon notice to the Borrower (i) declare the obligation of each Lender
to make Advances to the Borrower to be terminated, whereupon such obligations of
the Lenders shall forthwith terminate, provided, that any such request or
consent pursuant to this clause (i) shall be made solely by Lenders having
Percentages in the aggregate of not less 66-2/3%; (ii) declare the Notes of the
Borrower, all interest thereon and all other amounts payable by the Borrower
under this Agreement and the other Loan Documents to be forthwith due and
payable, whereupon such Notes, all such interest and all such amounts shall
become and be forthwith due and payable, without presentment, demand, protest or
further notice of any kind, all of which are hereby expressly waived by the
Borrower, provided, that any such request or consent pursuant to this clause
(ii) shall be made solely by the Lenders holding at least 66-2/3% of the then
aggregate Outstanding Credits; provided, however, that if such Event of Default
is an Event of Default pursuant to subsection (f) of Section 8.01, then (A) the
obligation of each Lender to make Advances to the Borrower shall automatically
be terminated and (B) the Notes of the Borrower, all interest thereon and all
other amounts payable by the Borrower under this Agreement and the other Loan
Documents shall automatically become and be due and payable, without
presentment, demand, protest or any notice of any kind, all of which are hereby
expressly waived by the Borrower.


                                   ARTICLE IX


                            THE ADMINISTRATIVE AGENT

         SECTION 9.01. AUTHORIZATION AND ACTION. Each Lender hereby appoints and
authorizes the Administrative Agent to take such action as agent on its behalf
and to exercise such powers under this Agreement as are delegated to the
Administrative Agent by the terms hereof, together with such powers as are
reasonably incidental thereto. As to any matters not expressly provided for by
the Loan Documents (including, without limitation, enforcement or collection
thereof), the Administrative Agent shall not be required to exercise any
discretion or take any action, but shall be required to act or to refrain from
acting (and shall be fully protected in so acting or refraining from acting)
upon the instructions of the Majority Lenders, and such instructions shall be
binding upon all Lenders; provided, however, that the Administrative Agent shall
not be required to take any action which exposes the Administrative Agent to
personal liability or which is contrary to the Loan Documents or applicable law.
The Administrative Agent

                                       47
<PAGE>

agrees to deliver promptly to each Lender notice of each notice given to it by
the Borrower pursuant to the terms of this Agreement.

         SECTION 9.02. ADMINISTRATIVE AGENT'S RELIANCE, ETC. Neither the
Administrative Agent nor any of its directors, officers, agents or employees
shall be liable for any action taken or omitted to be taken by it or them under
or in connection with any Loan Document, except for its or their own gross
negligence or willful misconduct. Without limitation of the generality of the
foregoing, the Administrative Agent: (i) may treat the payee of any Note as the
holder thereof until the Administrative Agent receives and accepts a Lender
Assignment entered into by the Lender which is the payee of such Note, as
assignor, and an assignee, as provided in Section 10.07; (ii) may consult with
legal counsel (including counsel for the Borrower), independent public
accountants and other experts selected by it and shall not be liable for any
action taken or omitted to be taken in good faith by it in accordance with the
advice of such counsel, accountants or experts; (iii) makes no warranty or
representation to any Lender and shall not be responsible to any Lender for any
statements, warranties or representations made in or in connection with any Loan
Document; (iv) shall not have any duty to ascertain or to inquire as to the
performance or observance of any of the terms, covenants or conditions of any
Loan Document on the part of the Borrower to be performed or observed, or to
inspect any property (including the books and records) of the Borrower; (v)
shall not be responsible to any Lender for the due execution, legality,
validity, enforceability, genuineness, sufficiency or value of any Loan Document
or any other instrument or document furnished pursuant hereto; and (vi) shall
incur no liability under or in respect of any Loan Document by acting upon any
notice, consent, certificate or other instrument or writing (which may be by
facsimile) believed by it to be genuine and signed or sent by the proper party
or parties.

         SECTION 9.03. CIBC AND ITS AFFILIATES. With respect to its Commitment
and the Note issued to it, CIBC shall have the same rights and powers under the
Loan Documents as any other Lender and may exercise the same as though it were
not the Administrative Agent, and the term "Lender" or "Lenders" shall, unless
otherwise expressly indicated, include CIBC in its individual capacity. CIBC and
its Affiliates may accept deposits from, lend money to, act as trustee under
indentures of, and generally engage in any kind of business with, the Borrower,
any of its Subsidiaries and any Person who may do business with or own
securities of the Borrower or any such Subsidiary, all as if CIBC were not the
Administrative Agent and without any duty to account therefore to the Lenders.

         SECTION 9.04. LENDER CREDIT DECISION. Each Lender acknowledges that it
has, independently and without reliance upon the Administrative Agent or any
other Lender and based on the Financial Statements and such other documents and
information as it has deemed appropriate, made its own credit analysis and
decision to enter into this Agreement. Each Lender also acknowledges that it
will, independently and without reliance upon the Administrative Agent or any
other Lender and based on such documents and information as it shall deem
appropriate at the time, continue to make its own credit decisions in taking or
not taking action under this Agreement.

         SECTION 9.05. INDEMNIFICATION. The Lenders agree to indemnify the
Administrative Agent (to the extent not reimbursed by the Borrower), ratably
according to the respective

                                       48
<PAGE>

principal amounts of the Notes then held by each of them (or if no Notes are at
the time outstanding, ratably according to the respective Commitments of the
Lenders; if any Notes or Commitments are held by the Borrower or any Affiliate
thereof, any ratable apportionment hereunder shall exclude the principal amount
of the Notes held by the Borrower or such Affiliate or their respective
Commitments (if any) hereunder), from and against any and all liabilities,
obligations, losses, damages, penalties, actions, judgments, suits, costs,
expenses or disbursements of any kind or nature whatsoever which may be imposed
on, incurred by, or asserted against the Administrative Agent in its capacity as
such in any way relating to or arising out of any Loan Document or any action
taken or omitted by the Administrative Agent in its capacity as such under any
Loan Document, provided that no Lender shall be liable for any portion of such
liabilities, obligations, losses, damages, penalties, actions, judgments, suits,
costs, expenses or disbursements resulting from the Administrative Agent's gross
negligence or willful misconduct. Without limitation of the foregoing, each
Lender agrees to reimburse the Administrative Agent promptly upon demand for
such Lender's ratable share of any out-of-pocket expenses (including counsel
fees) incurred by the Administrative Agent in connection with the preparation,
execution, delivery, administration, modification, amendment or enforcement
(whether through negotiations, legal proceedings or otherwise) of, or legal
advice in respect of rights or responsibilities under, the Loan Documents to the
extent that the Administrative Agent is entitled to reimbursement for such
expenses pursuant to Section 10.04 but is not reimbursed for such expenses by
the Borrower.

         SECTION 9.06. SUCCESSOR ADMINISTRATIVE AGENT. The Administrative Agent
may resign at any time by giving written notice thereof to the Lenders and the
Borrower, with any such resignation to become effective only upon the
appointment of a successor Administrative Agent pursuant to this Section 9.06.
Upon any such resignation, the Majority Lenders shall have the right to appoint
a successor Administrative Agent, which shall be a Lender or another commercial
bank or trust company reasonably acceptable to the Borrower organized or
licensed under the laws of the United States, or of any State thereof. If no
successor Administrative Agent shall have been so appointed by the Majority
Lenders, and shall have accepted such appointment, within 30 days after the
retiring Administrative Agent's giving of notice of resignation, then the
retiring Administrative Agent may, on behalf of the Lenders, appoint a successor
Administrative Agent, which shall be Lender or shall be another commercial bank
or trust company organized or licensed under the laws of the United States or of
any State thereof reasonably acceptable to the Borrower. In addition to the
foregoing right of the Administrative Agent to resign, the Majority Lenders may
remove the Administrative Agent at any time, with or without cause, concurrently
with the appointment by the Majority Lenders of a successor Administrative
Agent. Upon the acceptance of any appointment as Administrative Agent hereunder
by a successor Administrative Agent, such successor Administrative Agent shall
thereupon succeed to and become vested with all the rights, powers, privileges
and duties of the retiring Administrative Agent, and the retiring Administrative
Agent shall be discharged from its duties and obligations under this Agreement.
After any retiring Administrative Agent's resignation or removal hereunder as
Administrative Agent, the provisions of this Article IX shall inure to its
benefit as to any actions taken or omitted to be taken by it while it was
Administrative Agent under the Loan Documents.

         SECTION 9.07. OTHER AGENTS. Neither The Bank of New York, by virtue of
its designation as "Documentation Agent", nor Fleet National Bank, by virtue of
its designation as

                                       49
<PAGE>

"Syndication Agent", shall have any duties, liabilities, obligations or
responsibilities under this Agreement other than as a Lender hereunder.


                                    ARTICLE X


                                  MISCELLANEOUS

         SECTION 10.01. AMENDMENTS, ETC. No amendment or waiver of any provision
of any Loan Document, nor consent to any departure by the Borrower therefrom,
shall in any event be effective unless the same shall be in writing and signed
by the Majority Lenders, and then such waiver or consent shall be effective only
in the specific instance and for the specific purpose for which given; provided,
however, that no amendment, waiver or consent shall, unless in writing and
signed by all the Lenders, do any of the following: (a) waive, modify or
eliminate any of the conditions specified in Article V, (b) increase the
Commitment of any Lender hereunder or increase the Commitments of the Lenders
that may be maintained hereunder or subject the Lenders to any additional
obligations, (c) reduce the principal of, or interest on, the Notes, any
Applicable Margin or any fees or other amounts payable hereunder, (d) postpone
any date fixed for any payment of principal of, or interest on, the Notes or any
fees or other amounts payable under the Loan Documents, (e) change the
percentage of the Commitments or of the aggregate unpaid principal amount of the
Notes, or the number of Lenders which shall be required for the Lenders or any
of them to take any action under the Loan Documents, (f) amend any Loan Document
in a manner intended to prefer one or more Lenders over any other Lenders, or
(g) amend this Section 10.01; provided, that no amendment, waiver or consent
shall, unless in writing and signed by the Administrative Agent, in addition to
the Lenders required above to take such action, affect the rights or duties of
the Administrative Agent under any Loan Document.

         SECTION 10.02. NOTICES, ETC. Except as otherwise expressly provided
herein, all notices and other communications provided for under the Loan
Documents shall be in writing (including facsimile communication) and mailed,
sent by facsimile or hand delivered:

                  (i)      if to the Borrower, to it in care of NUSCO at 107
                           Selden Street, Berlin, Connecticut 06037, Attention:
                           Assistant Treasurer, facsimile number: (860)
                           665-5457, confirm number: (860) 665-3258;

                  (ii)     if to any Bank, at its Domestic Lending Office
                           specified opposite its name on Schedule I hereto;

                  (iii)    if to any Lender other than a Bank, at its Domestic
                           Lending Office specified in the Lender Assignment
                           pursuant to which it became a Lender; and

                                       50
<PAGE>

                  (iv)     if to the Administrative Agent, at its address at 425
                           Lexington Avenue, New York, New York 10017,
                           Attention: Agency Services, facsimile number: (212)
                           856-3691, confirm number: (212) 856-3763.

or, as to each party, at such other address as shall be designated by such party
in a written notice to the other parties. All such notices and communications
shall, when mailed, sent by facsimile or hand delivered, be effective five days
after when deposited in the mails, or when sent by facsimile, or when delivered,
respectively, except that notices and communications to the Administrative Agent
pursuant to Article II, III, IV or IX shall not be effective until received by
the Administrative Agent. With respect to any telephone notice given or received
by the Administrative Agent pursuant to Section 3.03 hereof, the records of the
Administrative Agent shall be conclusive for all purposes.

         SECTION 10.03. NO WAIVER OF REMEDIES. No failure on the part of the
Administrative Agent or any Lender to exercise, and no delay in exercising, any
right under any Loan Document shall operate as a waiver thereof; nor shall any
single or partial exercise of any such right preclude any other or further
exercise thereof or the exercise of any other right. The remedies herein
provided are cumulative and not exclusive of any remedies provided by law.

         SECTION 10.04. COSTS, EXPENSES AND INDEMNIFICATION.

         (a) The Borrower agrees to pay when due, in accordance with the terms
hereof: (i) all costs and expenses of the Administrative Agent in connection
with the preparation, negotiation, execution and delivery of the Loan Documents,
the administration of the Loan Documents, and any proposed modification,
amendment, or consent relating thereto (including, in each case, the reasonable
fees and expenses of counsel to the Administrative Agent); and (ii) all costs
and expenses of the Administrative Agent and each Lender (including all fees and
expenses of counsel) in connection with the enforcement, whether through
negotiations, legal proceedings or otherwise, of the Loan Documents.

         (b) The Borrower hereby agrees to indemnify and hold the Administrative
Agent and each Lender, and its officers, directors, employees, professional
advisors and affiliates (each, an "INDEMNIFIED PERSON") harmless from and
against any and all claims, damages, losses, liabilities, costs or expenses
(including reasonable attorney's fees and expenses, whether or not such
Indemnified Person is named as a party to any proceeding or investigation or is
otherwise subjected to judicial or legal process arising from any such
proceeding or investigation) which any of them may incur or which may be claimed
against any of them by any person or entity (except to the extent such claims,
damages, losses, liabilities, costs or expenses arise from the gross negligence
or willful misconduct of the Indemnified Person):

                  (i) by reason of or in connection with the execution, delivery
         or performance of the Loan Documents or any transaction contemplated
         thereby, or the use by the Borrower of the proceeds of any Advance;

                  (ii) in connection with or resulting from the utilization,
         storage, disposal, treatment, generation, transportation, release or
         ownership of any Hazardous Substance

                                       51
<PAGE>

         (A) at, upon or under any property of the Borrower or any of its
         Affiliates or (B) by or on behalf of the Borrower or any of its
         Affiliates at any time and in any place; or

                  (iii) in connection with any documentary taxes, assessments or
         charges made by any governmental authority by reason of the execution
         and delivery of the Loan Documents.

         (c) The Borrower's obligations under this Section 10.04 shall survive
the assignment by any Lender pursuant to Section 10.07 hereof and shall survive
as well the repayment of all amounts owing to the Lenders under the Loan
Documents and the termination of the Commitments. If and to the extent that the
obligations of the Borrower under this Section 10.04 are unenforceable for any
reason, the Borrower agrees to make the maximum contribution to the payment and
satisfaction thereof which is permissible under applicable law.

         (d) The Borrower's obligations under this Section 10.04 are in addition
to and shall not be deemed to supersede its indemnification and similar
obligations set forth in that certain Commitment Letter dated as of February 15,
2000 between the Borrower and CIBC.

         SECTION 10.05. RIGHT OF SET-OFF.

         (a) Upon (i) the occurrence and during the continuance of any Event of
Default, and (ii) the making of the request or the granting of the consent
specified by Section 8.02 to authorize the Administrative Agent to declare the
Notes due and payable pursuant to the provisions of Section 8.02, each Lender is
hereby authorized at any time and from time to time, to the fullest extent
permitted by law, to set off and apply any and all deposits (general or special,
time or demand, provisional or final) at any time held and other indebtedness at
any time owing by such Lender to or for the credit or the account of the
Borrower against any and all of the obligations of the Borrower now or hereafter
existing under the Loan Documents held by such Lender, irrespective of whether
or not such Lender shall have made any demand under the Loan Documents or such
Notes and although such obligations may be Unmatured. Each Lender agrees
promptly to notify the Borrower after any such set-off and application made by
such Lender, provided that the failure to give such notice shall not affect the
validity of such set-off and application. The rights of each Lender under this
Section are in addition to other rights and remedies (including, without
limitation, other rights of set-off) which such Lender may have.

         (b) The Borrower agrees that it shall have no right of off-set,
deduction or counterclaim in respect of its obligations under the Loan
Documents, and that the obligations of the Lenders hereunder are several and not
joint. Nothing contained herein shall constitute a relinquishment or waiver of
the Borrower's rights to any independent claim that the Borrower may have
against the Administrative Agent or any Lender, but no Lender shall be liable
for the conduct of the Administrative Agent or any other Lender, and the
Administrative Agent shall not be liable for the conduct of the other or any
Lender.

         SECTION 10.06. BINDING EFFECT. This Agreement shall become effective
when it shall have been executed by the Borrower and the Administrative Agent
and when the Administrative Agent shall have been notified by each Bank that
such Bank has executed it and

                                       52
<PAGE>

thereafter shall be binding upon and inure to the benefit of the Borrower, the
Administrative Agent and each Lender and their respective successors and
assigns, except that the Borrower shall not have the right to assign its rights
under the Loan Documents or any interest herein without the prior written
consent of the Lenders.

         SECTION 10.07. ASSIGNMENTS AND PARTICIPATION.

         (a) Each Lender may assign to one or more banks or other entities all
or a portion of its rights and obligations under the Loan Documents, including,
without limitation, all or a portion of its Commitment, the Advances owing to
it, and the Note or Notes held by it (with the prior written consent of the
Borrower and the Administrative Agent if the assignee thereunder is not then a
Lender or an Affiliate of a Lender, which consent shall not be unreasonably
withheld); provided, however, that (i) each such assignment shall be of a
constant, and not a varying, percentage of all of the assigning Lender's rights
and obligations under the Loan Documents, (ii) if the assignee thereunder is not
then a Lender or an Affiliate of a Lender, the amount of the Commitment, Advance
or Note being assigned pursuant to each such assignment shall in no event be
less than the lesser of the amount of the assigning Lender's Commitment and
$5,000,000, and (iii) the parties to each such assignment shall execute and
deliver to the Administrative Agent, for its acceptance and recording in the
Register, an assignment and acceptance in substantially the form of Exhibit
10.07 hereto (the "LENDER ASSIGNMENT"), together with any Note or Notes subject
to such assignment and a processing and recordation fee of $3,500. Upon such
execution, delivery, acceptance and recording, from and after the effective date
specified in each Lender Assignment, which effective date shall be at least five
Business Days after the execution thereof, (x) the assignee thereunder shall be
a party hereto and, to the extent that rights and obligations under the Loan
Documents have been assigned to it pursuant to such Lender Assignment, have the
rights and obligations of a Lender under the Loan Documents and (y) the Lender
assignor thereunder shall, to the extent that rights and obligations under the
Loan Documents have been assigned by it to an assignee pursuant to such Lender
Assignment, relinquish its rights and be released from its obligations under the
Loan Documents (and, in the case of a Lender Assignment covering all or the
remaining portion of an assigning Lender's rights and obligations under the Loan
Documents, such Lender shall cease to be a party to the Loan Documents);
provided, however, if an Event of Default shall have occurred and be continuing
a Lender may assign all or a portion of its rights and obligations without the
prior written consent of the Borrower but otherwise in accordance with this
Section.

         (b) By executing and delivering a Lender Assignment, the Lender
assignor thereunder and the assignee thereunder confirm to and agree with each
other and the other parties hereto as follows: (i) other than as provided in
such Lender Assignment, such assigning Lender makes no representation or
warranty and assumes no responsibility with respect to any statements,
warranties or representations made in or in connection with the Loan Documents
or the execution, legality, validity, enforceability, genuineness, sufficiency
or value of the Loan Documents or any other instrument or document furnished
pursuant thereto; (ii) such assigning Lender makes no representation or warranty
and assumes no responsibility with respect to the financial condition of the
Borrower or the performance or observance by the Borrower of any of its
obligations under the Loan Documents or any other instrument or document
furnished pursuant thereto; (iii) such assignee confirms that it has received a
copy of the Loan Documents,

                                       53
<PAGE>

together with copies of the Financial Statements, or the latest financial
statements delivered by the Borrower to the Administrative Agent pursuant to
Section 7.04 hereof, and such other documents and information as it has deemed
appropriate to make its own credit analysis and decision to enter into such
Lender Assignment; (iv) such assignee will, independently and without reliance
upon the Administrative Agent, such assigning Lender or any other Lender and
based on such documents and information as it shall deem appropriate at the
time, continue to make its own credit decisions in taking or not taking action
under the Loan Documents; (v) such assignee appoints and authorizes the
Administrative Agent to take such action as agent on its behalf and to exercise
such powers under the Loan Documents as are delegated to the Administrative
Agent by the terms thereof, together with such powers as are reasonably
incidental thereto; and (vi) such assignee agrees that it will perform in
accordance with their terms all of the obligations which by the terms of the
Loan Documents are required to be performed by it as a Lender.

         (c) The Administrative Agent shall maintain at its address referred to
in Section 10.02 a copy of each Lender Assignment delivered to and accepted by
it and a register for the recordation of the names and addresses of the Lenders
and the Commitment of, and principal amount of the Advances owing to, each
Lender from time to time (the "REGISTER"). The entries in the Register shall be
conclusive and binding for all purposes, absent manifest error, and the
Borrower, the Administrative Agent and the Lenders may treat each Person whose
name is recorded in the Register as a Lender hereunder for all purposes of the
Loan Documents. The Register shall be available for inspection by the Borrower
or any Lender at any reasonable time and from time to time upon reasonable prior
notice.

         (d) Upon its receipt of a Lender Assignment executed by an assigning
Lender and an assignee, together with any Note or Notes subject to such
assignment, the Administrative Agent shall, if such Lender Assignment has been
completed and is in substantially the form of Exhibit 10.07 hereto, (i) accept
such Lender Assignment, (ii) record the information contained therein in the
Register and (iii) give prompt notice thereof to the Borrower. Within five
Business Days after its receipt of such notice, the Borrower, at its own
expense, shall execute and deliver to the Administrative Agent in exchange for
the surrendered Note or Notes a new Note or Notes to the order of such assignee
in an amount equal to the Commitment and/or Advances assumed by it pursuant to
such Lender Assignment and, if the assigning Lender has retained a Commitment
and/or Advances hereunder, a new Note or Notes to the order of the assigning
Lender in an amount equal to the Commitment and/or Advances retained by it
hereunder. Such new Note or Notes shall be in an aggregate principal amount
equal to the aggregate principal amount of such surrendered Note or Notes, shall
be dated the effective date of such Lender Assignment and shall otherwise be in
substantially the form of Exhibit 1.01A hereto.

         (e) Each Lender may sell Participations to one or more banks or other
entities in or to all or a portion of its rights and obligations under the Loan
Documents (including, without limitation, all or a portion of its Commitment,
the Advances owing to it or the Note or Notes held by it); provided, however,
that (i) such Lender's obligations under the Loan Documents (including, without
limitation, its Commitment hereunder) shall remain unchanged, (ii) such Lender
shall remain solely responsible to the other parties hereto for the performance
of such obligations, (iii) such Lender shall remain the holder of any such Note
for all purposes of the Loan Documents, (iv) the Borrower, the Administrative
Agent and the other Lenders shall continue to deal solely

                                       54
<PAGE>

and directly with such Lender in connection with such Lender's rights and
obligations under the Loan Documents, and (v) the holder of any such
participation, other than an Affiliate of such Lender, shall not be entitled to
require such Lender to take or omit to take any action under the Loan Documents,
except action (A) reducing the principal of, or interest on, the Notes, any
Applicable Margin or any fees or other amounts payable under the Loan Documents,
or (B) postponing any date fixed for any payment of principal of, or interest
on, the Notes or any fees or other amounts payable under the Loan Documents.

         (f) Any Lender may, in connection with any assignment or participation
or proposed assignment or proposed participation pursuant to this Section 10.07,
disclose to the assignee or participant or proposed assignee or proposed
participant, any information relating to the Borrower furnished to such Lender
by or on behalf of the Borrower; provided that, prior to any such disclosure,
the assignee or participant or proposed assignee or participant shall agree, in
accordance with the terms of Section 10.08, to preserve the confidentiality of
any Confidential Information received by it from such Lender.

         (g) If any Lender shall have delivered a notice to the Administrative
Agent described in Section 4.03(a), (b), (c) or (f) hereof, or shall become a
non-performing Lender under Section 3.03(b) hereof, and if and so long as such
Lender shall not have withdrawn such notice or corrected such non-performance in
accordance with Section 3.03(b), the Borrower may demand that such Lender
assign, in accordance with Section 10.07 hereof, to one or more assignees
designated by the Borrower or the Administrative Agent (and reasonably
acceptable to the other), all (but not less than all) of such Lender's
Commitment, Advances, participatory and other rights and obligations under the
Loan Documents; provided that any such demand by the Borrower during the
continuance of an Event of Default or an Unmatured Default shall be ineffective
without the consent of the Majority Lenders. If, within 30 days following any
such demand by the Borrower, any such assignee so designated shall fail to
tender such assignment on terms reasonably satisfactory to the Borrower and the
Borrower and the Administrative Agent shall have failed to designate any such
assignee, then such demand by the Borrower shall become ineffective, it being
understood for purposes of this provision that such assignment shall be
conclusively deemed to be on terms reasonably satisfactory to such Lender, and
such Lender shall be compelled to tender such assignment forthwith, if (i) such
assignee (A) shall agree to such assignment in substantially the form of the
Lender Assignment and (B) shall tender payment to such Lender in an amount equal
to the full outstanding dollar amount accrued in favor of such Lender hereunder
(as computed in accordance with the records of the Administrative Agent) and
(ii) in the event the Borrower demanded such assignment, the Borrower shall
tender payment to the Administrative Agent of the processing and recording fee
specified in Section 10.07(a) for such assignment.

         (h) Anything in this Section 10.07 to the contrary notwithstanding, any
Lender may assign and pledge all or any portion of its Commitment and the
Advances owing to it to any Federal Reserve Bank (and its transferees) as
collateral security pursuant to Regulation A of the Board of Governors of the
Federal Reserve System and any Operating Circular issued by such Federal Reserve
Bank. No such assignment shall release the assigning Lender from its obligations
hereunder.

                                       55
<PAGE>

         SECTION 10.08. CONFIDENTIALITY. In connection with the negotiation and
administration of the Loan Documents, the Borrower has furnished or caused to
have furnished and will from time to time furnish or cause to be furnished to
the Administrative Agent and the Lenders (each, a "RECIPIENT") written
information which when delivered to the Recipient will be deemed to be
confidential (such information, other than any such information which (i) was
publicly available, or otherwise known to the Recipient, at the time of
disclosure, (ii) subsequently becomes publicly available other than through any
act or omission by the Recipient or (iii) otherwise subsequently becomes known
to the Recipient other than through a Person whom the Recipient knows to be
acting in violation of his or its obligations to the Borrower, being hereinafter
referred to as "CONFIDENTIAL INFORMATION"). The Recipient will not knowingly
disclose any such Confidential Information to any third party (other than to
those Persons who have a confidential relationship with the Recipient), and will
take all reasonable steps to restrict access to such information in a manner
designed to maintain the confidential nature of such information, in each case
until such time as the same ceases to be Confidential Information or as the
Borrower may otherwise instruct. It is understood, however, that the foregoing
will not restrict the Recipient's ability to freely exchange such Confidential
Information with prospective participants in or assignees of the Recipient's
position herein, but the Recipient's ability to so exchange Confidential
Information shall be conditioned upon any such prospective participant's
entering into an understanding as to confidentiality similar to this provision.
It is further understood that the foregoing will not prohibit the disclosure of
any or all Confidential Information if and to the extent that such disclosure
may be required (i) by a regulatory agency or otherwise in connection with an
examination of the Recipient's records by appropriate authorities, (ii) pursuant
to court order, subpoena or other legal process or (iii) otherwise, as required
by law; in the event of any required disclosure under clause (ii) or (iii),
above, the Recipient agrees to use reasonable efforts to inform the Borrower as
promptly as practicable unless the Lender is prohibited from doing so by court
order, subpoena or other legal process.

         SECTION 10.09. WAIVER OF JURY TRIAL. THE BORROWER, THE ADMINISTRATIVE
AGENT AND EACH OF THE LENDERS HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY
JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR RELATING TO THE
LOAN DOCUMENTS, OR ANY OTHER INSTRUMENT OR DOCUMENT DELIVERED HEREUNDER OR
THEREUNDER.

         SECTION 10.10. GOVERNING LAW. THE LOAN DOCUMENTS SHALL BE GOVERNED BY,
AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK. The
Borrower, each of the Lenders and the Administrative Agent: (i) irrevocably
submits to the jurisdiction of any New York State Court or Federal court sitting
in New York City in any action arising out of or relating to the Loan Documents,
(ii) agrees that all claims in such action may be decided in such court, (iii)
waives, to the fullest extent it may effectively do so, the defense of an
inconvenient forum and (iv) consents to the service of process by mail. A final
judgment in any such action shall be conclusive and may be enforced in other
jurisdictions. Nothing herein shall affect the right of any party to serve legal
process in any manner permitted by law or affect its right to bring any action
in any other court.

         SECTION 10.11. RELATION OF THE PARTIES; NO BENEFICIARY. No term,
provision or requirement, whether express or implied, of any Loan Document, or
actions taken or to be taken by any party thereunder, shall be construed to
create a partnership, association, or joint venture

                                       56
<PAGE>

between such parties or any of them. No term or provision of any Loan Document
shall be construed to confer a benefit upon, or grant a right or privilege to,
any Person other than the parties hereto.

         SECTION 10.12. EXECUTION IN COUNTERPARTS. This Agreement may be
executed in any number of counterparts and by different parties hereto in
separate counterparts, each of which when so executed shall be deemed to be an
original and all of which taken together shall constitute one and the same
agreement.

         SECTION 10.13. LIMITATION OF LIABILITY. No shareholder or trustee of NU
shall be held to any liability whatever for the payment of any sum of money or
for damages or otherwise under any Loan Document, and such Loan Documents shall
not be enforceable against any such trustee in their or his or her individual
capacities or capacity and such Loan Documents shall be enforceable against the
trustees of NU only as such, and every person, firm, association, trust or
corporation having any claim or demand arising under such Loan Documents and
relating to NU, its shareholders or trustees shall look solely to the trust
estate of NU for the payment or satisfaction thereof.


                                                                             S-1

         IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed by their respective officers thereunto duly authorized, as of the date
first above written.


                                         NORTHEAST UTILITIES



                                         By: /s/ RANDY A. SHOOP
                                             -----------------------------------
                                             Name:  Randy A. Shoop
                                             Title: Assistant Treasurer-Finance

                                       57
<PAGE>

                                                                             S-2

   Commitment:    $66,500,000            CANADIAN IMPERIAL BANK OF
                                         COMMERCE, NEW YORK AGENCY, as
                                             Bank and as Administrative Agent


                                         By: /s/ DENIS P. O'MEARA
                                             -----------------------------------
                                             Name:  Denis P. O'Meara
                                             Title: Executive Director


                   CIBC World Markets Corp. As Agent

                                                                             S-3

   Commitment:    $66,500,000            BARCLAYS BANK PLC



                                         By /s/ SYDNEY G. DENNIS
                                            ------------------------------------
                                            Name:  Sydney G. Dennis
                                            Title: Director


                                                                             S-4

  Commitment:     $66,500,000            THE BANK OF NEW YORK, as
                                            Bank and as Documentation Agent



                                         By: /s/ JOHN W. HALL
                                             -----------------------------------
                                             Name:  John W. Hall
                                             Title: Vice President


                                                                             S-5

                                         FLEET NATIONAL BANK,
                                            as Syndication Agent

  Commitment:     $66,500,000            FLEET NATIONAL BANK,
                                            as Trust Administrator for
                                            LongLane Master Trust IV, as Bank



                                         By: /s/
                                             -----------------------------------
                                             Name:
                                             Title:

                                       58
<PAGE>

                                   SCHEDULE I

                           APPLICABLE LENDING OFFICES

<TABLE>
<CAPTION>

 NAME OF BANK                        DOMESTIC LENDING OFFICE              EURODOLLAR LENDING OFFICE
 ------------                        -----------------------              -------------------------
<S>                                  <C>                                  <C>
 Barclays Bank PLC                   75 Wall Street, 11th Floor           75 Wall Street, 11th Floor
                                     New York, NY 10265                   New York, NY 10265
 The Bank of New York                One Wall Street                      One Wall Street
                                     New York, NY  10286                  New York, NY  10286
 Fleet National Bank,                100 Federal Street                   100 Federal Street
 as Trust Administrator for          Boston, MA  02110                    Boston, MA  02110
 LongLane Master Trust IV
 Canadian Imperial Bank of           425 Lexington Avenue                 425 Lexington Avenue
 Commerce                            New York, NY  10017                  New York, NY  10017
</TABLE>

                                       59
<PAGE>

                                   SCHEDULE II

                                 PENDING ACTIONS


                                      None.

                                       60
<PAGE>

                                                                   EXHIBIT 1.01A

                                     FORM OF
                                  CONTRACT NOTE



   $                                                       New York, New York
                                                             March 1, 2000


         FOR VALUE RECEIVED, the undersigned, NORTHEAST UTILITIES, an
unincorporated voluntary business association organized under the laws of the
Commonwealth of Massachusetts (the "BORROWER"), hereby promises to pay to the
order of [___________] (the "LENDER"), on the Termination Date (as defined in
the Credit Agreement referred to below), the lesser of the principal sum of
[_____________________] DOLLARS ($___________) and the aggregate unpaid
principal amount of all Contract Advances made by the Lender to the Borrower
pursuant to the Credit Agreement, in lawful money of the United States of
America in immediately available funds, and to pay interest on such principal
amount from time to time outstanding, in like funds, at a rate or rates per
annum and payable with respect to such periods and on such dates as determined
pursuant to the Credit Agreement.

         The Borrower promises to pay interest, on demand, on any overdue
principal and overdue interest from their due dates at a rate or rates
determined as set forth in the Credit Agreement.

         The Borrower hereby waives diligence, presentment, demand, protest and
notice of any kind whatsoever. The nonexercise by the holder of any of its
rights hereunder in any particular instance shall not constitute a waiver
thereof in that or any subsequent instance.

         All borrowings evidenced by this Contract Note and all payments and
prepayments of the principal hereof and interest hereon and the respective dates
thereof shall be endorsed by the holder hereof on the schedule attached hereto
and made a part hereof, or on a continuation thereof which shall be attached
hereto and made a part hereof, or otherwise recorded by such holder in its
internal records; provided, however, that any failure of the holder hereof to
make such a notation or any error in such notation shall not in any manner
affect the obligation of the

                                       61
<PAGE>

Borrower to make payments of principal and interest in accordance with the terms
of this Contract Note and the Credit Agreement.

         This Contract Note is one of the Contract Notes referred to in the Term
Loan Agreement, dated as of March 1, 2000 among the Borrower, the Lenders party
thereto, Canadian Imperial Bank of Commerce, New York Agency, as Administrative
Agent, The Bank of New York, as Documentation Agent, and Fleet National Bank, as
Syndication Agent (as amended from time to time in accordance with its terms,
the "CREDIT AGREEMENT") and is subject to the terms and conditions contained in
the Credit Agreement and is entitled to the benefits thereof. The Credit
Agreement, among other things, contains provisions for the acceleration of the
maturity hereof upon the happening of certain events, for prepayment of the
principal hereof prior to the maturity thereof and for the amendment or waiver
of certain provisions of the Credit Agreement, all upon the terms and conditions
therein specified. This Contract Note shall be construed in accordance with and
governed by the laws of the State of New York and any applicable laws of the
United States of America.

         No shareholder or trustee of the Borrower shall be held to any
liability whatever for the payment of any sum of money or for damages or
otherwise under this Contract Note, and this Contract Note shall not be
enforceable against any such trustee in their or his or her individual
capacities or capacity; this Contract Note shall be enforceable against the
trustees of the Borrower only as such, and every, person, firm, association,
trust or corporation having any claim or demand arising under this Contract Note
relating to the Borrower, its shareholders or trustees shall look solely to the
trust estate of the Borrower for payment or satisfaction thereof.

                                         NORTHEAST UTILITIES


                                         By /s/
                                            ------------------------------------
                                            Name:
                                            Title:


                               GRID NOTE SCHEDULE

- --------------------------------------------------------------------------------

DATE OF    AMOUNT OF   INTEREST   INTEREST   NUMBER   INTEREST   AMOUNT   NOTED
ADVANCE    PRINCIPAL    RATE       PERIOD    OF DAYS    DUE       PAID     BY
             PAID                                      DATE

- --------------------------------------------------------------------------------

- --------------------------------------------------------------------------------

- --------------------------------------------------------------------------------

- --------------------------------------------------------------------------------

- --------------------------------------------------------------------------------

                                       62
<PAGE>

                                                               EXHIBIT 3.01 (NU)

                      FORM OF NOTICE OF CONTRACT BORROWING


                                                            [Date]1     1    The
Notice of Contract Borrowing must be received by the Administrative Agent (i) in
the case of a proposed Contract Borrowing to consist of Eurodollar Rate
Advances, by hand or facsimile not later than 11:00 a.m. (New York City time),
three Business Days prior to the Funding Date and (ii) in the case of a proposed
Contract Borrowing to consist of Base Rate Advances, by hand or facsimile not
later than 11:00 a.m. (New York City time), on the Funding Date.


Canadian Imperial Bank of Commerce,
New York Agency
   as Administrative
   Agent for the Lenders party to
   the Credit Agreement referred to below
   425 Lexington Avenue
   New York, NY  10017

   Attention: ____________________


   Ladies and Gentlemen:

            The undersigned, Northeast Utilities (the "BORROWER"), refers to the
   Term Loan Agreement, dated as of March 1, 2000 (as amended from time to time
   in accordance with its terms, the "CREDIT AGREEMENT"), among the Borrower,
   the Lenders party thereto, Canadian Imperial Bank of Commerce, New York
   Agency, as Administrative Agent, The Bank of New York, as Documentation
   Agent, and Fleet National Bank, as Syndication Agent. Capitalized terms used
   herein and not otherwise defined herein shall have the meanings assigned to
   such terms in the Credit Agreement. The undersigned hereby gives you notice
   pursuant to Section 3.01 of the Credit Agreement that it requests a Contract
   Borrowing under the Credit Agreement, and in that connection sets forth below
   the terms on which such Borrowing is requested to be made:

     (A)      Date of proposed Contract Borrowing         _____________________
              (which is a Business Day)

     (B)      Principal Amount _____________________ of Contract Borrowing Not
              less than $5,000,000 and in integral multiples of $1,000,000.

     (C)      Type of Advance Eurodollar Rate Advance or Base Rate Advance.
     ----------------------

     (D)      Initial Interest Period                     _____________________

            Upon acceptance of any or all of the Contract Advances requested in
   this Notice of Contract Borrowing, the undersigned shall be deemed to have
   represented and warranted that the conditions precedent to each Contract
   Advance applicable to it specified in Section 5.02(a) of the Credit Agreement
   have been satisfied.

                                       Very truly yours,

                                       NORTHEAST UTILITIES

                                       By________________________________
                                           Name:
                                           Title:



   EXHIBIT 10.07



                            ASSIGNMENT AND ACCEPTANCE


                                     Dated ,


            Reference is made to the Term Loan Agreement, dated as of March 1,
   2000 (as amended from time to time in accordance with its terms, the "CREDIT
   AGREEMENT"), among Northeast Utilities (the "BORROWER"), the Lenders party
   thereto, Canadian Imperial Bank of Commerce, New York Agency, as
   Administrative Agent, The Bank of New York, as Documentation Agent, and Fleet
   National Bank, as Syndication Agent. Capitalized terms used herein and not
   defined shall have the meaning assigned to such terms in the Credit
   Agreement. Pursuant to the Credit Agreement, ________________ (the
   "ASSIGNOR") has committed to make advances ("ADVANCES") to the Borrower,
   which Advances are evidenced by the Contract Note issued by the Borrower to
   the Assignor.

            The Assignor and                  (the "ASSIGNEE") agree as follows:
                             -----------------

            1. The Assignor hereby sells and assigns, without recourse, to the
   Assignee, and the Assignee hereby purchases and assumes from the Assignor,
   without recourse to the Assignor, a portion of the Assignor's rights and
   obligations under the Loan Documents as of the Effective Date (as defined
   below) which represents the percentage interest specified on Schedule 1 of
   all outstanding rights and obligations of the Lenders under the Loan
   Documents (the "ASSIGNED INTEREST"), including, without limitation, such
   percentage interest in the Commitment as in effect on the Effective Date, the
   Advances outstanding on the Effective Date and the Notes. After giving effect
   to such sale and assignment, the Assignee's Commitment will be as set forth
   in Section 2 of Schedule 1. The effective date of this sale and assignment
   shall be the date specified on Schedule 1 hereto, which shall be no fewer
   than five Business Days following the date first set forth above (the
   "EFFECTIVE DATE").

            2. On the Effective Date, the Assignee will pay to the Assignor, in
   same day funds, at such address and account as the Assignor shall advise the
   Assignee, the principal amount of the Advances outstanding under the Loan
   Documents which are being assigned hereunder, and the sale and assignment
   contemplated hereby shall thereupon become effective. From and after the
   Effective Date, the Assignor agrees that the Assignee shall be entitled to
   all rights, powers and privileges of the Assignor under the Loan Documents to
   the extent of the Assigned Interest, including without limitation (i) the
   right to receive all payments in respect of the Assigned Interest for the
   period from and after the Effective Date, whether on account of principal,
   interest, fees, indemnities in respect of claims arising after the Effective
   Date (subject to Section 10.04 of the Credit Agreement), increased costs,
   additional amounts or otherwise; (ii) the right to vote and to instruct the
   Administrative Agent under the Credit Agreement based on the Assigned
   Interest; (iii) the right to set-off and to appropriate and apply deposits of
   the Borrower as set forth in the Credit Agreement; and (iv) the right to
   receive notices, requests, demands and other communications. The Assignor
   agrees that it will promptly remit to the Assignee any amount received by it
   in respect of the Assigned Interest (whether from the Borrower, the
   Administrative Agent or otherwise) in the same funds in which such amount is
   received by the Assignor.

            3. The Assignor (i) represents and warrants that it is the legal and
   beneficial owner of the interest being assigned by it hereunder and that such
   interest is free and clear of any adverse claim; (ii) other than as provided
   in this Assignment and Acceptance, makes no representation or warranty and
   assumes no responsibility with respect to any statements, warranties or
   representations made in or in connection with the Loan Documents or the
   execution, legality, validity, enforceability, genuineness, sufficiency or
   value of the Loan Documents or any other instrument or document furnished
   pursuant thereto; (iii) makes no representation or warranty and assumes no
   responsibility with respect to the financial condition of the Borrower or the
   performance or observance by the Borrower of any of its obligations under the
   Loan Documents or any other instrument or document furnished pursuant
   thereto; (iv) makes no other representation or warranty with respect to the
   Borrower, the Loan Documents or any other instrument or document furnished
   pursuant thereto, except as expressly set forth in clause (i) of this Section
   3; and (v) attaches its Notes which are subject to the assignment being made
   hereby and requests that the Administrative Agent obtain new Notes from the
   Borrower in accordance with the terms of subsection 10.07(d) of the Credit
   Agreement.

            4. The Assignee (i) confirms that it has received a copy of the
   Credit Agreement, together with copies of the Financial Statements, or the
   latest financial statements delivered by the Borrower to the Administrative
   Agent pursuant to Section 7.04 of the Credit Agreement, and such other
   documents and information as it has deemed appropriate to make its own credit
   analysis and decision to enter into this Assignment and Acceptance; (ii)
   agrees that it will, independently and without reliance upon the
   Administrative Agent, the Assignor or any other Lender and based on such
   documents and information as it shall deem appropriate at the time, continue
   to make its own credit decisions in taking or not taking action under the
   Loan Documents; (iii) appoints and authorizes the Administrative Agent to
   take such action as agent on its behalf and to exercise such powers under the
   Loan Documents as are delegated to the Administrative Agent by the terms
   thereof, together with such powers as are reasonably incidental thereto; (iv)
   agrees that it will perform in accordance with their terms all of the
   obligations which by the terms of the Loan Documents are required to be
   performed by it as a Lender; (v) specifies as its Domestic Lending Office
   (and address for notices) and Eurodollar Lending Office the offices set forth
   beneath its name on the signature pages hereof; and (vi) attaches the forms
   prescribed by the Internal Revenue Service of the United States certifying as
   to the Assignee's status for purposes of determining exemption from United
   States withholding taxes with respect to all payments to be made to the
   Assignee under the Loan Documents or such other documents as are necessary to
   indicate that all such payments are subject to such rates at a rate reduced
   by an applicable tax treaty.

            5. Following the execution of this Assignment and Acceptance, it
   will be delivered to the Administrative Agent for acceptance and recording by
   the Administrative Agent. Upon such acceptance and recording and receipt of
   any consent of the Borrower and the Administrative Agent required pursuant to
   Section 10.07(a) of the Credit Agreement, as of the Effective Date, the
   Assignee shall be a party to the Credit Agreement and, to the extent provided
   in this Assignment and Acceptance, have the rights and obligations of a
   Lender thereunder and under the Notes and the Assignor shall, to the extent
   provided in this Assignment and Acceptance, relinquish its rights and be
   released from its obligations under the Credit Agreement and the Notes.

            6. Upon such acceptance, recording and consent, from and after the
   Effective Date, the Administrative Agent shall make all payments under the
   Credit Agreement and the Notes in respect of the interest assigned hereby
   (including, without limitation, all payments of principal, interest and fees
   with respect thereto) to the Assignee. The Assignor and Assignee shall make
   all appropriate adjustments in payments under the Credit Agreement and the
   Notes for periods prior to the Effective Date directly between themselves.

            7. This Assignment and Acceptance shall be governed by, and
   construed in accordance with, the laws of the State of New York.

            8. This Assignment and Acceptance may be executed in any number of
   counterparts and by different parties hereto in separate counterparts, each
   of which when so executed shall be deemed to be an original and all of which
   taken together shall constitute one and the same agreement. Delivery of an
   executed counterpart of Schedule 1 to this Assignment and Acceptance by
   telecopier shall be effective as delivery of a manually executed counterpart
   of this Assignment and Acceptance.

            IN WITNESS WHEREOF, the parties hereto have caused this Assignment
   and Acceptance to be executed by their respective officers thereunto duly
   authorized, as of the date first above written, such execution being made on
   Schedule 1 hereto.
                                        2


                                   Schedule 1
                                       to
                                Lender Assignment
                                     Dated ,


   SECTION 1.
   ---------

            (a)      Total Credit Agreement Commitments:$________

            (b)      Percentage Interest:  Specify percentage to no more than 8
                     decimal points.
   ---------%

            (c)      Amount of Assigned Share:                   $________


   SECTION 2.
   ---------

            Assignee's Commitment:                               $________


   SECTION 3.
   ---------

            Effective Date: Such date shall be at least 5 Business  Days after
   the execution of this Lender Assignment.                 __________, ____


                                               [NAME OF ASSIGNOR], as Assignor


                                               By ______________________________
                                                  Name:
                                                  Title:


                                               [NAME OF ASSIGNEE], as Assignee


                                               By ______________________________
                                                  Name:
                                                  Title:



                          Domestic               Lending Office (and address for
                                                 notices):
                                    [Address]


                           Eurodollar Lending Office:
                                    [Address]


   Accepted and Consented to this      day
                                  ----
   of             :
      ------------ -

   CANADIAN IMPERIAL BANK OF COMMERCE,
      as Administrative Agent


   By ____________________________
      Name:
      Title:


   Consented tothis      day
                    ----
   of             :
      ------------

   NORTHEAST UTILITIES


   By:
      -----------------------------------------
       Name:
       Title:
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4.1.5.1
<SEQUENCE>3
<FILENAME>0003.txt
<DESCRIPTION>EXHIBIT 4.1.5.1
<TEXT>


Final

                               FIRST AMENDMENT TO
                               TERM LOAN Agreement


This FIRST AMENDMENT, dated as of December 15, 2000 (this "Amendment"), to that
certain TERM LOAN AGREEMENT, dated as of March 1, 2000 (the "Existing
Agreement"; as amended by this Amendment, the "Amended Agreement"), among
NORTHEAST UTILITIES, an unincorporated voluntary business association organized
under the laws of the Commonwealth of Massachusetts (the "Borrower"), the
Lenders parties thereto, Fleet National Bank, as Syndication Agent thereunder,
The Bank of New York, as Documentation Agent thereunder and CANADIAN IMPERIAL
BANK OF COMMERCE, a Canadian chartered bank ("CIBC") acting through its New York
Agency, as Administrative Agent for such Lenders.

WHEREAS, the parties have previously entered into the Existing Agreement; and

WHEREAS, the parties now wish to amend the Existing Agreement as herein set
forth;

NOW THEREFORE, the Borrower, the Lenders, such Syndication Agent, such
Documentation Agent and the Administrative Agent hereby agree as follows:

                                    ARTICLE I

                                   Definitions



SECTION 2.01.  Definitions.  Terms used but not otherwise defined in this
Amendment shall have the meanings assigned them in the Existing Agreement.



ARTICLE III

AMENDMENT OF EXISTING AGREEMENT

SECTION 4.01.  Amendments to Section 1.01 (Definitions).

(a)  The following definitions are hereby added to Section 1.01 of the
Existing Agreement:

"Consolidated EBIT" means, for any period (as determined on a consolidated basis
in accordance with generally accepted accounting principles), the Borrower's and
its Subsidiaries' net income for such period, adjusted as follows:

(i) increased by the amount of federal and state income taxes to the extent
deducted in the computation of such Borrower's and/or its Subsidiaries'
consolidated net income for such period; (ii) increased by the amount of
Consolidated Interest Expense deducted in the computation of the Borrower's
and/or its Subsidiaries' consolidated net income for such period; (iii)
increased by the amount of dividends on preferred stock deducted in the
computation of the Borrower's and/or its Subsidiaries' consolidated net income
for such period; (iv) decreased (increased) by the gain (loss) on asset sales
done outside the ordinary course of business by the Borrower and/or its
Subsidiaries to the extent such gains (losses) are not offset by increases
(decreases) in amortization of regulatory assets, and to the extent such gain
(loss) is included in the computation of the Borrower's and/or its Subsidiaries'
consolidated net income for such period; (v) decreased by the amount of revenues
accrued by the Borrower and/or its Subsidiaries related to interest on Stranded
Cost Recovery Obligations of Subsidiaries of the Borrower, and increased by the
amount of operating expenses accrued by the Borrower and/or its Subsidiaries
related to interest on Stranded Cost Recovery Obligations of Subsidiaries of the
Borrower, in each case to the extent included in the computation of the
Borrower's and/or its Subsidiaries' consolidated net income for such period; and
(vi) increased by the amount of the non-cash write-offs associated with the
September 8, 2000 PSNH restructuring settlement (PUC order no. 23,549) to the
extent included in the computation of the Borrower's and/or its Subsidiaries'
consolidated net income for such period.

"Stranded Cost Recovery Obligations" means, with respect to any Person, such
Person's obligations to make principal, interest or other payments to the issuer
of stranded cost recovery bonds pursuant to a loan agreement or similar
arrangement whereby the issuer has loaned the proceeds of such bonds to such
Person.

(b) The following definitions set forth in the Section 1.01 of the Existing
Agreement are hereby amended and restated to read in their entirety as follows:

"Consolidated Interest Expense" means, for any period, the aggregate amount of
any interest required to be paid during such period by the Borrower and its
Subsidiaries on Debt (including the current portion thereof) (as determined on a
consolidated basis in accordance with generally accepted accounting principles),
excluding interest required to be paid on the Stranded Cost Recovery Obligations
of any Subsidiary of the Borrower.

"Debt" means, for any Person, without duplication, (i) indebtedness of such
Person for borrowed money, including but not limited to obligations of such
Person evidenced by bonds, debentures, notes or other similar instruments
(excluding Stranded Cost Recovery Obligations which are non-recourse to such
Person), (ii) obligations of such Person to pay the deferred purchase price of
property or services (excluding any obligation of such Person to the United
States Department of Energy or its successor with respect to disposition of
spent nuclear fuel burned prior to April 3, 1983), (iii) obligations of such
Person as lessee under leases which shall have been or should be, in accordance
with generally accepted accounting principles, recorded as capital leases, (iv)
obligations under direct or indirect guaranties in respect of, and obligations
(contingent or otherwise) to purchase or otherwise acquire, or otherwise to
assure a creditor against loss in respect of, indebtedness or obligations of
others of the kinds referred to in clauses (i) through (iii), above, including
all Parent Support Obligations, (v) letters of credit, guaranties and other
forms of credit enhancement issued to support power sales and trading
activities, and (vi) liabilities in respect of unfunded vested benefits under
ERISA Plans.

"ERISA Plan Termination Event" means (i) a Reportable Event described in Section
4043 of ERISA and the regulations issued thereunder (other than a Reportable
Event not subject to the provision for 30-day notice to the PBGC under such
regulations) with respect to an ERISA Plan or an ERISA Multi- employer Plan, or
(ii) the withdrawal of the Borrower or any of its ERISA Affiliates from an ERISA
Plan or an ERISA Multi-employer Plan during a plan year in which it was a
"substantial employer" as defined in Section 4001(a)(2) of ERISA, or (iii) the
filing of a notice of intent to terminate an ERISA Plan or an ERISA
Multi-employer Plan or the treatment of an ERISA Plan amendment as a termination
or of an ERISA Multi-employer Plan amendment as a termination under Section 4041
of ERISA, or (iv) the institution of proceedings to terminate an ERISA Plan or
an ERISA Multi-employer Plan by the PBGC, or (v) any other event or condition
which might constitute grounds under Section 4042 of ERISA for the termination
of, or the appointment of a trustee to administer, any ERISA Plan or ERISA
Multi-employer Plan.

"Extraordinary Proceeds" shall mean, for any Person for any period, net proceeds
received by such Person during such period from (i) issuances of stranded cost
recovery bonds plus (ii) sales of assets by such Person or any of its
Subsidiaries not in the ordinary course of business plus (iii) the sale or
disposition (by way of merger, sale of capital stock, sale of assets or
otherwise) of any Subsidiary of such Person. For purposes of the foregoing, all
cash received by such Person from, or as a result of the sale or disposition of,
a Subsidiary shall be deemed to constitute "Extraordinary Proceeds" up to the
amount of proceeds received by, or as a result of the sale or disposition of,
such Subsidiary from such issuances and sales during the relevant period, net of
underwriting discounts and commissions, costs of sale and other, similar
transaction costs.

"First Mortgage Indenture" means, with respect to CL&P, the CL&P Indenture or
any successor thereto or replacement thereof; with respect to WMECO, the WMECO
Indenture or any successor thereto or replacement thereof; and with respect to
any other Person, an indenture or similar instrument pursuant to which such
Person may issue bonds, notes or similar instruments secured by a lien on all or
substantially all of such Person's fixed assets.

"Named Debt" means Debt of HWP under (i) the Reimbursement and Security
Agreement (1988 Series), dated as of November 3, 1999, as amended or extended
from time to time, between HWP and The Toronto-Dominion Bank and (ii) the
Reimbursement and Security Agreement (1990 Series), dated as of November 3,
1999, as amended or extended from time to time, between HWP and The Toronto-
Dominion Bank.

"Operating Cash Flow" shall mean, for any period, the sum of the following
amounts: (1) dividends paid to the Borrower by a Subsidiary thereof during such
period; (2) consulting and management fees paid to the Borrower for such period;
(3) tax sharing payments made to the Borrower during such period; (4) interest
and other distributions paid to the Borrower during such period with respect to
cash (e.g., NU System Money Pool) and other Permitted Investments of the
Borrower; and (5) other cash payments made to the Borrower by its Subsidiaries
other than (A) returns of invested capital, (B) payments of the principal on
Debt of any such Subsidiary to the Borrower (to the extent permitted hereunder)
and (C) Extraordinary Proceeds. If at any time there shall exist an event or
condition which permits any holder to accelerate the maturity date of any Debt
of, or terminate its commitment to extend credit to any Subsidiary, then the
contributions of such Subsidiary to Operating Cash Flow for any period ending at
or prior to such time shall be eliminated and Operating Cash Flow shall be
calculated after giving effect to such elimination.

"Principal Subsidiary" shall mean CL&P, WMECO, PSNH, HWP, NAEC, Select Energy,
Inc., HEC Inc., Northeast Generation Company, Mode One Communications, Inc.,
Yankee Gas Services Company, and any other Subsidiary, whether owned directly or
indirectly by the Borrower, which, with respect to the Borrower and its
Subsidiaries taken as a whole, represents at least ten percent (10%) of such
Borrower's consolidated assets or such Borrower's consolidated net income (or
loss).

(c) The definition of "Consolidated Operating Income" is hereby deleted from
Section 1.01 of the Existing Agreement.


SECTION 4.02.  Amendments to Section 7.02 (Negative Covenants).  Section 7.02
of the Existing Credit Agreement is hereby amended and restated to read in
its entirety as follows:


SECTION 7.02. Negative Covenants. On and after the Closing Date, and so long as
any Note shall remain unpaid or any Lender shall have any Commitment hereunder,
the Borrower shall not, or permit any Principal Subsidiary to, without the
written consent of the Majority Lenders:

(a)  Liens, Etc.  Create incur, assume or suffer to exist any Lien upon any
of its properties or assets (including the stock of its Subsidiaries),
whether now owned or hereafter acquired, except:

(i)  any Liens existing on the Closing Date;

(ii) in the case of CL&P, Liens created by the Indenture of Mortgage and Deed of
Trust dated as of May 1, 1921, from CL&P to Bankers Trust Company, as trustee,
as previously and hereafter amended and supplemented (the "CL&P Indenture");

(iii) in the case of WMECO, Liens created by the First Mortgage Indenture and
Deed of Trust dated as of August 1, 1954, from WMECO to State Street Bank and
Trust Company, as successor trustee, as previously and hereafter amended and
supplemented (the "WMECO Indenture");

(iv) in the case of PSNH, Liens created by the General and Refunding Mortgage
Indenture, dated as of August 15, 1978, between PSNH and New England Merchants
National Bank, as trustee, and to which First Union National Bank is successor
trustee, as previously and hereafter amended and supplemented (the "PSNH
Indenture");

(v) in the case of NAEC, Liens created by the First Mortgage Indenture and Deed
of Trust, dated as of June 1, 1992, between NAEC and United States Trust Company
of New York, as trustee, as previously and hereafter amended and supplemented
(the "NAEC Indenture");

(vi)  as permitted by Section 7.02(f) hereof;

(vii) Liens on the interests of CL&P and WMECO in (A) the Millstone Unit No. 1
created by (1) the Open-End Mortgage and Trust Agreement dated as of October 1,
1986, as previously and hereafter amended, made by CL&P in favor of State Street
Bank and Trust Company, as successor trustee, and (2) the Open-End Mortgage and
Trust Agreement dated as of October 1, 1986, as previously and hereafter
amended, made by WMECO in favor of State Street Bank and Trust Company, as
successor trustee, to the extent of the Debt from time to time secured by such
Open-End Mortgages and Trust Agreements, and (B) Millstone Unit No. 2 and
Millstone Unit No. 3 created by (1) the Open-End Mortgage, dated as of November
17, 2000, made by CL&P in favor of Citibank, N.A., as collateral agent, and (2)
the Open-End Mortgage, dated as of November 17, 2000, made by WMECO in favor of
Citibank, N.A., as collateral agent, to the extent of the Debt secured by such
Open-End Mortgages;

(viii) "Permitted Liens" or "Permitted Encumbrances" under the CL&P Indenture
(in the case of CL&P), the WMECO Indenture (in the case of WMECO), the PSNH
Indenture (in the case of PSNH) or the NAEC Indenture (in the case of NAEC), in
each case as such terms are defined on the date hereof, to the extent such Liens
do not secure Debt of the Borrower or any Principal Subsidiary;

(ix) any purchase money Lien or construction mortgage on assets hereafter
acquired or constructed by the Borrower or any Principal Subsidiary and any Lien
on any assets existing at the time of acquisition thereof by the Borrower or
such Principal Subsidiary or created within 180 days from the date of completion
of such acquisition or construction; provided that such Lien shall at all times
be confined solely to the assets so acquired or constructed and any additions
thereto;

(x) any existing Liens on assets now owned by the Borrower or any Principal
Subsidiary and Liens existing on assets of a corporation or other going concern
when it is merged into or with the Borrower or such Principal Subsidiary or when
substantially all of its assets are acquired by the Borrower or such Principal
Subsidiary; provided that such Liens shall at all times be confined solely to
such assets, or if such assets constitute a utility system, additions to or
substitutions for such assets;

(xi) Liens resulting from legal proceedings being contested in good faith by
appropriate legal or administrative proceedings by the Borrower or any Principal
Subsidiary, and as to which the Borrower or such Principal Subsidiary, to the
extent required by generally accepted accounting principles applied on a
consistent basis, shall have set aside on its books adequate reserves;

(xii)  Liens created in favor of the other contracting party in connection
with advance or progress payments;

(xiii) any Liens in favor of any state of the United States or any political
subdivision of any such state, or any agency of any such state or political
subdivisions, or trustee acting on behalf of holders of obligations issued by
any of the foregoing or any financial institutions lending to or purchasing
obligations of any of the foregoing, which Lien is created or assumed for the
purpose of financing all or part of the cost of acquiring or constructing the
property subject thereto;

(xiv) Liens resulting from conditional sale agreements, capital leases or other
title retention agreements including, without limitation, Liens arising under
leases of nuclear fuel from the Niantic Bay Fuel Trust;

(xv) with respect to pollution control bond financings, Liens on funds, accounts
and other similar intangibles of the Borrower or any Principal Subsidiary
created or arising under the relevant indenture, pledges of the related loan
agreement with the relevant issuing authority and pledges of the Borrower's or
such Principal Subsidiary's interest, if any, in any bonds issued pursuant to
such financings to a letter of credit bank or bond issuer or similar credit
enhancer;

(xvi) Liens granted on accounts receivable and Regulatory Assets in connection
with financing transactions, whether denominated as sales or borrowings;

(xvii) Liens on the assets of, or the stock issued by, Northeast Generation
Company or any other Subsidiary of the Borrower created to hold generating
assets if such Liens are created to secure nonrecourse Debt incurred to acquire,
construct or otherwise develop such generating assets;

(xviii)  Liens on assets of HWP permitted to exist by the terms of agreements
governing the Named Debt;

(xix)  any other Liens incurred in the ordinary course of business otherwise
than to secure Debt; and

(xx) any extension, renewal or replacement of Liens permitted by clauses (i),
(vii) through (x) and (xii) through (xvii); provided, however, that the
principal amount of Debt secured thereby shall not, at the time of such
extension, renewal or replacement, exceed the principal amount of Debt so
secured and that such extension, renewal or replacement shall be limited to all
or a part of the property which secured the Lien so extended, renewed or
replaced or to other property of no greater value than the property which
secured the Lien so extended, renewed or replaced.

(b) Mergers, Acquisitions, Sales of Assets, Etc. Merge with or into or
consolidate with or into, any Person, or purchase or otherwise acquire (whether
directly or indirectly) all or substantially all of the assets or stock of any
class of, or any partnership or joint venture interest in, any other Person, or
sell, transfer, convey, lease or otherwise dispose of all or any substantial
part of its assets; except for the following, and then only after receipt of all
necessary corporate and governmental or regulatory approvals and provided that,
before and after giving effect to any such merger, consolidation, purchase,
acquisition, sale, transfer, conveyance, lease or other disposition, no Event of
Default or Unmatured Default shall have occurred and be continuing:

(A)  NU may merge with or into Consolidated Edison, Inc. or a wholly owned
Subsidiary thereof;

(B) NU or any Subsidiary thereof may enter into such transactions with third
parties if the aggregate consideration involved in all such transactions does
not exceed $25,000,000 and if NU or such Subsidiary is the surviving legal
entity of any such transaction;

(C) any purchase or acquisition of a joint venture interest in a mutual
insurance company providing nuclear liability or nuclear property or replacement
power insurance;

(D) any sale of accounts receivable on reasonable commercial terms (including a
commercially reasonable discount) to obtain funding for CL&P and WMECO, as the
case may be;

(E) any sale or purchase of generating assets or Regulatory Assets on an
arms-length basis, subject to approval by the appropriate regulatory
authorities;

(F)  any sale of transmission assets on an arms-length basis as required by
the appropriate regulatory authorities; and

(G) the sale of the Borrower's or any Principal Subsidiary's assets in the
ordinary course of business on customary terms and conditions. For purposes of
this subsection (b), any sale of assets by the Borrower or any Principal
Subsidiary (in one or a series of transactions) will be deemed to be a
"substantial part" of its assets if (i) the book value of such assets exceeds
7.5% of the total book value of the assets (net of Regulatory Assets) of such
Person, as reflected in the most recent financial statements of the Borrower or
such Principal Subsidiary delivered to the Administrative Agent pursuant to
Section 7.04 hereof (or, if no such financial statements have been delivered to
the Administrative Agent as of the relevant date of determination, the Financial
Statements of such Person), or (ii) the gross revenue associated with such
assets accounts for more than 7.5% of the total gross revenue of the Borrower or
such Principal Subsidiary for the four proceeding fiscal quarters, as reflected
in the most recent financial statements of the Borrower or such Principal
Subsidiary delivered to the Administrative Agent pursuant to Section 7.04 hereof
(or, if no such financial statements have been delivered to the Administrative
Agent as of the relevant date of determination, the Financial Statements of such
Person).

(c) Compliance with ERISA. (i) Terminate, or permit any of its ERISA Affiliates
to terminate, any ERISA Plan so as to result in any liability of the Borrower or
any Principal Subsidiary to the PBGC in an amount greater than $1,000,000, or
(ii) permit to exist any occurrence of any Reportable Event (as defined in Title
IV of ERISA) which, alone or together with any other Reportable Event with
respect to the same or another ERISA Plan, has a reasonable possibility of
resulting in liability of the Borrower or any Principal Subsidiary to the PBGC
in an aggregate amount exceeding $1,000,000, or any other event or condition
which presents a material risk of such a termination by the PBGC of any ERISA
Plan or has a reasonable possibility of resulting in a liability of the Borrower
or any Principal Subsidiary to the PBGC in an aggregate amount exceeding
$1,000,000.

(d) Accounting Changes. Make any change in its accounting policies or reporting
practices except as required or permitted by the Securities and Exchange
Commission, the Financial Accounting Standards Board or any other generally
recognized accounting authority.

(e) Transactions with Affiliates. Engage in any transaction with any Affiliate
except (i) in accordance with the Public Utility Holding Company Act of 1935, to
the extent applicable thereto or (ii) on terms no less favorable to the Borrower
or the Principal Subsidiary party thereto than if the transaction had been
negotiated in good faith on an arms-length basis with a non-Affiliate and on
commercially reasonable terms or pursuant to a binding agreement in effect on
the Closing Date.

(f) Issuance of First Mortgage Bonds. In the case of Principal Subsidiaries
only, issue any First Mortgage Bonds on or after the Closing Date, whether in
addition to First Mortgage Bonds outstanding on the Closing Date or in
replacement of First Mortgage Bonds redeemed, retired, defeased, repaid or
prepaid on or after the Closing Date; provided, that (i) Yankee Gas Services
Company may issue First Mortgage Bonds, the proceeds of which are used to
refinance not more than $200,000,000 of Debt incurred by NU in connection with
the acquisition by NU of Yankee Energy System Inc., and (ii) Northeast
Generation Company may issue First Mortgage Bonds for the purpose of refinancing
up to $416,000,000 of its secured Debt outstanding on the Closing Date, to the
extent that the principal amount of any such First Mortgage Bonds is less than
or equal to the principal amount of the Debt so refinanced plus up to six months
of accrued interest on such Debt, determined at the time of the refinancing;
provided, that in no event shall the amount of First Mortgage Bonds issued by
Northeast Generation Company exceed $440,000,000.

(g) Interests in Nuclear Plants. Acquire any nuclear plant or any interest
therein not held on the Closing Date, other than so-called "power entitlements"
acquired for use in the ordinary course of business.

(h) Debt. Create, incur, assume or suffer to exist, any Debt of NU, NU
Enterprises, Inc. or any Subsidiary of NU Enterprises, Inc., other than (i) Debt
under the Loan Documents; (ii) other Debt in existence on the Closing Date, and
any renewal or replacement thereof by the debtor thereunder so long as such
renewal or replacement does not result in an increase in the amount of such Debt
or require, when compared to the Debt being renewed or replaced, additional
credit support or credit support of a different character (including, without
limitation, any collateral) that has not been first offered to the Lenders;
(iii) Parent Support Obligations in an amount not to exceed $500,000,000 at any
one time outstanding; (iv) Debt incurred by HEC Inc. in an aggregate principal
amount not to exceed $35,000,000; (v) in the case of NU Enterprises, Inc. and
its Subsidiaries, Debt owing to NU, NU Enterprises, Inc. or the NU System Money
Pool; and (vi) as permitted by Section 7.02(f) above.

(i) Investments. With respect to the Borrower only, purchase, hold or acquire
any capital stock, evidences of indebtedness or other securities (including any
option, warrant or other right to acquire any of the foregoing) of, make or
permit to exist any loans or advances to, guarantee any obligations of, or make
or permit to exist any investment or any other interest in, any other Person, or
purchase or otherwise acquire (in one transaction or a series of transactions)
any assets of any other Person constituting a business unit (each of the
foregoing, an "Investment"), except (i) equity and debt investments in
(including NU System Money Pool advances to) Select Energy Inc. in an aggregate
amount not to exceed $200,000,000; (ii) NU System Money Pool advances (other
than to Select Energy Inc.) in an aggregate amount not to exceed $100,000,000 at
any one time outstanding; (iii) other debt and equity investments in
Subsidiaries of the Borrower (other than NU System Money Pool advances and other
than in Select Energy Inc.) in an aggregate amount not to exceed $100,000,000
from and after the Closing Date; (iv) the issuance of up to $35,000,000 in
construction completion and similar performance guaranties on behalf of HEC Inc.
from and after the Closing Date; (v) Investments permitted by subsections (b)
and (h) above; (vi) Investments other than (A) those enumerated in clauses (i)
through (v) above and (B) NU System Money Pool Advances, in each case, made
prior to the Closing Date; and (vii) Permitted Investments.

(j) Restricted Payments. With respect to the Borrower only, declare or make, or
agree to pay or make, directly or indirectly, any Restricted Payment, except
that the Borrower may (i) pay dividends to its common stockholders in an
aggregate amount not to exceed $60,000,000 during any 12- month period beginning
or ending on the Closing Date or any day thereafter until and including the
Termination Date, and (ii) redeem or repurchase capital stock for an aggregate
amount not in excess of $215,000,000 in connection with the acquisition of
Yankee Energy System Inc..

(k) Financing Agreements. With respect to the Borrower only, permit any
Principal Subsidiary to enter into any agreement, contract, indenture or similar
obligation, or issue any security (all of the foregoing being referred to as
"Financing Agreements"), that is not in effect on the Closing Date, or amend or
modify any existing Financing Agreement, if the effect of such Financing
Agreement (or amendment or modification thereof) is to impose any additional
restriction not in effect on the Closing Date on the ability of such Principal
Subsidiary to pay dividends to the Borrower; provided, that the foregoing shall
not restrict the right of Northeast Generation Company, or any other Subsidiary
of the Borrower created to hold generating assets, to enter into any such
Financing Agreement in connection with the incurrence of nonrecourse Debt to
acquire, construct or otherwise develop generating assets.

SECTION 4.03.  Amendments to Section 7.03 (Financial Covenants).  Section
7.03 of the Existing Credit Agreement is hereby amended and restated to read
in its entirety as follows:

SECTION 7.03. Financial Covenants. On and after the Closing Date, so long as any
Note shall remain unpaid or any Lender shall have any Commitment hereunder, the
Borrower shall, unless the Majority Lenders shall otherwise consent in writing:

(a)  Common Equity Ratio.  Maintain at all times a ratio of Common Equity to
Total Capitalization of at least 0.30:1:00.

(b) Interest Coverage Ratio. Maintain, as of the end of each Fiscal Quarter,
with respect to the four Fiscal Quarters then ended, a ratio of Consolidated
EBIT to Consolidated Interest Expense of at least (i) 2.00:1:00 with respect to
the four Fiscal Quarters ending December 31, 2000 and March 31, 2001, and (ii)
2.20:1.00 with respect to any period of four Fiscal Quarters ending after March
31, 2001.

(c) Cash Flow Ratio. Maintain, as of the end of each Fiscal Quarter, with
respect to the four Fiscal Quarters then ended, a ratio of Operating Cash Flow
to Fixed Charges of at least 1.50:1.00.

SECTION 4.04.  Reference to and Effect on Other Documents.

(a) On and after the date this Amendment becomes effective in accordance with
Article III, below, each reference in the Existing Agreement to "this
Agreement", "hereunder", "hereof" or words of like import referring to the
Existing Agreement, and each reference in the Notes to "the Credit Agreement",
"thereunder", "thereof" or words of like import referring to the Existing
Agreement, shall mean and be a reference to the Amended Agreement.

(b) Except as specifically amended above, the Existing Agreement is and shall
continue to be in full force and effect and is hereby in all respects ratified
and confirmed.

(c) The execution, delivery and effectiveness of this Amendment shall not,
except as expressly provided herein, operate as a waiver of any right, power or
remedy of the Lenders or of the Administrative Agent under the Existing
Agreement, nor constitute a waiver of any provision of any of the foregoing.


ARTICLE V

Conditions Precedent to EFFECTIVENESS


SECTION 7.01.  Conditions Precedent to Effectiveness.  This Amendment shall
not become effective unless and until all of the following conditions
precedent shall have been satisfied:

(a) The Administrative Agent shall have received the following, each dated the
date of this Amendment, in form and substance reasonably satisfactory to the
Administrative Agent and its counsel:

(i)  counterparts of this Amendment duly executed by the Borrower and the
Majority Lenders;

(ii)  an opinion of Jeffrey C. Miller, Associate General Counsel to the
Borrower, in form and substance satisfactory to the Administrative Agent and
its counsel;

(iii) copies of all approvals, authorizations or consents of, or notices to or
registrations with, any governmental body or agency required for the Borrower to
enter into this Amendment, and of all such approvals, authorizations, notices or
registrations required to be obtained or made by the Borrower in connection with
the transactions contemplated by this Amendment, other than, in each case, those
previously delivered to the Administrative Agent pursuant to the Existing
Agreement;

(iv) a certificate of the Borrower certifying the names and true signatures of
the individuals authorized to sign this Amendment and the other documents to be
delivered by the Borrower hereunder; and

(v) such other documents, instruments, approvals (and, if requested by the
Administrative Agent, certified duplicates of executed copies thereof) or
opinions as the Administrative Agent may reasonably request.

(b) No Default or Event of Default shall have occurred and be continuing or
would result from the issuance of this Amendment, and the Administrative Agent
shall have received a certificate to such effect signed by a senior officer of
the Borrower and dated such date.


ARTICLE VIII

Representations and Warranties

SECTION 8.01.  Representations and Warranties of the Borrower.  The Borrower
represents and warrants to the Lenders as follows:

(a) Organization. The Borrower is a voluntary association organized under a
Declaration of Trust, duly organized, validly existing and in good standing
under the laws of the jurisdiction of its organization, has the requisite power
under its Declaration of Trust and authority to own its property and assets and
to carry on its business as now conducted. Commonwealth of Massachusetts.

(b) Authorization; No Conflict. The execution and delivery of this Amendment,
and the performance by the Borrower of its obligations under this Amendment and
the Amended Agreement are within the Borrower's powers under its Declaration or
Trust, have been duly authorized by all necessary action under its Declaration
of Trust and applicable law, and do not and will not contravene (i) the
Borrower's Declaration of Trust or any law or legal restriction or (ii) any
contractual restriction binding on or affecting the Borrower or its properties.

(c) Governmental Approvals. No authorization or approval or other action by, and
no notice to or filing with, any governmental authority or regulatory body is
required for the due execution and delivery by the Borrower of this Amendment
and the performance by the Borrower of this Amendment and the Amended Agreement
except for the approval, which has already been obtained and is in full force
and effect, of the United States Securities and Exchange Commission.

(d) Validity and Binding Nature. This Amendment and the Amended Agreement are
legal, valid and binding obligations of the Borrower enforceable against the
Borrower in accordance with their respective terms.

(e) Information. No exhibit, schedule, report or other written information
provided by the Borrower or its agents to the Administrative Agent or the
Lenders in connection with the negotiation, execution and closing of this
Amendment knowingly contained when made any material misstatement of fact or
knowingly omitted to state any material fact necessary to make the statements
contained therein not misleading in light of the circumstances under which they
were made.


ARTICLE IX

MISCELLANEOUS

SECTION 9.01. Costs, Expenses and Taxes. The Borrower agrees to pay on demand
all reasonable costs and expenses in connection with the preparation, execution,
delivery, filing, administration and enforcement of this Amendment and any other
documents delivered in connection with or related to this Amendment, including
the reasonable fees and expenses of counsel for the Bank with respect thereto.

SECTION 9.02.  Governing Law.  This Amendment shall be governed by, and
construed and interpreted in accordance with, the laws of the State of New
York.

SECTION 9.03.  Headings.  Section headings in this Amendment are included
herein for convenience of reference only and shall not constitute a part of
this Amendment for any other purpose.

SECTION 9.04. Limitation of Liability. The Declaration of Trust of Northeast
Utilities provides that no shareholder shall be held to any liability whatever
for the payment of any sum of money or for damages or otherwise under any
contract, obligation, or undertaking made, entered into or issued by the
trustees of Northeast Utilities or by any officer, agent or representative
elected or appointed by the trustees, and no such contract, obligation or
undertaking shall be enforceable against the trustees or any of them in their
individual capacities or capacity and all such contracts, obligations and
undertakings shall be enforceable only against the trustees as such, and every
person, firm, association, trust and corporation having any claim or demand
arising out of any such contract, obligation or undertaking shall look only to
the trust estate for the payment or satisfaction thereof.

S - 2

Signature Page to First Amendment

S - 1

Signature Page to First Amendment

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly
executed and delivered by their respective officers hereunto duly authorized as
of the date first above written.

NORTHEAST UTILITIES


By:
Title:


CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY, as Bank and as
Administrative Agent


By
Name:
Title:



BARCLAYS BANK PLC


By
Name:
Title:


THE BANK OF NEW YORK, as Bank and as Documentation Agent


By
Name:
Title:


FLEET NATIONAL BANK, as Syndication Agent


By
Name:
Title:


FLEET NATIONAL BANK, as Trust Administrator for LongLane Master Trust IV, as
Bank


By
Name:
Title:



COMMERZBANK AG


By
Name:
Title:


By
Name:
Title:


HEWLETT-PACKARD MASTER TRUST


By
Name:
Title:



IBM RETIREMENT PLAN


By
Name:
Title:


LUCENT TECHNOLOGIES INC.
MASTER PENSION TRUST


By
Name:
Title:


KZH LANGDALE LLC


By
Name:
Title:


VAN KAMPEN MERRITT PRIME RATE
INCOME TRUST


By
Name:
Title:
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4.2.24.2
<SEQUENCE>4
<FILENAME>0004.txt
<DESCRIPTION>EXHIBIT 4.2.24.2
<TEXT>


                   STANDBY BOND PURCHASE AGREEMENT

                     Dated as of October 24, 2000

                                among

                THE CONNECTICUT LIGHT AND POWER COMPANY,

                       THE PARTICIPATING BANKS

                                and

                       THE BANK OF NEW YORK,

                        as Purchasing Bank

                        THE BANK OF NEW YORK

                        Administrative Agent

                     BNY CAPITAL MARKETS, INC.

                  Lead Arranger and Book Manager









                                TABLE OF CONTENTS

ARTICLE I

DEFINITIONS

Section 1.01 Certain Defined Terms.
Section 1.02 Accounting Terms and Determinations.
Section 1.03 Basis for Ratings.
Section 1.04 Interpretation.

ARTICLE II

standby bond purchase facility

Section 2.01 Purchase of Unremarketed Bonds.
(a) Commitment to Purchase Unremarketed Bonds.
(b) Manner of Purchase.
Section 2.02 Purchased Bonds as Bank Bonds; Bank Rate.
Section 2.03 Redemption of Bank Bonds.
Section 2.04 Remarketing of Bank Bonds.
Section 2.05 Application of Payments on Bank Bonds.
Section 2.06 Repayment and Prepayment of Disbursements.
(a) Scheduled Repayments.
(b) Optional Prepayments.
(c) Mandatory Prepayments.
(d) Transfer of Excess Bank Bonds.
Section 2.07 Interest on Disbursements and Other Amounts.
(a) Interest Rate Options.
(b) Applicable Rates.
(c) Overdue Amounts.
(d) Payment Dates.
Section 2.08 Commitment Fee.
Section 2.09 Computation of Interest and Fees; Maximum
             Interest Rate.
Section 2.10 Reduction or Termination of Commitment.
(a)   Reduction upon Retirement of Bank Bonds.
(b) Reduction upon Conversion of Bank Bonds.
(c) Optional Termination by the Company.
(d) Reduction or Termination of Participation Amounts.
Section 2.11 Basis for Determining Interest Rate
             Inadequate or Unfair.
Section 2.12 Illegality.
Section 2.13 Increased Costs.
Section 2.14 Capital Adequacy.
Section 2.15 Funding Losses.
Section 2.16 Payments.
Section 2.17 Distribution of Payments by the Purchasing Bank.
Section 2.18 Sharing of Recoveries.

ARTICLE III

CONDITIONS PRECEDENT

Section 3.01 Conditions Precedent Subject to Fulfillment on the Closing
             Date.
Section 3.02 Additional Conditions Precedent Subject to Fulfillment on
             the Closing Date.
Section 3.03 Conditions Subject to Fulfillment on Each Purchase Date.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES29
Section 4.01 Organization.
Section 4.02 Authorization.
Section 4.03.Enforceability.
Section 4.04 Approvals.
Section 4.05 Financial Information.
Section 4.06 Litigation.
Section 4.07 Reoffering Circular.
Section 4.08 Environmental Matters.
Section 4.09 Investment Company Act.
Section 4.10 Public Utility.
Section 4.11 All Other Representations and Warranties Accurate.

ARTICLE V

COVENANTS

Section 5.01 Further Assurances.
Section 5.02 Maintenance of Remarketing Agent.
Section 5.03 Amendments to Related Documents.
Section 5.04 Offering Circular.
Section 5.05 Remarketing.
Section 5.06 Substitute Liquidity Facility.
Section 5.07 Remarketing Agent.
Section 5.08 Entry into Conflicting Agreements; Performance of Related
             Documents.
Section 5.09 Financial Statements.
Section 5.10 Certificates; Other Information.
Section 5.11 Payment of Obligations.
Section      5.12 Conduct of Business; Maintenance of Existence; Compliance with
             Obligations and Laws; Merger.
Section 5.13 Maintenance of Property; Insurance.
Section 5.14 Inspection; Books and Records; Discussions.
Section 5.15 Notices.

ARTICLE VI

EVENTS OF DEFAULT; REMEDIES

Section 6.01 Events of Default.
Section 6.02 Remedies.
(a)   Events of Suspension.
(b)   Events of Termination.
(c)   Other Remedies.
(d) Direction by Required Banks.

ARTICLE VII

MISCELLANEOUS
Section 7.01 Amendments, Etc.
Section 7.02 Notices, Etc.
Section 7.03 No Implied Waiver: Remedies Cumulative.
Section 7.04 Indemnification.
Section 7.05 Limitation of Liability.
Section 7.06 Costs, Expenses and Taxes.
Section 7.07 Binding Effect; Assignment; Participations.
Section 7.08 Set-Off.
Section 7.09 Severability.
Section 7.10 Governing Law.
Section 7.11 Jurisdiction; Service of Process;  Waiver of
             Jury Trial.
Section 7.12 Survival of Representations and Warranties.
Section 7.13 Entirety.
Section 7.14 Execution in Counterparts.
Section 7.15 Headings.
Section 7.16 Effectiveness.
Section 7.17 Confidentiality.
Section 7.18 Purchasing Bank's Rights and Responsibilities.
Section 7.19 Reimbursement and Indemnification by
             Participating Banks.
Section 7.20 Participating Banks' Obligations Absolute.
Section 7.21 Beneficiaries.




ANNEX A - Participating Banks, Lending Offices and Notice Addresses EXHIBIT 2.01
- - Form of Purchase Certificate EXHIBIT 2.06 - Form of Notice of Prepayment
EXHIBIT 2.07 - Form of Notice of Interest Rate Election EXHIBIT 2.16 - Form of
Non-US Bank Certificate EXHIBIT 7.07(b) - Form of Joinder Agreement EXHIBIT
7.07(c) - Form of Assignment and Acceptance



STANDBY BOND PURCHASE AGREEMENT

This STANDBY BOND PURCHASE AGREEMENT, dated as of October 24, 2000, among THE
CONNECTICUT LIGHT AND POWER COMPANY, a Connecticut corporation, the
PARTICIPATING BANKS and THE BANK OF NEW YORK, as Purchasing Bank.

W I T N E S S E T H :

WHEREAS, pursuant to the Indenture (such term and all other capitalized terms
used in these recitals having the meanings set forth or referred to in Section
1.01), the Issuer has issued the Bonds;

WHEREAS, the payment of the principal of and interest (at a rate per annum not
in excess of 18 percent) on the Bonds (including Unremarketed Bonds purchased by
the Purchasing Bank pursuant to this Agreement) is insured by the Bond Insurance
Policy issued by the Bond Insurer for the benefit of the holders from time to
time of the Bonds (including the Purchasing Bank);

WHEREAS, in order to provide liquidity support for the Bonds, the Company has
requested the Purchasing Bank to agree to purchase Unremarketed Bonds from time
to time and has requested the Participating Banks to participate in the
Purchasing Bank's obligation to make such purchases, all in accordance with the
terms and conditions hereof; and

WHEREAS, the Purchasing Bank is willing to agree to so purchase Unremarketed
Bonds and the Participating Banks are willing to agree to so participate in such
purchase obligation, all in accordance with the terms and conditions hereof;

NOW, THEREFORE, the parties hereto agree as follows:


ARTICLE I

DEFINITIONS

Section 1.01  Certain Defined Terms.

The following terms, as used herein, have the following meanings:

"Adjusted London Interbank Offered Rate" means, in regards to any Interest
Period, a rate per annum equal to the quotient (rounded upward, if necessary, to
the next higher 1/100 of 1 percent) obtained by dividing (a) the applicable
London Interbank Offered Rate by (b) 1.00 minus the Euro-Dollar Reserve
Percentage. The Adjusted London Interbank Offered Rate shall be adjusted
automatically on and as of the effective date of any change in the Euro-Dollar
Reserve Percentage.

"Affiliate" means, with respect to any Person, any other Person directly or
indirectly controlling (including all directors and officers of such Person),
controlled by, or under direct or indirect common control with, such Person. A
Person shall be deemed to control another entity if such Person possesses,
directly or indirectly, the power to direct or cause the direction of the
management and policies of such entity, whether through the ownership of voting
securities, by contract or otherwise.

"Agreement" means this Standby Bond Purchase Agreement.

"Applicable Law" means (a) all applicable common law and principles of equity
and (b) all applicable provisions of all (i) constitutions, statutes, rules,
regulations and orders of governmental bodies, (ii) Governmental Approvals and
Governmental Registrations and (iii) orders, decisions, judgments and decrees.

"Applicable Lending Office" means, with respect to a Bank, (a) in the case of
its Domestic Disbursement Participations, its Domestic Lending Office and (b) in
the case of its Euro-Dollar Disbursement Participations, its Euro-Dollar Lending
Office.

"Applicable Margin" means, with respect to any Euro-Dollar Disbursement on any
date, (a) for any date occurring prior to the Stated Expiration Date:

(i) if either the Company's senior secured debt or the Bond Insurer's long- term
debt or claims paying ability is rated either A- or higher by S and P or A3 or
higher by Moody's, 0.350 percent per annum;

(ii) if clause (i) does not apply but either the Company's senior secured debt
or the Bond Insurer's long-term debt or claims paying ability is rated either
BBB+ or higher by S and P or Baa1 or higher by Moody's, 0.500 percent per annum;
and

(iii)  if neither clause (i) nor clause (ii) applies, 0.875 percent per
annum; and

(b) for any date occurring on or after the Stated Expiration Date, the rate per
annum that would otherwise be applicable pursuant to clause (a) above plus 0.50
percent.

"Approved Fund" means any Fund that is administered or managed by (a) a Bank,
(b) an Affiliate of a Bank or (c) an entity or an Affiliate of an entity that
administers or manages a Bank.

"Assignment and Acceptance" means an assignment and acceptance agreement in the
form of Exhibit 7.07(c) with such variations as shall be acceptable to the
Persons whose consent is required therefor under Section 7.07(c).

"Available Interest Commitment" means, at any time, (a) the amount of the
Interest Commitment at such time less (b) the aggregate principal amount of
Interest Disbursements outstanding at such time.

"Available Principal Commitment" means, at any time, (a) the amount of the
Principal Commitment at such time less (b) the aggregate principal amount of
Principal Disbursements outstanding at such time.

"Bank Bond" means any Unremarketed Bond or portion thereof purchased by the
Purchasing Bank pursuant to Section 2.01 that has not been (a) resold by the
Purchasing Bank pursuant to Section 2.04, (b) transferred to the Company
pursuant to Section 2.06(d), or (c) redeemed, cancelled, defeased or otherwise
retired in accordance with the Indenture.

"Bank Information" has the meaning assigned to that term in Section 7.04(a).

"Bank Rate" means, for any day, with respect to any Bank Bond, the rate per
annum necessary to produce an interest accrual on such Bank Bond for such day
equal to daily interest at a rate per annum equal to the Base Rate for such day
(or with respect to any overdue amount, the Base Rate for such day plus 2
percent per annum) on an amount equal to the sum of (a) the principal amount of
such Bank Bond as of such date plus (b) the unpaid principal amount as of such
date of any Interest Disbursement made as part of the Purchase Price for such
Bank Bond.

"Banks" means each of the Participating Banks and the Purchasing Bank.

"Base Rate" means, for any day, an interest rate per annum equal to the greater
of (a) the Prime Rate in effect for such day or (b) the sum of the Federal Funds
Rate in effect for such day plus 0.50 percent.

"Bond Documents" means the Bonds, the Indenture, the Loan Agreement and the
Mortgage Bond Documents.

"Bond Insurance Policy" means the municipal bond insurance policy issued by the
Bond Insurer (including any riders and endorsements thereto) with respect to the
Bonds, as such insurance policy may be amended, modified or supplemented from
time to time.

"Bond Insurer" means (a) AMBAC Assurance Corporation, a Wisconsin stock
insurance company, and (b) any other insurance or indemnity company or other
type of financial institution that either replaces AMBAC Assurance Corporation
as "Bond Insurer" under and as defined in the Indenture or is provided as an
additional "Bond Insurer" under and as defined in the Indenture.

"Bond Insurer Event of Insolvency" means the occurrence of one or more of the
following events: (a) the issuance of an order of rehabilitation, liquidation or
dissolution of the Bond Insurer; (b) the commencement by the Bond Insurer of a
voluntary case or other proceeding seeking rehabilitation, dissolution,
liquidation, reorganization or other relief with respect to itself or its debts
under any bankruptcy, insolvency or other similar law now or hereafter in
effect, including the appointment of a trustee, receiver, liquidator, custodian
or other similar official for itself or any substantial part of its property;
(c) the consent of the Bond Insurer to, or the acquiescence by the Bond Insurer
in, any case or proceeding described in the preceding clause (b) that is
commenced against it; (d) the making by the Bond Insurer of a general assignment
for the benefit of creditors; (e) the failure of the Bond Insurer, or the
admission by the Bond Insurer in writing of its inability, generally to pay its
debts or claims as they become due; (f) the initiation by the Bond Insurer of
any action to authorize any of the foregoing; (g) the commencement of an
involuntary case or other proceeding against the Bond Insurer seeking
liquidation, reorganization or other relief with respect to it or its debts
under any bankruptcy, insolvency or other similar law now or hereafter in effect
or seeking the appointment of a trustee, receiver, liquidator, custodian or
other similar official of it or any substantial part of its property, and such
involuntary case remaining undismissed and unstayed for a period of 60 days; or
(h) the entering of an order for relief against the Bond Insurer under the
federal bankruptcy laws as now or hereafter in effect.

"Bond Insurer Potential Insolvency" means any event or condition that would
become a Bond Insurer Event of Insolvency under clause (g) of the definition
thereof after the lapse of the 60-day period referred to in such clause (g).

"Bonds" means the 62,000,000 dollars Pollution Control Revenue Bonds (The
Connecticut Light and Power Company Project - 1996A Series) authorized and
issued pursuant to Section 2.3 of the Indenture. The term "Bonds" includes
Unremarketed Bonds and Bank Bonds.

"Closing Date" means October 24, 2000.

"Code" means the Internal Revenue Code of 1986, as amended.

"Combined Available Commitment" means, on any date, an amount equal to the sum
of (a) the Available Principal Commitment as in effect on such date and (b) the
Available Interest Commitment as in effect on such date.

"Commitment" means, as the context may require, (a) the Principal Commitment and
the Interest Commitment or (b) the Purchasing Bank's obligation to purchase
Unremarketed Bonds pursuant Section 2.01 in amounts limited thereby.

"Commitment Fee Rate" means, for any day:

(a) if either the Company's senior secured debt or the Bond Insurer's long- term
debt or claims paying ability is rated either A- or higher by S and P or A3 or
higher by Moody's, 0.150 percent per annum;

(b) if clause (a) does not apply but either the Company's senior secured debt or
the Bond Insurer's long-term debt or claims paying ability is rated either BBB+
or higher by S and P or Baa1 or higher by Moody's, 0.175 percent per annum; and

(c)  if neither clause (a) nor clause (b) applies, 0.225 percent per annum.

"Commitment Fees" means fees payable pursuant to Section 2.08.

"Commitment Termination Date" means the earliest to occur of the following
dates: (a) the Stated Expiration Date, (b) the date on which the Commitment is
reduced to zero or terminated in accordance with Section 2.10, or (c) the date
on which the Commitment is terminated in accordance with Section 6.02(b).

"Company" means The Connecticut Light and Power Company, a Connecticut
corporation.

"Company Disclosure Documents" means the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1999, the Company's Quarterly Report on
Form 10-Q for the period ended June 30, 2000, and the Company's Current Reports
on Form 8-K dated December 2, 1999 and March 14, 2000.

"Contaminant" means any waste, pollutant, hazardous substance, toxic substance,
hazardous waste, special waste, industrial substance or waste, petroleum or
petroleum-derived substance or waste, or any constituent of any such substance
or waste, including any such substance regulated under any Environmental Law.

"Daily Mode" has the meaning ascribed to such term in the Indenture.

"Default" means any condition or event that constitutes an Event of Default or
that, with the giving of notice or lapse of time or both would, unless cured or
waived, become an Event of Default.

"Disbursement" means an amount transferred by the Purchasing Bank to the Paying
Agent pursuant to Section 2.01(b)(i) for the purpose of paying the Purchase
Price of Unremarketed Bonds. Any amount so transferred shall constitute a
Disbursement regardless of whether such amount is used by the Paying Agent to
purchase Unremarketed Bonds on the specified Purchase Date.

"Disbursement Group" means at any time a group of Disbursements consisting of
(a) all Disbursements that are Domestic Disbursements at such time or (b) all
Disbursements that are Euro-Dollar Disbursements having the same Interest Period
at such time.

"Disbursement Participation" means (a) with respect to the Purchasing Bank, such
Bank's retained interest in a Disbursement and (b) with respect to a
Participating Bank, such Bank's participation interest in such Disbursement.

"Domestic Business Day" means any day except a Saturday, Sunday or other day on
which commercial banks in New York, New York are authorized or required by law
to close.

"Domestic Disbursement" means a Disbursement that bears interest on the basis of
the Base Rate in accordance with Section 2.07(b).

"Domestic Disbursement Participation" means a Disbursement Participation in a
Domestic Disbursement.

"Domestic Lending Office" of any Bank means (a) (i) in the case of the
Purchasing Bank, the Purchasing Bank's office located at One Wall Street, New
York, New York and (ii) in the case of a Participating Bank, the branch or
office of such Bank set forth below such Bank's name under the heading

"Domestic Lending Office" on Annex A or, in the case of a Participating Bank
that became a Participating Bank pursuant to Section 7.07(b) or (c), the branch
or office of such Bank designated as its "Domestic Lending Office" in the
Joinder Agreement or Assignment and Acceptance pursuant to which such Bank
became a Participating Bank or (b) in the case of any Bank, such other branch or
office of such Bank designated by such Bank from time to time as the branch or
office at which its Domestic Disbursement Participations are to be made or
maintained.

"Enacted", as applied to a Regulatory Change, means the date such Regulatory
Change first becomes effective or is implemented or first required or expected
to be complied with, whether the same is (a) the result of an enactment by a
government or any agency or political subdivision thereof, a determination of a
court or regulatory authority, a request or directive of a regulatory authority,
or otherwise or (b) enacted, adopted, issued or proposed before or after the
Closing Date.

"Environmental Laws" means any and all Applicable Laws relating to the
environment or to emissions, discharges or releases of Contaminants into the
environment including, ambient air, surface water, ground water or land, or
otherwise relating to the manufacture, processing, distribution, use, treatment,
storage, disposal, transport or handling of Contaminants or the clean-up or
other remediation thereof.

"Environmental Liabilities and Costs" means all liabilities, obligations,
responsibilities, obligations to conduct Remedial Actions, losses, damages,
punitive damages, consequential damages, treble damages, costs and expenses
(including all reasonable fees, disbursements and expenses of counsel, expert
and consulting fees and costs of investigations and feasibility studies), fines,
penalties, and monetary sanctions, interest, direct or indirect, known or
unknown, absolute or contingent, past, present or future, resulting from any
claim or demand, by any Person, whether based in contract, tort, implied or
express warranty, strict liability, criminal or civil statute, including any
Environmental Law, arising from on-site environmental, health or safety
conditions, or the Release or threatened Release of a Contaminant into the
environment, as a result of past, present or future operations of the Company or
any previous owners or lessees of any of its properties.

"ERISA" means the Employee Retirement Income Security Act of 1974 and the rules
and regulations issued thereunder, as from time to time in effect.

"ERISA Affiliate" means any trade or business (whether or not incorporated) that
is a member of a group of (a) organizations described in Section 414(b) or (c)
of the Code and (b) solely for purposes of potential liability under Section
302(c)(11) of ERISA and Section 412(c)(ii) of the Code and the Lien created
under Section 302(f) of ERISA and under Section 412(n) of the Code,
organizations described in Section 414(m) or (o) of the Code of which the
Company is a member.

"ERISA Termination Event" means, with respect to any Plan, (a) any Reportable
Event with respect to such Plan, (b) the termination of such Plan, or the filing
of notice of intent to terminate such Plan, or the treatment of any amendment to
such Plan as a termination under ERISA Section 4041, (c) the institution of
proceedings to terminate such Plan under ERISA Section 4042 or (d) the
appointment of a trustee to administer such Plan under ERISA Section 4042.

"Euro-Dollar Business Day" means any Domestic Business Day on which commercial
banks are open for international business (including dealings in dollar
deposits) in the London interbank market.

"Euro-Dollar Disbursement" means a Disbursement that bears interest on the basis
of an Adjusted London Interbank Offered Rate in accordance with Section 2.07(b).

"Euro-Dollar Disbursement Participation" means a Disbursement Participation in a
Euro-Dollar Disbursement.

"Euro-Dollar Lending Office" of any Bank means (a) (i) in the case of the
Purchasing Bank, the Purchasing Bank's office located at One Wall Street, New
York, New York and (ii) in the case of a Participating Bank, the branch or
office of such Bank set forth below such Bank's name under the heading "Euro-
Dollar Lending Office" on Annex A or, in the case of a Participating Bank that
became a Participating Bank pursuant to Section 7.07(b) or (c), the branch or
office of such Bank designated as its "Euro-Dollar Lending Office" in the
Joinder Agreement or Assignment and Acceptance pursuant to which such Bank
became a Participating Bank or (b) in the case of any Bank, such other branch or
office of such Bank designated by such Bank from time to time as the branch or
office at which its Euro-Dollar Participations are to be made or maintained.

"Euro-Dollar Reserve Percentage" means for any day that percentage (expressed as
a decimal) which is in effect on such day, as prescribed by the Board of
Governors of the Federal Reserve System (or any successor) for determining the
maximum reserve requirement for a member bank of the Federal Reserve System in
New York City with deposits exceeding five billion dollars in respect of
"Eurocurrency liabilities" (or in respect of any other category of liabilities
that includes deposits by reference to which the interest rate on Euro-Dollar
Disbursements is determined or any category of extensions of credit or other
assets that includes loans by a non-United States office of the Purchasing Bank
to United States residents).

"Event of Default" has the meaning set forth in Section 6.01.

"Event of Suspension" has the meaning set forth in Section 6.02(a).

"Event of Termination" or "event of termination" has the meaning set forth in
Section 6.02(b).

"Federal Funds Rate" means, for any day, the rate per annum (rounded upwards, if
necessary, to the nearest 1/100th of 1 percent) equal to the weighted average of
the rates on overnight Federal funds transactions with members of the Federal
Reserve System arranged by Federal funds brokers on such day, as published by
the Federal Reserve Bank of New York on the Domestic Business Day next
succeeding such day; provided that (a) if such day is not a Domestic Business
Day, the Federal Funds Rate for such day shall be such rate on such transactions
on the next preceding Domestic Business Day as so published on the next
succeeding Domestic Business Day, and (b) if no such rate is so published on
such next succeeding Domestic Business Day, the Federal Funds Rate for such day
shall be the average rate quoted to the Purchasing Bank on such day on such
transactions as determined by the Purchasing Bank.

"First Mortgage Bonds" means the 1996 Series B First Mortgage Bonds issued by
the Company and delivered to the Trustee.

"First Mortgage Indenture" means the Indenture of Mortgage and Deed of Trust,
dated as of May 1, 1921, between the Company and Bankers Trust Company, as
trustee.

"Fixed Rate Mode" has the meaning ascribed to such term in the Indenture.

"Flexible Mode" has the meaning ascribed to such term in the Indenture.

"Fund" means any Person (other than a natural Person) that is (or will be)
engaged in making, purchasing, holding or otherwise investing in commercial
loans and similar extensions of credit in the ordinary of its business.

"GAAP" means generally accepted accounting principles in the United States in
effect from time to time, as applied to a regulated utility.

"Governmental Approval" means any authorization, consent, approval, license (or
the like) or exemption (or the like) of any Governmental Authority.

"Governmental Authority" means any Federal, state, local or foreign court or
governmental agency, authority, instrumentality or regulatory body.

"Governmental Registration" means any registration or filing (or the like) with,
or report or notice (or the like) to, any Governmental Authority.

"Indenture" means the Amended and Restated Indenture of Trust, dated as of May
1, 1996, as amended and restated as of January 1, 1997, between the Issuer and
State Street Bank and Trust Company (successor to Fleet National Bank), as
trustee.

"Interest Commitment" means 918,000 dollars (calculated on the basis of an
assumed rate of 12 percent per annum for 45 days on the initial Principal
Commitment), as such amount may be reduced from time to time pursuant to Section
2.10. Any termination of the Commitment shall be deemed to reduce the Interest
Commitment to zero.

"Interest Disbursement" means a Disbursement made for the purpose of paying that
portion of the Purchase Price for Unremarketed Bonds corresponding to accrued
and unpaid interest thereon.

"Interest Payment Date" means the first day of each month.

"Interest Period" means, with respect to each Euro-Dollar Disbursement, a period
commencing on the date specified in the applicable Notice of Interest Rate
Election and ending one, two, three or six months thereafter, as the Company may
elect in such Notice of Interest Rate Election; provided that (a) any Interest
Period that would otherwise end on a day that is not a Euro- Dollar Business Day
shall be extended to the next succeeding Euro-Dollar Business Day unless such
day falls in another calendar month, in which case such Interest Period shall
end on the next preceding Euro-Dollar Business Day; and (b) any Interest Period
that begins on the last Euro-Dollar Business Day of a calendar month (or on a
day for which there is no numerically corresponding day in the calendar month at
the end of such Interest Period) shall end on the last Euro-Dollar Business Day
of a calendar month.

"Issuer" means the Connecticut Development Authority.

"Joinder Agreement" means a joinder agreement in the form of Exhibit 7.07(b)
with such variations as shall be acceptable to the Persons whose consent is
required therefor under Section 7.07(b).

"Lead Arranger" means BNY Capital Markets, Inc.

"Lien" means any mortgage, pledge, title retention agreement, lien, claim,
charge, encumbrance or security interest.

"Loan Agreement" means the Amended and Restated Loan Agreement, dated as of May
1, 1996, as amended and restated as of January 1, 1997, between the Issuer and
the Company.

"London Interbank Offered Rate" means, in regards to any Interest Period, the
rate per annum (rounded upward, if necessary, to the next higher 1/16 of 1
percent) at which deposits in U.S. dollars are offered to the Purchasing Bank in
the London interbank market at approximately 11:00 a.m. (London time) two
Euro-Dollar Business Days before the first day of such Interest Period in an
amount approximately equal to the principal amount of the Euro-Dollar
Disbursement to which such Interest Period is to apply and for a period of time
comparable to such Interest Period.

"Materially Adverse Effect" means, relative to any occurrence of whatever nature
(including any adverse determination in any litigation, arbitration, or
governmental investigation or proceeding), a materially adverse effect on (a)
the consolidated business, assets, revenues, financial condition, results of
operations, operations, or prospects of the Company and its Subsidiaries; (b)
the ability of the Company to make any payment when due under this Agreement or
to perform any of its other obligations hereunder or under the Related
Documents; or (c) the legality, validity, binding nature or enforceability of
this Agreement or any of the Related Documents.

"Maximum Interest Rate" means, with respect to interest payable on any amount,
the rate of interest on such amount that, if exceeded, could, under Applicable
Law, result in (a) civil or criminal penalties being imposed upon the payee or
(b) the payee's being unable to enforce payment of (or, if collected, retain)
all or any part of such amount or the interest payable thereon.

"Moody's" means Moody's Investors Service, Inc.

"Mortgage Bond Documents" means the First Mortgage Bonds, the First Mortgage
Indenture (to the extent relating to the issuance of the First Mortgage Bonds)
and any supplemental indenture or indentures pursuant to which the Company
creates, issues and delivers to the Trustee its First Mortgage Bonds.

"Multiannual Mode" has the meaning ascribed to such term in the Indenture.

"Multiemployer Plan" means a multiemployer plan as defined in Section 4001(a)(3)
of ERISA to which the Company or any ERISA Affiliate is making or accruing an
obligation to make contributions, or has within any of the preceding five plan
years made or accrued an obligation to make contributions.

"Non-US Bank" means a Person that is not a United States Person and that is not
described in Section 881(c)(3) of the Code.

"Non-US Bank Certificate" means a certificate in the form of Exhibit 2.16.

"Notice of Interest Rate Election" means a notice in the form of Exhibit 2.07.

"Notice of Prepayment" means a notice in the form of Exhibit 2.06.

"NU" means Northeast Utilities.

"Offering Circular" means any offering circular or other document (whether
preliminary or final) used in connection with the offering and sale or the
re-offering and re-sale or remarketing of the Bonds, including the Reoffering
Circular.

"Parent" means, with respect to a Bank, any Person controlling such Bank.

"Participating Bank" means (a) any Person listed on Annex A and (b) any Person
that is granted a Participation Interest by the Purchasing Bank pursuant to
Section 7.07(b) or is assigned a Participation Interest by a Participating Bank
pursuant to Section 7.07(c).

"Participation Amount" of any Participating Bank means the amount set forth
opposite such Participating Bank's name under the heading "Participation Amount"
on Annex A or, in the case of a Participating Bank that became a Participating
Bank pursuant to Section 7.07(b) or (c), the Participation Amount granted or
assigned to such Participating Bank, in any case, as the same may be reduced
from time to time pursuant to Section 2.10(d) or reduced or increased from time
to time pursuant to assignments in accordance with Section 7.07(c).

"Participation Interests" means, with respect to a Participating Bank, such
Participating Bank's participation interests in the Commitment and outstanding
Disbursements.

"Participation Share" means, at any time, (a) so long as the Commitment has not
expired or been terminated, (i) with respect to the Purchasing Bank, the
percentage equivalent of a fraction, the numerator of which shall be the amount
of the Commitment at such time reduced by the sum of all of the Participating
Banks' Participation Amounts at such time and the denominator of which shall be
the amount of the Commitment at such time, and (ii) with respect to a
Participating Bank, the percentage equivalent of a fraction, the numerator of
which shall be such Participating Bank's Participation Amount at such time and
the denominator of which shall be the amount of the Commitment at such time, and
(b) at any time after the Commitment has expired or been terminated, (i) with
respect to the Purchasing Bank, the percentage equivalent of a fraction, the
numerator of which shall be the amount of the aggregate principal amount of
outstanding Disbursements at such time reduced by the sum of all of the
Participating Banks' Participation Interests in the principal of outstanding
Disbursements at such time and the denominator of which shall be the aggregate
principal amount of outstanding Disbursements at such time, and (ii) with
respect to a Participating Bank, the percentage equivalent of a fraction, the
numerator of which shall be the aggregate amount of such Participating Bank's
Participation Interests in the principal of outstanding Disbursements at such
time and the denominator of which shall be the amount of the aggregate principal
amount of Disbursements at such time.

"Paying Agent" has the meaning ascribed to such term in the Indenture.

"PBGC" means the Pension Benefit Guaranty Corporation or any Person succeeding
to any or all of its functions under ERISA.

"Person" means an individual, a corporation, a partnership, a limited liability
company, an association, a trust or any other entity or organization, including
a government or political subdivision or an agency or instrumentality thereof.

"Plan" means any employee pension benefit plan (other than a Multiemployer Plan)
subject to the provisions of Title IV of ERISA that is maintained for current or
former employees, or any beneficiaries thereof, of the Company or any ERISA
Affiliate.

"Prime Rate" means the rate of interest publicly announced by The Bank of New
York in New York City from time to time as its prime commercial lending rate
(which rate is a reference rate and not necessarily the lowest rate of interest
charged by The Bank of New York to its prime customers).

"Principal Commitment" means 62,000,000 dollars, as such amount may be reduced
from time to time pursuant to Section 2.10. Any termination of the Commitment
shall be deemed to reduce the Principal Commitment to zero.

"Principal Disbursement" means a Disbursement made for the purpose of paying
that portion of the Purchase Price for Unremarketed Bonds corresponding to the
principal amount thereof.

"Purchase Certificate" means a certificate in the form of Exhibit 2.01.

"Purchase Date" means each date fixed for the purchase of Bonds by the
Purchasing Bank in accordance with the terms of the Indenture.

"Purchase Price" has the meaning assigned to that term in Section 2.01(a)(i).

"Purchasing Bank" means The Bank of New York.

"Register" has the meaning assigned to that term in Section 7.07(d).

"Regulatory Change" means any Applicable Law, interpretation, directive,
determination, request or guideline (whether or not having the force of law), or
any change therein or in the administration or enforcement thereof, that is
Enacted after the Closing Date, including any such that imposes, increases or
modifies any Tax, reserve requirement, insurance charge, special deposit
requirement, assessment or capital adequacy requirement, or determines that the
Commitment does not constitute commitments with an original maturity of one year
or less, but excluding any such that imposes, increases or modifies any Tax on
the overall net income of a Bank.

"Related Documents" means the Bond Documents, the Bond Insurance Policy, the
Remarketing Agreement and the Tax Regulatory Agreement.

"Release" means any release, spill, emission, leaking, pumping, injection,
deposit, disposal, discharge, disbursal, leeching or migration into the indoor
or outdoor environment or into or out of any property owned by the Company or
any of its Subsidiaries, including the movement of Contaminants through or in
the air, soil, surface water, ground water or property.

"Remarketing Agent" has the meaning ascribed to such term in the Indenture.

"Remarketing Agreement" means the Remarketing Agent's Agreement, dated as of May
1, 1996, among the Issuer, the Company and the Lead Arranger (as successor
Remarketing Agent to Goldman, Sachs and Co.) or any successor remarketing
agreement or agreements entered into in connection with the Bonds in accordance
herewith and with the Indenture.

"Remedial Action" means all actions required to (a) clean up, remove, treat or
in any other way adjust Contaminants in the indoor or outdoor environment; (b)
prevent the Release or threat of Release or minimize the further Release of
Contaminants so that they do not migrate or endanger or threaten to endanger
public health or welfare or the indoor or outdoor environment; or (c) perform
pre-remedial studies and investigations and post-remedial monitoring and care.

"Reoffering Circular" means the Reoffering Circular of the Company, dated
January 20, 1997, including documents incorporated therein by reference, used in
connection with the reoffering of the Bonds, and any supplement thereto used
with respect to the Bonds.

"Reportable Event" means any reportable event as defined in Section 4043(c) of
ERISA or the regulations issued thereunder with respect to a Plan (other than a
Plan maintained by an ERISA Affiliate that is considered an ERISA Affiliate only
pursuant to subsection (m) or (o) of Code Section 414) requiring notice to PBGC
under applicable regulations.

"Required Banks" means, at any time, Banks the aggregate of whose Participation
Shares at such time exceeds 50 percent.

"S and P" means Standard and Poor's Ratings Services (a division of The
McGraw-Hill Companies, Inc.).

"SG Bond Purchase Agreement" means that Standby Bond Purchase Agreement, dated
January 23, 1997, among The Connecticut Light and Power Company, Societe
Generale, New York Branch, as bank, and Fleet National Bank, as trustee.

"Stated Expiration Date" means October 23, 2001.

"Subparticipant" has the meaning assigned to that term in Section 7.07(c)

"Subsidiary" means, as to any Person, any corporation, association, partnership,
joint venture or other business entity of which such Person or any Subsidiary of
such Person, directly or indirectly, either (a) in respect of a corporation,
owns or controls more than 50 percent of the outstanding stock having ordinary
voting power to elect a majority of the board of directors or similar managing
body of such corporation, irrespective of whether a class or classes shall or
might have voting power by reason of the happening of any contingency, or (b) in
respect of an association, partnership, joint venture or other business entity,
is entitled to share in more than 50 percent of the profits and losses, however
determined of such entity.

"Tax" means any Federal, State or foreign tax, assessment, or other charge
imposed by a Governmental Authority upon a Person or upon its assets, revenues,
income or profits.

"Tax Regulatory Agreement" means the Tax Regulatory Agreement, dated as of the
date of initial issuance and delivery of the Bonds, among the Issuer, the
Company and the Trustee.

"Trustee" has the meaning ascribed to such term in the Indenture.

"United States" means the United States of America, including the States and the
District of Columbia, but excluding its territories and possessions.

"United States Person" means a corporation, partnership or other entity created,
organized or incorporated under the laws of the United States of America or a
State thereof (including the District of Columbia).

"Unremarketed Bonds" means Bonds in Daily, Weekly or Flexible Mode that are
tendered or deemed tendered for purchase pursuant to the provisions of the
Indenture and for which remarketing proceeds have not been received by the
Remarketing Agent.

"Weekly Mode" has the meaning ascribed to such term in the Indenture.

"Welfare Plan" means a "welfare plan", as such term is defined in Section 3(1)
of ERISA.

"Withdrawal Liability" means liability to a Multiemployer Plan as a result of a
complete or partial withdrawal from such Multiemployer Plan, as such terms are
defined in Part I of Subtitle E of Title IV of ERISA.

Section 1.02  Accounting Terms and Determinations.

Except as otherwise expressly provided herein, all terms of an accounting or
financial nature shall be construed in accordance with GAAP.

Section 1.03  Basis for Ratings.

Except with respect to the ratings assigned to the Bonds, the Company's senior
secured debt or the Bond Insurer's claims-paying ability, references herein to
credit ratings are to ratings assigned to unsecured obligations without third
party credit support. Except as aforesaid, ratings assigned to any obligation
that is secured or that has the benefit of third party credit support shall be
disregarded. For purposes hereof, the rating in effect on any date is that in
effect on the close of business on such date.

Section 1.04  Interpretation.

(a) Except as otherwise specified herein, all references herein (i) to any
Person shall be deemed to include such Person's successors and assigns, (ii) to
any Applicable Law defined or referred to herein shall be deemed references to
such Applicable Law or any successor Applicable Law as the same may have been or
may be amended or supplemented from time to time and (iii) to any agreement or
contract defined or referred to herein shall be deemed references to such
agreement or contract (and, in the case of any instrument, any instrument issued
in substitution therefor) as the terms thereof may have been or may be amended,
supplemented, waived or otherwise modified from time to time.

(b) When used in this Agreement, the words "herein", "hereof" and "hereunder"
and words of similar import shall refer to this Agreement as a whole and not to
any provision of this Agreement, and the words "Article", "Section", "Annex",
"Schedule" and "Exhibit" shall refer to Articles and Sections of, and Annexes,
Schedules and Exhibits to, this Agreement unless otherwise specified.

(c) Whenever the context so requires, the neuter gender includes the masculine
or feminine, the masculine gender includes the feminine, and the singular number
includes the plural, and vice versa.

(d) Any item or list of items set forth following the word "including",
"include" or "includes" is set forth only for the purpose of indicating that,
regardless of whatever other items are in the category in which such item or
items are "included", such item or items are in such category, and shall not be
construed as indicating that the items in the category in which such item or
items are "included" are limited to such items or to items similar to such
items.

(e) Each authorization in favor of a Bank or any other Person granted by or
pursuant to this Agreement shall be deemed to be irrevocable and coupled with an
interest.

(f) Except as otherwise specified herein, all references to the time of day
shall be deemed to be to New York City time as then in effect.

ARTICLE II

standby bond purchase facility

Section 2.01  Purchase of Unremarketed Bonds.

(a)  Commitment to Purchase Unremarketed Bonds.

(i) Subject to the terms and conditions of this Agreement, the Purchasing Bank
agrees to purchase Unremarketed Bonds on any Domestic Business Day prior to the
Commitment Termination Date at a price (the "Purchase Price") equal to 100
percent of the principal amount thereof plus (if such Purchase Date is not a day
on which interest is payable on such Unremarketed Bonds) accrued interest, if
any, to such Purchase Date; provided, however, that (A) the aggregate Purchase
Price payable by the Purchasing Bank on any Purchase Date shall not exceed (x)
with respect to the portion of such aggregate Purchase Price corresponding to
principal of the Unremarketed Bonds to be purchased, the Available Principal
Commitment as in effect on such Purchase Date and (y) with respect to the
portion of such aggregate Purchase Price corresponding to accrued interest on
the Unremarketed Bonds to be purchased, the Available Interest Commitment as in
effect on such Purchase Date; and (B) Unremarketed Bonds that are held by or for
the account of the Company, any Affiliate of the Company or any broker-dealer
holding Unremarketed Bonds pursuant to an arrangement with the Company or any
Affiliate of the Company shall not be purchased by the Purchasing Bank
hereunder.

(ii) Each Participating Bank shall have a participation interest in the
Commitment and each Disbursement made pursuant thereto, to the extent of such
Bank's Participation Share thereof. The Purchasing Bank shall remain solely
responsible to the Company, the Paying Agent, the Trustee and the holders of the
Bonds for the performance of the entire Commitment notwithstanding such grant of
participation interests to the Participating Banks, and its obligations to such
Persons hereunder shall be undiminished thereby.

(b)  Manner of Purchase.

(i) If the Purchasing Bank receives a Purchase Certificate from the Paying Agent
no later than (x) 12:30 p.m. on the specified Purchase Date, in the case of
Unremarketed Bonds that are in the Weekly Mode, or (y) 1:00 p.m. on the
specified Purchase Date, in the case of Unremarketed Bonds that are in the Daily
Mode or in the Flexible Mode, the Purchasing Bank will, subject to satisfaction
of the other terms and conditions set forth in this Agreement, transfer not
later than 3:00 p.m. on such Purchase Date to the Paying Agent, in funds to be
available as specified in such Purchase Certificate, an amount equal to the
aggregate Purchase Price for such Unremarketed Bonds. The Purchasing Bank agrees
to use its own funds to purchase Unremarketed Bonds.

(ii) Upon receiving a Purchase Certificate from the Paying Agent, the Purchasing
Bank shall promptly give each Participating Bank telephonic notice (confirmed in
writing) of (A) the applicable Purchase Date, (B) the aggregate amount of
Disbursements to be made on such date and (C) such Participating Bank's
Participation Share of such aggregate amount of Disbursements. Each
Participating Bank shall pay to the Purchasing Bank such Participating Bank's
Participation Share of the Disbursements to be made on the specified Purchase
Date no later than (A) 3:00 p.m. on the date such notice is given to such Bank
(or, if later, the specified Purchase Date) if such notice is given by 1:30 p.m.
on any Domestic Business Day, or (B) 12:00 p.m. on the Domestic Business Day
following the date such notice is given to such Bank if such notice is given
after 1:30 p.m. on any Domestic Business Day on or after the specified Purchase
Date. If a Participating Bank should for any reason not make any payment to the
Purchasing Bank hereunder on the date such payment is due, the Purchasing Bank
shall be entitled to recover from such Participating Bank such amounts, plus
interest thereon from and including the date such payment was due to but
excluding the day such amounts are recovered by the Purchasing Bank at the
Federal Funds Rate until (and including) the third Domestic Business Day after
the date due and thereafter at the Base Rate plus 2 percent.

Section 2.02  Purchased Bonds as Bank Bonds; Bank Rate.

Pursuant to Section 2.3(G)(9) of the Indenture, Unremarketed Bonds purchased by
the Purchasing Bank pursuant to Section 2.01 shall constitute Bank Bonds and
shall bear interest on the unpaid principal amount thereof at the Bank Rate.
Interest on Bank Bonds shall be payable monthly in arrears on each Interest
Payment Date (or, in the event that the maturity of the Bonds shall have been
accelerated in accordance with the terms of the Bond Documents, payable on
demand by the Purchasing Bank). As provided in Sections 2.3(G)(9) and 9.10(4) of
the Indenture, Bank Bonds shall be held in trust by the Paying Agent for the
benefit of the Purchasing Bank.

Section 2.03  Redemption of Bank Bonds.

(a) Bank Bonds shall be subject to mandatory and optional redemption as provided
in Sections 2.4(A), (C), (D) and (G)(ii) of the Indenture and, as permitted by
Section 2.4(G)(i) of the Indenture, shall also be subject to mandatory
redemption as provided in Section 2.03(b) and (c).

(b) The Bank Bonds outstanding on the Stated Expiration Date shall be redeemed
in ten consecutive semi-annual installments of equal principal amount,
commencing on the date six months after the Stated Expiration Date, at a price
equal to the principal amount thereof plus accrued and unpaid interest at the
Bank Rate to but excluding the date of redemption. If, after the Stated
Expiration Date, any Bank Bonds are otherwise redeemed or cease to be Bank Bonds
as a result of being remarketed or purchased by the Company, the remaining
redemption installments shall be reduced in inverse order of their maturity.

(c) Upon receipt by the Trustee of a demand by the Purchasing Bank in accordance
with clause (iii) of the second sentence of Section 6.02(b), all outstanding
Bank Bonds shall be immediately redeemed at a price equal to the principal
amount thereof plus accrued and unpaid interest at the Bank Rate to but
excluding the date of redemption.

Section 2.04  Remarketing of Bank Bonds.

(a) In accordance with Section 9.19 of the Indenture, the Remarketing Agent
shall solicit offers to purchase and use its best efforts to find a purchaser
for Bank Bonds; provided, however, that Bank Bonds shall not be released by the
Paying Agent unless and until the Purchasing Bank has been paid the principal of
and interest accrued on such Bonds at the Bank Rate.

(b) Notwithstanding the foregoing, no Bank Bonds shall be remarketed after the
Commitment Termination Date or the date, if any, on which the maturity of the
Bonds shall have been accelerated in accordance with the terms of the Bond
Documents, unless the purchaser of such Bonds shall have acknowledged, in a
manner reasonably satisfactory to the Purchasing Bank, that such Bonds shall not
be entitled to the benefits of this Agreement.

Section 2.05  Application of Payments on Bank Bonds.

Payments received by the Purchasing Bank in respect of the principal of or
interest on Bank Bonds (whether pursuant to a scheduled payment thereof, upon
redemption or acceleration, upon purchase of Bank Bonds pursuant to a
remarketing thereof or substitution of another liquidity facility, or otherwise)
shall be applied as follows:

(a) Payments in respect of principal of Bank Bonds shall be applied to the
payment of the Principal Disbursements.

(b) Payments in respect of interest accrued on Bank Bonds at the time of their
purchase by the Purchasing Bank shall be applied to the payment of Interest
Disbursements.

(c) Payments in respect of interest accruing on Bank Bonds after their purchase
by the Purchasing Bank shall be applied in the following order of priorities:
first to the payment of accrued and unpaid interest on the Disbursements,
second, to the payment of accrued and unpaid fees and expenses payable to the
Banks hereunder, and third, to the Company (or if such payment shall have been
made by the Bond Insurer pursuant to the Bond Insurance Policy, to the Bond
Insurer).

Section 2.06  Repayment and Prepayment of Disbursements.

(a)  Scheduled Repayments.

(i)  Interest Disbursements.

The Company shall repay in full the Interest Disbursements made on any Purchase
Date on the first Interest Payment Date following such Purchase Date.

(ii)  Principal Disbursements.

The Company shall repay the aggregate amount of Principal Disbursements
remaining outstanding on the Stated Expiration Date in ten equal consecutive
semi-annual installments commencing on the date six months after such date.
Additional amounts of Principal Disbursements paid or prepaid after the Stated
Expiration Date shall be applied to the remaining installments in inverse order
of maturity.

(b)  Optional Prepayments.

The Company may, at any time and from time to time, prepay the Disbursements in
whole or in part, without premium or penalty, except that any optional partial
prepayment shall be in an aggregate principal amount of 1,000,000 dollars or any
multiple of 100,000 dollars in excess thereof. Any prepayment of Euro-Dollar
Disbursements made on a day other than the last day of the applicable Interest
Periods therefor shall be accompanied by the amount, if any, required to be paid
in respect thereof pursuant to Section 2.15. The Company shall give the
Purchasing Bank a Notice of Prepayment no later than 11:00 a.m. on, in the case
of a prepayment of Domestic Disbursements, the Domestic Business Day before the
date of such prepayment and, in the case of a prepayment of Euro-Dollar
Disbursements, the third Euro-Dollar Business Day before the date of such
prepayment. Each Notice of Prepayment shall specify (i) the date such prepayment
is to be made, (ii) the Disbursements to be prepaid (whether Domestic
Disbursements or Euro-Dollar Disbursements and, in the case of Euro-Dollar
Disbursements, the last day of the applicable Interest Periods for such
Disbursements) and (iii) for each such Disbursement, the amount thereof to be
prepaid. Amounts to be so prepaid shall irrevocably be due and payable on the
date specified in the applicable Notice of Prepayment, together with interest
accrued thereon to but excluding the date of prepayment. The Purchasing Bank
shall give each Participating Bank prompt notice of each Notice of Prepayment
that it receives and the amounts of such Participating Bank's Participation
Interests in Disbursements affected thereby.

(c)  Mandatory Prepayments.

(i)

If at any time the aggregate principal amount of outstanding Principal
Disbursements shall exceed the aggregate principal amount of Bank Bonds, the
Company shall, upon demand by the Purchasing Bank, immediately prepay Principal
Disbursements to such extent. If at any time the amount of any outstanding
Interest Disbursement made in connection with the purchase of an Unremarketed
Bond shall exceed the amount of interest accrued on such Bank Bond at the time
of its purchase that then remains unpaid, the Company shall, upon demand by the
Purchasing Bank, immediately prepay such Interest Disbursement to such extent.

(ii)

On each date that Bank Bonds are required to be redeemed pursuant to Section
2.03(A), (C), (D) or G(ii) of the Indenture or Section 2.03(c), the Company
shall prepay (A) Principal Disbursements in an aggregate principal amount equal
to the aggregate amount of Bank Bonds required to be redeemed and (B) to the
extent not previously paid, the full amount of all Interest Disbursements, if
any, made by the Purchasing Bank as part of the Purchase Price for such Bonds.

(iii)

Without duplication of other payments or prepayments required under this Section
2.06, on each date that any payments are received by the Purchasing Bank in
respect of principal of Bank Bonds or interest accrued on Bank Bonds at the time
of their purchase by the Purchasing Bank, Disbursements shall be prepaid through
the application of such payments as provided in Section 2.05.

(d)  Transfer of Excess Bank Bonds.

If at any time the aggregate principal amount of Bank Bonds shall exceed the
aggregate principal amount of outstanding Principal Disbursements (as a result
of a prepayment pursuant to Section 2.06(b) or otherwise), the Bank shall, upon
request of the Company, transfer to the Company Bank Bonds in an aggregate
principal amount equal to such excess.

Section 2.07  Interest on Disbursements and Other Amounts.

(a)  Interest Rate Options.

(i)

All Disbursements made by the Purchasing Bank on any Purchase Date shall
initially be Domestic Disbursements. Thereafter, the Company may from time to
time elect to change or continue the type of interest rate borne by each
Disbursement Group (subject in each case to the provisions of Sections 2.11 and
2.12), as follows:

(A) if such Disbursements are Domestic Disbursements, the Company may elect to
convert such Disbursements to Euro-Dollar Disbursements as of any Euro-Dollar
Business Day; and

(B) if such Disbursements are Euro-Dollar Disbursements, the Company may elect
to convert such Disbursements to Domestic Disbursements or elect to continue
such Disbursements as Euro-Dollar Disbursements for an additional Interest
Period, in each case effective on the last day of the then current Interest
Period applicable to such Disbursements.

(ii)

Each such election shall be made by delivering a Notice of Interest Rate
Election to the Purchasing Bank no later than 11:00 a.m. on the third Euro-
Dollar Business Day before the conversion or continuation selected in such
notice is to be effective. A Notice of Interest Rate Election may, if it so
specifies, apply to only a portion of the aggregate principal amount of the
relevant Disbursement Group; provided that the portion to which such Notice of
Interest Rate Election applies, and the remaining portion to which it does not
apply, are each at least 3,000,000 dollars.

(iii)

Each Notice of Interest Rate Election shall specify (A) the Disbursement Group
(or portion thereof) to which such notice applies; (B) the date on which the
conversion or continuation selected in such notice is to be effective, which
shall comply with the applicable clause of subsection (i) above; (C) if the
Disbursements comprising such Disbursement Group are to be converted, the new
type of Disbursements (i.e. Domestic or Euro-Dollar) and, if such new
Disbursements are Euro-Dollar Disbursements, the duration of the initial
Interest Period applicable thereto; and (D) if such Disbursements are to be
continued as Euro-Dollar Disbursements for an additional Interest Period, the
duration of such additional Interest Period. Each Interest Period specified in a
Notice of Interest Rate Election shall comply with the provisions of the
definition of Interest Period.

(iv)

A Notice of Interest Rate Election is nonrevocable by the Company. If the
Company fails to deliver a timely Notice of Interest Rate Election to the
Purchasing Bank for any Disbursement Group of Euro-Dollar Disbursements, such
Disbursements shall be converted into Domestic Disbursements on the last day of
the then current Interest Period applicable thereto.

(v)

The Purchasing Bank shall give each Participating Bank prompt notice of each
Notice of Interest Rate Election that it receives and the amounts of such
Participating Bank's Participation Interests in Disbursements affected thereby.

(vi)

Notwithstanding anything herein to the contrary, (A) the Company may not elect
to convert a Domestic Disbursement to a Euro-Dollar Disbursement or continue a
Euro-Dollar Disbursement as a Euro-Dollar Disbursement for another Interest
Period at any time that a Default shall have occurred and be continuing, and (B)
the Company shall convert and continue Disbursements in a manner such that no
payment of Euro-Dollar Disbursements will have to be made prior to the last day
of an applicable Interest Period in order to repay the Disbursements in the
amounts and on the dates specified in Section 2.06(a).

(b)  Applicable Rates.

(i) Subject to Section 2.07(c), each Domestic Disbursement shall bear interest
on the outstanding principal amount thereof, for each day from and including the
date such Disbursement is made to but excluding the date such Disbursement is
required to be repaid hereunder, at a rate per annum equal to the Base Rate for
such day.

(ii) Subject to Section 2.07(c), each Euro-Dollar Disbursement shall bear
interest on the outstanding principal amount thereof, for each day during each
Interest Period applicable thereto, at a rate per annum equal to the sum of the
Applicable Margin for such day plus the Adjusted London Interbank Offered Rate
applicable to such Interest Period.

(c)  Overdue Amounts.

Any overdue principal of, or interest on, any Disbursement and any other amount
payable hereunder that is not paid when due, whether at stated maturity or
otherwise, shall bear interest, from the date the same becomes due until such
amount is paid in full, at a rate per annum equal to 2 percent over the Base
Rate as in effect from time to time (except that an overdue amount of principal
of a Euro-Dollar Disbursement that becomes due prior to the last day of an
applicable Interest Period shall bear interest at a rate per annum equal to 2
percent above the rate that would otherwise be applicable to such Disbursement
until the last day of such Interest Period and at a rate per annum equal to 2
percent over the Base Rate in effect from time to time thereafter).

(d)  Payment Dates.

Interest on Disbursements shall be payable (i) on each Interest Payment Date,
(ii) at the time of any payment or prepayment of Disbursements to the extent
accrued on the amount paid or prepaid and (iii) at such other times as required
by Section 2.05(c). Notwithstanding the foregoing, interest on overdue amounts
(including overdue amounts of Disbursements) shall be payable on demand.

Section 2.08  Commitment Fee.

The Company shall pay to the Purchasing Bank a commitment fee at a per annum
rate for each day equal to the Commitment Fee Rate for such day on the Combined
Available Commitment at the close of business on such day. Such commitment fee
shall accrue from and including the Closing Date to but excluding the Commitment
Termination Date. Fees accrued under this Section shall be payable (i) quarterly
in arrears on each March 31, June 30, September 30 and December 31 (commencing
on December 31, 2000) and (ii) on the Commitment Termination Date. If the
Commitment is reduced pursuant to Section 2.10, all fees accrued under this
Section to but excluding the effective date of such reduction with respect to
portion of the Combined Available Commitment eliminated by such reduction shall
be payable on such date.

Section 2.09 Computation of Interest and Fees; Maximum Interest Rate. (a)
Interest based on the Prime Rate shall be computed on the basis of a year of 365
days (or 366 days in a leap year) and paid for the actual number of days elapsed
(including the first day but excluding the last day). All other interest and all
fees shall be computed on the basis of a year of 360 days and paid for the
actual number of days elapsed (including the first day but excluding the last
day).

(b) The Purchasing Bank shall determine each interest rate applicable hereunder.
The Purchasing Bank shall give prompt notice to the Company and the
Participating Banks of each rate of interest so determined, and its
determination thereof shall be conclusive in the absence of manifest error.

(c) Nothing contained herein shall require the payment of interest on Bank Bonds
or Disbursements at a rate exceeding the Maximum Interest Rate. If interest
payable on any Bank Bond or Disbursement for any period would otherwise exceed
the maximum amount permitted by the Maximum Interest Rate, such interest payment
shall automatically be reduced to such maximum permitted amount, and interest on
other Bank Bonds or Disbursements (as the case may be) for such period and/or
interest on all Bank Bonds or Disbursements (as the case may be) for subsequent
periods, to the extent less than the maximum amount permitted by the Maximum
Interest Rate, shall be increased to permit payment of such reduction at the
earliest possible date.

Section 2.10  Reduction or Termination of Commitment.

(a)  Reduction upon Retirement of Bank Bonds.

In the event of any redemption, cancellation, defeasance, or any other
retirement of any Bonds, the Company shall have the right to reduce the
Principal Commitment by an amount equal to the principal amount of Bonds so
redeemed, canceled, defeased, or otherwise retired, by giving to the Purchasing
Bank written notice of such reduction (which notice shall state the amount of
such reduction and the date or dates of such redemption, purchase and
cancellation, defeasance, or other retirement).

(b)  Reduction upon Conversion of Bank Bonds.

Any time after the close of business on the fifth Domestic Business Day
following the date on which Bonds are converted to Fixed Rate Mode or
Multiannual Mode (but prior, in the case of Bonds converted to Multiannual Mode,
to any date on which the Company gives notice of its intent to convert such
Bonds to Daily, Weekly or Flexible Mode), the Company shall have the right to
reduce the Principal Commitment by an amount equal to the principal amount of
Bonds so converted, by giving to the Purchasing Bank written notice of such
reduction (which notice shall state the amount of such reduction and the date or
dates of such conversion).

(c)  Optional Termination by the Company.

(i)

The Company shall have the right to terminate the Commitment at any time upon 30
days' written notice to the Purchasing Bank, the Bond Insurer, the Trustee, the
Paying Agent and the Remarketing Agent; provided, however, that in connection
with any such termination the Company shall pay to the Banks any and all amounts
then accrued or owing to the Banks under this Agreement and there shall be
purchased from the Purchasing Bank all Bank Bonds, together with accrued
interest thereon.

(ii)

In the event that (A) the Purchasing Bank shall fail to purchase Unremarketed
Bonds when required under the terms or conditions of this Agreement or (B)
bankruptcy, insolvency, receivership, liquidation or other similar proceedings
are instituted against the Purchasing Bank, the Company shall have the right to
immediately terminate the Commitment upon written notice to the Purchasing Bank,
the Bond Insurer, the Trustee, the Paying Agent and the Remarketing Agent;
provided, however, that in connection with any such termination the Company
shall pay to the Banks any and all amounts then accrued or owing to the Banks
under this Agreement and there shall be purchased from the Purchasing Bank all
Bank Bonds, together with accrued interest thereon.

(d)  Reduction or Termination of Participation Amounts.

Upon any reduction or termination of the Commitment, the Participation Amounts
of all Participating Banks shall automatically be reduce proportionately or
terminated, as the case may be. The Purchasing Bank shall give each
Participating Bank prompt notice of any notice of Commitment reduction or
termination that it receives pursuant to this Section 2.10 and, in the case of a
reduction, the amount of the reduction of such Participating Bank's
Participation Amount.

Section 2.11  Basis for Determining Interest Rate Inadequate or Unfair.

If prior to the first day of any Interest Period for any Disbursement Group of
Euro-Dollar Disbursements, (a) the Purchasing Bank determines that for any
reason appropriate information is not available to it for purposes of
determining the Adjusted London Interbank Rate for such Interest Period or (b)
the Required Banks determine that the Adjusted London Interbank Offered Rate
will not adequately and fairly reflect the cost to them of funding their
Euro-Dollar Disbursement Participations for such Interest Period, the Purchasing
Bank shall forthwith give notice thereof to the Company, whereupon until the
Purchasing Bank notifies the Company that the circumstances giving rise to such
suspension no longer exist, the obligations of the Purchasing Bank to make or
continue Euro-Dollar Disbursements or to convert outstanding Domestic
Disbursements into Euro-Dollar Disbursements shall be suspended and each
outstanding Euro-Dollar Disbursement shall be converted into a Domestic
Disbursement on the last day of the then current Interest Period applicable
thereto.

Section 2.12  Illegality.

If, on or after the date of this Agreement, the adoption of any Applicable Law,
or any change in any Applicable Law, or any change in the interpretation or
administration thereof by any Governmental Authority charged with the
interpretation or administration thereof, or compliance by a Bank (or its
Euro-Dollar Lending Office) with any request or directive (whether or not having
the force of law) of any such Governmental Authority, shall restrict the ability
of such Bank (or its Euro-Dollar Lending Office) to make, maintain or fund its
Euro-Dollar Disbursement Participations (or, in the case of the Purchasing Bank,
the Euro-Dollar Disbursements), such Bank shall forthwith give notice thereof to
the Company and the Purchasing Bank, whereupon until such Bank notifies the
Company and the Purchasing Bank that the circumstances giving rise to such
suspension no longer exist, the obligation of the Purchasing Bank to continue
Euro-Dollar Disbursements as Euro-Dollar Disbursements for additional Interest
Periods or to convert outstanding Domestic Disbursements into Euro-Dollar
Disbursements shall be suspended. Before giving any notice pursuant to this
Section 2.12, the affected Bank shall designate a different Euro-Dollar Lending
Office if such designation will avoid the need for giving such notice and will
not, in the judgment of such Bank, be otherwise disadvantageous to such Bank. If
such notice is given, each Euro-Dollar Disbursement then outstanding shall be
converted to a Domestic Disbursement either (a) on the last day of the then
current Interest Period applicable to each Euro-Dollar Disbursement
Participation if the affected Bank may lawfully continue to maintain and fund
Euro-Dollar Disbursement Participations to such day or (b) immediately if the
affected Bank shall determine that it may not lawfully continue to maintain and
fund Euro-Dollar Disbursement Participations to such day.

Section 2.13  Increased Costs.

If, in the determination of any Bank, an Regulatory Change Enacted on or after
the date of this Agreement:

(a) shall subject such Bank (or its Applicable Lending Office) to any tax, duty
or other charge with respect to Bank Bonds, Disbursements or Disbursement
Participations or its obligation to purchase and hold Bank Bonds or make or
maintain Disbursements or Disbursement Participations or shall change the basis
of taxation of payments to such Bank (or its Applicable Lending Office) of the
principal of or interest on Disbursements or Disbursement Participations or any
other amounts due under this Agreement in respect of Disbursements or
Disbursement Participations or its obligation to purchase and hold Bank Bonds or
make or maintain Disbursements or Disbursement Participations (except for
changes in the rate of tax on the overall net income of such Bank or its
Applicable Lending Office imposed by the jurisdiction in which such Bank's
principal executive office or Applicable Lending Office is located, including
under United States federal, home state and home locality income tax laws); or

(b) shall impose, modify or deem applicable any reserve (including any such
requirement imposed by the Board of Governors of the Federal Reserve System, but
excluding any such requirement included in an applicable Euro-Dollar Reserve
Percentage), special deposit, insurance assessment or similar requirement
against assets of, deposits with or for the account of, or credit extended by,
such Bank (or its Applicable Lending Office) or shall impose on such Bank (or
its Applicable Lending Office) or on the London interbank market any other
condition affecting Bank Bonds, Disbursements or Disbursement Participations or
its obligation to purchase and hold Bank Bonds or make or maintain Disbursements
or Disbursement Participations, as the case may be;

and the result of any of the foregoing is to increase the cost to such Bank (or
its Applicable Lending Office) of purchasing or holding Bank Bonds or making or
maintaining any Disbursements or Disbursement Participations or to reduce the
amount of any sum received or receivable by such Bank (or its Applicable Lending
Office) under this Agreement, by an amount deemed by such Bank to be material,
then, within 30 days after demand by such Bank, the Company shall pay to such
Bank such additional amount or amounts as will compensate such Bank for such
increased cost or reduction. Such Bank will promptly notify the Company of any
event of which it has knowledge, occurring after the date hereof, which will
entitle such Bank to compensation pursuant to this Section 2.13 and will
designate a different Applicable Lending Office if such designation will avoid
the need for, or reduce the amount of, such compensation and will not, in the
judgment of such Bank, be otherwise disadvantageous to such Bank. A certificate
of such Bank claiming compensation under this Section 2.13 and setting forth in
reasonable detail the additional amount or amounts to be paid to it hereunder,
which shall be based on such estimates, assumptions, allocations and the like
that such Bank shall in good faith determine to be appropriate, shall be
conclusive in the absence of manifest error. In determining such amount, such
Bank may use any reasonable averaging and attribution methods.

Section 2.14  Capital Adequacy.

If, in the determination of any Bank, an Regulatory Change Enacted on or after
the date of this Agreement has or would have the effect of reducing the rate of
return on capital of such Bank (or its Parent) as a consequence of such Bank's
obligations hereunder to a level below that which such Bank (or its Parent)
could have achieved but for such Regulatory Change (taking into consideration
its policies with respect to capital adequacy) by an amount deemed by such Bank
to be material, then from time to time, within 30 days after demand by such
Bank, the Company shall pay to such Bank such additional amount or amounts as
will compensate such Bank (or its Parent) for such reduction. Such Bank will
promptly notify the Company of any event of which it has knowledge, occurring
after the date hereof, which will entitle such Bank to compensation pursuant to
this Section 2.14 and will designate a different Applicable Lending Office if
such designation will avoid the need for, or reduce the amount of, such
compensation and will not, in the judgment of such Bank, be otherwise
disadvantageous to such Bank. A certificate of such Bank claiming compensation
under this Section 2.14 and setting forth in reasonable detail the additional
amount or amounts to be paid to it hereunder, which shall be based on such
estimates, assumptions, allocations and the like that such Bank shall in good
faith determine to be appropriate, shall be conclusive in the absence of
manifest error. In determining such amount, such Bank may use any reasonable
averaging and attribution methods.

Section 2.15  Funding Losses.

If any payment of principal with respect to any Euro-Dollar Disbursement is made
or any Euro-Dollar Disbursement is converted to a Domestic Disbursement on any
day other than the last day of the Interest Period applicable to such
Euro-Dollar Disbursement (pursuant to Section 2.06(a), (b) or (c), Section 2.12,
or otherwise), the Company shall reimburse each Bank within 15 days after demand
for any resulting loss or expense incurred by such Bank, including any loss
incurred as a result of a decline in the London Interbank Offered Rate since the
rate for such Euro-Dollar Disbursement was set for such Interest Period, but
excluding loss of margin for the period after any such payment or conversion;
provided that such Bank shall have delivered to the Company a certificate
setting forth in reasonable detail the amount of such loss or expense, which
shall be based on such estimates, assumptions, allocations and the like that
such Bank shall in good faith determine to be appropriate, which certificate
shall be conclusive in the absence of manifest error.

Section 2.16  Payments.

(a) All amounts payable to a Bank hereunder shall be paid, in Federal or other
immediately available funds, to such Bank at its Domestic Lending Office or at
such other address as such Bank may designate by notice to the Company. Amounts
payable to a Bank in respect of Euro-Dollar Disbursement Participations (or, the
case of the Purchasing Bank, Euro-Dollar Disbursements) shall be payable for the
account of such Bank's Eurodollar Lending Office; amounts payable to a Bank in
respect of Domestic Disbursement Participations (or, the case of the Purchasing
Bank, Domestic Disbursements) shall be payable for the account of such Bank's
Domestic Lending Office.

(b)  All amounts payable by the Company to a Bank hereunder shall be paid not
later than 3:00 p.m. on the date when due.  Any payment by the Company
received by a Bank after 3:00 p.m. shall be deemed to be received on the
following Domestic Business Day.

(c) Whenever any amount payable to a Bank hereunder is due on a day that is not
a Domestic Business Day, the date for payment thereof shall be extended to the
next succeeding Domestic Business Day. If the date for any payment is extended
by operation of law or otherwise, such payment shall bear interest for such
extended time at the rate of interest applicable hereunder.

(d)  (i)

All amounts payable by the Company to a Bank hereunder shall be paid without any
reduction or deduction whatsoever, including any reduction or deduction for any
set-off, recoupment, counterclaim or Tax, except for Taxes required by
Applicable Law to be withheld or deducted. If any Taxes are required to be
withheld or deducted from any such payment, the Company shall pay to the
applicable Bank the amount that, after deduction from such increased amount of
all Taxes required to be withheld or deducted therefrom, will yield to such Bank
the amount stated to be payable hereunder. Notwithstanding the foregoing, the
Company shall not be required to pay any increased amounts pursuant to this
Section 2.16(d) on account of Taxes measured by or based upon the overall net
income of a Bank. The Company will execute and deliver to the affected Bank at
its request such further instruments as may be necessary or desirable to give
full force and effect to any such increase. The Company will, upon the request
of an affected Bank, provide such Bank with evidence satisfactory to it of the
payment of any Taxes. If any Taxes required to be borne by the Company pursuant
to this Section 2.16(d) are paid by a Bank, the Company will, upon demand of
such Bank, reimburse such Bank for such payments, together with any interest,
penalties and expenses in connection therewith.

(ii)

Notwithstanding anything to the contrary contained herein, the Company shall not
be required to pay any additional amount in respect of withholding of United
States Federal income taxes pursuant to Section 2.16(d)(i) to any Bank except
(A) in the case of a Person that is a Bank on the Closing Date, to the extent
such Taxes are required to be withheld as a result of a Regulatory Change
Enacted after the Closing Date and (B) in the case of a Person that becomes a
Bank after the Closing Date, to the extent (1) such Taxes are required to be
withheld as a result of a Regulatory Change Enacted after the date such Person
becomes a Bank or (2) such additional amount would have been payable had such
Person not become a Bank; provided, however, that the Company shall not be
required to pay any additional amount in respect of withholding of United States
Federal income taxes pursuant to Section 2.16(d)(i) to the extent such
withholding is required because such Bank has failed to submit any form or
certificate that it is entitled to so submit under Applicable Law.

(iii)

There shall be submitted to the Company and the Purchasing Bank, (A) on or
before the first date that interest or fees are payable to the such
Participating Bank hereunder, (1) if at the time the same are applicable, (aa)
by each Participating Bank that is not a United States Person, two duly
completed and signed copies of Internal Revenue Service Form W-8BEN or W-8ECI
(or successor forms), in either case entitling such Participating Bank to a
complete exemption from withholding of any United States federal income taxes on
all amounts to be received by such Participating Bank hereunder, or (bb) by each
Participating Bank that is a Non-US Bank and the Issuing Bank if it is a Non-US
Bank, (x) a duly completed Internal Revenue Service Form W-8BEN (or successor
form) and (y) a Non-US Bank Certificate or (2) if at the time any of the
foregoing are inapplicable, duly completed and signed copies of such form, if
any, as entitles such Participating Bank to exemption from withholding of United
States federal income taxes to the maximum extent to which such Participating
Bank is then entitled under Applicable Law, and (B) from time to time
thereafter, prior to the expiration or obsolescence of any previously delivered
form or upon any previously delivered form becoming inaccurate or inapplicable,
such further duly completed and signed copies of such form, if any, as entitles
such Participating Bank to exemption from withholding of United States Federal
income taxes to the maximum extent to which such Person is then entitled under
Applicable Law. Each Participating Bank shall promptly notify the Company and
the Purchasing Bank if (A) it is required to withdraw or cancel any form or
certificate previously submitted by it or any such form or certificate has
otherwise become ineffective or inaccurate or (B) payments to it are or will be
subject to withholding of United States Federal income taxes to a greater extent
than the extent to which payments to it were previously subject. Upon the
request of the Company or the Purchasing Bank, each Participating Bank that is a
United States Person shall from time to time submit to the Company and the
Purchasing Bank a certificate to the effect that it is such a United States
Person and a duly completed Internal Revenue Service Form W-9 (or successor
form).

Section 2.17  Distribution of Payments by the Purchasing Bank.

(a) When, if and to the extent that the Purchasing Bank receives (from the
Company, the Bond Insurer, the Paying Agent, the Trustee or any other Person
obligated with respect to the Disbursements, by exercise of any right of set-
off, counterclaim or banker's lien, or otherwise) a payment or prepayment in
respect of (i) the principal of or interest on the Disbursements or interest on
overdue amounts thereof or (ii) Commitment Fees or interest on overdue amounts
thereof, the Purchasing Bank shall promptly pay to each Participating Bank such
Participating Bank's Participation Share of such payment; provided, however,
that a Bank to which the Purchasing Bank grants a participation in the
Commitment and any outstanding Disbursements after the Closing Date shall not be
entitled to any payment on account of Commitment Fees or interest on
Disbursements with respect to such participation to the extent such amounts are
payable for any period prior to the date such participation was granted. Except
for amounts explicitly set forth herein, no Participating Bank shall be entitled
to share in or receive any fee or other payment to which the Purchasing Bank may
be entitled, or which it has received or may receive, in respect of this
Agreement.

(b) If the Purchasing Bank should for any reason make any payment to a
Participating Bank in anticipation of the receipt of funds from the Company, the
Bond Insurer, any other Person obligated with respect to the Disbursements and
such funds are not received by the Purchasing Bank from the Company, the Bond
Insurer or such Person on the date payment is due, or such payment is in excess
of the amount due such Participating Bank hereunder, then such Participating
Bank shall, upon request by the Purchasing Bank, forthwith return to the
Purchasing Bank any such amounts transferred to such Participating Bank by the
Purchasing Bank, plus interest thereon from and including the day such amounts
were transferred by the Purchasing Bank to such Participating Bank to but
excluding the day such amounts are returned by such Participating Bank at a per
annum rate (calculated on the basis of a 360 day year) equal to the Federal
Funds Rate.

(c) If the Purchasing Bank is required at any time to return pursuant to any
bankruptcy, insolvency, liquidation or reorganization law, or any sharing clause
herein or in any of the Related Documents or otherwise, any portion of the
payments made by the Company, the Bond Insurer or any other Person obligated
with respect to any of the Disbursements or otherwise received by the Purchasing
Bank and paid to the Participating Banks, each Participating Bank shall, on
demand of the Purchasing Bank, forthwith return to the Purchasing Bank any such
amounts received by such Participating Bank, but without interest thereon unless
the Purchasing Bank is required to pay interest on such amounts to the person
recovering such payment, in which case with interest thereon, computed at the
same rate, and on the same basis, as the interest that the Purchasing Bank is
required to pay.

Section 2.18  Sharing of Recoveries.

If a Participating Bank receives (from the Company, the Bond Insurer, the Paying
Agent, the Trustee or any other Person obligated with respect to the
Disbursements, by exercise of any right of set-off, counterclaim or banker's
lien, or otherwise) any payment on account of its Participation Interests in
excess of such Participating Bank's Participation Share of such amount, such
Participating Bank shall promptly deliver such excess to the Purchasing Bank. If
such Participating Bank is required at any time to return, pursuant to any
bankruptcy, insolvency, liquidation or reorganization law or otherwise, any
portion of the amounts referred to in the preceding sentence, the Purchasing
Bank shall, on demand of such Participating Bank, return to such Participating
Bank such excess (or the appropriate portion of such excess) received by the
Purchasing Bank (and, to the extent paid by the Purchasing Bank to other
Participating Banks, as received from such other Participating Banks), but
without interest thereon unless such Participating Bank is required to pay
interest on such excess (or such portion) to the Person recovering such payment,
in which case with interest thereon, computed at the same rate, and on the same
basis, as the interest that such Participating Bank is required to pay.


ARTICLE III

CONDITIONS PRECEDENT

Section 3.01  Conditions Precedent Subject to Fulfillment on the Closing
Date.

The obligation of the Purchasing Bank to purchase Unremarketed Bonds pursuant to
this Agreement is subject to the condition precedent that the Banks shall have
received on or before the Closing Date the following, each in form and substance
satisfactory to the Banks and counsel for the Purchasing Bank:

(a)  This Agreement, duly executed on behalf of the Company.

(b) (i) Counterparts (or certified copies thereof) of each of the Related
Documents (other than the Bonds and the First Mortgage Bonds) that, when taken
together, bear the signatures of all of the respective parties thereto and that
are in full force and effect in accordance with their respective terms and are
satisfactory to the Purchasing Bank in form and substance and (ii) a specimen of
each Bond and First Mortgage Bond.

(c)  A copy of the Reoffering Circular, certified to be a true copy by an
officer of the Company.

(d) A certificate of the secretary or an assistant secretary of the Company,
certifying the names and true signatures of the officers of the Company
authorized to execute on behalf of the Company this Agreement and the Related
Documents to which the Company is a party.

(e) Evidence that all necessary action required to be taken by (i) the Issuer
(including the adoption or enactment by the Issuer of all necessary resolutions
and ordinances) and (ii) any Governmental Authority, in connection with the
authorization, execution, issuance, delivery and performance of this Agreement
and the Related Documents, and any other document or instrument required to be
delivered pursuant hereto or thereto or in connection with the transactions
contemplated hereby or thereby, has been taken.

(f) Evidence that, as of the Closing Date, all conditions contained in the
Indenture and the Loan Agreement for the replacement of the SG Bond Purchase
Agreement with this Agreement have been satisfied.

(g) A copy of the Bond Insurance Policy which shall provide that it insures all
principal of and interest (at a rate per annum not in excess of 18 percent per
annum) when due on the Bonds (including payment of interest on Bank Bonds at the
Bank Rate and payment of principal of and accrued interest on Bank Bonds upon
any redemption provided for herein or in the Indenture), executed by the Bond
Insurer, together with evidence satisfactory to the Purchasing Bank that such
Bond Insurance Policy is in full force and effect and is non-cancelable and that
all premiums required to be paid thereunder have been paid in full.

(h) Legal opinions of (i) Day, Berry and Howard LLP, as special counsel to the
Company, (ii) Jeffrey C. Miller, Assistant General Counsel of Northeast
Utilities Service Company, (iii) counsel to the Bond Insurer satisfactory to the
Purchasing Bank, and (iv) Winthrop, Stimson, Putnam and Roberts, counsel to the
Purchasing Bank, in each case, as to such matters incident to this Agreement,
the Related Documents and the transactions contemplated hereby and thereby as
the Purchasing Bank shall have reasonably requested.

(i) Evidence of the power and authority of the Trustee and the Paying Agent to
accept and execute their respective responsibilities under the Indenture.

(j) An executed copy of each document, instrument, certificate and opinion
delivered pursuant to the Indenture.

(k) Such other documents, instruments, opinions and approvals (and, if requested
by any Bank, certified duplicates or executed copies thereof) as any Bank shall
have reasonably requested.

Section 3.02  Additional Conditions Precedent Subject to Fulfillment on the
Closing Date.

The obligation of the Purchasing Bank to purchase Unremarketed Bonds pursuant to
this Agreement is subject to the further conditions precedent that on the
Closing Date:

(a) The following statements shall be true and shall be deemed to have been
represented by the Company as being true on and as of the Closing Date, and each
Bank shall have received a certificate of the Company signed by an authorized
officer dated the Closing Date, stating that, to the best of such authorized
officer's knowledge after due inquiry:

(i) The representations and warranties of the Company contained in Article IV
are true and correct in all material respects on and as of the Closing Date as
though made on and as of the Closing Date; and

(ii) No event has occurred and is continuing, or would result from the
effectiveness of this Agreement, that constitutes a Default.

(b) Each Bank shall have received payment in full of all fees and other sums
required to be paid to or for the account of such Bank on or prior to the
Closing Date.

Section 3.03  Conditions Subject to Fulfillment on Each Purchase Date.

The obligation of the Purchasing Bank to purchase Unremarketed Bonds pursuant to
this Agreement on each Purchase Date shall be subject to the fulfillment of the
following conditions precedent on and as of such Purchase Date:

(a)

The Purchasing Bank shall have received a duly completed Purchase Certificate
for the purchase of such Unremarketed Bonds on such Purchase Date in accordance
with Section 2.01(b)(i).

(b)

The Unremarketed Bonds to be so purchased are not held by or for the account of
the Company, any Affiliate of the Company or any broker-dealer holding
Unremarketed Bonds pursuant to an arrangement with the Company or any Affiliate
of the Company.

(c)

No Event of Suspension shall have occurred and be continuing.

(d)

The amount being demanded for payment by the Purchasing Bank under Section 2.01
does not exceed the Combined Available Commitment on such Purchase Date (prior
to giving effect to such payment).

(e)

The Commitment Termination Date shall not have occurred.
Notwithstanding the foregoing, if the condition set forth in clause (b) above is
satisfied for some but not all of the Unremarketed Bonds covered by a Purchase
Certificate, then, provided that all of the other conditions to purchase have
been satisfied, the Purchasing Bank shall be obligated to purchase so much of
such Unremarketed Bonds for which the condition set forth in clause (b) is
satisfied.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES

In order to induce each Bank to enter into and perform its obligations under
this Agreement, the Company hereby represents and warrants as follows:

Section 4.01  Organization.

The Company is duly organized, validly existing and in good standing under the
laws of the State of Connecticut, and has all requisite corporate power and
authority to own or lease its properties and to conduct its business as now
conducted and as proposed to be conducted, and is duly qualified and authorized
to engage in business as a public utility in the State of Connecticut.

Section 4.02  Authorization.

The execution, delivery and performance by the Company of this Agreement and the
Related Documents to which it is a party are within the Company's corporate
powers, have been duly authorized by all necessary corporate action, and (a) do
not contravene, violate or breach: (i) Applicable Law; (ii) the Certificate of
Incorporation or By-laws of the Company; or (iii) any indenture, mortgage, loan
agreement or other contract or instrument to which the Company is a party or by
which it or its assets are bound; and (b) do not result in or require the
creation of any Lien except as provided in or contemplated by this Agreement or
the Related Documents upon or with respect to any of the Company's properties.

Section 4.03  Enforceability.

This Agreement is, and the Related Documents to which the Company is a party
are, legal, valid and binding obligations of the Company, enforceable against
the Company in accordance with their respective terms, except as enforceability
may be limited by applicable bankruptcy, insolvency, reorganization, moratorium
or similar Applicable Laws affecting the enforcement of creditors' rights
generally and by general equitable principles (whether enforcement is sought by
proceedings in equity or at law).

Section 4.04  Approvals.

No authorization of, approval or other action by, and no notice to or filing
with, any Governmental Authority is required for the due execution, delivery and
performance by the Company of this Agreement or any Related Document, except
those that have been, or will be simultaneously with the execution hereof, duly
obtained or made and are in full force and effect.

Section 4.05  Financial Information.

(a) The audited balance sheet of the Company as at December 31, 1999, and the
audited statements of income and cash flows of the Company for the fiscal year
then ended as set forth in the Company's Annual Report on Form 10-K for such
fiscal year and (b) the unaudited balance sheet of the Company as at June 30,
2000 and the unaudited statements of income and cash flows of the Company for
the six-month period then ended as set forth in the Company's Quarterly Report
on Form 10-Q for the period then ended, fairly present in all material respects
the financial condition and results of operations of the Company at and for the
respective periods ended on such dates, and have been prepared in accordance
with GAAP, consistently applied. Since December 31, 1999, there has been no
material adverse change in the financial condition, operations, properties or
prospects of the Company and its Subsidiaries, taken as a whole, except to the
extent, if any, described in the Company Disclosure Documents.

Section 4.06  Litigation.

Except for any pending or threatened action, suit, investigation or proceeding
as disclosed in the Company Disclosure Documents or otherwise disclosed to the
Banks in writing prior to the date hereof (as to which no representation or
warranty is being made), there is no action, suit or proceeding (or to the best
knowledge of the Company, investigation) pending or, to the best knowledge of
the Company, threatened (a) in connection with this Agreement or any of the
transactions contemplated by this Agreement or the Related Documents, or (b)
against or affecting the Company, the result of which is reasonably likely to
have a Materially Adverse Effect.

Section 4.07    Reoffering Circular.

Except for information contained in the Reoffering Circular describing any Bank,
the Issuer, the Bond Insurer or The Depository Trust Company, as to which no
representation or warranty is made, (a) the Reoffering Circular as of its issue
date was, and any supplement or amendment thereto will be, accurate in all
material respects for the purposes for which their use is or shall be
authorized, and (b) the Reoffering Circular as of its issue date did not, and
any such supplement or amendment will not, contain any untrue statement of a
material fact or omit to state any material fact necessary to make the
statements made therein, in the light of the circumstances under which they are
or were made, not misleading.

Section 4.08  Environmental Matters.

Except as disclosed or for matters identified in the Company Disclosure
Documents (as to which no representation or warranty is made):

(a) The operations of the Company comply in all respects with all applicable
Environmental Laws concerning environmental health and safety except where the
failure to comply would not have a Materially Adverse Effect;

(b) The Company has obtained or made timely application for all environmental,
health and safety permits necessary for its operation. All such permits
previously obtained are in effect or timely application for renewal thereof is
pending, and no action to revoke the same is pending and the period to appeal
such permits have expired, and the Company is in compliance with all terms and
conditions of such permits except where the failure to comply would not have a
Materially Adverse Effect;

(c) With respect to property currently or formerly owned or operated by it, the
Company is not (at the time of ownership or operation) subject to any
outstanding written notice or order from, or agreement with, any Governmental
Authority or other Person in respect to which the Company (i) is required to
take any Remedial Action that would or might reasonably be expected to have a
Materially Adverse Effect or (ii) would be reasonably likely to be required to
incur any Environmental Liabilities and Costs arising from the Release or
threatened Release of a Contaminant into the environment that would or might
reasonably be expected to result in a Materially Adverse Effect;

(d) The Company has not received written notification pursuant to Environmental
Laws that any of its current or past operations, or any by- product thereof, is
related to or subject to any investigation by any Governmental Authority
evaluating whether any Remedial Action is needed to respond to a Release or
threatened Release of a Contaminant into the environment, which investigation is
reasonably likely to lead to the Company having to take Remedial Action, or
having to incur Environmental Liabilities and Costs, in each case which would
have a Materially Adverse Effect; and

(e) The Company has not filed any notice under any applicable Environmental Law
reporting a Release of a Contaminant into the environment that is reasonably
likely to lead to any Governmental Authority or any other Person having to take
Remedial Action or having to incur Environmental Liabilities and Costs, that
would have a Materially Adverse Effect.

Section 4.09  Investment Company Act.

The Company is not an "investment company", or a company "controlled by an
investment company" within the meaning of the Investment Company Act of 1940.

Section 4.10  Public Utility.

All outstanding shares of capital stock having ordinary voting power for the
election of directors of the Company have been validly issued, are fully paid
and nonassessable, and are owned beneficially by NU, free and clear of any Lien.
NU is a "holding company" (as defined in the Public Utility Holding Company Act
of 1935, as amended (the "1935 Act")). Except for the post- closing filing on
Form U-6B-2 required to be made with the Securities and Exchange Commission
pursuant to the 1935 Act, the Company is not required to obtain any consents or
make any filings pursuant to the 1935 Act in order to execute, deliver and
perform this Agreement or any of the Related Documents to which it is a party.

Section 4.11  All Other Representations and Warranties Accurate.

All representations and warranties made by the Company in any of the Related
Documents are true and correct in all material respects at and as of the date
hereof, except that any such representations and warranties that expressly speak
of a particular date were true and correct in all material respects as of such
date.

ARTICLE V

COVENANTS

So long as the Purchasing Bank has any Commitment hereunder, any Disbursements
shall remain outstanding, or any other amount shall be accrued or owing to the
Banks hereunder:

Section 5.01  Further Assurances.

The Company will, to the extent permitted by Applicable Law, execute,
acknowledge where appropriate, and deliver or file, and cause to be executed,
acknowledged where appropriate, and delivered or filed, from time to time
promptly at the request of the Purchasing Bank or the Required Banks, all such
instruments and documents as are reasonably necessary or advisable to carry out
the intent and purpose of this Agreement and the Related Documents.

Section 5.02  Maintenance of Remarketing Agent.

The Company will maintain in place a Remarketing Agent in accordance with the
provisions of the Indenture.

Section 5.03  Amendments to Related Documents.

Without the prior written consent of the Purchasing Bank and the Required Banks,
the Company shall not enter into or consent to any amendment, modification or
termination of any Related Document, except (a) as may be required to comply
with applicable law, (b) as necessary to obtain a credit rating on the Bonds by
S and P, Moody's or any other rating agency then rating the Bonds, or (c) for
amendments that would not affect the rights and obligations of the Banks under
such Related Document. With respect to any amendment to any Related Document of
the type described in clause (a), (b) or (c) of the preceding sentence, each
Bank hereby agrees that it shall cooperate with the Company in delivering its
consent which may nevertheless be required under such Related Document; provided
that no Bank shall be required to deliver any such consent with respect to any
amendment that it determines would be materially adverse to its interests.
Notwithstanding anything to the contrary contained herein or in the Related
Documents, the Company shall not agree to surrender, amend or modify the Bond
Insurance Policy or to release or substitute the Bond Insurer thereunder.

Section 5.04  Offering Circular.

The Company will not include, or permit to be included, any information,
material or reference relating to any Bank in any Offering Circular or any
tombstone advertisement, unless such information, material or reference is
approved in writing by such Bank prior to its inclusion therein, and the Company
will not distribute or use, or permit to be distributed or used, any Offering
Circular unless copies of such Offering Circular are furnished to such Bank
prior to the distribution or use thereof. The Banks will use all reasonable
efforts to respond to any request for such approval in a timely fashion.

Section 5.05  Remarketing.

The Company will not permit the Remarketing Agent to remarket any Bonds at a
price less than the principal amount thereof plus accrued interest, if any,
thereon to the respective dates of remarketing.

Section 5.06  Substitute Liquidity Facility.

The Company will not substitute another liquidity facility for the obligations
of the Purchasing Bank to purchase Unremarketed Bonds pursuant to this Agreement
unless prior to or simultaneously with such substitution, there shall be
purchased from the Purchasing Bank, at a price not less than the principal
amount thereof plus accrued interest, if any, thereon to the date of purchase,
all Bank Bonds purchased pursuant to this Agreement and the Company shall have
paid to the Banks any and all amounts accrued or owing to the Banks under this
Agreement (after giving effect to the application of the proceeds of the Bank
Bonds in accordance with Section 2.05 of this Agreement).

Section 5.07  Remarketing Agent.

Without the prior written approval of the Purchasing Bank and the Required Banks
(which approval shall not be unreasonably withheld), the Company will not (a)
appoint or permit or suffer to be appointed any successor Remarketing Agent
unless the successor Remarketing Agent is a nationally recognized remarketing
agent for municipal obligations, or (b) enter into any successor Remarketing
Agreement that contains provisions (including provisions that protect the rights
and interests of the Banks) that are not substantially (other than the identity
of the successor Remarketing Agent and fees payable thereunder) the same in all
respects material, in the judgment of the Purchasing Bank and the Required
Banks, to the interests of the Banks as those contained in the predecessor
Remarketing Agreement. The Company shall provide to the Banks a copy of such
successor Remarketing Agreement promptly upon execution and delivery thereof.

Section 5.08  Entry into Conflicting Agreements; Performance of Related
Documents.

(a) The Company will not enter into any agreement containing any provision that
would be violated or breached by the performance by the Company of its
obligations hereunder or under the Related Documents.

(b) The Company will punctually pay or cause to be paid when due all amounts
payable by it under the Loan Agreement, the First Mortgage Bonds and the other
Related Documents and observe and perform all of the conditions, covenants and
requirements of the Loan Agreement, the First Mortgage Bonds and the other
Related Documents applicable to it.

Section 5.09  Financial Statements.

The Company will furnish to the Banks:

(a) as soon as available and in any event within 105 days after the end of each
fiscal year of the Company, a copy of the Company's report on Form 10-K
submitted to the Securities and Exchange Commission with respect to such fiscal
year, or, if the Company ceases to be required to submit such report, a copy of
the annual audit report for such year for the Company including therein a
consolidated balance sheet of the Company as of the end of such fiscal year and
consolidated statements of income and retained earnings and of cash flows of the
Company for such fiscal year, all in reasonable detail and certified by (i) a
nationally-recognized independent public accountant and (ii) by the Chief
Financial Officer, Treasurer, Assistant Treasurer or Comptroller of the Company
as having been prepared in accordance with GAAP applied consistently with those
financial statements referred to in Section 4.05; and

(b) as soon as available and in any event within 60 days after the end of each
of the first three fiscal quarters of each fiscal year of the Company, a copy of
the Company's Quarterly Report on Form 10-Q submitted to the Securities and
Exchange Commission with respect to such quarter, or if the Company ceases to be
required to submit such report, a consolidated balance sheet of the Company as
of the end of such fiscal quarter and consolidated statements of income and
retained earnings and of cash flows of the Company for the period commencing at
the end of the previous fiscal year and ending with the end of such fiscal
quarter, all in reasonable detail and duly certified (subject to year-end audit
adjustments) by the Chief Financial Officer, Treasurer, Assistant Treasurer or
Comptroller of the Company as having been prepared in accordance with GAAP
applied consistently with those financial statements referred to in Section
4.05.

Section 5.10  Certificates; Other Information.

The Company will furnish to the Banks:

(a) concurrently with the delivery of the financial statements referred to in
Section 5.09(a) above, a certificate of the independent certified public
accountants reporting on such financial statements stating that in making the
examination necessary therefor no knowledge was obtained of any Default, except
as specified in such certificate;

(b) concurrently with the delivery of the financial statements referred to in
Sections 5.09(a) and (b), a certificate of an authorized officer stating that,
to the best of such officer's knowledge, the Company during such period has in
all material respects observed or performed all of its covenants and other
agreements, and satisfied every condition, contained in this Agreement and the
Related Documents to be observed, performed or satisfied by it, and that such
officer has obtained no knowledge of any Default, in each case except as
specified in such certificate;

(c) promptly after the filing thereof, copies of each prospectus (excluding any
prospectus contained in any Form S-8), and Current Report on Form 8-K, if any,
that the Company files with, the Securities and Exchange Commission or any
governmental authority which may be substituted therefor; and

(d) promptly, such additional financial and other information as any Bank may
from time to time reasonably request.

Section 5.11  Payment of Obligations.

The Company shall pay, discharge or otherwise satisfy at or before maturity or
before they become delinquent, as the case may be, all Taxes imposed on it or
its income, profits or revenues or any of its properties, except when the amount
or validity thereof is currently being contested in good faith by appropriate
proceedings and reserves in conformity with GAAP with respect thereto have been
provided on the books of the Company.

Section 5.12 Conduct of Business; Maintenance of Existence; Compliance with
Obligations and Laws; Merger.

(a) The Company shall, except to the extent such failure would not, in the
aggregate, have a Materially Adverse Effect, (i) continue to engage in business
as a public utility under the laws of the State of Connecticut, (ii) preserve,
renew and keep in full force and effect its corporate existence and take all
reasonable action to maintain all rights, licenses, approvals, privileges and
franchises necessary or desirable in the normal conduct of its business, except
as otherwise permitted by Section 5.12(b) or 5.13, and (iii) comply with all of
its contractual obligations and all Applicable Law.

(b) Nothing contained in this Agreement shall prevent any lawful consolidation
or merger of the Company with or into any other corporation or corporations
lawfully authorized to acquire and operate the properties of the Company, or a
series of consolidations or mergers, in which the Company or its successor or
successors shall be a party, or any sale of all or substantially all of the
properties of the Company as an entirety to a corporation lawfully authorized to
acquire and operate the same; provided that (i) upon any such consolidation,
merger or sale, the corporation formed by such consolidation, or into which such
merger may be made, or making such purchase shall execute and deliver to the
Banks an instrument, in form and substance reasonably satisfactory to the
Purchasing Bank and the Required Banks, whereby such corporation shall
effectively assume the due and punctual payment of any amounts due hereunder and
the due and punctual performance and observance of all covenants and agreements
to be performed by the Company pursuant to this Agreement; and (ii) immediately
after such consolidation, merger or sale no Event of Default shall have occurred
and be continuing. Upon any such consolidation or merger or sale, the succesor
corporation shall succeed to and be substituted for the Company hereunder with
the same effect as if such successor corporation had been named herein. Every
such successor corporation shall possess, and may exercise, from time to time,
each and every right and power hereunder of the Company, in its name or
otherwise; and any act, proceeding, resolution or certificate by any of the
terms of this Agreement, required or provided to be done, taken and performed or
made, executed or verified by any board or officer of the Company shall and may
be done, taken and performed or made, executed or verified with like force and
effect by the corresponding board or officer of any such successor corporation.
If consolidation, merger or sale or other transfer is made as permitted by this
Section, the provisions of this Section shall continue in full force and effect
and no further consolidation, merger or sale or other transfer shall be made
except in compliance with the provisions of this Section 5.12(b).

Section 5.13  Maintenance of Property; Insurance.

The Company shall (a) keep all property useful and necessary in its business in
good working order and condition, except where the failure to do so would not
have a Materially Adverse Effect, and (b)(i) maintain with financially sound and
reputable insurance companies insurance on all its property in at least such
amounts and against at least such risks as are usually insured against in the
same general area by companies engaged in the same or a similar business, and
(ii) furnish to any Bank, upon written request, full information as to the
insurance carried.

Section 5.14  Inspection; Books and Records; Discussions.

The Company shall keep proper books of records and account in conformity with
GAAP and Applicable Law in which entries shall be made of all dealings and
transactions in relation to its business and activities; and permit
representatives of any Bank to visit and inspect any of its properties and
examine and make abstracts from any of its books and records at any reasonable
time and as often as may reasonably be desired, and to discuss the business,
operations, properties and financial and other condition of the Company with
officers and employees of the Company and with its independent certified public
accountants; provided that the foregoing shall not require the Company to waive
any attorney-client privilege or violate any confidentiality agreements to which
it is a party.

Section 5.15  Notices.

The Company shall give notice to the Banks of each of the following promptly
after the Company has knowledge thereof:

(a)  the occurrence of any Default;

(b)  (i) the occurrence or expected occurrence of any ERISA Termination Event
that could have a Materially Adverse Effect; and

(c)  any notices received from the Bond Insurer.
Each notice pursuant to this section shall be accompanied by a statement of a
senior officer of the Company setting forth details of the occurrence referred
to therein and stating what action the Company proposes to take with respect
thereto, it being understood and agreed that delivery of reports required by
Section 5.10(c) will fulfill the notice requirements of this Section 5.15 with
respect to the information contained in such reports; provided that such reports
are delivered promptly after the Company gains knowledge of the information that
it is required to provide the Banks under this Section 5.15.

ARTICLE VI

EVENTS OF DEFAULT; REMEDIES

Section 6.01  Events of Default.

Each of the following shall constitute an "Event of Default":

(a) The Company shall fail to pay when due, or to cause to be paid when due, any
principal of any Disbursement or shall fail to pay, within five days of the due
date thereof, any interest or fees payable hereunder; or

(b)

Any representation or warranty of the Company made in, or deemed to have been
made by the Company pursuant to, this Agreement or any of the Related Documents
to which the Company is a party, or by any of its officials in any certificate,
agreement, instrument or statement contemplated by or made or delivered pursuant
to or in connection herewith or therewith (including the Reoffering Circular),
shall prove to have been incorrect in any material respect when made or when
deemed made; or

(c)

Any "Event of Default" under the Indenture or any "event of default" under the
Loan Agreement shall have occurred and be continuing; or

(d)

The Company shall fail to perform or observe any covenant or agreement set
forth in Section 5.03; or

(e) The Company shall fail to perform or observe any other term, covenant or
agreement (other than one described in any other paragraph of this Section 6.01)
contained in this Agreement or the Related Documents on its part to be performed
or observed, and any such failure shall remain unremedied for 30 days after
written notice thereof shall have been given to the Company by the Purchasing
Bank or the Required Banks;

(f) Any default or similar event shall occur with respect to any indebtedness
having an aggregate principal amount in excess of 10,000,000 dollars with
respect to which the Company is an obligor, the effect of which is to permit the
holder or holders of such indebtedness, or a trustee or agent on behalf of such
holder or holders, to cause any such indebtedness to become due prior to its
stated maturity, or any such indebtedness shall be declared to be due and
payable prior to its stated maturity or shall not be paid when due;

(g) The Company shall make a general assignment for the benefit of creditors,
file a petition in bankruptcy, be unable generally to pay its debts as they
become due, or be adjudicated insolvent or bankrupt or there shall be entered
any order or decree granting relief in any voluntary or involuntary case
commenced by or against the Company under any applicable bankruptcy, insolvency
or other similar law now or hereafter in effect, or the Company shall petition
or apply to any court or administrative body for the appointment of any
receiver, trustee, liquidator, assignee, custodian, sequestrator (or other
similar official) of the Company or of any substantial part of the Company's
properties, or shall commence any proceeding in a court of law for a
reorganization, readjustment of debt, dissolution, liquidation, assignment or
other similar procedure under the laws or statutes of any jurisdiction, whether
now or hereafter in effect, or there shall be commenced against the Company any
such proceeding in a court of law that remains undismissed or not discharged,
vacated or stayed within 90 days after commencement, or the Company by any act
shall indicate its consent to, approval of or acquiescence in any of the
foregoing or take any action for the purpose of effecting any of the foregoing;
or

(h) The Company shall commence proceedings seeking to limit its liability under
this Agreement or the Bank Bonds.

(i) The ratings assigned to the Bond Insurer's long-term debt or claims paying
ability are withdrawn, suspended and/or reduced to below BBB- (or its equivalent
rating) by S and P and are withdrawn, suspended and/or reduced to below Baa3 (or
its equivalent rating) by Moody's; or

(j)  A Bond Insurer Event of Insolvency shall have occurred; or

(k) The Bond Insurer shall fail, wholly or partially, to make a payment when and
as required under the provisions of any Bond Insurance Policy (including
principal of, and interest at the Bank Rate on, Bank Bonds); or

(l) The Bond Insurer or any other Person shall claim or assert in writing that
any Bond Insurance Policy is invalid or unenforceable against the Bond Insurer,
or the Bond Insurer shall repudiate its obligations or deny that it has any
further liability under any Bond Insurance Policy or the validity or
enforceability of any Bond Insurance Policy shall be contested in any contest or
proceeding (including an appellate proceeding) directly or indirectly by the
Bond Insurer or any other Person and, in the case of a Person other than the
Bond Insurer, the Bond Insurer shall fail to defend or assert such validity or
enforceability or to appeal such contest or proceeding pursuant to appropriate
proceedings or actions; or

(m) Any Governmental Authority with competent jurisdiction shall announce, find
or rule that any Bond Insurance Policy is null and void or otherwise invalid or
unenforceable against the Bond Insurer; or

(n)  Any Bond Insurance Policy is surrendered, canceled or terminated, or
amended or modified in any material respect; or

(o) A court of competent jurisdiction enters a final nonappealable judgment that
any Bond Insurance Policy is not valid and binding on or enforceable against the
Bond Insurer.

Section 6.02  Remedies.

(a)  Events of Suspension.

(i) Each of the following shall constitute an "Event of Suspension": (A) the
occurrence of any Event of Default set forth in Section 6.01(i)-(o) or (B) a
Bond Insurer Potential Insolvency. During the continuance of any Event of
Suspension, the Commitment shall be suspended and the Purchasing Bank shall be
under no obligation to purchase any Unremarketed Bonds. The Purchasing Bank
shall give written notice of any Event of Suspension to the Company, the
Trustee, the Paying Agent and the Remarketing Agent promptly after it becomes
aware thereof; provided, however, that the Purchasing Bank shall not incur any
liability or responsibility whatsoever by reason of the Purchasing Bank's
failure to give such notice and such failure shall in no way affect the
suspension of the Commitment. The suspension of the Commitment shall not extend
the Stated Expiration Date or affect any other remedy provided under this
Section 6.02, and no cure of an Event of Suspension shall reinstate the
Commitment if the Commitment shall have expired or been terminated prior
thereto.

(ii) For the purposes of Section 6.02(a)(i), (A) an Event of Suspension
resulting from an Event of Default under Section 6.01(l) or (m) shall be deemed
to cease to exist if and only if a court of competent jurisdiction shall find or
rule that such Bond Insurance Policy is valid and binding on the Bond Insurer in
accordance with its terms, (B) an Event of Suspension resulting from a Bond
Insurer Potential Insolvency shall be deemed to cease to exist if and only if
such Bond Insurer Potential Insolvency shall cease to exist and no Bond Insurer
Event of Insolvency shall have occurred and (C) any other Event of Suspension
shall be deemed to cease to exist if and only if the Event of Default from which
such Event of Suspension resulted shall cease to exist.

(b)  Events of Termination.

Each of the following shall constitute an "Event of Termination" or an "event of
termination": (i) the occurrence of an Event of Default under Section 6.01(j),
(k), (n) or (o), (ii) the occurrence of an Event of Default under Section
6.01(i) and the continuance of such Event of Default for a period of 30
consecutive days, or (iii) the occurrence of an Event of Default under Section
6.01(l) or (m) and the entry by a court of competent jurisdiction of a final
nonappealable judgment that the Bond Insurance Policy is not valid and binding
on the Bond Insurer. During the continuance of an Event of Termination, the
Purchasing Bank may do any or all of the following: (i) by notice to the
Company, declare all Disbursements to be, and all Disbursements shall thereupon
become, immediately due and payable, (ii) by notice to the Trustee declare that,
on the fifth Domestic Business Day after the 45th day after notice of such Event
of Termination is received by the Trustee, the Commitment shall terminate, in
which event the Commitment shall so terminate on such day (if not previously
expired or terminated), and (iii) by notice to the Trustee, demand the immediate
redemption of all Bank Bonds in accordance with Section 2.4(G)(ii) of the
Indenture and Section 2.03(c) hereof. The Purchasing Bank shall promptly give
the Company, the Paying Agent and the Remarketing Agent a copy of any notice
given to the Trustee pursuant to clause (ii) or (iii) of the preceding sentence;
provided, however, that the Purchasing Bank shall not incur any liability or
responsibility whatsoever by reason of the Purchasing Bank's failure to give a
copy of such notice and such failure shall in no way affect the effectiveness of
any remedies elected by the Banks.

(c)  Other Remedies.

During the continuance of any Event of Default, the Banks, in addition, shall
have all remedies provided at law or equity, including the right to demand and
receive specific performance; provided, however, that, except as otherwise
provided in subsection (a) or (b) of this Section 6.02, the Purchasing Bank
shall not have the right to suspend, terminate or otherwise reduce the
Commitment.

(d)  Direction by Required Banks.

The Purchasing Bank shall (i) in the case of an Event of Termination, take any
or all of the actions referred to in clause (i)-(iii) of Section 6.02(b) if so
directed by the Required Banks and (ii) in the case of any Event of Default or
Event of Termination, take such other action with respect thereto as shall be
reasonably directed by the Required Banks.

ARTICLE VII

MISCELLANEOUS

Section 7.01    Amendments, Etc.

(a) No amendment or waiver of any provision of this Agreement, nor consent to
any departure by the Company therefrom, shall in any event be effective unless
the same shall be in writing and signed by the Purchasing Bank and the Required
Banks and, in the case of an amendment, the Company; provided, however, that no
amendment or waiver shall be effective, unless in writing and signed by each
Participating Bank affected thereby, to the extent it (i) extends the Stated
Expiration Date, (ii) increases the amount of the Commitment or such Bank's
Participation Amount, (iii) reduces or postpones any payment of any principal of
or interest on any Disbursement or any Commitment Fees, (iv) waives or changes
any condition precedent set forth in Article III, (v) changes Section 5.03, (vi)
changes Section 2.13, 2.14, 2.15, 7.04 or 7.06, (vii) modifies Section 2.17(a)
or 2.18 or any other provision providing for the equal or ratable treatment of
the Banks or (viii) modifies the definition of "Required Banks" or this Section
7.01(a) or any other provision requiring the consent of all of the Banks.

(b) Without the prior written consent of the Required Banks, the Purchasing Bank
shall not give or withhold its agreement to any waiver, modification or
amendment of any term, provision or covenant of any of the Related Documents;
provided, however, that, without the prior written consent of each Participating
Bank, the Purchasing Bank (i) shall not consent to any modification of the Bond
Insurance Policy or (ii) agree to purchase Unremarketed Bonds at a time when the
Purchasing Bank's obligation to do so has been suspended or terminated pursuant
to the terms hereof.

Section 7.02  Notices, Etc.

Except as otherwise expressly provided herein, all notices and other
communications provided for hereunder shall be in writing (including telecopier
communication) and shall be given to such party (a) in the case of the Company
or the Purchasing Bank, at its address or telecopier number set forth on the
signature pages hereof, (b) in the case of the Participating Banks, at its
address or telecopier number set forth below such Bank's name under the heading
"Notice Address" on Annex A or, in the case of a Participating Bank that became
a Participating Bank pursuant to Section 7.07(b) or (c), the address for notices
to such Bank set forth in the Joinder Agreement or Assignment and Acceptance
pursuant to which such Bank became a Participating Bank, (c) in the case of the
Trustee, the Paying Agent and the Remarketing Agent, to their respective
addresses or telecopier numbers set forth in the Indenture and/or the other
Related Documents, or (d) as to each of the foregoing, at such other address as
shall be designated by such Person in a written notice to the others. All such
notices and communications shall be effective (x) if given by telecopier, when
transmitted to the telecopier number specified as aforesaid, (y) if given by
mail, 72 hours after such communication is deposited in the mails with first
class postage prepaid, addressed as aforesaid, and (z) if given by other means,
when delivered at the address specified as aforesaid, except that written
notices to any Bank pursuant to the provisions of Article II shall not be
effective until received.

Section 7.03  No Implied Waiver: Remedies Cumulative.

No failure on the part of the Banks to exercise, and no delay in exercising, any
right under this Agreement shall operate as a waiver thereof; nor shall any
single or partial exercise of any right under this Agreement preclude any other
or further exercise thereof or the exercise of any other right. The remedies
herein provided are cumulative and not exclusive of any remedies provided by
law.

Section 7.04  Indemnification.

The Company agrees to indemnify the Banks, the Lead Arranger, the Trustee, their
respective Affiliates and the respective directors, officers, agents and
employees of the foregoing (each an "Indemnitee") for, and to hold harmless each
Indemnitee from and against any and all liabilities, losses, damages, costs and
reasonable expenses of any kind (including the reasonable fees and disbursements
of counsel) that may be incurred by such Indemnitee in connection with any
investigative, administrative or judicial proceeding (whether or not such
Indemnitee shall be designated a party thereto) in any way relating to or
arising out of:

(a) any alleged inaccuracy of, or any alleged untrue statement contained in, any
Offering Circular or any amendment or supplement thereto, or by reason of the
alleged omission to state therein a material fact necessary to make the
statements contained in any Offering Circular or any amendment or supplement
thereto, in the light of the circumstances under which they were made, not
misleading, other than any action or proceeding alleging any inaccuracy in a
material respect, or an untrue statement of a material fact, with respect to
information supplied by and describing a Bank in any Offering Circular or any
amendment or supplement thereto (the "Bank Information"), or alleging any
omission to state therein a material fact necessary to make the statements in
the Bank Information, in the light of the circumstances under which they were
made, not misleading; or

(b) the execution, delivery or performance of this Agreement, any Related
Document or any transaction contemplated hereby or thereby (including, without
limitation, by reason of or in connection with the purchase by the Purchasing
Bank of Unremarketed Bonds); provided, however, that the Company shall not be
required to indemnify any Indemnitee pursuant to this Section 7.04(a)(ii) for
any claims, damages, losses, liabilities, costs or expenses to the extent, but
only to the extent, caused by the willful misconduct or gross negligence of such
Indemnitee as determined by a court of competent jurisdiction or arising from
any litigation brought by such Indemnitee against the Company in which a final,
nonappealable judgment has been rendered against such Indemnitee.

Section 7.05  Limitation of Liability.

The Company assumes all risks of the acts or omissions of the Trustee, the
Paying Agent, the Remarketing Agent and the Bond Insurer with respect to the use
of the Disbursements under this Agreement. None of the Banks nor any of their
respective officers, directors, agents or employees shall be liable or
responsible for, and none of the Company's obligations under this Agreement
shall be affected by, (a) any mechanical error, omission, interruption or delay
in the transmission, dispatch or delivery of any message or advice, however
transmitted, in connection with this Agreement; (b) the use that may be made of
the Commitment or any acts or omissions of the Trustee, the Paying Agent or the
Remarketing Agent in connection therewith; (c) the validity, sufficiency or
genuineness of documents, or of any endorsement thereon, even if such documents
should prove to be in any or all respects invalid, insufficient, fraudulent or
forged; (d) payment by the Purchasing Bank against presentation of a Purchase
Certificate that does not comply with the terms of this Agreement; (e) any act,
or any failure to act, by the Trustee or the Paying Agent that results in the
failure of the Paying Agent (i) to credit the appropriate account with funds
made available by the Purchasing Bank pursuant to this Agreement or (ii) to
effect the purchase for the account of the Purchasing Bank of Unremarketed Bonds
with such funds pursuant to this Agreement; (f) any other circumstances
whatsoever in making or failing to make payment under this Agreement or (g) any
other action, inaction or omission that may be taken by it in good faith in
connection with this Agreement; provided that the Company shall have a claim
against any Bank, and such Bank shall be liable to the Company, to the extent of
any direct, as opposed to consequential, damages suffered by the Company that
the Company proves were caused by such Bank's willful misconduct or gross
negligence.

Section 7.06  Costs, Expenses and Taxes.

The Company shall pay (a) all reasonable out-of-pocket expenses of the
Purchasing Bank and the Lead Arranger, including the reasonable fees and
disbursements of special counsel for the Purchasing Bank, in connection with the
preparation, negotiation and closing of this Agreement, any waiver or consent
hereunder or any amendment hereof or in connection with any Default or alleged
Default, and (b) if an Event of Default occurs, all reasonable out-of-pocket
expenses incurred by the Banks, including (without duplication) the reasonable
fees and disbursements of outside counsel, in connection with such Event of
Default and any collection, bankruptcy, insolvency and other enforcement
proceedings resulting therefrom. In addition, the Company shall pay any and all
costs and expenses of the Banks (including reasonable counsel fees and expenses)
in connection with the transfer, exchange and registration of Bank Bonds and any
and all recording, stamp and other taxes and fees payable or determined to be
payable in connection with the execution, delivery, filing and recording of this
Agreement, any Related Document and such other documents, and agrees to save the
Banks harmless from and against any and all liabilities with respect to or
resulting from any delay in paying or omission to pay such taxes or fees.

Section 7.07    Binding Effect; Assignment; Participations.

(a) This Agreement shall be binding upon and inure to the benefit of the Company
and the Banks and their respective successors and assigns, except that the
Company shall not have the right to assign any of its rights or obligations
hereunder or any interest herein without the prior written consent of each of
the Banks.

(b) The Purchasing Bank may grant one or more Persons additional participations
in the Commitment and Disbursements; provided that (i) so long as no Event of
Default pursuant to Section 6.01(g) has occurred and is continuing, the Company
has consented to such grant of a participation (each such consent not to be
unreasonably withheld or delayed), (ii) the Person to which such participation
is granted shall have executed and delivered to the Purchasing Bank a Joinder
Agreement and (iii) after giving effect to the grant of such participation, the
aggregate amount of the Participation Amounts does not exceed the Commitment.
From and after the effective date of a Joinder Agreement, the Person granted
Participation Interests thereunder shall be a party hereto and, to the extent of
the Participation Interests granted by such Joinder Agreement, have the rights
and obligations of a Participating Bank under this Agreement.

(c) Any Participating Bank may assign to one or more Persons all or a portion of
its rights and obligations under this Agreement (including all or a portion of
its Participation Amount and Participation Interests); provided that (i) each of
the Purchasing Bank and, so long as no Event of Default pursuant to Section
6.01(g) has occurred and is continuing, the Company has consented to such
assignment (each such consent not to be unreasonably withheld or delayed), (ii)
each partial assignment shall not be of less than 5,000,000 dollars of the
assigning Participating Bank's Participation Amount and shall be made as an
assignment of a proportionate part of all the assigning Participating Bank's
rights and obligations under this Agreement (including Participation Interests
in outstanding Disbursements) with respect to the Participation Amount assigned
and (iii) the parties to each assignment shall execute and deliver to the
Purchasing Bank a Assignment and Acceptance, together with a processing and
recordation fee of 3,500 dollars. From and after the effective date of an
Assignment and Acceptance, the assignee thereunder shall be a party hereto and,
to the extent of the interest assigned by such Assignment and Acceptance, shall
have the rights and obligations of a Participating Bank under this Agreement,
and the assigning Participating Bank thereunder shall, to the extent of the
interest assigned by such Assignment and Acceptance, be released from its
obligations under this Agreement (and, in the case of a Assignment and
Acceptance covering all of the assigning Participating Bank's rights and
obligations under this Agreement, such Participating Bank shall cease to be a
party hereto). Any assignment or transfer by a Participating Bank of rights or
obligations under this Agreement that does not comply with this paragraph shall
be treated for purposes of this Agreement as a sale by such Participating Bank
of a participation in such rights and obligations in accordance with paragraph
(e) of this Section 7.07.

(d) The Purchasing Bank, acting solely for this purpose as an agent of the
Company, shall maintain at one of its offices in New York City a copy of each
Joinder Agreement and Assignment and Acceptance delivered to it and a register
for the recordation of the names and addresses of the Participating Banks, and
the Participation Amounts of, and Participation Interests held by, each
Participating Bank pursuant to the terms hereof from time to time (the
"Register"). The entries in the Register shall be conclusive, and the Company,
the Purchasing Bank and the Participating Banks may treat each Person whose name
is recorded in the Register pursuant to the terms hereof as a Participating Bank
hereunder for all purposes of this Agreement, notwithstanding notice to the
contrary. The Register shall be available for inspection by the Company and any
Participating Bank, at any reasonable time and from time to time upon reasonable
prior notice.

(e) Any Participating Bank may, without the consent of, or notice to, the
Company or the Purchasing Bank, sell subparticipations to one or more banks or
other entities (a "Subparticipant") in all or a portion of such Participating
Bank's rights and/or obligations under this Agreement (including all or a
portion of its Participation Amount and Participation Interests); provided that
(i) such Participating Bank's obligations under this Agreement shall remain
unchanged, (ii) such Participating Bank shall remain solely responsible to the
other parties hereto for the performance of such obligations and (iii) the
Company, the Purchasing Bank and the other Participating Banks shall continue to
deal solely and directly with such Participating Bank in connection with such
Participating Bank's rights and obligations under this Agreement. Any agreement
or instrument pursuant to which a Participating Bank sells such a participation
shall provide that such Participating Bank shall retain the sole right to
enforce this Agreement and to approve any amendment, modification or waiver of
any provision of this Agreement; provided that such agreement or instrument may
provide that such Participating Bank will not, without the consent of the
Subparticipant, agree to any amendment, modification or waiver described in
clauses (i)-(iii) of Section 7.01(a) that affects such Subparticipant. Subject
to paragraph (f) of this Section 7.07, the Company agrees that each
Subparticipant shall be entitled to the benefits of Sections 2.13, 2.14 and 2.15
to the same extent as if it were a Participating Bank and had acquired its
interest by assignment pursuant to paragraph (c) of this Section 7.07. To the
extent permitted by law, each Subparticipant also shall be entitled to the
benefits of Section 7.08 as though it were a Participating Bank, provided such
Subparticipant agrees to be subject to Section 2.18 as though it were a
Participating Bank.

(f) A Subparticipant shall not be entitled to receive any greater payment under
Sections 2.13, 2.14 or 2.15 than the applicable Participating Bank would have
been entitled to receive with respect to the participation sold to such
Subparticipant, unless the sale of the participation to such Subparticipant is
made with the Company's prior written consent. A Subparticipant that would be a
Non-US Bank if it were a Participating Bank shall not be entitled to the
benefits of Section 2.16(d) unless the Company is notified of the participation
sold to such Subparticipant and such Subparticipant agrees, for the benefit of
the Company, to comply with Section 2.16(d)(iii) as though it were a
Participating Bank.

(g) Any Bank may at any time pledge or assign a security interest in all or any
portion of its rights under this Agreement to secure obligations of such Bank,
including without limitation any pledge or assignment to secure obligations to a
Federal Reserve Bank; provided that no such pledge or assignment of a security
interest shall release a Bank from any of its obligations hereunder or
substitute any such pledgee or assignee for such Bank as a party hereto.

Section 7.08  Set-Off.

The Purchasing Bank and each Participating Bank is hereby authorized by the
Company, at any time and from time to time, without notice, (a) during any Event
of Default, to set off against, and to appropriate and apply to the payment of,
the liabilities of the Company under this Agreement (whether owing to such
Person or to any other Person that is the Purchasing Bank or a Participating
Bank and whether matured or unmatured, fixed or contingent or liquidated or
unliquidated and including the amounts to which a Participating Bank is entitled
with respect to its Participation Interests) any and all liabilities owing by
such Person or any of its Affiliates to the Company (whether payable in U.S.
dollars or any other currency, whether matured or unmatured and, in the case of
liabilities that are deposits, whether general or special, time or demand and
however evidenced and whether maintained at a branch or office located within or
without the United States) and (b) during any Default, to suspend the payment
and performance of such liabilities owing by such Person or its Affiliates in an
amount equal to the amount then due and payable under this Agreement and, in the
case of liabilities that are deposits, to return as unpaid for insufficient
funds any and all checks and other items drawn against such deposits.

Section 7.09  Severability.

Any provision of this Agreement that is prohibited, unenforceable, or not
authorized in any jurisdiction shall, as to such jurisdiction, be ineffective to
the extent of such prohibition, unenforceability or non-authorization without
invalidating the remaining provisions hereof or affecting the validity,
enforceability or legality of such provision in any other jurisdiction.

Section 7.10  Governing Law.

PURSUANT TO SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW, This
Agreement shall be governed by, and construed in accordance with, the law of the
State of New York.

Section 7.11  Jurisdiction; Service of Process;  Waiver of Jury Trial.

(a) In connection with any civil action or proceeding arising out of, based upon
or in any way connected to this Agreement, each of the Company and the
Participating Bank submits to the non-exclusive jurisdiction of state and
federal courts located in the City and State of New York in personam and agrees
that such courts are convenient forums. Each of the Company and the
Participating Banks waives personal service upon it and consents to service of
process by mailing a copy thereof to it by registered or certified mail.

(b) EACH OF THE BANKS AND THE COMPANY WAIVE THE RIGHT TO TRIAL BY JURY IN ANY
CIVIL ACTION OR PROCEEDING ARISING OUT OF, OR BASED UPON, OR IN ANY WAY
CONNECTED WITH THIS AGREEMENT.

Section 7.12  Survival of Representations and Warranties.

All agreements, representations and warranties made in this Agreement and in any
certificates delivered pursuant hereto shall survive the execution and delivery
of this Agreement, and the agreements contained in Sections 2.11, 2.12, 2.13,
2.14, 2.15, 7.04, 7.06 and 7.19 shall survive the termination of this Agreement
and payment of all other amounts payable hereunder.

Section 7.13  Entirety.

This Agreement embodies the entire agreement and understanding between the Banks
and the Company with respect to the subject matter hereof and supersedes all
other prior discussions, negotiations, arrangements and understandings relating
to the subject matter hereof.

Section 7.14  Execution in Counterparts.

This Agreement may be executed in any number of counterparts and by different
parties hereto on separate counterparts, each of which counterparts, when so
executed and delivered, shall be deemed to be an original and all of which
counterparts, taken together, shall constitute but one and the same agreement.

Section 7.15  Headings.

Section headings and the table of contents in this Agreement are included herein
for convenience of reference only and shall not constitute a part of this
Agreement for any other purpose.

Section 7.16  Effectiveness.

This Agreement shall become effective upon receipt by each Bank of counterparts
hereof signed by each of the parties hereto (or, in the case of any party as to
which an executed counterpart shall not have been received, receipt by each Bank
in form satisfactory to it of telegraphic, telex, facsimile or other written
confirmation from such party of execution of a counterpart hereof by such
party).

Section 7.17  Confidentiality.

Each Bank agrees to take normal and reasonable precautions and exercise due care
to maintain the confidentiality of all non-public information provided to it by
the Company or any Subsidiary in connection with this Agreement and the Related
Documents; provided that such Bank may disclose to, and exchange and discuss
with, any other Person (such Bank and each such other Person being hereby
authorized to do so), any information concerning the Company or any Subsidiary
(whether received by such Bank or such other Person in connection with or
pursuant to this Agreement or otherwise) (a) to independent auditors or bank
examiners or other governmental authorities, (b) to any Affiliate of the Bank,
(c) to any participant or proposed participant pursuant to Section 7.07 that has
agreed to be bound by the provisions of this Section 7.17 and (d) for the
purpose of (i) complying with Applicable Law, (ii) protecting, preserving,
exercising or enforcing any of their rights under or related to this Agreement
or the Related Documents, (iii) performing any of their obligations under or
related to this Agreement or the Related Documents or (iv) consulting with its
legal counsel other advisors with respect to any of the foregoing. Each Bank
shall, and shall cause any Affiliate to which it provides such non-public
information to, use such non- public information only in connection with this
Agreement and other existing or prospective credit arrangements with the Company
not involving the purchase or sale of the securities.

Section 7.18  Purchasing Bank's Rights and Responsibilities.

(a) Except as otherwise expressly provided in this Agreement, the Purchasing
Bank (i) shall have the sole right to exercise or refrain from exercising any
rights or remedies it may have, or to take or refrain from taking any other
action, with respect to the Disbursements or under this Agreement or any of the
Related Documents or otherwise available to it, and (ii) shall not be required
to obtain the consent of or consult with the Purchasing Banks with respect
thereto.

(b) The Purchasing Bank shall administer this Agreement in accordance with its
customary practices with respect to similar credit facilities with respect to
which it has not granted participations. The Purchasing Bank shall not, however,
have any liability to the Participating Bank with respect to the exercise of its
discretionary powers over the administration of this Agreement except to the
extent such exercise constitutes a grossly negligent or willful failure to
comply with such customary practices. The Purchasing Bank (i) shall be entitled
to rely upon any writing, statement, consent, certificate or notice or any fax
or telex message reasonably believed by it to be signed and sent by the proper
person, (ii) may consult with counsel, independent public accountants,
appraisers and other experts selected by it and shall not be liable for any
action taken or omitted to be taken in good faith in reliance on the advice of
any such expert, and (iii) may employ agents or attorneys-in-fact and shall not
be liable for the default or misconduct of any such person unless the Purchasing
Bank was grossly negligent in selecting such person.

(c) The Purchasing Bank shall have no duties or responsibilities, and makes no
representations or warranties, to the Participating Banks except as expressly
set forth in this Agreement. Without limiting the generality of the foregoing,
neither the Participating Bank nor any of its officers, directors or employees
shall be responsible to the Participant for, or shall be deemed to have made any
representation or warranty with respect to, (i) the accuracy of any statement,
representation or warranty made by any other person in or in connection with
this Agreement or the Related Documents, (ii) the validity, enforceability,
collectability or sufficiency of this Agreement or the Related Documents, (iii)
the past, present or future financial condition of the Company, the Bond Insurer
or any other Person or (iv) the performance of any of the terms, provisions or
conditions of this Agreement or the Related Documents on the part of the
Company, the Trustee, the Paying Agent, the Bond Insurer, the Remarketing Agent
or any other Person.

(d) Each Participating Bank acknowledges that (i) it has reviewed and is
familiar with this Agreement and the Related Documents, (ii) it has made its own
independent investigation of the financial condition and financial prospects of
the Company, the Bond Insurer and all other obligors under the Related
Documents, (iii) in entering into this Agreement, it has made its own credit
analysis and decision and is not relying on the investigation of the Purchasing
Bank or any of its directors, officers or employees or upon any financial
projections, estimates, appraisals, financial summaries or credit memoranda
prepared by or on behalf of the Purchasing Bank and given directly or indirectly
to such Participating to assist such Participating in making its own independent
evaluation and (iv) it will, independently and without reliance upon the
Purchasing Bank and based on such documents and information as it shall deem
appropriate at the time, continue to make its own credit decision in taking or
not taking action under this Agreement and (v) no fiduciary relationship exists
between such Participating Bank and the Purchasing Bank with respect to its
Participation Interests.

Section 7.19  Reimbursement and Indemnification by Participating Banks.

To the extent the Purchasing Bank is not reimbursed and indemnified by the
Company pursuant to Section 7.04(a) or 7.06, each Participating Bank agrees to
indemnify the Purchasing Bank for such Participating Bank's Participation Share
of any and all losses, liabilities, obligations, damages, penalties, actions,
judgments, suits, costs, expenses (including, without limitation, fees and
expenses of counsel) or disbursements of any kind or nature whatsoever which may
be imposed on, incurred by or asserted against the Purchasing Bank in any way
relating to or arising out of (i) the Disbursements, this Agreement or any of
the Related Documents or any other document delivered in connection with the
Disbursements or the transactions contemplated hereby or the enforcement of any
of the terms hereof (provided that such Participating Bank shall not be liable
for any of the foregoing to the extent they arise from the Purchasing Bank's
gross negligence or willful misconduct) or (ii) without limiting the generality
of the foregoing, the failure of such Participating Bank to comply with the
provisions of Section 2.16(d)(iii) or any inaccuracy in any document delivered
pursuant thereto.

Section 7.20  Participating Banks' Obligations Absolute.

Each Participating Bank's obligations under this Agreement shall constitute
absolute, unconditional and continuing obligations and are irrespective of (i)
any invalidity, unenforceability or insufficiency of any of the Related
Documents, (ii) any default by or insolvency of the Company, the Bond Insurer or
any other Person obligated with respect to any of the Disbursements, (iii) any
act or omission (other than acts or omissions arising out of or relating to
gross negligence or willful misconduct by the Purchasing Bank) on the part of
the Purchasing Bank, any other bank, the Issuer, the Bond Insurer or any other
Person hereunder or under the Related Documents, (iv) the absence of notice to
such Participating Bank with respect to any of the foregoing, and (v) any
requirement that the Purchasing Bank, any other bank, the Issuer, the Bond
Insurer or any other Person take any action against the Company, the Bond
Insurer or any other Person obligated with respect to the Disbursements.

Section 7.21  Beneficiaries.

This Agreement shall be for the benefit of the parties hereto, the Trustee, the
Paying Agent and the holders of the Bonds, and nothing contained herein, express
or implied, is intended to give any Person other than the parties hereto, the
Trustee, the Paying Agent and the holders of the Bonds any right, remedy, or
claim hereunder or by reason hereof.


IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly
executed and delivered by their respective officers thereunto duly authorized as
of the date set forth below.

THE CONNECTICUT LIGHT AND POWER COMPANY
By:
Name:  Randy A. Shoop
Title:  Treasurer
Address:
The Connecticut Light and Power Company
if by mail:
P.O. Box 270
Hartford, CT  06141-0270
if by delivery:
107 Selden Street
Berlin, CT  06037

Attention:  Treasurer
Telephone: 860-665-3258; Telecopy:  860-665-5457

THE BANK OF NEW YORK,
as Purchasing Bank

By:
Name:
Title:
Address: One Wall Street, 18th Floor
New York, NY  10286

Attention:  Lawrence Berger
Telephone:  212-635-8403; Telecopy:  212-635-8059

with a copy to:

BNY Capital Markets, Inc.
One Wall Street, 18th Floor
New York, NY  10286

Attention:  Lawrence Berger
Telephone:  212-635-8403; Telecopy:  212-635-8059

BANK HAPOALIM, B.M.,

as Participating Bank
By:
Name:
Title:

Den Danske Bank A/S,

as Participating Bank
By:
Name:
Title:

CITIC KA WAH BANK LIMITED,

as Participating Bank
By:
Name:
Title:


Citizens BANK OF MASSACHUSETTS,

as Participating Bank

By:
Name:
Title:
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.26
<SEQUENCE>5
<FILENAME>0005.txt
<DESCRIPTION>EXHIBIT 10.26
<TEXT>


                             NEW ENGLAND POWER POOL


                RESTATED NEW ENGLAND POWER POOL AGREEMENT


                FERC ELECTRIC THIRD REVISED RATE SCHEDULE NO. 5



            (As amended through the Sixty-Ninth Agreement
             Amending New England Power Pool Agreement)











                          TABLE OF CONTENTS           SHEET NO.


PART ONE INTRODUCTION

SECTION 1 DEFINITIONS 1.1 Accepted Electric Industry Practice 1.2 Adjusted Load
1.3 Adjusted Monthly Peak 1.4 Adjusted Net Interchange 1.5 Administrative
Procedures 1.6 AGC Capability 1.7 AGC Entitlement 1.8 Agreement 1.9 Annual
Transmission Revenue Requirements 1.10 Automatic Generation Control or AGC 1.11
Balloting Agent 1.12 Bid Price 1.13 Bilateral Transaction 1.14 Clearing Price
1.15 CMS 1.16 CMS/MSS Effective Date 1.17 Commission 1.18 Congestion 1.19
Congestion Component 1.20 Congestion Cost 1.21 Congestion Revenue 1.22
Congestion Revenue Fund 1.23 Control Area 1.24 Curtailment 1.25 Day-Ahead 1.26
Day-Ahead Market 1.27 Demand Bid 1.28 Demand Bid Price 1.29 Direct Assignment
Facilities 1.30 Dispatch Day 1.31 Dispatchable Load 1.32 Dispatch Price 1.33
Distribution Company 1.34 Distribution Company Load Zone 1.35 EHV PTF 1.36
Electrical Load 1.37 Eligible Customer 1.38 End User Behind-the-Meter Generation
1.39 End User Organization 1.40 End User Participant 1.41 Energy 1.42 Energy
Entitlement 1.43 Entitlement 1.44 Entity 1.45 Excepted Transaction 1.46 External
Node 1.47 Facilities Study 1.48 FCR 1.49 Financial Congestion Right 1.50 Firm
Contract 1.51 First Effective Date 1.52 Governance Only Member 1.53 HQ Contracts
1.54 HQ Energy Banking Agreement 1.55 HQ Interconnection 1.56 HQ Interconnection
Agreement 1.57 HQ Interconnection Capability Credit 1.58 HQ Interconnection
Transfer Capability 1.59 HQ Net Interconnection Capability Credit 1.60 HQ Phase
I Energy Contract 1.61 HQ Phase I Percentage 1.62 HQ Phase I Transfer Credit
1.63 HQ Phase II Firm Energy Contract 1.64 HQ Phase II Gross Transfer
Responsibility 1.65 HQ Phase II Net Transfer Responsibility 1.66 HQ Phase II
Percentage 1.67 HQ Phase II Transfer Credit 1.68 HQ Use Agreement 1.69 Hub 1.70
Hub Price 1.71 Installed Capability 1.72 Installed Capability Entitlement 1.73
Installed Capability Responsibility 1.74 Installed System Capability 1.75
Interchange Transactions 1.76 Internal Point-to-Point Service 1.77 Interruption
1.78 ISO 1.79 Kilowatt 1.80 Large End User 1.81 Liaison Committee 1.82 Load 1.83
Load Asset Contract 1.84 Load Zone 1.85 Local Network 1.86 Local Network Service
1.87 Location 1.88 Locational Price 1.89 Lost Opportunity Cost 1.90 Lower
Voltage PTF 1.91 Marginal Loss 1.92 Marginal Loss Component 1.93 Marginal Loss
Revenue 1.94 Marginal Loss Revenue Fund 1.95 Market Products 1.96 Market Rules
1.97 Markets Committee 1.98 Megawatt 1.99 Monthly 1.100 MSS 1.101 NEPOOL 1.102
NEPOOL Control Area 1.103 NEPOOL Installed Capability 1.104 NEPOOL Installed
Capability Responsibility 1.105 NEPOOL Objective Capability 1.106 NEPOOL Market
1.107 NEPOOL System Rules 1.108 NEPOOL Transmission System 1.109 NERC 1.110 {Net
Hourly Load Obligation for Energy 1.111 New Unit 1.112 No-Load Price 1.113 Nodal
Price 1.114 Node 1.115 Non-Participant 1.116 NPCC 1.117 OASIS 1.118 Operable
Capability 1.119 Operating Reserve 1.120 Operating Reserve Entitlement 1.121
Other HQ Energy 1.122 Participant 1.123 Participants Committee 1.124
Pool-Planned Facility 1.125 Pool-Planned Unit 1.126 Power Year 1.127 Prior
NEPOOL Agreement 1.128 Proxy Unit 1.129 PTF 1.130 Publicly Owned Entity 1.131
Real-Time 1.132 Real-Time Market 1.133 Reference Node 1.134 Regional Network
Service 1.135 Related Person 1.136 Reliability Committee 1.137 Reliability
Standards 1.138 Reliability Must Run 1.139 Reliability Region 1.140 {Reserve
Contract 1.141 {Reserve Price 1.142 Resource 1.143 Review Board43 1.144 RMR
1.145 RMR Charge 1.146 RMR Uplift 1.147 Scheduled Dispatch Period 1.148 Second
Effective Date 1.149 Sector 1.149A Self-Schedule 1.149B Self-Supply 1.150
Service Agreement 1.151 Settlement Obligation 1.152 Shift Factor 1.153 Small End
User 1.154 Standard Offer Obligation 1.155 Start-Up Price 1.156 Summer
Capability 1.157 Summer Period 1.158 Supply Obligation 1.159 Supply Offer 1.160
Supply Offer Price 1.161 System Contract 1.162 System Impact Study 1.163 System
Operator 1.164 Target Availability Rate 1.165 Tariff 1.166 Tariff Committee
1.167 Technical Committees 1.168 Third Effective Date 1.169 Through or Out
Service 1.170 Transition Period 1.171 Transmission Customer 1.172 Transmission
Owner 1.173 Transmission Owners Committee 1.174 Transmission Provider 1.175 Unit
Contract 1.176 Withdrawal Factor 1.177 Winter Capability 1.178 Winter Period
1.179 Zonal Price 1.180 4-Hour Reserve 1.181 4-Hour Reserve Entitlement 1.182
10-Minute Spinning Reserve 1.183 10-Minute Non-Spinning Reserve 1.184 30-Minute
Operating Reserve 1.185 Modification of Certain Definitions When a Participant
Purchases a Portion of Its Requirements from Another Participant Pursuant to
Firm Contract

SECTION 2  PURPOSE; EFFECTIVE DATES
2.1  Purpose
2.2  Effective Dates; Transitional Provisions

SECTION 3  MEMBERSHIP
3.1  Membership
3.2  Operations Outside the Control Area
3.3  Lack of Place of Business in New England
3.4  Obligation for Deferred Expenses
3.5  Financial Security

SECTION 4  STATUS OF PARTICIPANTS
4.1  Treatment of Certain Entities as Single Participant
4.2  Participants to Retain Separate Identities

SECTION 5  NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS
5.1  NEPOOL Objectives
5.2  Cooperation by Participants

PART TWO GOVERNANCE

SECTION 6 COMMITTEE ORGANIZATION AND VOTING 6.1 Principal Committees 6.2 Sector
Representation 6.3 Appointment of Members and Alternates 6.4 Term of Members 6.5
Regular and Special Meetings 6.6 Notice of Meetings 6.7 Attendance 6.8 Quorum
6.9 Voting Definitions 6.10 Voting On Proposed Actions 6.11 Voting On Amendments
6.12 Designated Representatives and Proxies 6.13 Limits on Representatives 6.14
Adoption of Bylaws 6.15 Joint Meetings of Technical Committees

SECTION 7 PARTICIPANTS COMMITTEE
7.1  Officers
7.2  Adoption of Budgets
7.3  Establishing Reliability Standards
7.4  Appointment and Compensation of NEPOOL Personnel
7.5  Duties and Authority
7.6  Attendance of Participants at Committee Meeting
7.7  Appeal of Actions to Review Board

SECTION 8  RELIABILITY COMMITTEE
8.1  Officers
8.2  Notice to Members and Alternates of Participants Committee
8.3  Voting; Appeal of Actions
8.4  Responsibilities
8.5  Establishment of Subcommittees and Task Forces
8.6  Further Powers and Duties

SECTION 9  TARIFF COMMITTEE
9.1  Officers
9.2  Notice to Members and Alternates of Participants Committee
9.3  Voting; Appeal of Actions
9.4  Responsibilities
9.5  Establishment of Subcommittees and Task Forces
9.6  Further Powers and Duties

SECTION 10 MARKETS COMMITTEE
10.1  Officers
10.2 Notice to Members and Alternates of Participants Committee 10.3 Voting;
Appeal of Actions 10.4 Responsibilities 10.5 Establishment of Subcommittees and
Task Forces 10.6 Further Powers and Duties 10.7 Development of Rules Relating to
Non-Participant Supply and Demand-side Resources

SECTION 11   FURTHER RESTRUCTURING

SECTION 11A REVIEW BOARD 11A.1 Organization 11A.2 Composition 11A.3
Qualifications 11A.4 Term 11A.5 Meetings 11A.6 Bylaws
11A.7  Procedure on Appeal of Participant Committee Action or Failure
to Take Action
11A.8  Effect of a Review Board Decision
11A.9
11A.10
11A.11

SECTION 11B TRANSMISSION OWNERS COMMITTEE 11B.1 Organization 11B.2 Membership
11B.3 Appointment of Members and Alternates 11B.4 Term of Members 11B.5 Regular
and Special Meetings 11B.6 Notice of Meetings 11B.7 Attendance 11B.8 Votes 11B.9
Appointment of Task Forces or Working Groups 11B.10 Officers 11B.11 Adoption of
Bylaws 11B.12 Review of Committee Actions

SECTION 11C LIAISON COMMITTEE 11C.1 Organization; Duties 11C.2 Membership 11C.3
Regular and Special Meetings 11C.4 Notice of Meetings 11C.5 Attendance 11C.6
Officers

PART THREE     MARKET PROVISIONS

SECTION 12 INSTALLED CAPABILITY OBLIGATIONS AND PAYMENTS 12.0 Continuing
Reliability Measures 12.1 Obligations to Provide Installed Capability 12.2
Computation of Installed Capability Responsibilities
12.3  [Deleted.]
12.4  [Deleted.]
12.5  Consequences of Deficiencies in Installed Capability Responsibility
12.6  [Deleted]
12.7  Payments to Participants Furnishing Installed Capability

SECTION 13 OPERATION, GENERATION, OTHER RESOURCES, AND INTERRUPTIBLE CONTRACTS
13.1 Maintenance and Operation in Accordance with Accepted Electric Industry
Practice 13.2 Central Dispatch 13.3 Maintenance and Repair 13.4 Objectives of
Day-to-Day System Operation 13.5 Satellite Membership

SECTION 14   INTERCHANGE TRANSACTIONS
14.1 Obligation for Energy, Operating Reserve and Automatic Generation Control
14.2 Obligation to Bid or Schedule, and Right to Receive Energy, Operating
Reserve and Automatic Generation Control 14.3 Amount of Energy, Operating
Reserve and Automatic Generation Control Received or Furnished 14.4 Payments by
Participants Receiving Energy Service, Operating Reserve and Automatic
Generation Control 14.5 Payments to Participants Furnishing Energy Service,
Operating Reserve, and Automatic Generation Control 14.6 Energy Transactions
with Non-Participants 14.7 Participant Purchases Pursuant to Firm Contracts and
System Contracts 14.8 Determination of Energy Clearing Price 14.9 Determination
of Operating Reserve Clearing Price 14.10 Determination of AGC Clearing Price
14.11 Funds to or from which Payments are to be Made 14.12 Development of Rules
Relating to Nuclear and Hydroelectric Generating Facilities, Limited-Fuel
Generating Facilities, and Interruptible Loads 14.13 Dispatch and Billing Rules
During Energy Shortages 14.14 Congestion Uplift 14.14A CMS/MSS Implementation
Studies Related to Congestion 14.15 Additional Uplift Charges

SECTION 14A PARTICIPANT MARKET TRANSACTIONS ON AND AFTER THE CMS/MSS EFFECTIVE
DATE 14A.1 Supply Obligations and Settlement Obligations for Energy, Operating
Reserve, 4-Hour Reserve and Automatic Generation Control 14A.2 Right to Receive
Service 14A.3 Participation in the Day-Ahead Market 14A.4 Nature of Demand Bids
and Supply Offers; Limitations; Self-Schedules and Self-Supplies 14A.5
Scheduling Procedures in the Day-Ahead Market 14A.6 Participation in the
Real-Time Market 14A.7 Scheduling Procedures in the Real-Time Market 14A.8
Settlement Obligation Payments for Energy, Operating Reserves, 4-Hour Reserves
and Automatic Generation Control 14A.9 Supply Obligation Payments For Energy,
Operating Reserves, 4-Hour Reserves and Automatic Generation Control 14A.10
Contract and Scheduling Authority 14A.11 Bilateral Transactions and Participant
Transactions with Non- Participants 14A.12 Determination of Locational Prices
14A.13 Determination of Operating Reserve and 4-Hour Reserve Clearing Prices
14A.14 Determination of AGC Clearing Price 14A.15 Funds to or from which
Payments are to Be Made 198WW14A.16 Marginal Losses 14A.17 Congestion Cost and
Revenues 14A.18 Market Monitoring and Reports 14A.19 Additional Uplift
ChargesPART FOUR TRANSMISSION PROVISIONS

SECTION 15  OPERATION OF TRANSMISSION FACILITIES
15.1 Definition of PTF
15.2 Maintenance and Operation in Accordance with Accepted Electric Industry
Practice
15.3 Central Dispatch
15.4 Maintenance and Repair
15.5 Additions to or Upgrades of PTF

SECTION 16  SERVICE UNDER TARIFF
16.1 Effect of Tariff
16.2 Obligation to Provide Regional Service
16.3 Obligation to Provide Local Network Service
16.4 Transmission Service Availability
16.5 Transmission Information
16.6 Distribution of Transmission Revenues

SECTION 17  POOL-PLANNED UNIT SERVICE
17.1 Effective Period
17.2 Obligation to Provide Service
17.3 Rules for Determination of Facilities Covered by Particular Transactions
17.4 Payments for Uses of EHV PTF During the Transition Period
17.5 Payments for Uses of Lower Voltage PTF
17.6 Use of Other Transmission Facilities by Participants
17.7 Limits on Individual Transmission Charges

SECTION 17A     TRANSMISSION OWNERS RESERVED RIGHTS
17A.1
17A.2
17A.3
17A.4
17A.5
17A.6
17A.7
17A.8

PART FIVE GENERAL

SECTION 18 GENERATION AND TRANSMISSION FACILITIES 18.1 Designation of
Pool-Planned Facilities 18.2 Construction of Facilities
18.3 Protective Devices for Transmission Facilities and Automatic Generation
Control Equipment
18.4 Review of Participant's Proposed Plans
18.5 Participant to Avoid Adverse Effect

SECTION 19  EXPENSES
19.1 Annual Fee
19.2  NEPOOL Expenses
19.3  Restructuring Costs

SECTION 20  INDEPENDENT SYSTEM OPERATOR

SECTION 21  MISCELLANEOUS PROVISIONS
21.1  Alternative Dispute Resolution
21.2 Payment of Pool Charges; Termination of Status as Participant 21.3
Assignment 21.4 Force Majeure 21.5 Waiver of Defaults 21.6 Other Contracts 21.7
Liability and Insurance 21.8 Records and Information 21.9 Consistency with NPCC
and NERC Standards 21.10 Construction 21.11 Amendment 21.12 Termination 21.13
Notices to Participants, Committees, Committee Members, or the System Operator
21.14 Severability and Renegotiation 21.15 No Third-Party Beneficiaries 21.16
Counterparts

ATTACHMENT A  METHODOLOGY FOR DETERMINATION OF TRANSMISSION FLOWS
ATTACHMENT B  NEPOOL OPEN ACCESS TRANSMISSION TARIFF
ATTACHMENT C  RELIABILITY REGIONS









THIS AGREEMENT dated as of the first day of September, 1971, as amended, was
entered into by the signatories thereto for the establishment by them of a bulk
power pool to be known as NEPOOL and is restated by an amendment dated as of
December 1, 1996 and amended by subsequent amendments.

In consideration of the mutual agreements and undertakings herein, the
signatories hereby agree as follows:

                                    PART ONE
                                  INTRODUCTION

                                    SECTION 1
                                   DEFINITIONS

Whenever used in this Agreement, in either the singular or the plural number,
the terms contained in this Section shall have the meanings set forth herein. If
a term is identified in this Section with an asterisk (*), the definition may be
modified in certain cases pursuant to the last subsection of this Section 1. If
a term includes language in brackets ([ ]), such language shall become effective
automatically on the CMS/MSS Effective Date. Certain definitions are included in
braces ({ }). These definitions are still subject to further modification or
deletion and will not become effective except pursuant to a further Commission
order. To the extent appropriate to reflect the understandings of this
introductory text, future composite copies of this Agreement may remove brackets
([]), and braces ({ }), and part or all of this explanatory introductory
language, and may renumber the definitions, without further specific amendment
to or restatement of this Agreement.

1.1 Accepted Electric Industry Practice shall mean any of the practices,
methods, and acts engaged in or approved by a significant portion of the
electric utility industry during the relevant time period, or any of the
practices, methods, and acts which, in the exercise of reasonable judgement in
light of the facts known at the time the decision was made, could have been
expected to accomplish the desired result at a reasonable cost consistent with
good business practices, reliability, safety and expedition. Accepted Electric
Industry Practice is not limited to a single, optimum practice method or act to
the exclusion of others, but rather is intended to include acceptable practices,
methods, or acts generally accepted in the region.

1.2 Adjusted Load * (not less than zero) of a Participant during any particular
hour is the Participant's Load during such hour less any Kilowatts received (or
Kilowatts which would have been received except for the application of Section
14.7(b)) by such Participant pursuant to a Firm Contract.

1.3 Adjusted Monthly Peak of a Participant for a month is its Monthly Peak,
provided that if there has been a transfer between Participants, in whole or
part, of the responsibilities under this Agreement during such month pursuant to
a Firm Contract, the Adjusted Monthly Peak of each such Participant shall
reflect the effect of such transaction, but the Adjusted Monthly Peak of a
Participant shall not be changed from the Monthly Peak to reflect the effect of
any other transaction.

1.4 Adjusted Net Interchange of a Participant for an hour is (a) the Kilowatts
produced by or delivered to the Participant from its Energy Entitlements or
pursuant to arrangements entered into under Section 14.6, as adjusted in
accordance with Market Rules approved by the Markets Committee to take account
of associated electrical losses, as appropriate, minus (b) the sum of (i) the
Electrical Load of the Participant for the hour, and (ii) the kilowatthours
delivered by such Participant to other Participants pursuant to Firm Contracts
or System Contracts, in accordance with the treatment agreed to pursuant to
Section 14.7(a), together with any associated electrical losses. This section
shall terminate and be of no further force and effect after final settlement
with respect to services rendered until the CMS/MSS Effective Date.

1.5 Administrative Procedures are procedures adopted by the System Operator in
order to fulfill its responsibilities to apply and implement NEPOOL System
Rules.

1.6 AGC Capability of an electric generating unit or combination of units is the
maximum dependable ability of the unit or units to increase or decrease the
level of output within a time frame specified by Market Rules approved by the
Markets Committee, in response to a remote direction from the System Operator in
order to maintain currently proper power flows into and out of the NEPOOL
Control Area and to control frequency.

1.7 AGC Entitlement is the right for the purposes of settlement to all or a
portion of the AGC Capability of a generating unit or units to which an Entity
is entitled as an owner (either sole or in common) or as a purchaser under a
Unit Contract, reduced by any portion thereof which such Entity is selling
pursuant to a Unit Contract. An AGC Entitlement in a generating unit or units
may, but need not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the related
Installed Capability Entitlement, Energy Entitlement[, 4-Hour Reserve
Entitlement] or Operating Reserve Entitlement.

1.8 Agreement is this restated contract and attachments, including the Tariff,
as amended and restated from time to time.

1.9 Annual Transmission Revenue Requirements of a Participant's PTF or of all
Participants' PTF for purposes of this Agreement are the amounts determined in
accordance with Attachment F to the Tariff.

1.10 Automatic Generation Control or AGC is a measure of the ability of a
generating unit or portion thereof to respond automatically within a specified
time to a remote direction from the System Operator to increase or decrease the
level of output in order to control frequency and to maintain currently proper
power flows into and out of the NEPOOL Control Area.

1.11 Balloting Agent is the Secretary of the Participants Committee.

1.12 Bid Price is the amount which a Participant offers to accept, in a notice
furnished to the System Operator by it or on its behalf in accordance with the
Market Rules approved by the Markets Committee, as compensation for (i)
furnishing Installed Capability to other Participants pursuant to this
Agreement, or (ii) preparing the start up or starting up or increasing the level
of operation of, and thereafter operating, a generating unit or units to provide
Energy to other Participants pursuant to this Agreement, or (iii) having a unit
or units available to provide Operating Reserve to other Participants pursuant
to this Agreement, or (iv) having a unit or units available to provide AGC to
other Participants pursuant to this Agreement, or (v) providing to other
Participants Installed Capability, Energy, Operating Reserve and/or AGC pursuant
to a Firm Contract or System Contract in accordance with Section 14.7. This
definition shall terminate and be of no further force and effect after final
settlement with respect to services rendered before the CMS/MSS Effective Date.

1.13 Bilateral Transaction is a transaction, including a Firm Contract, System
Contract, Load Asset Contract or other contract, between two or more
Participants submitted for the transfer of Settlement Obligations in accordance
with the Market Rules with respect to Installed Capability, Energy at one or
more Locations within the NEPOOL Control Area, Operating Reserve[, 4-Hour
Reserve] and/or AGC. When used in the plural form, it may be any or all such
arrangements or combinations thereof, as the context requires.

1.14 Clearing Price is the amount determined for Energy, Operating Reserve and
AGC pursuant to Sections 14.8, 14.9 and 14.10, respectively, until the CMS/MSS
Effective Date, and thereafter pursuant to Sections 14A.8(a), 14A.8(b) and
14A.8(c), respectively.

1.15 CMS is the Congestion management system under the NEPOOL arrangements,
including Locational Prices for Energy and Financial Congestion Rights.

1.16 CMS/MSS Effective Date is the date on which the provisions of Section 14A
shall become fully effective and supersede the provisions of Section 14. The
CMS/MSS Effective Date shall be a date fixed by the Participants Committee which
occurs after NEPOOL System Rules and computer programs to fully implement
Section 14A of the Agreement and Schedules 13, 14 and 15 of the Tariff are in
place and at least thirty (30) days have elapsed since the Participants
Committee has provided notice to the Commission of the proposed CMS/MSS
Effective Date.

1.17  Commission is the Federal Energy Regulatory Commission.

1.18 Congestion is a condition of the NEPOOL Transmission System in which
transmission limitations prevent unconstrained regional economic dispatch of the
power system. Following the CMS/MSS Effective Date, Congestion is the condition
that results in the Congestion Component of the Locational Price at one Location
being different from the Congestion Component of the Locational Price at another
Location during any given hour of the Dispatch Day in the Day-Ahead Market and
Real-Time Market.

1.19 Congestion Component is the component of the Nodal Price that reflects the
marginal cost of Congestion at a given Node or External Node relative to the
Reference Node. When used in connection with Zonal Price and Hub Price, the term
Congestion Component refers to the Congestion Components of the Nodal Prices
that comprise the Zonal Price and Hub Price averaged or weighted in the same way
that Nodal Prices are averaged or weighted to determine the Zonal Price and Hub
Price, respectively.

1.20 Congestion Cost is the cost of Congestion as defined in Section 14.14 of
the Agreement and Section 24 of the Tariff for services until the CMS/MSS
Effective Date. On and after the CMS/MSS Effective Date, Congestion Cost is the
cost of Congestion as measured by the difference between the Congestion
Components of the Locational Prices at different Locations and/or Reliability
Regions on the NEPOOL Transmission System.

1.21 Congestion Revenue for each hour is the surplus revenue, if any, for each
hour after netting the revenues paid and collected for the Congestion Components
of Locational Price for all Energy transactions on the NEPOOL Transmission
System, including Energy deliveries by Non-Participant Transmission Customers
taking service under the Tariff, as settled in accordance with the Market Rules.
Congestion Revenue is calculated for each hour of the Dispatch Day in the
Day-Ahead Market and Real-Time Market as provided in Section E of Schedule 14 of
the Tariff and the applicable Market Rules.

1.22 Congestion Revenue Fund is the fund of Congestion Revenue administered by
the System Operator in accordance with Section 14A.17 of the Agreement,
Schedules 13 and 14 of the Tariff, and the applicable Market Rules.

1.23 Control Area is an electric power system or combination of electric power
systems to which a common automatic generation control scheme is applied in
order to:

(i) match, at all times, the power output of the generators within the electric
power system(s) and capacity and energy purchased from entities outside the
electric power system(s), with the load within the electric power system(s);

(ii) maintain scheduled interchange with other Control Areas, within the limits
of Accepted Electric Industry Practice;

(iii) maintain the frequency of the electric power system(s) within reasonable
limits in accordance with Accepted Electric Industry Practice and the criteria
of the applicable regional reliability council or the NERC; and

(iv) provide sufficient generating capacity to maintain operating reserves in
accordance with Accepted Electric Industry Practice.

1.24 Curtailment is a reduction in firm or non-firm transmission service in
response to a transmission capacity shortage as a result of system reliability
conditions.

1.25 Day-Ahead is the calendar day immediately preceding a Dispatch Day for
which Participants submit Demand Bids and Supply Offers in accordance with
applicable Market Rules and the System Operator schedules Resources for Energy,
Operating Reserve, 4-Hour Reserve and AGC in accordance with applicable NEPOOL
System Rules.

1.26 Day-Ahead Market is the market provided for in Section 14A and conducted in
the calendar day immediately preceding a Dispatch Day in which Energy, Operating
Reserve, 4-Hour Reserve and AGC are scheduled for a Dispatch Day, based on the
Day-Ahead Demand Bids and Supply Offers and applicable NEPOOL System Rules.

1.27 Demand Bid is a proposal by a Participant to receive and pay for Energy, at
a specified Location and at a specified Demand Bid Price, that is submitted to
the System Operator pursuant to the Agreement and applicable Market Rules, and
includes information with respect to the quantity to be received and paid for
and other matters complying with the Market Rules.

1.28 Demand Bid Price is the price specified by a Participant to the System
Operator in a Demand Bid for Energy at a specified Location.

1.29 Direct Assignment Facilities are facilities or portions of facilities that
are Non-PTF and are constructed for the sole use/benefit of a particular
Transmission Customer requesting service under the Tariff or Generator Owner
requesting an interconnection. Direct Assignment Facilities shall be specified
in a separate agreement with the Transmission Provider whose transmission system
is to be modified to include and/or interconnect with said Facilities, shall be
subject to applicable Commission requirements and shall be paid for by the
Transmission Customer or a Generator Owner in accordance with the separate
agreement and not under the Tariff.

1.30 Dispatch Day is the period beginning at the minute ending 0001 and ending
at 2400 each day.

1.31 Dispatchable Load is any portion of the Electrical Load of a Participant
that meets the requirements of the Market Rules to qualify as Operating Reserve
or 4-Hour Reserve or to have its Energy consumption modified in Real-Time
because of its ability to respond to remote dispatch instructions from the
System Operator. A Demand Bid to receive and pay for Energy at an External Node
shall, if scheduled, be considered a Dispatchable Load for the purposes of the
Day-Ahead Market and the Real-Time Market.

1.32 Dispatch Price of a generating unit or combination of units, or a Firm
Contract or System Contract permitted to be bid to supply Energy in accordance
with Section 14.7(b) until the CMS/MSS Effective Date or permitted to be
included in a Supply Offer for Energy in accordance with 14A.11(b) on and after
the CMS/MSS Effective Date, is the price to provide Energy from the unit or
units or Firm Contract or System Contract, as determined pursuant to the Market
Rules to incorporate the Bid Price or Supply Offer Price, as appropriate, for
such Energy and any loss adjustments, if and as appropriate under applicable
Market Rules.

1.33  Distribution Company has the meaning specified in Section 14A.12(b).

1.34  Distribution Company Load Zone has the meaning specified in Section
14A.12(b).

1.35 EHV PTF are PTF transmission lines which are operated at 230 kV or above
and related PTF facilities, including transformers which link other EHV PTF
facilities, but do not include transformers which step down from 230 kV or a
higher voltage to a voltage below 230 kV.

1.36 Electrical Load (in Kilowatts) of a Participant during any particular hour
is the total during such hour (eliminating any distortion arising out of (i)
Interchange Transactions, or (ii) transactions across the system of such
Participant, or (iii) deliveries between Entities constituting a single
Participant, or (iv) other electrical losses, if and as appropriate), of

(a)  kilowatthours provided by such Participant to its retail customers for
consumption, plus

(b)  kilowatthours of use by such Participant, plus

(c)  kilowatthours of electrical losses and unaccounted for use by the
Participant on its system, plus

(d)  kilowatthours used by such Participant for pumping Energy for its
Entitlements in pumped storage hydroelectric generating facilities, plus

(e)  kilowatthours delivered by such Participant to Non-Participants, plus

(f) kilowatthours of Electrical Load responsibility incurred due to a transfer
from another Participant pursuant to a Load Asset Contract for Electrical Load,
minus

(g) kilowatthours of Electrical Load responsibility transferred to another
Participant pursuant to a Load Asset Contract for Electrical Load. The
Electrical Load of a Participant may be calculated in any reasonable manner
which substantially complies with this definition.

1.37 Eligible Customer is the following: (i) Any Participant that is engaged, or
proposes to engage, in the wholesale or retail electric power business is an
Eligible Customer under the Tariff. (ii) Any electric utility (including any
power marketer), Federal power marketing agency, or any other entity generating
electric energy for sale or for resale is an Eligible Customer under the Tariff.
Electric energy sold or produced by such entity may be electric energy produced
in the United States, Canada or Mexico. However, with respect to transmission
service that the Commission is prohibited from ordering by Section 212(h) of the
Federal Power Act, such entity is eligible only if the service is provided
pursuant to a state requirement that the Transmission Provider with which that
entity is directly interconnected offer the unbundled transmission service, or
pursuant to a voluntary offer of such service by the Transmission Provider with
which that entity is directly interconnected. (iii) Any end user taking or
eligible to take unbundled transmission service pursuant to a state requirement
that the Transmission Provider with which that end user is directly
interconnected offer the transmission service, or pursuant to a voluntary offer
of such service by the Transmission Provider with which that end user is
directly interconnected, is an Eligible Customer under the Tariff.

1.38 End User Behind-the-Meter Generation is generation that has all three of
the following attributes: (a) it is owned by a Governance Only Member; and (b)
it is used to meet that Governance Only Member's load or, for any hour in which
the output of the End User Behind-the-Meter Generation owned by the Governance
Only Member exceeds its Electrical Load, another Participant which is not a
Governance Only Member is obligated under tariff or contract to report such
excess to the ISO pursuant to applicable Market Rules; and (c) it is delivered
to the Governance Only Member without the use of PTF or another Entity's
transmission or distribution facilities.

1.39 End User Organization is an End User Participant which is (a) a registered
tax-exempt non-profit organization with (i) an organized board of directors and
(ii) a membership (A) of at least 100 Entities that buy electricity at wholesale
or retail in the New England states or (B) with an aggregate peak monthly demand
(non-coincident) for load in New England, including load served by End User
Behind-the-Meter Generation, of at least ten (10) megawatts or (b) a
municipality or other governmental agency located in New England which does not
meet the definition of Publicly Owned Entity.

1.40 End User Participant is a Participant which is a consumer of electricity in
the NEPOOL Control Area that generates or purchases electricity primarily for
its own consumption or a non-profit group representing such consumers.

1.41  Energy is electrical energy, measured in kilowatthours or
megawatthours.

1.42 Energy Entitlement is a right for purposes of settlement to all or a
portion of the electric output of a generating unit at the Node where such unit
is interconnected to the NEPOOL Transmission System to which an Entity is
entitled as an owner (either sole or in common) or as a purchaser pursuant to a
Unit Contract, reduced by any portion thereof which such Entity is selling
pursuant to a Unit Contract. An Energy Entitlement in a generating unit or units
may, but need not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the related
Installed Capability Entitlement, Operating Reserve Entitlements[, 4-Hour
Reserve Entitlement] or AGC Entitlement.

1.43 Entitlement is an Installed Capability Entitlement, Energy Entitlement,
Operating Reserve Entitlement[, 4-Hour Reserve Entitlement] or AGC Entitlement.
When used in the plural form, it may be any or all such Entitlements or
combinations thereof, as the context requires.

1.44 Entity is any person or organization whether the United States of America
or Canada or a state or province or a political subdivision thereof or a duly
established agency of any of them, a private corporation, a partnership, an
individual, an electric cooperative or any other person or organization
recognized in law as capable of owning property and contracting with respect
thereto that is either:

(a) engaged in the electric power business (the generation and/or transmission
and/or distribution of electricity for consumption by the public or the
purchase, as a principal or broker, of Installed Capability, Energy, Operating
Reserve, [4-Hour Reserve] and/or AGC for resale); or

(b) a consumer of electricity in the NEPOOL Control Area that generates or
purchases electricity primarily for its own consumption or a non-profit group
representing such consumers.

1.45 Excepted Transaction is a transaction specified in Section 25 of the Tariff
for the applicable period specified in that Section, or in Sections 25A and 25B
of the Tariff.

1.46 External Node is a bus or buses used for establishing a Locational Price
for Energy received by Participants from, or delivered by Participants to, a
neighboring Control Area.

1.47 Facilities Study is an engineering study conducted pursuant to this
Agreement or the Tariff by the System Operator and/or one or more affected
Participants to determine the required modifications to the NEPOOL Transmission
System, including the cost and scheduled completion date for such modifications,
that will be required to provide a requested transmission service or
interconnection.

1.48  FCR is a Financial Congestion Right.

1.49 Financial Congestion Right is a financial instrument that evidences the
rights and obligations specified in Schedule 14 of the Tariff.

1.50 Firm Contract is any contract, other than a Unit Contract, for the purchase
of Installed Capability, Energy [at a Location], Operating Reserves[, 4-Hour
Reserves] and/or AGC, pursuant to which the purchaser's right to receive such
Installed Capability, Energy, Operating Reserves[, 4- Hour Reserves] and/or AGC
is subject only to the supplier's inability to satisfy its obligations
thereunder as the result of events beyond the supplier's reasonable control.

1.51  First Effective Date is March 1, 1997.

1.52 Governance Only Member is an End User Participant that participates in
NEPOOL for governance purposes only and elects to be a Governance Only Member
before its application is approved by NEPOOL.

1.53 HQ Contracts are the HQ Interconnection Agreement, the HQ Phase I Energy
Contract, and the HQ Phase II Firm Energy Contract.

1.54 HQ Energy Banking Agreement is the Energy Banking Agreement entered into on
March 21, 1983 by Hydro-Quebec, the Participants, New England Electric
Transmission Corporation and Vermont Electric Transmission Company, Inc., as it
may be amended from time to time.

1.55 HQ Interconnection is the United States segment of the transmission
interconnection which connects the systems of Hydro-Quebec and the Participants.
"Phase I" is the United States portion of the 450 kV HVDC transmission line from
a terminal at the Des Cantons Substation on the Hydro- Quebec system near
Sherbrooke, Quebec to a terminal having an approximate rating of 690 MW at a
substation at the Comerford Generating Station on the Connecticut River. "Phase
II" is the United States portion of the facilities required to increase to
approximately 2000 MW the transfer capacity of the HQ Interconnection, including
an extension of the HVDC transmission line from the terminus of Phase I at the
Comerford Station through New Hampshire to a terminal at the Sandy Pond
Substation in Massachusetts. The HQ Interconnection does not include any PTF
facilities installed or modified to effect reinforcements of the New England AC
transmission system required in connection with the HVDC transmission line and
terminals.

1.56 HQ Interconnection Agreement is the Interconnection Agreement entered into
on March 21, 1983 by Hydro-Quebec and the Participants, as it may be amended
from time to time.

1.57 HQ Interconnection Capability Credit of a Participant for a month during
the Base Term (as defined in Section 1.63) of the HQ Phase II Firm Energy
Contract is the sum in Kilowatts of (1)(a) the Participant's percentage share,
if any, of the HQ Phase I Transfer Capability times (b) the HQ Phase I Transfer
Credit, plus (2)(a) the Participant's percentage share, if any, of the HQ Phase
II Transfer Capability, times (b) the HQ Phase II Transfer Credit. The
Participants Committee shall establish appropriate HQ Interconnection Capability
Credits to apply for a Participant which has such a percentage share (i) during
an extension of the HQ Phase II Firm Energy Contract, and (ii) following the
expiration of the HQ Phase II Firm Energy Contract.

1.58 HQ Interconnection Transfer Capability is the transfer capacity of the HQ
Interconnection under normal operating conditions, as determined in accordance
with Accepted Electric Industry Practice. The "HQ Phase I Transfer Capability"
is the transfer capacity under normal operating conditions, as determined in
accordance with Accepted Electric Industry Practice, of the Phase I terminal
facilities as determined initially as of the time immediately prior to Phase II
of the Interconnection first being placed in service, and as adjusted thereafter
only to take into account changes in the transfer capacity which are independent
of any effect of Phase II on the operation of Phase I. The "HQ Phase II Transfer
Capability" is the difference between the HQ Interconnection Transfer Capability
and the HQ Phase I Transfer Capability. Determinations of, and any adjustment
in, transfer capacity shall be made by the Markets Committee in accordance with
a schedule consistent with that followed by it in its determination of the
Winter Capability and Summer Capability of generating units.

1.59 HQ Net Interconnection Capability Credit of a Participant at a particular
time is its HQ Interconnection Capability Credit at the time in Kilowatts, minus
a number of Kilowatts equal to (1) the percentage of its share of the HQ
Interconnection Transfer Capability committed or used by it for an "Entitlement
Transaction" at the time under the HQ Use Agreement, times (2) its HQ
Interconnection Capability Credit for the current month.

1.60 HQ Phase I Energy Contract is the Energy Contract entered into on March 21,
1983 by Hydro-Quebec and the Participants, as it may be amended from time to
time.

1.61 HQ Phase I Percentage is the percentage of the total HQ Interconnection
Transfer Capability represented by the HQ Phase I Transfer Capability.

1.62 HQ Phase I Transfer Credit is 60/69 of the HQ Phase I Transfer Capability,
or such other fraction of the HQ Phase I Transfer Capability as the Participants
Committee may establish.

1.63 HQ Phase II Firm Energy Contract is the Firm Energy Contract dated as of
October 14, 1985 between Hydro-Quebec and certain of the Participants, as it may
be amended from time to time. The "Base Term" of the HQ Phase II Firm Energy
Contract is the period commencing on the date deliveries were first made under
the Contract and ending on August 31, 2000.

1.64 HQ Phase II Gross Transfer Responsibility of a Participant for any month
during the Base Term of the HQ Phase II Firm Energy Contract (as defined in
Section 1.63) is the number in Kilowatts of (a) the Participant's percentage
share, if any, of the HQ Phase II Transfer Capability for the month times (b)
the HQ Phase II Transfer Credit. Following the Base Term of the HQ Phase II Firm
Energy Contract, and again following the expiration of the HQ Phase II Firm
Energy Contract, the Participants Committee shall establish an appropriate HQ
Phase II Gross Transfer Responsibility that shall remain in effect concurrently
with the HQ Interconnection Capability Credit.

1.65 HQ Phase II Net Transfer Responsibility of a Participant for any month is
its HQ Phase II Gross Transfer Responsibility for the month minus a number of
Kilowatts equal to (1) the highest percentage of its share of the HQ
Interconnection Transfer Capability committed or used by it on any day of the
month for an "Entitlement Transaction" under the HQ Use Agreement, times (2) its
HQ Phase II Gross Transfer Responsibility for the month.

1.66 HQ Phase II Percentageis the percentage of the total HQ Interconnection
Transfer Capability represented by the HQ Phase II Transfer Capability.

1.67 HQ Phase II Transfer Credit is 90/131 of the HQ Phase II Transfer
Capability, or such other fraction of the HQ Phase II Transfer Capability as the
Participants Committee may establish.

1.68 HQ Use Agreement is the Agreement with Respect to Use of Quebec
Interconnection dated as of December 1, 1981 among certain of the Participants,
as amended and restated as of September 1, 1985 and as it may be further amended
from time to time.

1.69 Hub is a specific set of pre-defined Nodes, approved by the Participants
Committee, for which a Locational Price will be calculated and which can be used
to establish a reference price for Energy purchases and the transfer of
Settlement Obligations for Energy and for the designation of FCRs in accordance
with Schedule 14 of the Tariff.

1.70 Hub Price in each hour of the Dispatch Day in the Day-Ahead Market and the
Real-Time Market is the price used for Energy purchases and Settlement
Obligations for Energy which are treated as being transferred at a Hub in the
hour. Hub Prices are calculated in accordance with Section 14A.12 of the
Agreement and Schedule 13 of the Tariff.

1.71 Installed Capability of an electric generating unit or combination of units
during the Winter Period is the Winter Capability of such unit or units and
during the Summer Period is the Summer Capability of such unit or units.

1.72 Installed Capability Entitlement is (a) the right to all or a portion of
the Installed Capability of a generating unit or units to which an Entity is
entitled as an owner (either sole or in common) or as a purchaser pursuant to a
Unit Contract, (b) reduced by any portion thereof which such Entity is selling
pursuant to a Unit Contract, and (c) further reduced or increased, as
appropriate, to recognize rights to receive or obligations to supply Installed
Capability pursuant to Firm Contracts or System Contracts in accordance with
Section 14.7(a). An Installed Capability Entitlement relating to a unit or units
may, but need not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the related
Energy Entitlement, Operating Reserve Entitlements, or AGC Entitlement.

1.73 Installed Capability Responsibility * of a Participant for any month is the
number of Kilowatts determined in accordance with Section 12.2.

1.74 Installed System Capability of a Participant at a particular time is (i)
the sum of such Participant's Installed Capability Entitlements plus (ii) its HQ
Net Interconnection Capability Credit at the time.

1.75 Interchange Transactions are transactions deemed to be effected under
Section 12 of the Prior NEPOOL Agreement prior to the Second Effective Date, and
transactions deemed to be effected under Section 14 of this Agreement on and
after the Second Effective Date.

1.76 Internal Point-to-Point Service is the transmission service by that name
provided pursuant to Section 19 of the Tariff.

1.77  Interruption

(a) Until the CMS/MSS Effective Date, Interruption is a reduction in non- firm
transmission service due to economic reasons pursuant to Section 28.7 of the
Tariff, other than a reduction which results from a failure to dispatch a
generating resource, including a contract, used in a transaction requiring
Through or Out Service which is out of merit order.

(b) On and after the CMS/MSS Effective Date, Interruption is a reduction in
non-firm transmission service due to economic reasons pursuant to Section 28.7
of the Tariff, other than a reduction which results from a failure to dispatch a
generating resource, including a Supply Offer or a Demand Bid at an External
Node, used in a transaction requiring Through or Out Service which is out of
merit order.

1.78 ISO is the Independent System Operator which is responsible for the
continued operation of the NEPOOL Control Area from the NEPOOL control center
and the administration of the Tariff, subject to regulation by the Commission.

1.79  Kilowatt is a kilowatthour per hour.

1.80 Large End User is an End User Participant which is considered for this
purpose to be (a) a single end user with a peak monthly demand (non- coincident)
for load in New England, including load served by End User Behind-the-Meter
Generation, of at least one (1) megawatt, or (b) a group of two or more
corporate entities each with a peak monthly demand (non- coincident) for load in
New England, including load served by End User Behind-the-Meter Generation, of
at least 0.35 megawatts that together totals at least one (1) megawatt.

1.81  Liaison Committee is the committee whose responsibilities are specified
in Section 11C.

1.82 Load * (in Kilowatts) of a Participant during any particular hour is the
total during such hour (eliminating any distortion arising out of (i)
Interchange Transactions, or (ii) transactions across the system of such
Participant, or (iii) deliveries between Entities constituting a single
Participant, or (iv) other electrical losses, if and as appropriate) of

(a) kilowatthours provided by such Participant to its retail customers for
consumption (excluding any kilowatthours which may be classified as
interruptible under Market Rules approved by the Markets Committee), plus

(b)  kilowatthours delivered by such Participant pursuant to Firm Contracts
to its wholesale customers for resale, plus

(c)  kilowatthours of use by such Participant, exclusive of use by such
Participant for the operation and maintenance of its generating unit or
units, plus

(d)  kilowatthours of electrical losses and unaccounted for use by the
Participant on its system.

The Load of a Participant may be calculated in any reasonable manner which
substantially complies with this definition.

For the purposes of calculating a Participant's Annual Peak, Adjusted Monthly
Peak, Adjusted Annual Peak and Monthly Peak, the Load of a Participant shall be
adjusted to eliminate any distortions resulting from voltage reductions. In
addition, upon the request of any Participant, the Markets Committee shall make,
or supervise the making of, appropriate adjustments in the computation of Load
for the purposes of calculating any Participant's Annual Peak, Adjusted Monthly
Peak, Adjusted Annual Peak and Monthly Peak to eliminate any distortions
resulting from emergency load curtailments which would significantly affect the
Load of any Participant.

1.83 Load Asset Contract is a transaction for the transfer of responsibility for
Electrical Load (and may include Electrical Load qualifying as Dispatchable
Load), Installed Capability, or the rights to compensation for Operating Reserve
to the extent the transfer relates to Dispatchable Load, the terms of which
shall conform to the requirements of applicable Market Rules.

1.84 Load Zone is a Reliability Region, except as otherwise provided in Section
14A.12(b) of the Agreement and Schedule 13 of the Tariff.

1.85 Local Network is the transmission facilities constituting a local network
identified on Attachment E to the Tariff, and any other local network or change
in the designation of a Local Network as a Local Network which the Participants
Committee may designate or approve from time to time. The Participants Committee
may not unreasonably withhold approval of a request by a Participant that it
effect such a change or designation.

1.86 Local Network Service is the service provided, under a separate tariff or
contract, by a Participant that is a Transmission Provider to another
Participant, or other entity connected to the Transmission Provider's Local
Network to permit the other Participant or entity to efficiently and
economically utilize its resources to serve its load.

1.87  Location is a Node, External Node, Load Zone, or Hub.

1.88 Locational Price is the price of Energy at a Location or Reliability
Region, calculated in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff. The Locational Price for a Node is the Nodal Price at
that Node; the Locational Price for an External Node is the Nodal Price at that
External Node; the Locational Price for a Load Zone or Reliability Region is the
Zonal Price for that Load Zone or Reliability Region, respectively; and the
Locational Price for a Hub is the Hub Price for that Hub.

1.89 Lost Opportunity Cost is the amount determined for a Resource, other than a
Dispatchable Load, in accordance with Section 14A.13(d).

1.90 Lower Voltage PTF are all PTF facilities other than EHV PTF.

1.91 Marginal Loss is the additional Energy required to overcome transmission
losses or the decrease in Energy consumed through losses on the NEPOOL
Transmission System associated with serving a small increment of demand at a
Node or External Node. The cost of Marginal Losses at each Location, relative to
the cost of Marginal Losses at the Reference Node, is reflected in the Marginal
Loss Component of the Locational Price at that Location.

1.92 Marginal Loss Component is the component of the Nodal Price at a given Node
or External Node that reflects the Marginal Loss at that Node or External Node.
When used in connection with Hub Price or Zonal Price, the term Marginal Loss
Component refers to the Marginal Loss Components of the Nodal Prices that
comprise the Hub Price or Zonal Price, which Marginal Loss Components are
averaged or weighted in the same way that Nodal Prices are averaged or weighted
to determine the Hub Price and Zonal Price, respectively.

1.93 Marginal Loss Revenue for each hour is the surplus revenue, if any, that is
collected by the System Operator after netting payments for Energy under
Sections 14A.8 and 14A.9, and subtracting Congestion Revenue, as settled in
accordance with the Market Rules.

1.94 Marginal Loss Revenue Fund is the fund of Marginal Loss Revenue
administered by the System Operator in accordance with Section 14A.16 of the
Agreement, Schedule 13 of the Tariff, and the applicable Market Rules.

1.95  Market Products are Installed Capability, Operable Capability, Energy,
each category of Operating Reserve and AGC.

1.96 Market Rules are the system rules and operating procedures adopted pursuant
to the System Operator Agreement in connection with the administration of the
NEPOOL Market.

1.97 Markets Committee is the committee whose responsibilities are specified in
Section 10 and which may have additional responsibilities under a proper
delegation of authority by the Participants Committee. To the extent
practicable, references in the Agreement to the Markets Committee shall include
the prior Regional Market Operations Committee as the predecessor of the Markets
Committee.

1.98 Megawatt is a measure of the rate at which Energy is produced and is equal
to a megawatthour per hour. Use of the term Megawatt shall be construed to
include fractional Megawatts.

1.99 Monthly Peak of a Participant for a month is the maximum Adjusted Load of
the Participant during any hour in the month.

1.100  MSS is the multi-settlement system provided for in Section 14A.

1.101 NEPOOL is the New England Power Pool, the power pool created under and
governed by this Agreement, and the Entities collectively participating in the
New England Power Pool as Participants.

1.102 NEPOOL Control Area is the integrated electric power system to which a
common Automatic Generation Control scheme and various operating procedures are
applied by or under the supervision of the System Operator in order to:

(i) match, at all times, the power output of the generators within the electric
power system and capacity and Energy purchased from entities outside the
electric power system, with the load within the electric power system;

(ii) maintain scheduled interchange with other interconnected systems, within
the limits of Accepted Electric Industry Practice;

(iii) maintain the frequency of the electric power system within reasonable
limits in accordance with Accepted Electric Industry Practice and the criteria
of the NPCC and NERC; and

(iv) provide sufficient generating capacity to maintain operating reserves in
accordance with Accepted Electric Industry Practice.

1.103 NEPOOL Installed Capability at any particular time is the sum of the
Installed System Capabilities of all Participants at such time.

1.104 NEPOOL Installed Capability Responsibility for any month is the sum of the
Installed Capability Responsibilities of all Participants during that month.

1.105 NEPOOL Objective Capability for any year or period during a year is the
minimum NEPOOL Installed Capability, treating the reliability benefits of the HQ
Interconnection as Installed Capability, as established by the Participants
Committee, required to be provided by the Participants in aggregate for the
period to meet the reliability standards established by the Participants
Committee pursuant to Section 7.5(e).

1.106 NEPOOL Market is the market for electric energy, capacity and certain
ancillary services within the NEPOOL Control Area.

1.107 NEPOOL System Rules are the Market Rules, the NEPOOL Information Policy,
the Administrative Procedures, the Reliability Standards and any other system
rules, procedures or criteria for the operation of the NEPOOL System and
administration of the NEPOOL Market, the NEPOOL Agreement and the NEPOOL Tariff.

1.108  NEPOOL Transmission System is the system of transmission facilities
defined as PTF.

1.109  NERCis the North American Electric Reliability Council.

1.110 {Net Hourly Load Obligation for Energy ("NHLO") of a Participant for an
hour is an amount equal to (i) the Participant's Electrical Load for the hour,
(ii) plus or minus, as appropriate, the Settlement Obligations for Energy which
the Participant transfers to or assumes from another Participant pursuant to a
Bilateral Transaction (other than a Load Asset Contract already reflected in the
determination of the Participant's Electrical Load) in which the quantity of
Settlement Obligation for Energy transferred from the Participant purchaser to
the Participant seller thereunder is expressed in terms of a percentage (with or
without an optional cap on the total transfer) of the Participant purchaser's
Energy obligation, where the obligation is calculated as the Electrical Load of
the Participant purchaser less megawatthours of Energy sales by the Participant
purchaser to Non- Participants. The Bilateral Transaction identified in (ii)
includes a transaction which is submitted in accordance with Market Rule 4,
Appendix 4- D, "Internal Obligation Transfer Contracts" and is described in the
second bullets of Market Rule 12, Appendix 12-A-1, Sections B.IIa.4 and D.II.a4,
as such Market Rules were in effect on December 31, 1999.}

1.111 New Unit is an electric generating unit (including a unit or units owned
by a Non-Participant in which a Participant has an Entitlement under a Unit
Contract) first placed into commercial operation after May 1, 1987 (or, in the
case of a unit or units owned by a Non-Participant, in which a Participant's
Unit Contract Entitlement became effective after May 1, 1987) and not listed on
Exhibit B to the Prior NEPOOL Agreement.

1.112 No-Load Price is the price, in dollars per hour, for a generating unit
that must be paid to Participants with Energy Entitlements in the unit for being
scheduled in the Day-Ahead Market, in addition to the Start-Up Price and Supply
Offer Price for Energy, for each hour that the generating unit is scheduled in
the Day-Ahead Market.

1.113 Nodal Price in each hour of the Dispatch Day in the Day-Ahead Market and
Real-Time Market is the price for Energy received or furnished at a Node or
External Node in the hour, as calculated in accordance with Section 14A.12 of
the Agreement and Schedule 13 of the Tariff.

1.114 Node is a point on the NEPOOL Transmission System where Energy is received
or furnished, and for which Nodal Prices are calculated.

1.115  Non-Participant is any entity which is not a Participant.

1.116  NPCC is the Northeast Power Coordinating Council.

1.117  OASIS is the Open Access Same-Time Information System of the System
Operator.

1.118 Operable Capability of an electric generating unit or units in any hour is
the portion of the Installed Capability of the unit or units which is operating
or available to respond within an appropriate period (as identified in Market
Rules approved by the Markets Committee) to the System Operator's call to meet
the Energy and/or Operating Reserve and/or AGC requirements of the NEPOOL
Control Area during a Scheduled Dispatch Period or is available to respond
within an appropriate period to a schedule submitted by a Participant for the
hour in accordance with Market Rules approved by the Markets Committee.

1.119 Operating Reserve is any or a combination of 10-Minute Spinning Reserve,
10-Minute Non-Spinning Reserve, and 30-Minute Operating Reserve, as the context
requires.

1.120 Operating Reserve Entitlement is the right to all or a portion of the
Operating Reserve of any category which can be provided by a Resource to which
an Entity is entitled as an owner (either sole or in common), as a supplier of
Dispatchable Load, or as a purchaser pursuant to a Unit Contract, reduced by any
portion thereof which such Entity is selling pursuant to a Unit Contract. An
Operating Reserve Entitlement in any category relating to a generating unit or
units may, but need not, be combined with any other Entitlements relating to
such generating unit or units and may be transferred separately from the other
categories of Operating Reserve Entitlements related to such unit or units and
from the related Installed Capability Entitlement, Energy Entitlement[, 4-Hour
Reserve Entitlement] or AGC Entitlement.

1.121 Other HQ Energy is Energy purchased under the HQ Phase I Energy Contract
which is classified as "Other Energy" under that contract.

1.122 Participant is an eligible Entity (or group of Entities which has elected
to be treated as a single Participant pursuant to Section 4.1) which is a
signatory to this Agreement and has become a Participant in accordance with
Section 3.1 until such time as such Entity's status as a Participant terminates
pursuant to Section 21.2.

1.123 Participants Committee is the committee whose responsibilities are
specified in Section 7. To the extent applicable, references in the Agreement to
the Participants Committee shall include the prior Management Committee or
Executive Committee as the predecessor of the Participants Committee.

1.124 Pool-Planned Facility is a generation or transmission facility designated
as "pool-planned" pursuant to Section 18.1.

1.125 Pool-Planned Unit is one of the following units: New Haven Harbor Unit 1
(Coke Works), Mystic Unit 7, Canal Unit 2, Potter Unit 2, Wyman Unit 4, Stony
Brook Units 1, 1A, 1B, 1C, 2A and 2B, Millstone Unit 3, Seabrook Unit 1 and
Waters River Unit 2 (to the extent of 7 megawatts of its Summer Capability and
12 megawatts of its Winter Capability).

1.126 Power Year is (i) the period of twelve (12) months commencing on November
1, in each year to and including 1997; (ii) the period of seven (7) months
commencing on November 1, 1998; and (iii) the period of twelve (12) months
commencing on June 1, 1999 and each June 1 thereafter.

1.127 Prior NEPOOL Agreement is the NEPOOL Agreement as in effect on December 1,
1996.

1.128 Proxy Unit is a hypothetical electric generating unit which possesses a
Winter Capability, equivalent forced outage rate, annual maintenance outage
requirement, and seasonal derating determined in accordance with Section
12.2(a)(2).

1.129 PTF are the pool transmission facilities defined in Section 15.1, and any
other new transmission facilities which the Reliability Committee determines, in
accordance with criteria approved by the Participants Committee and subject to
review by the System Operator, should be included in PTF.

1.130 Publicly Owned Entity is an Entity which is either a municipality or an
agency thereof, or a body politic and public corporation created under the
authority of one of the New England states, authorized to own, lease and operate
electric generation, transmission or distribution facilities, or an electric
cooperative, or an organization of any such entities.

1.131 Real-Time is a current period of a Dispatch Day for which the System
Operator dispatches Resources for Energy and AGC, designates Resources for AGC
and Operating Reserve and, if necessary, activates 4-Hour Reserves.

1.132 Real-Time Market is the market provided for in Section 14A in which
obligations and prices with respect to Energy, Operating Reserve, 4-Hour Reserve
and AGC are determined from the actual dispatch and designations by the System
Operator during a Dispatch Day, based on applicable Demand Bids and Supply
Offers and NEPOOL System Rules.

1.133 Reference Node is the Node identified by the System Operator in accordance
with the NEPOOL System Rules relative to which all mathematical quantities
pertaining to physical operation, including Shift Factors and Withdrawal
Factors, shall be calculated with respect to the dispatch of the system and the
derivation of Locational Prices.

1.134 Regional Network Serviceis the transmission service by that name provided
pursuant to Section 14 of the Tariff.

1.135  Related Personof a Participant is:

(a) for all Participants, either (i) a corporation, partnership, business trust
or other business organization 10% or more of the stock or equity interest in
which is owned directly or indirectly by, or is under common control with, the
Participant, or (ii) a corporation, partnership, business trust or other
business organization which owns directly or indirectly 10% or more of the stock
or other equity interest in the Participant, or (iii) a corporation,
partnership, business trust or other business organization 10% or more of the
stock or other equity interest in which is owned directly or indirectly by a
corporation, partnership, business trust or other business organization which
also owns 10% or more of the stock or other equity interest in the Participant,
or (iv) a natural person, or a member of such natural person's immediate family,
who is, or within the last 12 months has been, an officer, director, partner,
employee, or representative in NEPOOL activities of, or natural person having a
material ongoing business or professional relationship directly related to
NEPOOL activities with, the Participant or any corporation, partnership,
business trust or other business organization related to the Participant
pursuant to clauses (i), (ii) or (iii) of this Section 1.135(a); and

(b) for all End User Participants which are also natural persons, a Related
Person is (i) a member of such End User's immediate family, or (ii) a
Participant and any corporation, partnership, business trust, or other business
organization related to the Participant pursuant to clauses (i), (ii) or (iii)
of Section 1.135(a), of which such End User Participant, or a member of such End
User Participant's immediate family, is, or within the last twelve (12) months
has been, an officer, director, partner, or employee of, or with which an
individual End User Participant has, or within the last twelve (12) months had,
a material ongoing business or professional relationship directly related to
NEPOOL activities, or (iii) another Participant which, within the last twelve
(12) months, has paid a portion of the End User Participant's expenses under
Section 19 of this Agreement, or (iv) a corporation, partnership, business trust
or other business organization in which the End User Participant owns stock
and/or equity with a fair market value in excess of $50,000.

(c) Notwithstanding the foregoing, for the purposes of this definition, an
individual shall not be deemed to have or had a material on-going business
relationship directly related to NEPOOL activities with any corporation,
partnership, business trust, other business organization or Publicly Owned
Entity solely as a result of being served, as a customer, with electricity or
gas.

1.136 Reliability Committee is the committee whose responsibilities are
specified in Section 8 and which may have additional responsibilities under a
proper delegation of authority by the Participants Committee. To the extent
practicable, references in the Agreement to the Reliability Committee shall
include the prior Market Reliability Planning Committee or the prior Regional
Transmission Planning Committee as the predecessor of the Reliability Committee.

1.137 Reliability Standards are those rules, standards, procedures and protocols
approved by the Participants Committee pursuant to Section 7.3, or its
predecessors, that set forth specifics concerning how the System Operator shall
exercise its authority over matters pertaining to the reliability of the bulk
power system.

1.138 Reliability Must Run is a Resource or portion of a Resource that is
scheduled in the Day-Ahead Market by the System Operator out of merit in order
to create sufficient local Operating Reserve to preserve reliability within a
Reliability Region.

1.139 Reliability Region is, as of March 31, 2000, any one of the regions
identified in Attachment C to the Agreement. Subsequent to March 31, 2000, the
System Operator, in a filing with the Commission and following consultation with
the Reliability Committee, may reconfigure Reliability Regions and add or
subtract Reliability Regions as necessary over time to reflect changes to the
grid or changes in patterns of usage and intra-zonal Congestion. Reliability
Regions reflect the operating characteristics of, and the major transmission
constraints on, the NEPOOL Transmission System.

1.140 {Reserve Contract is a contract entered into pursuant to Section 14A.10(c)
between the System Operator and a Participant under which the Participant agrees
to furnish 10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve and/or
4-Hour Reserve.}

1.141 {Reserve Price is the price a Participant agrees to accept in a Reserve
Contract for furnishing 10-Minute Non-Spinning Reserve, 30-Minute Operating
Reserve and/or 4-Hour Reserve.}

1.142 Resource means a generating unit, a Dispatchable Load, or a Supply Offer
to supply service from another Control Area at an External Node.

1.143  Review Boardis the board whose responsibilities are specified in
Section 11A.

1.144  RMR is Reliability Must Run.

1.145 RMR Charge is the charge to Participants pursuant to Section 14A.19(d) to
recover RMR Uplift.

1.146 RMR Uplift is the uplift for RMR determined in accordance with Section
14A.19(d).

1.147 Scheduled Dispatch Period is the shortest period for which the System
Operator performs and publishes a projected dispatch schedule based on projected
Electrical Load and actual Bid Prices and Participant-directed schedules for
Resources submitted in accordance with Section 14.2(d) until the CMS/MSS
Effective Date, and based on projected Electrical Load, Demand Bids, Supply
Offers, and Self-Schedules and Self-Supplies submitted in accordance with
applicable Market Rules for periods on and after the CMS/MSS Effective Date.

1.148  Second Effective Date is May 1, 1999.

1.149  Sector has the meaning specified in Section 6.2.

1.149A Self-Schedule is the action of a Participant in scheduling its Resource,
in accordance with applicable Market Rules, to provide service in an hour,
whether or not in the absence of that action the Resource would have been
scheduled or dispatched to provide the service by the System Operator.

1.149B Self-Supply is the action of a Participant in designating its Resource in
accordance with applicable Market Rules to meet its own service requirements in
whole or in part.

1.150 Service Agreement is the initial agreement and any amendments or
supplements thereto entered into by the Transmission Customer and the System
Operator for service under the Tariff.

1.151 Settlement Obligation prior to the CMS/MSS Effective Date, is an
obligation as defined in Section 14.1(a) for Energy, Section 14.1(b) for
Operating Reserve and Section 14.1(c) for AGC, and all applicable Market Rules
and, on and after the CMS/MSS Effective Date, is an obligation as defined in
Section 14A.1(b) for Energy, Section 14A.1(c) for Operating Reserve, Section
14A.1(d) for 4-Hour Reserve and Section 14A.1(e) for AGC, and all applicable
Market Rules.

1.152 Shift Factor is the factor which relates to the change in power flow over
the PTF that results from an increment of generation at a given Node or External
Node and a corresponding increment of load at the Reference Node, relative to
the size of the increment of generation. Shift Factors are used to calculate
Locational Prices in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.

1.153 Small End User is a End User Participant which does not otherwise meet the
definition of Large End User or End User Organization.

1.154 Standard Offer Obligation has the meaning specified in Section
14A.12(b)(ii) of the Agreement and Schedule 13 of the Tariff.

1.155 Start-Up Price is the price, in dollars, that must be paid for a
generating unit to Participants with Energy Entitlements in the unit each time
the unit is scheduled in the Day-Ahead Market to start up.

1.156 Summer Capability of an electric generating unit or combination of units
is the maximum dependable load carrying ability in Kilowatts of such unit or
units (exclusive of capacity required for station use) during the Summer Period,
as determined by the Markets Committee in accordance with Section 10.4(d).

1.157 Summer Period in each Power Year is the four-month period from June
through September.

1.158 Supply Obligation is an obligation as defined in Section 14A.1(a) for
Energy, Operating Reserve, 4-Hour Reserve, and/or AGC.

1.159 Supply Offer is a proposal to furnish Energy at a Node or External Node,
Operating Reserve, 4-Hour Reserve and/or AGC from a Resource that meets the
applicable requirements set forth in the Market Rules that a Participant with
Supply Offer authority for the Resource submits to the System Operator pursuant
to the Agreement and applicable Market Rules, and includes a Supply Offer Price
and information with respect to the quantity proposed to be furnished, technical
parameters for the Resource, timing and other matters.

1.160 Supply Offer Price is the price specified to the System Operator in a
Supply Offer to provide Energy, Operating Reserve, AGC and/or 4-Hour Reserve
from a Resource pursuant to this Agreement and applicable Market Rules.

1.161 System Contract is any contract for the purchase of Installed Capability,
Energy [at a Location], Operating Reserves[, 4-Hour Reserves] and/or AGC, other
than a Unit Contract, pursuant to which the purchaser is entitled to a
specifically determined or determinable amount of such Installed Capability,
Energy, Operating Reserves[, 4-Hour Reserves] and/or AGC.

1.162 System Impact Study is an assessment pursuant to Part V, VI or VII of the
Tariff of (i) the adequacy of the NEPOOL Transmission System to accommodate a
request for the interconnection of a new or materially changed generating unit
or a new or materially changed interconnection to another Control Area or new
Regional Network Service, Internal Point-to-Point Service or Through or Out
Service, and (ii) whether any additional costs may be required to be incurred in
order to provide the interconnection or transmission service.

1.163 System Operator is the central dispatching agency provided for in this
Agreement which has responsibility for the operation of the NEPOOL Control Area
from the NEPOOL control center and the administration of the Tariff. The System
Operator is ISO New England Inc., unless replaced by a substitute independent
system operator, a regional transmission organization or an entity that forms a
part of a regional transmission organization that has, in each case, been
approved by the Commission.

1.164 Target Availability Rate is the assumed availability of a type of
generating unit utilized by the Participants Committee in its determination
pursuant to Section 7.5(e) of NEPOOL Objective Capability.

1.165 Tariff is the NEPOOL Open Access Transmission Tariff set out in Attachment
B to the Agreement, as modified and amended from time to time.

1.166 Tariff Committee is the committee whose responsibilities are specified in
Section 9 and which may have additional responsibilities under a proper
delegation of authority by the Participants Committee. To the extent
practicable, references in the Agreement to the Tariff Committee shall include
the prior Regional Transmission Operations Committee as the predecessor of the
Tariff Committee.

1.167  Technical Committees are the Reliability Committee, the Tariff
Committee and the Markets Committee.

1.168 Third Effective Date is the date on which all Interchange Transactions
shall begin to be effected on the basis of separate Bid Prices for each type of
Entitlement. The Third Effective Date shall be fixed at the discretion of the
Participants Committee to occur within six months to one year after the Second
Effective Date, or at such later date as the Commission may fix on its own or
pursuant to a request by the Participants Committee.

1.169 Through or Out Service is the transmission service by that name provided
pursuant to Section 18 of the Tariff.

1.170 Transition Period is the six- year period commencing on March 1, 1997.

1.171 Transmission Customer is any Eligible Customer that (i) is a Participant
which is not required to sign a Service Agreement with respect to a service to
be furnished to it in accordance with Section 48 of the Tariff or (ii) executes,
on its own behalf or through its Designated Agent, a Service Agreement, or (iii)
requests in writing, on its own behalf or through its Designated Agent, that
NEPOOL file with the Commission a proposed unexecuted Service Agreement in order
that the Eligible Customer may receive transmission service under the Tariff.

1.172 Transmission Owner is a Transmission Provider which makes its PTF
available under the Tariff and owns a Local Network listed in Attachment E to
the Tariff which is not a Publicly Owned Entity, including any affiliate of a
Transmission Provider that owns transmission facilities that are made available
as part of the Transmission Provider's Local Network; provided that if a
Transmission Provider is not listed in Attachment E to the Tariff on May 10,
1999, the Transmission Provider must also (i) own, or lease with rights
equivalent to ownership, PTF with an original capital investment in its PTF as
of the end of the most recent year for which figures are available from annual
reports submitted to the Commission in Form 1 or any similar form containing
comparable annualized data of at least $30,000,000, and (ii) provide
transmission service to non-affiliated customers pursuant to an open access
transmission tariff on file with the Commission.

1.173 Transmission Owners Committee is the committee whose responsibilities are
specified in Section 11B.

1.174 Transmission Provider is the Participants, collectively, which own PTF and
are in the business of providing transmission service or provide service under a
local open access transmission tariff, or in the case of a state or municipal or
cooperatively-owned Participant, would be required to do so if requested
pursuant to the reciprocity requirements specified in the Tariff, or an
individual such Participant, whichever is appropriate.

1.175 Unit Contract is a purchase contract pursuant to which the purchaser is in
effect currently entitled, [at a specified Location], either (i) to a
specifically determined or determinable portion of the capability of a specific
electric generating unit or units, or (ii) to a specifically determined or
determinable amount of Installed Capability, Energy, Operating Reserves[, 4-Hour
Reserves] and/or AGC if, or to the extent that, a specific electric generating
unit or units is or can be operated.

1.176 Withdrawal Factor is the factor which measures the proportion of a small
increment of power injected at a given Node that can be withdrawn at the
Reference Node (with any difference between the amounts injected and withdrawn
attributable to Marginal Losses). Withdrawal Factors are used to calculate
Locational Prices in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.

1.177 Winter Capability of an electric generating unit or combination of units
is the maximum dependable load carrying ability in Kilowatts of such unit or
units (exclusive of capacity required for station use) during the Winter Period,
as determined by the Markets Committee in accordance with Section 10.4(d).

1.178 Winter Period in each Power Year is (i) the seven-month period from
November through May and the month of October for the Power Year commencing on
November 1 in 1997 or a prior Power Year; (ii) the seven-month period from
November through May for the Power Year commencing on November 1, 1998; and
(iii) the eight-month period from October through May for the Power Year
commencing on June 1, 1999 and each June 1 thereafter.

1.179 Zonal Price in each hour of the Dispatch Day in the Day-Ahead Market and
the Real-Time Market is the price for Energy received in a Load Zone or
Reliability Region in the hour, as calculated in accordance with Section 14A.12
of the Agreement and Schedule 13 of the Tariff.

1.180 4-Hour Reserve is an option for Energy, which can be called upon by the
System Operator in one or more hours of the Dispatch Day for at least the
minimum period defined in the NEPOOL System Rules and for the number of hours
offered and at Energy prices at least equal to the prices set forth in a Day-
Ahead Supply Offer (unless such prices are reduced in a Real-Time Supply Offer)
and to or from which Energy can be adjusted within four hours in response to
dispatch instructions and in accordance with applicable NEPOOL System Rules,
from one of the following Resources to the extent the Resource providing 4-Hour
Reserve has not been scheduled to provide Energy, Operating Reserve or AGC in
the Day-Ahead Market: (i) a generating unit capable of providing Energy; (ii) a
load capable of reducing its consumption of Energy within four hours, including
Demand Bids at External Nodes; and (iii) to the extent permitted by applicable
NEPOOL System Rules, a Supply Offer to supply Energy from another Control Area
at an External Node.

1.181 4-Hour Reserve Entitlement is the right for the purpose of satisfying a
Supply Obligation for Energy from all or a portion of the 4-Hour Reserve which
can be provided by a Resource to which an Entity is entitled as an owner (either
sole or in common), as a supplier of load or as a purchaser pursuant to a Unit
Contract, reduced by any portion thereof which such Entity is selling pursuant
to a Unit Contract. A 4-Hour Reserve Entitlement in a generating unit or units
may, but need not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the related
{Installed Capability Entitlement,} Energy Entitlement, Operating Reserve
Entitlement or AGC Entitlement.

1.182  10-Minute Spinning Reserve

(a) Until the CMS/MSS Effective Date, in an hour is the contingency protection
benefit for the system available from the combination of the following Resources
that are designated by the System Operator in accordance with the Market Rules
to be available: (i) the Megawatts available from an electric generating unit or
units that are synchronized to the system (including units outside the NEPOOL
Control Area to the extent permitted by applicable Market Rules), unloaded
during all or part of the hour, and capable of providing contingency protection
by loading to supply Energy immediately on demand, increasing the Energy output
over no more than ten minutes to the full amount of generating capacity so
designated, and sustaining such Energy output for so long as the System Operator
determines in accordance with the Market Rules is necessary; and (ii) any
Dispatchable Load of a Participant that the System Operator is able to verify as
capable of providing contingency protection by immediately on demand reducing
Energy requirements within ten minutes and maintaining such reduced Energy
requirements for so long as the System Operator determines in accordance with
the Market Rules is necessary.

(b) On and after the CMS/MSS Effective Date, in an hour is an option for Energy,
which can be called upon by the System Operator in such hour at Energy prices at
least equal to the prices set forth in a Day-Ahead Supply Offer (unless such
prices are reduced in a Real-Time Supply Offer), from one of the following
Resources to the extent the Resource in the Day-Ahead Market has not been
scheduled or in the Real-Time Market has not been dispatched for Energy and to
or from which Energy can be adjusted within ten (10) minutes in response to
dispatch instructions and sustaining such adjusted level of Energy for so long
as the System Operator determines in accordance with the Market Rules is
necessary: (i) a generating unit that is synchronized to the system; or (ii) a
Dispatchable Load; and (iii) to the extent permitted by applicable Market Rules,
a Supply Offer to supply Energy from another Control Area at an External Node.

1.183  10-Minute Non-Spinning Reserve

(a) Until the CMS/MSS Effective Date, in an hour is the contingency protection
benefit for the system available from the combination of the following Resources
that are designated by the System Operator in accordance with the Market Rules
to be available: (i) the Megawatts available from an electric generating unit or
units that are not synchronized to the system (including units outside the
NEPOOL Control Area to the extent permitted by applicable Market Rules), during
all or part of the hour, and capable of providing contingency protection by
loading to supply Energy within ten minutes to the full amount of generating
capacity so designated, and sustaining such Energy output for so long as the
System Operator determines in accordance with the Market Rules is necessary;
(ii) any Dispatchable Load of a Participant that the System Operator is able to
verify as capable of providing contingency protection by reducing Energy
requirements within ten minutes and maintaining such reduced Energy requirements
for so long as the System Operator determines in accordance with the Market
Rules is necessary; and (3) any other Resources that were able to be designated
for the hour as 10-Minute Spinning Reserve but were not designated by the System
Operator for such purpose in the hour.

(b) On and after the CMS/MSS Effective Date, in an hour is an option for Energy,
which can be called upon by the System Operator in such hour at Energy prices at
least equal to the prices set forth in a Day-Ahead Supply Offer (unless such
prices are reduced in a Real-Time Supply Offer), from one of the following
Resources to the extent the Resource in the Day-Ahead Market has not been
scheduled or in the Real-Time Market has not been dispatched for Energy or for
AGC or 10-Minute Spinning Reserve, and to or from which Energy can be adjusted
within ten (10) minutes in response to dispatch instructions and which is
capable of sustaining such adjusted level of Energy for so long as the System
Operator determines in accordance with Market Rules is necessary: (i) a
generating unit capable of providing such Energy; (ii) a Dispatchable Load; and
(iii) to the extent permitted by applicable Market Rules, a Supply Offer to
supply Energy from another Control Area at an External Node.

1.184  30-Minute Operating Reserve

(a) Until the CMS/MSS Effective Date, in an hour is the contingency protection
benefit for the system available from the combination of the following Resources
that are designated by the System Operator in accordance with the Market Rules
to be available: (i) the Megawatts available from an electric generating unit or
units (including units outside the NEPOOL Control Area to the extent permitted
by applicable Market Rules) that are capable of providing contingency protection
by loading to supply Energy within thirty minutes of demand at an output equal
to its full amount of generating capacity so designated and sustaining Energy
output for so long as the System Operator determines in accordance with the
Market Rules is necessary; (ii) any Dispatchable Load of a Participant that the
System Operator is able to verify as capable of providing contingency protection
by reducing Energy requirements within thirty minutes and maintaining such
reduced Energy requirements for so long as the System Operator determines in
accordance with the Market Rules is necessary; and (3) any other Resources that
were able to be designated for the hour as 10-Minute Spinning Reserve or
10-Minute Non- Spinning Reserve but were not designated by the System Operator
for such purposes in the hour.

(b) On and after the CMS/MSS Effective Date, in an hour is an option for Energy,
which can be called upon by the System Operator in such hour at Energy prices at
least equal to the prices set forth in a Day-Ahead Supply Offer (unless such
prices are reduced in a Real-Time Supply Offer) from one of the following
Resources to the extent the Resource in the Day-Ahead Market has not been
scheduled or in the Real-Time Market has not been dispatched for Energy or
designated for AGC, 10-Minute Spinning Reserve, or 10-Minute Non- Spinning
Reserve, and to or from which Energy can be adjusted in response to dispatch
instructions within thirty (30) minutes and which are capable of sustaining such
adjusted level of Energy for so long as the System Operator determines in
accordance with the Market Rules is necessary: (i) a generating unit capable of
providing such Energy; (ii) a Dispatchable Load; and (iii) to the extent
provided in applicable Market Rules, a Supply Offer to supply Energy from
another Control Area at an External Node.

1.185  Modification of Certain Definitions When a Participant Purchases a
Portion of Its Requirements from Another Participant Pursuant to Firm
Contract.

Definitions marked by an asterisk (*) are modified as follows when a Participant
purchases a portion of its requirements of electricity from another Participant
pursuant to a Firm Contract:

(a) If the Firm Contract limits deliveries to a specifically stated number of
Kilowatts and requires payment of a demand charge thereon (thus placing the
responsibility for meeting additional demands on the purchasing Participant):

(1) in computing the Adjusted Load of the purchasing Participant, the Kilowatts
received pursuant to such Firm Contract shall be deemed to be the number of
Kilowatts specified in the Firm Contract; and

(2) in computing the Load of the supplying Participant, the Kilowatts delivered
pursuant to such Firm Contract shall be deemed to be the number of Kilowatts
specified in the Firm Contract.

(b) If the Firm Contract does not limit deliveries to a specifically stated
number of Kilowatts, but entitles the Participant to receive such amounts of
electricity as it may require to supply its electric needs (thus placing the
responsibility for meeting additional demands on the supplying Participant):

(1)  the Installed Capability Responsibility of the purchasing Participant
shall be equal to the amount of its Installed Capability Entitlements;

(2) in computing the Adjusted Load of the purchasing Participant, the Kilowatts
received pursuant to such Firm Contract shall be deemed to be a quantity Rl; and

(3) in computing the Load of the supplying Participant, the Kilowatts delivered
pursuant to such Firm Contract shall be deemed to be a quantity Rl. The quantity
Rl equals (i) the Load of the purchasing Participant less (ii) the amount of the
purchasing Participant's Installed Capability Entitlements multiplied by a
fraction (EQUATION) wherein:

X  is the maximum Load of the purchasing Participant in the month, and

Y is the NEPOOL Installed Capability Responsibility multiplied by the purchasing
Participant's fraction P determined pursuant to Section 12.2(a)(1), computed as
if the Firm Contract did not exist.

Terms used in this Agreement that are not defined above, or in the sections in
which such terms are used, shall have the meanings customarily attributed to
such terms in the electric power industry in New England.

[Next Sheet is 58]



                                    SECTION 2

                            PURPOSE; EFFECTIVE DATES

2.1 Purpose. This Restated NEPOOL Agreement is intended to provide for a
restructuring of the New England Power Pool by modifying the pool's governance
and market provisions to take account of a changed competitive environment, by
modifying the transmission responsibilities of the Participants so that the pool
will perform the functions of a regional transmission group and provide service
to Participants and Non-Participants under a regional open access transmission
tariff, and by providing for the activation of the ISO and the execution of a
contract between the ISO and NEPOOL to define the ISO's responsibilities.

2.2 Effective Dates; Transitional Provisions. The provisions of Parts One, Two,
Four and Five of this Agreement and the Tariff became effective on the First
Effective Date and replaced on the First Effective Date the provisions of
Sections 1-8, inclusive, 10, 11, 13, 14.2, 14.3, 14.4 and 16 of the Prior NEPOOL
Agreement. The provisions of Sections 12.1(a), 12.2, 12.4 (as to Installed
Capability only), 12.5 and 12.7(a) of this Agreement became effective on April
1, 1998 and replaced on such date the provisions of Section 9 of the Prior
NEPOOL Agreement.

The effectiveness of the remaining Sections of this Restated NEPOOL Agreement
shall be delayed pending the preparation of implementing criteria, rules and
standards and computer programs. These Sections became effective on the Second
Effective Date and replaced on the Second Effective Date the remaining
provisions of the Prior NEPOOL Agreement, which continued in effect until the
Second Effective Date.

As provided in Section 14, certain portions of Section 14 which became effective
on the Second Effective Date will be superseded on the Third Effective Date by
other portions of Section 14.

[Next Sheet is 60]



                                    SECTION 3
                                   MEMBERSHIP

3.1 Membership. Those Entities which are Participants in NEPOOL on the First
Effective Date shall continue to be Participants. Any other Entity may, upon
compliance with such reasonable conditions as the Participants Committee may
prescribe, become a Participant by depositing a counterpart of this Agreement as
theretofore amended, duly executed by it, with the Secretary of the Participants
Committee, accompanied by a certified copy of a vote of its board of directors,
or such other body or bodies as may be appropriate, duly authorizing its
execution and performance of this Agreement, and a check in payment of the
application fee described below.

Any such Entity which satisfies the requirements of this Section 3.1 shall
become a Participant, and this Agreement shall become fully binding and
effective in accordance with its terms as to such Entity, as of the first day of
the second calendar month following its satisfaction of such requirements;
provided that an earlier or later effective time may be fixed by the
Participants Committee with the concurrence of such Entity or by the Commission.

The application fee to be paid by each Entity seeking to become a Participant
shall be in addition to the annual fee provided by Section 19.1 and shall be
$500 for an applicant which qualifies for membership only as an End User
Participant, and $5,000 for all other applicants, or such other amount as may be
fixed by the Participants Committee.

3.2 Operations Outside the Control Area. Subject to the reciprocity requirements
of the Tariff, if a Participant serves a Load, or has rights in supply or
demand-side resources or owns transmission and/or distribution facilities,
located outside of the NEPOOL Control Area, such Load and resources shall not be
included for purposes of determining the Participant's rights, responsibilities
and obligations under this Agreement, except that the Participant's Entitlements
in facilities or its rights in demand side- resources outside the NEPOOL Control
Area shall be included in such determinations if, to the extent, and while such
Entitlements are used for retail or wholesale sales within the NEPOOL Control
Area or such Entitlements or rights are designated by a Participant for purposes
of meeting its obligations under Section 12 of this Agreement.

3.3 Lack of Place of Business in New England. If and for so long as a
Participant does not have a place of business located in one of the New England
states, the Participant shall be deemed to irrevocably (1) submit to the
jurisdiction of any Connecticut state court or United States Federal court
sitting in Connecticut (the state whose laws govern this Agreement) over any
action or proceeding arising out of or relating to this Agreement that is not
subject to the exclusive jurisdiction of the Commission, (2) agree that all
claims with respect to such action or proceeding may be heard and determined in
such Connecticut state court or Federal court, (3) waive any objection to venue
or any action or proceeding in Connecticut on the basis of forum non conveniens,
and (4) agree that service of process may be made on the Participant outside
Connecticut by certified mail, postage prepaid, mailed to the Participant at the
address of its member on the Participants Committee as set out in the NEPOOL
roster or at the address of its principal place of business.

3.4 Obligation for Deferred Expenses. NEPOOL may provide for the deferral on the
books of the Participants from time to time of capital or other expenditures,
and the recovery of the deferred expenses in subsequent periods. Any Entity
which becomes a Participant during the recovery period for any such deferred
expenses shall be obligated, together with the continuing Participants, for its
share of the current and deferred expenses pursuant to Section 19.2.

3.5 Financial Security. For an Entity applying to become a Participant or any
continuing Participant that the Participants Committee reasonably determines may
fail to meet its financial obligations under the Agreement, the Participants
Committee may require reasonable credit review procedures which shall be made in
accordance with standard commercial practices. In addition, the Participants
Committee may prescribe for such Entity or Participant a requirement that the
Entity or Participant provide and maintain in effect an irrevocable letter of
credit as security to meet its responsibilities and obligations under the
Agreement, or an alternative form of security proposed by the Entity or
Participant and acceptable to the Participants Committee and consistent with
commercial practices established by the Uniform Commercial Code that protects
the Participants against the risk of non-payment.

[Next Sheet is 64]




                                    SECTION 4

                             STATUS OF PARTICIPANTS

4.1 Treatment of Certain Entities as Single Participant. All Entities which are
controlled by a single person (such as a corporation or a business trust) which
owns at least seventy-five percent of the voting shares of, or equity interest
in, each of them shall be collectively treated as a single Participant for
purposes of this Agreement, if they each elect such treatment. They are
encouraged to do so. Such an election shall be made in writing and shall
continue in effect until revoked in writing.

In view of the long-standing arrangements in Vermont, Vermont Electric Power
Company, Inc. and any other Vermont electric utilities which elect in writing to
be grouped with it shall be collectively treated as a single Participant for
purposes of this Agreement; provided, however, that any Vermont electric utility
which is a Publicly Owned Entity may elect to join the Publicly Owned Entity
Sector and be treated as a member of that Sector for purposes of governance,
annual fees and NEPOOL expense allocation, without losing the benefits of single
Participant status for any other purpose under this Agreement.

4.2 Participants to Retain Separate Identities. The signatories to this
Agreement shall not become partners by reason of this Agreement or their
activities hereunder, but as to each other and to third persons, they shall be
and remain independent contractors in all matters relating to this Agreement.
This Agreement shall not be construed to create any liability on the part of any
signatory to anyone not a party to this Agreement. Each signatory shall retain
its separate identity and, to the extent not limited hereby, its individual
freedom in rendering service to its customers.

[Next Sheet is 66]



                                    SECTION 5
                 NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS

5.1 NEPOOL Objectives. The objectives of NEPOOL are, through joint planning,
central dispatching, cooperation in environmental matters and coordinated
construction, central dispatch by the Error! Reference source not found. of the
operation and coordinated maintenance of electric supply and demand-side
resources and transmission facilities, the provision of an open access regional
transmission tariff and the provision of a means for effective coordination with
other power pools and utilities situated in the United States and Canada,

(a)  to assure that the bulk power supply of the NEPOOL Control Area conforms
to proper standards of reliability;

(b) to create and maintain open, non-discriminatory, competitive, unbundled
markets for Energy, capacity, and ancillary services that function efficiently
in a changing electric power industry and have access to regional transmission
at rates that do not vary with distance;

(c) to attain maximum practicable economy, consistent with proper standards of
reliability and the maintenance of competitive markets, in such bulk power
supply; and

(d)  to provide access to competitive markets within the NEPOOL Control Area
and to neighboring regions;

and to provide for equitable sharing of the resulting responsibilities, benefits
and costs.

5.2 Cooperation by Participants. In order to attain the objectives of NEPOOL set
forth in Section 5.1, each Participant shall observe the provisions of this
Agreement in good faith, shall cooperate with all other Participants and shall
not either alone or in conjunction with one or more other Entities take
advantage of the provisions of this Agreement so as to harm another Participant
or to prejudice the position of any Participant in the electric power business.



                                    PART TWO
                                   GOVERNANCE


                                    SECTION 6
                        COMMITTEE ORGANIZATION AND VOTING

6.3  Principal Committees.  There shall be four principal NEPOOL Committees
(the "Principal Committees"), as follows:

(a)  the Participants Committee which shall have the responsibilities
specified in Section 7;

(b)  the Reliability Committee which shall have the responsibilities
specified in Section 8;

(c)  the Tariff Committee which shall have the responsibilities specified in
Section 9; and

(d)  the Markets Committee which shall have the responsibilities specified in
Section 10.

In addition, there shall be a Transmission Owners Committee and a Liaison
Committee, which shall have the responsibilities specified in Sections 11B and
11C, respectively, and such other committees as may be established from time to
time by the Participants Committee.

6.4 Sector Representation. The members of each Principal Committee shall each
belong to a single sector for voting purposes ("Sector"). Each Participant shall
be obligated to designate in a notice to the Secretary of the Participants
Committee a Sector that it or its Related Persons is eligible to join and that
it elects to join for purposes of all of the Principal Committees; provided,
however, that a Participant and the Participants which are its Related Persons
shall not be eligible to join the End User Sector if any one of them is not
eligible to join the End User Sector. A Participant and its Related Persons
shall together be entitled to join only one Sector and shall have no more than
one vote on each Principal Committee.

The Sectors for each Principal Committee, the criteria for eligibility for
membership in each Sector and the minimum requirement which a Participant must
meet as a member of a Sector in order to appoint a voting member of the Sector
and Committee are as follows:

(a) a Generation Sector, which a Participant shall be eligible to join if (i) it
(A) owns or leases with rights equivalent to ownership facilities for the
generation of electric energy that are located within the NEPOOL Control Area
which are currently in operation, or (B) has proposed generation for operation
within the NEPOOL Control Area either which has received approvals under
Sections 18.4 and/or 18.5 within the past two years or for which completed
environmental air or environmental siting applications have been filed or
permits exist, and (ii) it is not a Publicly Owned Entity. Purchasing all or a
portion of the output of a generation facility shall not be sufficient to
qualify a Participant to join the Generation Sector.

A Participant which joins the Generation Sector shall be entitled but not
required to designate an individual voting member of each Principal Committee,
and an alternate to the member, if its operating or proposed generation
facilities in the NEPOOL Control Area have or will have, when placed in
operation, an aggregate Winter Capability of at least 15 MW.

A Participant which joins the Generation Sector but elects not to or is not
eligible to designate an individual voting member, shall be represented by a
group voting member and an alternate to that member for each Principal Committee
(collectively, the "Generation Group Member"). The Generation Group Member shall
be appointed by a majority of the Participants in the Generation Sector electing
or required to be represented by that member. The Generation Group Member shall
have the same percentage of the Sector vote as the individual voting members
designated by other Participants in the Generation Sector which meet the 15 MW
threshold and designate an individual voting member. The Generation Group Member
shall be entitled to split his or her vote.

(b) a Transmission Sector, which a Participant shall be eligible to join if it
is a Transmission Provider and is not a Publicly Owned Entity. Taking
transmission service shall not be sufficient to qualify a Participant to join
the Transmission Sector.

A Participant which joins the Transmission Sector shall be entitled to designate
an individual voting member of each Principal Committee, and an alternate to the
member, if it owns or leases with rights equivalent to ownership PTF with an
original capital investment in its PTF as of the end of the most recent year for
which figures are available from annual reports submitted to the Commission in
Form 1 or any similar form containing comparable annualized data of at least
$30,000,000. A Transmission Provider with facilities which were included as PTF
prior to December 31, 1998 only pursuant to clause (3) of the definition of PTF
pursuant to Section 15.1 shall be entitled to designate an individual voting
member of each Principal Committee, and an alternate to the member, whether or
not PTF which it owns or leases with rights equivalent to ownership which has an
original capital investment of at least $30,000,000, so long as such
Transmission Provider continues to own PTF.

A Participant which joins the Transmission Sector but which is not entitled to
designate an individual voting member of each Principal Committee because (i)
it, together with all of its Related Persons, does not meet the $30,000,000
threshold or (ii) it no longer owns PTF and it does not have a Related Person
that is entitled to designate an individual voting member for each Principal
Committee in another Sector, together with the other Participants in the
Transmission Sector which for the same reasons are unable to designate an
individual voting member, shall be represented by a group voting member of each
Principal Committee (the "Transmission Group Member"), and an alternate to that
member. The Transmission Group Member and alternate shall be appointed by a
majority vote of all Participants in the Transmission Sector required to be
represented by that Member. The Transmission Group Member shall have the same
percentage of the Sector vote as the individual voting members designated by
other Participants in the Transmission Sector which meet the $30,000,000
threshold unless and until the original capital investment in PTF of the
Participants represented by the Transmission Group Member equals or exceeds
twice the $30,000,000 threshold amount. If the aggregate original capital
investment in PTF equals or exceeds twice the $30,000,000 threshold amount, the
percentage of the Sector votes assigned to the Transmission Group Member shall
equal the number of full multiples of the $30,000,000 threshold, provided that
the Transmission Group Member shall in no event be entitled to more than
twenty-five percent (25%) of the Sector vote. For example, if Participants
represented by the Transmission Group Member have an aggregate original capital
investment in PTF in the NEPOOL Control Area totaling $70,000,000, the
Transmission Group Member will have the same percentage of such votes as two
($70,000,000/$30,000,000 Threshold = 2.33) individual voting members designated
by individual Participants, provided that there are at least six other members
in the Sector so the Transmission Group Member does not have more than
twenty-five percent (25%) of the Transmission Sector vote. The Transmission
Group Member shall be entitled to split his or her vote.

(c) a Supplier Sector, which a Participant shall be eligible to join if (i) it
engages in, or is licensed or otherwise authorized by a state or federal agency
with jurisdiction to engage in, power marketing, power brokering or load
aggregation within the NEPOOL Control Area or it had been engaged on and before
December 31, 1998 solely in the distribution of electricity in the NEPOOL
Control Area, and (ii) it is not a Publicly Owned Entity. A Participant which
joins the Supplier Sector shall be entitled to designate a voting member of each
Principal Committee, and an alternate to the member.

(d) a Publicly Owned Entity Sector, which all Participants which are Publicly
Owned Entities are eligible to join and shall join, and which End User
Participants are eligible to join if there is not an activated End User Sector.
A Participant which joins the Publicly Owned Entity Sector shall be entitled to
designate a voting member of each Principal Committee, and an alternate to the
member, except for

End User Participants whose voting interests while they are in the Publicly
Owned Entity Sector are defined in Section 6.2(e) below.

(e) an End User Sector, which an End User Participant is eligible to join
provided all of its Related Persons which are Participants are also eligible to
join the End User Sector. Participants which join the End User Sector shall be
entitled to designate an individual voting member of each Principal Committee
and an alternate to the member; provided, however, that a voting member, and the
alternate to the member, designated by a Small End User shall not be a Related
Person of another Participant in a Sector other than the End User Sector.

Until the total number of End User Participants electing to join the End User
Sector and eligible to designate an individual voting member ("End User Votes")
is at least ten (10), all End User Participants electing to join the End User
Sector shall be members of the Publicly Owned Entity Sector. So long as the
total number of End User Votes is less than three (3), the End User Participants
in the Publicly Owned Entity Sector shall be represented on each Principal
Committee by a single voting member. During such time as there are at least
three (3), but less than ten (10), End User Votes, End User Participants
electing to join the End User Sector shall become a sub- sector of the Publicly
Owned Entity Sector. Such sub-sector shall have twenty percent (20%) of the
Publicly Owned Entity Sector's vote, and each individual voting member of such
sub-sector shall be allocated a per capita share of the sub-sector's vote. The
End User Sector shall become fully operational automatically as soon, and shall
remain operational so long as, there are at least ten (10) End User Votes.

The System Operator shall have the right to designate, by written notice
delivered to the Secretary of the appropriate Principal Committee, a non- voting
member and an alternate to each Principal Committee. All Participants have the
right to join and be a member of a Sector. If a Participant ceases to be
eligible to be a member of the Sector which it previously joined and is not
eligible to join another existing Sector other than the End User Sector, it
shall have the right to remain and vote in the Sector in which the Participant
is currently a member for up to one year. By the end of such year, the NEPOOL
Participants Committee shall make a filing with the Commission pursuant to which
the Participant can join another Sector that either exists or is created
pursuant to the NEPOOL Participants Committee filing. Separate Sectors may be
created, and the membership of existing Sectors may be modified, by amendment of
the Agreement.

6.5 Appointment of Members and Alternates. A Participant or group of
Participants shall designate, by a written notice delivered to the Secretary of
the appropriate Committee, the voting member appointed by it for the Committee
and an alternate of the member. In the absence of the member, the alternate
shall have all the powers of the member, including the power to vote. A
Participant may change the Sector of which it is a member. Other than for Sector
changes required by Section 6.4(c), a change in the Sector in which a
Participant is a member shall become effective beginning on the first annual
meeting of the Participants Committee following notice of such change.

6.6 Term of Members. Each voting member of a Principal Committee shall hold
office until either (a) such member is replaced by the Participant or group of
Participants which appointed the member, or (b) the appointing Participant
ceases to be a Participant, or (c) the appointing Participant (or its Related
Person) is no longer eligible to be in the Sector to which it belongs, but is
eligible to join a different Sector. Replacement of a member shall be effected
by delivery by a Participant or group of Participants of written notice of such
replacement to the Secretary of the appropriate Committee.

6.7 Regular and Special Meetings. Each Principal Committee shall hold its annual
meeting in December or January at such time and place as the Chair shall
designate and shall hold other meetings in accordance with a schedule adopted by
the Committee or at the call of the Chair. Five or more voting members of a
Principal Committee may call subject to the notice provisions of Section 6.6 a
special meeting of the Committee in the event that the Chair fails to schedule
such a meeting within three business days following the Chair's receipt from
such members of a request specifying the subject matters to be acted upon at the
meeting.

6.8 Notice of Meetings. Written or electronic notice of each meeting of a
Principal Committee shall be given to each Participant, whether or not such
Participant is entitled to appoint an individual voting member of the Committee,
not less than three business days prior to the date of the meeting in the case
of the Technical Committees and five business days prior to the date of the
meeting for the Participants Committee.

A notice of meeting shall specify the principal subject matters expected to be
acted upon at the meeting. In addition, such notice shall include, or specify
internet location of, all draft resolutions to be voted at the meeting (which
draft resolutions may be subject to amendment of intent but not subject matter
during the meeting), and all background materials deemed by the Chair or
Secretary to be necessary to the Committee to have an informed opinion on such
matters. Motions raised for which no draft resolutions or background materials
have been provided may not be acted upon at a meeting and shall be deferred to a
subsequent meeting which is properly noticed.

6.9 Attendance. Regular and special meetings may be conducted in person, by
telephone, or other electronic means by means of which all persons participating
in the meeting can communicate in real time with each other. In order to vote
during the course of a meeting, attendance is required in person or by telephone
or other real time electronic means by a voting member or its alternate or a
duly designated agent who has been given, in writing, the authority to vote for
the member on all matters or on specific matters in accordance with Section
6.12.

6.10 Quorum. All actions by a Principal Committee, other than a vote by the
Participants Committee by written ballot to amend the NEPOOL Agreement or
Tariff, shall be taken at a meeting at which the members in attendance pursuant
to Section 6.7 constitute a Quorum. A Quorum requires the attendance by members
which satisfy the Sector Quorum requirements (as defined in Section 6.9) for a
majority of the activated Sectors. No action may be taken by a Principal
Committee unless a Quorum is present; provided, however, that if a Quorum is not
present, the voting members then present shall have the power to adjourn the
meeting from time to time until a Quorum shall be present.

6.11 Voting Definitions. For purposes of this Section 6.9 and Sections 6.10,
6.11 and 6.13, the following terms shall have the following respective meanings:

(a) Sector Voting Share: for each active Sector, is the quotient obtained by
dividing one hundred percent (100%) by the number of active Sectors. For
example, if there are five active Sectors, the Sector Voting Share of each of
the Sectors is twenty percent (20%). The aggregate Sector Voting Shares shall
equal one hundred percent (100%).

(b) Sector Quorum: for a Sector shall be the lesser of (i) fifty percent (50%)
or more (rounded to the next higher whole number) of the voting members of the
Sector, or (ii) five (5) or more voting members of the Sector for the
Participants Committee or three (3) or more voting members of the Sector for the
Technical Committees.

(c) Member Fixed Voting Share: for a Committee voting member, whether or not the
member is in attendance, is the quotient obtained by dividing (i) the Sector
Voting Share of the Sector to which the Participant or group of Participants
which appointed the Committee voting member belongs by (ii) the total number of
Committee voting members appointed by members of that Sector, adjusted, if
necessary, to take into account (A) the manner in which the voting shares of End
User Participants are to be determined while they are members of the Publicly
Owned Entity Sector, and (B) any required change in the voting share of a Group
Member, in each case as determined in accordance with Section 6.2.

(d) Member Adjusted Voting Share: for a Committee voting member which casts an
affirmative or negative vote on a proposed action or amendment and which has
been appointed by a Participant or group of Participants which are members of a
Sector satisfying its Sector Quorum requirement for the proposed action or
amendment, is the quotient obtained by dividing (i) the Sector Voting Share of
that Sector by (ii) the number of voting members appointed by members of that
Sector which cast affirmative or negative votes on the matter, adjusted, if
necessary, for End User Participants and group voting members as provided in the
definition of "Member Fixed Voting Share".

(e) NEPOOL Vote: with respect to a proposed action or amendment is the sum of
(i) the Member Adjusted Voting Shares of the voting members of the Committee
which cast an affirmative vote on the proposed action or amendment and which
have been appointed by a Participant or group of Participants which are members
of a Sector satisfying its Sector Quorum requirements and (ii) the Member Fixed
Voting Shares of the voting members of the Committee which cast an affirmative
vote on the proposed action or amendment and which have been appointed by a
Participant or group of Participants which are members of a Sector which fails
to satisfy its Sector Quorum requirements.

(f) Minimum Response Requirement: with respect to a proposed amendment to this
Agreement or Tariff means that the ballots received by the Balloting Agent from
Participants relating to the proposed amendment before the end of the
appropriate time specified in Section 6.11(c) must satisfy the following
thresholds:

(i) the sum of the Member Fixed Voting Shares of the Participant voting members
whose ballots are received must equal at least fifty percent (50%); and

(ii) the Participants whose voting members timely return ballots for or against
the amendment must include Participants that are represented by voting members
having at least fifty percent (50%) of the Member Fixed Voting Shares in each of
a majority of the activated Sectors.

6.12 Voting On Proposed Actions. All matters to be acted upon by a Principal
Committee shall be stated in the form of a motion by a voting member, which must
be seconded. Only one motion and any one amendment to that motion may be pending
at one time. Passage of a motion requires a NEPOOL Vote as determined pursuant
to Section 6.9 equal to or greater than two thirds of the aggregate Sector
Voting Shares. Voting members not in attendance or represented at a meeting as
specified in Section 6.7 or abstaining shall not be counted as affirmative or
negative votes.

6.13  Voting On Amendments.  Subject to Section 21.11 and Section 17A,
amendments to the NEPOOL Agreement or Tariff shall be accomplished as
follows:

(a) Amendments shall be drafted by a standing or ad hoc NEPOOL committee or a
Participant and sent to the Participants Committee for its consideration.

(b) The Participants Committee shall take action pursuant to Section 6.10 to
direct the Balloting Agent to circulate ballots for approval of the draft
Amendment to each Participant for execution by its voting member or alternate on
the Participants Committee or such Participant's duly authorized officer.

(c) In order to be counted, ballots must be executed and returned to the
Balloting Agent for NEPOOL in accordance with the following schedule:

(i) If the ballots are delivered to each Participant by regular mail, properly
executed ballots must be returned to and received by the Balloting Agent within
ten (10) business days after deposit of such ballots in the mail by the
Balloting Agent, and

(ii) If the ballots are delivered to each Participant by overnight delivery,
facsimile, electronic mail or hand delivery, then properly executed ballots must
be returned to and received by the Balloting Agent within five (5) business days
after (A) deposit of such ballots with an overnight delivery courier if
delivered by overnight delivery, or (B) transmission of such ballots by the
Balloting Agent if delivered by facsimile or electronic mail, or (C) receipt by
the Participant if delivered by hand delivery.

(iii) If the Minimum Response Requirement for an amendment has not been received
by the Balloting Agent within the schedule identified in subsection (i) or (ii)
above, the Balloting Agent shall send notice by overnight delivery, facsimile,
electronic mail or hand delivery to all non-responding Participants and shall
count any additional properly executed ballots which it receives within five (5)
business days after such notice. The date by which properly executed ballots
must be returned and received by the Balloting Agent shall be specified by the
Balloting Agent in the notice accompanying such ballots.

(d) A Participant may appeal to the Review Board or submit for resolution
pursuant to the alternative dispute resolution provisions of Section 21.1 a
proposed amendment for which ballots have been circulated, provided that such
appeal is taken or submission is presented before the end of the tenth (10th)
business day after the Participants Committee has taken action to direct the
Balloting Agent to circulate ballots for approval of the draft amendment, by
giving to the Secretary of the Participants Committee a signed and written
notice of appeal or submission. The appeal shall be moot, or submission shall be
deemed withdrawn, if the amendment is not approved in balloting by the
Participants Committee. If the amendment is approved, a valid appeal or
submission shall stay the filing with the Commission of any amendment to the
NEPOOL Agreement or Tariff until either (i) a decision on the appeal by the
Review Board, or (ii) the earlier of resolution pursuant to Section 21.1 or
termination pursuant to Section 21.1.B(2) of the suspension effects of the
submission.

(e) In order for a proposed amendment to the NEPOOL Agreement or Tariff to be
approved by the Participants Committee, the following criteria must be
satisfied:

(i) The Minimum Response Requirement must be satisfied with respect to the
proposed amendment.

(ii) The affirmative ballot votes with respect to the proposed amendment must
equal or exceed two thirds of the aggregate Sector Voting Shares.

6.14 Designated Representatives and Proxies. The vote of any member of a
Principal Committee or the member's alternate, other than a ballot on an
amendment, may be cast by another person pursuant to a written, standing
designation or proxy; provided, however, that the vote of a member or alternate
to that member representing a Small End User may not be cast by a Participant or
a Related Person of a Participant in a Sector other than the End User Sector. A
designation or proxy shall be dated not more than one year previous to the
meeting and shall be delivered by the member or alternate to the Secretary of
the Committee at or prior to any votes being taken at the meeting at which the
vote is cast pursuant to such designation or proxy. A single individual may be
the designated representative of or be given the proxy of the voting members
representing any number of Participants of any one Sector or Participants from
multiple Sectors.

6.15 Limits on Representatives. In the Generation Sector, no one person may
exercise more than twenty-five percent (25%) of that Sector's total Member Fixed
Voting Shares without the unanimous written agreement of all members of the
Generation Sector. In the End User Sector, no one person may vote on behalf of
more than five (5) Small End Users. Except as otherwise provided herein, other
Sectors may by unanimous written agreement elect to impose limits on the voting
power any one individual may have in that

Sector through being the designated representative of multiple voting members or
carrying multiple proxies from voting members of that Sector. Notice of any such
limits on voting power must be posted on the System Operator home page and be
capable of being accessed by all Participants.

6.16 Adoption of Bylaws. The Participants Committee shall adopt bylaws,
consistent with this Agreement, governing procedural matters including the
conduct of its meetings and those of the other Principal Committees. If there is
any conflict between such bylaws and the Agreement, the Agreement shall control.
A Principal Committee may vote to waive its bylaws for a particular meeting,
provided the motion to effect the waiver is approved in accordance with Section
6.10.

6.17 Joint Meetings of Technical Committees. It is recognized that
responsibilities of the Technical Committees may overlap in certain areas. In
areas of overlap, the Reliability Committee is responsible for addressing
reliability matters, the Markets Committee is responsible for addressing market
implications of actions or recommendations, and the Tariff Committee is
responsible for addressing issues relating to transmission and ancillary
services. The Chairs of the Technical Committees, with input from the Liaison
Committee Co-Chairs or entire Liaison Committee, as appropriate, shall
prioritize and sequence Technical Committee activities to ensure full and proper
input by Participants while maximizing the efficiency of the decision making
process. To the extent appropriate and desirable, the Technical Committees are
authorized and encouraged to hold meetings, and to conduct studies and exercise
responsibilities, jointly with other Technical Committees.

[Next Sheet is 90]



                                    SECTION 7
                             PARTICIPANTS COMMITTEE

7.1 Officers. At its annual meeting, the Participants Committee shall elect from
among its members a Chair and Vice-Chair; it shall also elect a Secretary who
shall not be a member. These officers shall have the powers and duties usually
incident to such offices and as set forth in the Committee bylaws.

7.2 Adoption of Budgets. At each annual meeting, the Participants Committee
shall adopt a NEPOOL budget for the ensuing calendar year. In adopting budgets
the Participants Committee shall give due consideration to the budgetary
requests of each committee. The Participants Committee may modify any NEPOOL
budget from time to time after its adoption.

7.3 Establishing Reliability Standards. It shall be the duty of the Participants
Committee, after review of reports, recommendations and actions of the System
Operator and the Reliability Committee and such other matters as the
Participants Committee deems pertinent, to establish or approve Reliability
Standards for the bulk power supply of NEPOOL. Such Reliability Standards shall
be consistent with the directives of NERC and the NPCC and shall be reviewed
periodically by the Participants Committee and revised as the Participants
Committee deems appropriate.

7.4 Appointment and Compensation of NEPOOL Personnel. The Participants Committee
shall determine what personnel are desirable for the effective operation and
administration of NEPOOL and shall fix or authorize the fixing of the
compensation for such persons. In addition, the Participants Committee shall
determine what resources are desirable for the effective operation of the
Technical Committees and shall, on its own or pursuant to the recommendation of
a Technical Committee, authorize the incurrence of such expenses as may be
required to enable the Technical Committee, or its subgroups, to properly
perform their duties, including, but not limited to, the retention of a
consultant or the procurement of computer time.

7.5  Duties and Authority.

(a) The Participants Committee shall have the duty and requisite authority to
administer, enforce and interpret the provisions of this Agreement and any other
agreement or document approved by the Participants Committee or its predecessor
in order to accomplish the objectives of NEPOOL including the making of any
decision or determination necessary under any provision of this Agreement or any
other agreement or document approved by the Participants Committee or its
predecessor and not expressly specified to be decided or determined by any other
body.

(b) The Participants Committee shall have the authority to provide for such
facilities, materials and supplies as the Participants Committee may determine
are necessary or desirable to carry out the provisions of this Agreement.

(c) The Participants Committee shall have, in addition to the authority provided
in Section 7.3, the authority, after consultation with other NEPOOL committees
and the System Operator, to establish or approve consistent standards with
respect to any aspect of arrangements between Participants and Non-Participants
which it determines may adversely affect the reliability of NEPOOL, and to
review such arrangements to determine compliance with such standards.

(d) The Participants Committee, or its designee, shall have the authority to act
on behalf of all Participants in carrying out any action properly taken pursuant
to the provisions of this Agreement. Without limiting the foregoing general
authority, the Participants Committee, or its designee, shall have the authority
on behalf of all Participants to execute any contract, lease or other instrument
which has been properly authorized pursuant to this Agreement including, but not
limited to, one or more contracts with the System Operator, and to file with the
Commission and other appropriate regulatory bodies: (i) this Agreement and
documents amending or supplementing this Agreement, including the Tariff, (ii)
contracts with Non- Participants or the System Operator, and (iii) related
tariffs, rate schedules and certificates of concurrence. The Participants
Committee shall, in addition, have the authority to represent NEPOOL in
proceedings before the Commission.

(e) The Participants Committee shall have the duty and requisite authority,
after consultation with other NEPOOL committees and the System Operator, to fix
the NEPOOL Objective Capability for each month of each Power Year prior to the
beginning of the Power Year and thereafter to review at least annually the
anticipated Load of the NEPOOL Participants and NEPOOL Installed Capability for
each month of such Power Year and to make such adjustments in the NEPOOL
Objective Capability as the Participants Committee may determine on the basis of
such review. Since changes in the circumstances which must be assumed by the
Participants Committee in fixing NEPOOL Objective Capability for a future period
can significantly affect the required level of NEPOOL Objective Capability for
that period, the Participants Committee shall, where appropriate, also determine
the effect on NEPOOL Objective Capability of significant changes in
circumstances from those assumed, either by fixing alternative NEPOOL Objective
Capabilities, or by adopting adjustment factors or formulas.

(f) The Participants Committee shall have the duty and requisite authority to
establish or approve schedules fixing the amounts to be paid by Participants and
Non-Participants to permit the recovery of expenses incurred in furnishing some
or all of the services furnished by NEPOOL either directly or through the System
Operator.

(g) The Participants Committee shall have the duty and requisite authority to
provide for the sharing by Participants, on such basis as the Participants
Committee may deem appropriate, of payments and costs which are not otherwise
reimbursed under this Agreement and which are incurred by Participants or under
arrangements with Non-Participants and approved or authorized by the Committee
as necessary in order to meet or avoid short-term deficiencies in the amount of
resources available to meet the Pool's reliability objectives.

(h) The Participants Committee shall have the authority, at the time that it
acts on an Entity's application pursuant to Section 3.1 to become a Participant,
to waive, conditionally or unconditionally, compliance by such Entity with one
or more of the obligations imposed by this Agreement if the Participants
Committee determines that such compliance would be unnecessary or inappropriate
for such Entity and the waiver for such Entity will not impose an additional
burden on other Participants.

(i) The Participants Committee shall have the authority to establish standard
conditions and waivers with respect to applications by Entities for membership
in NEPOOL and to modify such standard conditions and waivers as appropriate in
connection with changed circumstances with respect to such applicants, provided
that the Participants Committee determines that the standard conditions and
waivers for such Entities will not impose an additional burden on other
Participants.

(j) The Participants Committee shall have the duty and requisite authority to
act on appeals to it from the actions of other Principal Committees if delegated
to such Committees by the Participants Committee pursuant to Section 7.5(k), to
appoint the Review Board, and to appoint a special committee to administer
NEPOOL's alternate dispute resolution procedures or to take any other action if
it determines that such action is necessary or appropriate to achieve a prompt
resolution of disputes under the provisions of Section 21.1.

(k) The Participants Committee shall have the authority to delegate its powers
and duties to one or more of the Technical Committees, the System Operator, or
other entity as it sees fit provided that (i) such delegation is clearly stated
and approved by a Participant Committee action, (ii) such delegation does not
violate any other provision set forth herein, and (iii) the action of such
entity on any matter delegated to it may be appealed by any Participant to the
Participants Committee provided such an appeal is taken prior to the end of the
tenth business day following the action of the Technical Committee, the System
Operator, or such entity by giving to the Secretary of the Participants
Committee a signed and written notice of appeal, a copy of which the Secretary
shall provide to the System Operator and each member and alternate of the
Participants Committee. Pending action on the appeal by the Participants
Committee, the giving of a notice of appeal as aforesaid shall suspend the
action appealed from.

(l) The Participants Committee shall have the duty and requisite authority to
establish the NEPOOL Information Policy.

(m) The Participants Committee shall have the duty and requisite authority to
adopt and approve, amend and approve or resubmit to one or more Technical
Committees for additional comment, any matter submitted to the Participants
Committee by a Technical Committee.

(n) The Participants Committee shall have such further powers and duties as are
conferred or imposed upon it by other sections of this Agreement.

7.6 Attendance of Participants at Committee Meeting. Each Participant which does
not have the right to designate an individual voting member of the Participants
Committee shall, with the exception of meetings held pursuant to Section 11B.9
and meetings in executive session pursuant to Section 11B.10, be entitled to
attend any meeting of the Committee or any other NEPOOL committee, and shall
have a reasonable opportunity to express views on any matter to be acted upon at
the meeting.

7.7 Appeal of Actions to Review Board. Any Participant which otherwise has the
ability to submit a matter for resolution under Section 21.1 may, in lieu of
submitting a dispute as to a Participants Committee action or failure to take
action for resolution pursuant to Section 21.1, appeal such matter to the Review
Board. Except as otherwise provided in Section 6.11, such an appeal shall be
taken prior to the end of the tenth business day following the meeting of the
Participants Committee to which the appeal relates by giving to the Secretary of
the Participants Committee by hand delivery, facsimile, electronic mail or
regular mail a signed and written notice of appeal, a copy of which the
Secretary shall provide to each Participant. If no appeal of a Participants
Committee action or failure to take action is taken, and the action or failure
to take action is not submitted for resolution pursuant to Section 21.1, within
such time period, that Participants Committee action or failure to take action
shall be final and effective. If an appeal is taken, pending action on the
appeal by the Review Board, the giving of a notice of appeal as aforesaid shall
suspend the action appealed from. To the extent any action taken relates to the
approval of a rule or procedure which must be filed with the Commission, the
rule or procedure shall not be filed until the time for appeal or submission for
dispute resolution has elapsed and, if an appeal has been filed or submission
for dispute resolution has been made, either (i) a decision on the appeal has
been issued by the Review Board, or (ii) the earlier of resolution pursuant to
Section 21.1 of the matter submitted for dispute resolution or the termination
pursuant to Section 21.1.B(2) of the suspension effect of such submission.

[Next Sheet is 100]




                                    SECTION 8
                              RELIABILITY COMMITTEE

8.1 Officers. The Reliability Committee shall have a Chair, Vice-Chair and
Secretary. The Chair and Secretary of the Reliability Committee shall be
appointed by the System Operator from time to time in accordance with Section
20(j). The Chair will be responsible for presiding at meetings of the Committee
and establishing agendas for its meetings in conjunction with the Vice-Chair and
shall have the powers and duties as set forth in the Committee bylaws. The
Secretary shall have the powers and duties usually incident to such office and
as set forth in the Committee bylaws. The Chair and Secretary shall have no
voting rights. The Vice-Chair shall be elected by the Reliability Committee from
among its voting members from time to time. The Vice-Chair shall have the powers
and duties usually incident to such office and such powers and duties as set
forth in the Committee bylaws, including, without limitation, the responsibility
to develop in conjunction with the Chair, Committee meeting agendas.

8.2 Notice to Members and Alternates of Participants Committee. Prior to the end
of the fifth business day following a meeting of the Reliability Committee, the
Secretary of the Reliability Committee shall give written notice to the System
Operator and each member and alternate of the Participants Committee of any
action taken by the Reliability Committee at such meeting.

8.3 Voting; Appeal of Actions. Votes taken by the Reliability Committee shall be
binding on the Participants only for those matters in which the Committee has
specifically designated authority under this Agreement or has been properly
delegated authority by the Participants Committee pursuant to Section 7.5(k).

Any Participant may appeal to the Participants Committee any binding action
taken by the Reliability Committee. Such an appeal shall be taken prior to the
end of the tenth business day following the meeting of the Reliability Committee
to which the appeal relates by giving to the Secretary of the Participants
Committee a signed and written notice of appeal, a copy of which the Secretary
shall provide to the System Operator and each member and alternate of the
Participants Committee. Pending action on the appeal by the Participants
Committee, the giving of a notice of appeal as aforesaid shall suspend the
action appealed from.

8.4 Responsibilities. The Reliability Committee shall perform the following
functions, in conjunction with the System Operator as appropriate, and shall
recommend action to the System Operator, Participants Committee or Transmission
Owners, as appropriate, with respect thereto:

(a) provide input to the Participants Committee, Transmission Owners, and System
Operator, as appropriate, on transmission facilities and the development of a
regional transmission plan in order to achieve the objectives of NEPOOL;

(b)  following appropriate study, recommend NEPOOL Objective Capability for
each Power Year;

(c) periodically review the procedures used to calculate NEPOOL Installed
Capability, NEPOOL Objective Capability and NEPOOL Capability Responsibility;

(d) periodically prepare short and long term load forecasts for use in NEPOOL
studies and operations and to meet requirements of regulatory agencies;

(e) review communications and liaison arrangements between NEPOOL and
governmental authorities on power supply, environmental, load forecasting, and
transmission issues;

(f) coordinate the collection and exchange of necessary system data and future
plans related to reliability for use in NEPOOL planning and to meet requirements
of regulatory agencies;

(g)  coordination of studies of, and provide information to Participants on,
maintenance schedules for the supply and demand-side resources and
transmission facilities of the Participants;

(h) based on appropriate studies, recommend for Participants Committee approval
Reliability Standards to assure the reliable operation and facilitate the
efficient operation of the NEPOOL Control Area bulk power system and those
operating rules which guide the implementation of the Reliability Standards.
Such Reliability Standards and operating rules shall include, without
limitation, the following:

(i) standards to determine the current Annual Peak, Adjusted Annual Peak,
Monthly Peak, Adjusted Monthly Peak, and aggregate obligations of the
Participants in each of the NEPOOL Markets;

(ii) standards to establish short and long term load forecasts for use in NEPOOL
operations and to meet requirements of regulatory agencies;

(iii)  standards with respect to the administration and enforcement of,
and reporting pursuant to, NERC and NPCC policies and requirements;

(iv)  standards for use in planning and design of the NEPOOL interconnected
bulk power system;

(v) standards to ensure the continuous reliability of the bulk power
transmission system, such standards to include, without limitation, criteria and
rules relating to protective equipment, transfer limits, voltage schedules,
voltage guides, operating guides, sub-area reserves, switching, voltage control,
load shedding, emergency and restoration procedures, and the coordination of
scheduling of the operation and maintenance of supply and demand-side resources
and transmission facilities of the Participants;

(vi) standards for determining the capabilities of each electric generating unit
or combination of units in which a Participant has an Entitlement in a uniform
manner applying generally accepted engineering principles; and

(vii)  as appropriate, reliability standards for interpool coordination
transactions.

(i) review proposed supply and demand-side resource plans and the proposed
transmission and interconnection plans of Participants pursuant to Section 18.4
and, based on such review, recommend action regarding such proposed plans;

(j) make recommendations regarding procedures for dispatch infrastructure (i.e.
voice and data communications protocols, AGC pulsing arrangements, Energy
Management System and System Control and Data Acquisition interfaces, Satellite
relations, etc.);

(k) provide input and make recommendations with respect to the reliability
considerations of general system operations (i.e. commitment/ decommitment, real
time dispatch, review and approval of distribution of reserves, etc.);

(l) recommend to the Participants Committee the retention of a consultant,
procurement of computer time, or the incurrence of consultant expenses or such
other expenses as may be required to enable the Reliability Committee, its
subcommittees, and task forces properly to perform their duties;

(m) make recommendations to the Participants Committee, Transmission Owners, and
System Operator, as appropriate, with respect to development and amendment of
interconnection procedures and documents related to such procedures; and

(n) to the extent appropriate, develop criteria, guidelines and methodologies to
assure consistency in monitoring and assessing conformance of Participant and
regional transmission plans to accepted reliability criteria.

8.5  Establishment of Subcommittees and Task Forces.  The Reliability
Committee shall have the authority to establish subcommittees and task forces
for particular studies.

8.6 Further Powers and Duties. The Reliability Committee shall have such further
powers and duties as are consistent with the duties and responsibilities set
forth herein or as may be properly delegated to it by the Participants
Committee.

[Next Sheet is 108]



                                    SECTION 9
                                TARIFF COMMITTEE

9.1 Officers. The Tariff Committee shall have a Chair, Vice-Chair and Secretary.
The Chair and Secretary of the Tariff Committee shall be appointed by the System
Operator from time to time in accordance with Section 20(j). The Chair will be
responsible for presiding at meetings of the Committee and establishing agendas
for its meetings in conjunction with the Vice-Chair and shall have the powers
and duties as set forth in the Committee bylaws. The Secretary shall have the
powers and duties usually incident to such office and as set forth in the
Committee bylaws. The Chair and Secretary shall have no voting rights. The
Vice-Chair shall be elected by the Tariff Committee from among its voting
members from time to time. The Vice-Chair shall have the powers and duties
usually incident to such office and such powers and duties as set forth in the
Committee bylaws, including, without limitation, the responsibility to develop
in conjunction with the Chair, Committee meeting agendas.

9.2 Notice to Members and Alternates of Participants Committee. Prior to the end
of the fifth business day following a meeting of the Tariff Committee, the
Secretary of the Tariff Committee shall give written notice to the System
Operator and each member and alternate of the Participants Committee of any
action taken by the Tariff Committee at such meeting.

9.3 Voting; Appeal of Actions. Votes taken by the Tariff Committee shall be
binding on the Participants only for those matters in which the Committee has
specifically designated authority under this Agreement or has been properly
delegated authority by the Participants Committee pursuant to Section 7.5(k).

Any Participant may appeal to the Participants Committee any binding action
taken by the Tariff Committee. Such an appeal shall be taken prior to the end of
the tenth business day following the meeting of the Tariff Committee to which
the appeal relates by giving to the Secretary of the Participants Committee a
signed and written notice of appeal, a copy of which the Secretary shall provide
to the System Operator and each member and alternate of the Participants
Committee. Pending action on the appeal by the Participants Committee, the
giving of a notice of appeal as aforesaid shall suspend the action appealed
from.

9.4 Responsibilities. The Tariff Committee shall perform the following
functions, in conjunction with the System Operator as appropriate, and shall
recommend action to the System Operator, Participants Committee or Transmission
Owners, as appropriate, with respect thereto:

(a)  develop appropriate billing procedures for transmission and ancillary
services pursuant to this Agreement and the Tariff;

(b) develop and recommend to the Participants Committee and the Transmission
Owners Committee, as appropriate, (i) amendments, additions and other changes to
the Tariff and (ii) related Tariff rules;

(c)  providing input to the System Operator on the development of
Administrative Procedures with respect to the administration of the Tariff
and the OASIS;

(d) to the extent appropriate, conduct and/or review such studies and make such
determinations as are assigned to the Committee pursuant to this Agreement and
the Tariff with respect to financial treatment of additions to or upgrades of
PTF; and

(e) recommend to the Participants Committee the retention of a consultant,
procurement of computer time, or the incurrence of consultant expenses or such
other expenses as may be required to enable the Tariff Committee, its
subcommittees, and task forces properly to perform their duties.

9.5  Establishment of Subcommittees and Task Forces.  The Tariff Committee
shall have the authority to establish subcommittees and task forces for
particular studies.

9.6 Further Powers and Duties. The Tariff Committee shall have such further
powers and duties as are consistent with the duties and responsibilities set
forth herein or as may be properly delegated to it by the Participants
Committee.

[Next Sheet is 112]




                                   SECTION 10
                                MARKETS COMMITTEE

10.1 Officers. The Markets Committee shall have a Chair, Vice-Chair and
Secretary. The Chair and Secretary of the Markets Committee shall be appointed
by the System Operator from time to time in accordance with Section 20(j). The
Chair will be responsible for presiding at meetings of the Committee and
establishing agendas for its meetings in conjunction with the Vice-Chair and
shall have the powers and duties as set forth in the Committee bylaws. The
Secretary shall have the powers and duties usually incident to such office and
as set forth in the Committee bylaws. The Chair and Secretary shall have no
voting rights. The Vice-Chair shall be elected by the Markets Committee from
among its voting members from time to time. The Vice-Chair shall have the powers
and duties usually incident to such office and such powers and duties as set
forth in the Committee bylaws, including, without limitation, the responsibility
to develop in conjunction with the Chair, Committee meeting agendas.

10.2 Notice to Members and Alternates of Participants Committee. Prior to the
end of the fifth business day following a meeting of the Markets Committee, the
Secretary of the Markets Committee shall give written notice to the System
Operator and each member and alternate of the Participants Committee of any
action taken by the Markets Committee at such meeting.

10.3 Voting; Appeal of Actions. Votes taken by the Markets Committee shall be
binding on the Participants only for those matters in which the Committee has
specifically designated authority under this Agreement or has been properly
delegated authority by the Participants Committee pursuant to Section 7.5(k).

Any Participant may appeal to the Participants Committee any binding action
taken by the Markets Committee. Such an appeal shall be taken prior to the end
of the tenth business day following the meeting of the Markets Committee to
which the appeal relates by giving to the Secretary of the Participants
Committee a signed and written notice of appeal, a copy of which the Secretary
shall provide to the System Operator and each member and alternate of the
Participants Committee. Pending action on the appeal by the Participants
Committee, the giving of a notice of appeal as aforesaid shall suspend the
action appealed from.

10.4 Responsibilities. The Markets Committee shall perform the following
functions, in conjunction with the System Operator as appropriate, and shall
recommend action to the System Operator, Participants Committee or Transmission
Owners, as appropriate, with respect thereto:

(a) based on appropriate studies, develop market procedures to assure the
reliable operation and facilitate the efficient operation of the NEPOOL Control
Area bulk power supply;

(b) (i) evaluate studies of the market implications of maintenance schedules for
the supply and demand-side resources and transmission facilities of the
Participants and operable capacity margins, and (ii) develop market procedures
for scheduling maintenance for supply and demand resources and transmission
resources;

(c) to the extent appropriate to assure the efficient operation of the NEPOOL
Markets, develop reasonable standards, criteria and rules relating to protective
equipment, switching, voltage control, load shedding, emergency and restoration
procedures, and the operation and maintenance of supply and demand-side
resources and transmission facilities of the Participants;

(d) develop procedures for determining the market implications of the seasonal
capabilities of each electric generating unit or combination of units in which a
Participant has an Entitlement;

(e) develop procedures for determining as appropriate from time to time the
current Annual Peak, Adjusted Annual Peak, Monthly Peak, Adjusted Monthly Peak,
Installed Capability Responsibility, and obligations for Energy, Operating
Reserve and AGC of each Participant;

(f) develop Market Rules and periodically review and recommend changes thereto
as appropriate. Such Market Rules shall include, without limitation, the
following:

(i)  submission of Bid Prices and the determination of prices for each of the
NEPOOL Markets;

(ii) determination for each Participants of its obligations under each of the
NEPOOL Markets;

(iii)  establishment or approval of appropriate billing procedures for
market transactions pursuant to this Agreement;

(iv) calculation and equitable apportionment of losses incurred in connection
with Interchange Transactions; and

(v) interpool market contract coordination as appropriate.

(g)  develop operating procedures relating to the administration of the
NEPOOL Markets and periodically review and recommend changes thereto as
appropriate; and

(h) recommend the retention of a consultant, procurement of computer time, or
the incurrence of consultant expenses or such other expenses as may be required
to enable the Markets Committee, its subcommittees, and task forces properly to
perform their duties.

10.5  Establishment of Subcommittees and Task Forces.  The Markets Committee
shall have the authority to establish subcommittees and task forces for
particular studies.

10.6 Further Powers and Duties. The Markets Committee shall have such further
powers and duties as are consistent with the duties and responsibilities set
forth herein or as may be properly delegated to it by the Participants
Committee.

10.7 Development of Rules Relating to Non-Participant Supply and Demand-side
Resources. It is recognized that arrangements between Participants and Non-
Participants with respect to the Non-Participants' supply and demand-side
resources may create special problems in the application of Sections 12 and 14.
Accordingly, the Markets Committee shall analyze such special problems and
recommend to the Participants Committee appropriate rules for reflecting such
resources in the Installed System Capability of a Participant which enters into
such an arrangement and for the treatment of such arrangements for Energy,
Operating Reserve and AGC purposes. Upon approval by the Participants Committee,
such rules shall supersede the provisions of Sections 12 and 14 (and the related
definitions in Section 1) to the extent of any conflict therewith upon
acceptance by the Commission.

[Next Sheet is 118]



                                   SECTION 11
                              FURTHER RESTRUCTURING

The NEPOOL Participants undertake to finalize by March 31, 2000 the negotiation
of more comprehensive arrangements for the reassignment of appropriate
administrative responsibilities to the System Operator in the Interim ISO
Agreement.



                                   SECTION 11A
                                  REVIEW BOARD

11A.1 Organization. There shall be a Review Board which, in addition to
responsibility under Section 11B.12, shall be responsible for ruling on appeals
taken from actions of the Participants Committee and for advising the
Participants Committee as to the issues raised on any appeals before it provided
that appeals from actions of the System Operator shall not be taken to the
Review Board. In ruling on appeals, the Review Board shall consider, among other
things, whether the action is consistent with Commission policies. In addition,
if the appeal relates to an amendment to the Agreement or market rule, the
Review Board shall consider the extent to which such amendment imposes a burden
on the Participants which do not vote in favor of the amendment that is
materially greater in degree than that imposed on the Participants which have
voted in favor of the amendment. The Review Board shall not have the right to
review or otherwise participate in actions of the System Operator or to take any
action with respect to any matter involving a dispute between the System
Operator and either NEPOOL or any Participant. The Participants agree that the
process of selecting the Review Board shall commence upon the initial formation
of the Participants Committee. Until the initial organization of the Review
Board is completed, the Board of Directors of the System Operator or a committee
thereof consisting of not less than three System Operator Directors designated
by the System Operator Board of Directors shall perform the functions of the
Review Board, provided that the provisions of Sections 11A.2 through 11A.6 shall
not be applicable to the Board of Directors of the System Operator acting as a
Review Board. All expenses incurred by the System Operator as a result of the
Board of Directors in acting as the Review Board shall be NEPOOL expenses.

11A.2 Composition. The Review Board shall be composed of five members. The
Review Board Members shall initially be selected by the Participants Committee
from a slate of candidates. An independent consultant, retained by the
Participants Committee, shall prepare a list of persons qualified and willing to
serve on the Review Board. A subcommittee appointed by the Participants
Committee shall review the list and distribute to the members of the
Participants Committee a slate from among the list proposed by the independent
consultant, along with information on the background and experience of the
persons on the slate appropriate to evaluating their fitness for service on the
Review Board. If the Participants Committee fails to select a full Review Board
from the slate proposed by the subcommittee, the Committee shall direct the
independent consultant to propose a further list of nominees for consideration
at the next regular meeting of the Participants Committee. Thereafter, prior to
the expiration of a Review Board Member's term, and upon the occurrence of any
vacancy on the Board, the Participants Committee shall select a successor
Member.

11A.3 Qualifications. The Review Board Members shall be independent experts
knowledgeable about issues typically faced by entities engaged in energy
production, transmission, distribution and sale under Federal or State
regulation. A Review Board Member shall not be, and shall not have been at any
time within five years of election to the Review Board, a director, officer or
employee of a Participant or of a Related Person of a Participant. While serving
on the Review Board, a Review Board Member shall have no direct business
relationship or other affiliation with any Participant or its Related Persons
and shall otherwise be subject to the same independence requirements imposed on
Directors of the System Operator Board of Directors.

11A.4 Term. A Review Board Member shall serve for a term of three years;
provided, however, that two of the Review Board Members selected initially shall
be chosen by lot to serve a term of two years, two of the Review Board Members
selected initially shall be chosen by lot to serve a term of three years and the
other Review Board Member selected initially shall serve a term of four years.

11A.5 Meetings. Meetings of the Review Board may be conducted in person or by
telephone or other electronic means by means of which all persons participating
in the meeting can communicate in real time with each other.

11A.6 Bylaws. To the extent not inconsistent with any provision of this
Agreement, the Participants Committee shall adopt bylaws establishing procedures
for the Review Board's activities as it may deem appropriate, including but not
limited to bylaws governing the scheduling, noticing and conduct of meetings of
the Review Board, a code of conduct, selection of a Chair and Vice-Chair of the
Review Board, and action by the Review Board without a meeting. Such bylaws
shall not modify or be inconsistent with any of the rights or obligations
established by this Agreement.

11A.7  Procedure on Appeal of Participant Committee Action or Failure to
Take Action.

(a) Submission of an Appeal: A Participant seeking review ("Appealing Party") by
the Review Board of action of the Participants Committee shall give written
notice of the appeal in accordance with Section 7.7, and the appeal shall have
the suspension effect specified in Section 7.7.

(b) Intervenors and Time Limits: Any other Participant that wishes to
participate in the appeal proceeding hereunder shall give signed written notice
to the Secretary of the Participants Committee no later than ten (10) business
days after the Appealing Party has given notice of appeal and shall upon the
approval of the Review Board be permitted to participate in the appeal.

(c) Procedural Rules: The procedural rules (if any), for the conduct of the
appeal shall be determined by the Review Board in consultation with the
Participants Committee and each Appealing Party on a case-by-case basis.

(d) Pre-hearing Submissions: Each Appealing Party shall provide the Review
Board, within 15 days of the giving of its notice of appeal or such other time
as permitted by the Review Board, a brief written statement of its complaint and
a statement of the remedy or remedies it seeks, accompanied by copies of any
documents or other materials it wishes the Review Board to review. The
Participants Committee and, as appropriate, any other Participant participating
in the appeal will provide the Review Board, within 10 days of the Appealing
Party's submission or such other time as permitted by the Review Board, copies
of the minutes of all NEPOOL committee meetings at which the matter was
discussed and if deemed appropriate by the Participants Committee or otherwise
requested by the Review Board a brief description of the action (or failure to
act) being appealed and a brief statement explaining why the Participants
Committee believes its action (or failure to act) should be upheld by the Review
Board, together with copies of documents or other materials referenced in such
submission for the Review Board to review and materials, if any, which
interested Participants provide to the Secretary of the Participants Committee
and reasonably request be submitted to the Review Board.

In addition, each party shall designate one or more individuals to be available
to answer questions the Review Board may have on the documents or other
materials submitted. The answers to all such questions shall be reduced to
writing by the party providing the answer and a copy shall be made available to
any requesting Participant.

(e)  Hearing: A hearing (if any) will be held as soon as is reasonably
practicable.

(f) Decision: The Review Board's decision, to the extent practicable, shall be
due, within ninety (90) days of the giving of notice of the appeal.

11A.8  Effect of a Review Board Decision.

(a) Each Review Board Member shall have one vote and a decision of the Review
Board, either to grant or deny an appeal, shall require affirmative votes by a
majority of the Review Board Members but not less than three (3) such Members.

(i) Appeal denied. If the Review Board denies the appeal, the action of the
Participants Committee will be final and effective, subject to Commission
acceptance if and as required.

(ii) Appeal granted. If the Review Board grants the appeal, the Review Board's
determination (granting the appeal) will be final and the action of the
Participants Committee shall not take effect.

(b) If the Review Board grants an appeal, the Review Board may submit a proposed
resolution of the matter that was the subject of the appeal to the Participants
Committee. The Participants Committee may, but is not required to, take further
action with regard to the matter. If the Participants Committee votes on an
action regarding the matter (including a vote not to act on the matter), the
action or non-action of the Participants Committee shall be subject to further
appeal by any Participant to the Review Board in accordance with Section 7.7.
Any proposed resolution that the Review Board submits to the Participants
Committee is advisory only.

11A.9 An action or failure to act once appealed by a Participant to the Review
Board may not be subject to the alternative dispute resolution provisions of
Section 21.1, regardless of the outcome of the appeal. Conversely, an action or
failure to act submitted for resolution by a Participant pursuant to Section
21.1 may not be brought before the Review Board. If more than one Participant
appeals and/or submits for alternative dispute resolution under Section 21.1 the
same issue, the Participant that first takes such action shall determine whether
the issue is to be heard by the Review Board or considered under Section 21.1;
provided that each Participant challenging an action or failure to take action
shall have the same opportunity to present its case and may not be excluded from
participating under Section 11A.7(b).

11A.10 Any action taken or failure to take action by the Review Board does not
restrict or limit in any way the rights of a Participant to seek review by the
Commission, or a review in any other forum available to the Participant and
there shall be no requirement to submit an appeal to the Review Board concerning
any amendment, action or inaction by the Participants Committee prior to a
Participant exercising any such rights to seek review by the Commission or any
other forum with jurisdiction.

11A.11 The Review Board may not take action that is inconsistent with or
infringes upon any of the rights set forth in Section 17A.

[Next Sheet is 128]



                                   SECTION 11B
                          TRANSMISSION OWNERS COMMITTEE

11B.1 Organization. There shall be a Transmission Owners Committee established
pursuant to this Section 11B which shall implement the rights reserved to
Transmission Owners by Section 17A.

11B.2 Membership. Membership on the Transmission Owners Committee shall be open
to all Transmission Owners, regardless of their individual choices in Sector
membership under Section 6.2.

11B.3 Appointment of Members and Alternates. A Transmission Owner shall join the
Transmission Owners Committee by written notice delivered to the Secretary of
the Transmission Owners Committee, and shall designate in the notice the initial
member appointed by it for the Committee and an alternate of the member. In the
absence of the member, the alternate shall have all the powers of the member,
including the power to vote.

11B.4 Term of Members. A member of the Transmission Owners Committee appointed
by a Transmission Owner shall serve until replaced by the Transmission Owner
which appointed it or until such Transmission Owner ceases to be a Participant
or otherwise lose its right to appoint the member. Appointment or replacement of
a member shall be effected by a Transmission Owner by giving written notice of
such appointment or replacement to the Secretary of the Transmission Owners
Committee.

11B.5 Regular and Special Meetings. The Transmission Owners Committee shall hold
its annual meeting in December or January at such time and place as the Chair
shall designate and shall hold other meetings in accordance with a schedule
adopted by the Committee or at the call of the Chair. Thirty percent (30%) or
more of the voting members of the Transmission Owners Committee may call a
special meeting of the Committee in the event that the Chair shall fail to call
such a meeting within three business days following the Chair's receipt from
such members of a request specifying the subject matters to be acted upon at the
meeting.

11B.6 Notice of Meetings. Written notice of each meeting of the Transmission
Owners Committee shall be given to each Transmission Owner and to other
Participants not less than five (5) business days prior to the date of the
meeting.

11B.7 Attendance. Regular and special meetings may be conducted in person, by
telephone, or other electronic means by means of which all persons participating
in the meeting can communicate in real time with each other. In order to vote
during the course of a meeting, attendance is required in person or by telephone
or other real time electronic means by a voting member or its alternate or a
duly designated agent who has been given, in writing, the authority to vote for
the member on all matters or the proxy to vote for the member on specific
matters.

11B.8 Votes. Any action taken by the Transmission Owners Committee shall require
the concurrence of:

(i) representatives of at least two-thirds of the Transmission Owners provided
that Transmission Owners that are Related Persons to one another shall together
have a single vote; and

(ii) representatives of Transmission Owners having at least two-thirds of the
Weighted Votes of all Transmission Owners, where each Transmission Owner's
Weighted Vote is equal to its original capital investment in its PTF as of the
end of the most recent year for which figures are available.

Notwithstanding the foregoing, if a vote is taken and paragraph (i) above is
satisfied but paragraph (ii) above is not, the action being voted on by the
Transmission Owners Committee shall pass if (1) there are seven or more
Transmission Owners on the Committee and fewer than three Transmission Owners
oppose the action or (2) there are less than seven Transmission Owners on the
Committee and only one Transmission Owner opposes the action.

11B.9 Appointment of Task Forces or Working Groups. The Transmission Owners
Committee shall have the authority to appoint task forces or working groups to
address matters for which the Committee is responsible. Notwithstanding Section
7.6, such tasks force or working groups may be limited to Transmission Owners
only.

11B.10 Officers. At its annual meeting, the Transmission Owners Committee shall
elect from its members a Chair and a Vice-Chair; it shall also elect a Secretary
who need not be a member of the Committee. These officers shall have the powers
and duties usually incident to such offices, including the right to convene an
executive session of the Transmission Owners Committee to consider and vote upon
submittals to the Commission or litigation strategy.

11B.11 Adoption of Bylaws. The Transmission Owners Committee may adopt bylaws,
consistent with this Agreement, governing procedural matters including the
conduct of its meetings.

11B.12 Review of Committee Actions. To the extent the Commission determines,
pursuant to Section 17A.7, that Transmission Owners have the exclusive right to
make unilateral filings under Section 205 of the Federal Power Act, a
Transmission Owner may either submit a dispute for resolution pursuant to
Section 21.1 or appeal to the Review Board any action taken by the Transmission
Owners Committee with respect to such a Section 205 filing. Such a submission or
appeal shall be taken prior to the end of the tenth business day following the
meeting of the Transmission Owners Committee to which the submission or appeal
relates by giving to the Secretary of the Transmission Owners Committee a signed
and written notice of submission or appeal. Pending action on an appeal by the
Review Board, the giving of a notice of appeal as aforesaid shall suspend the
action appealed from. For purposes of the application of the dispute resolution
process of Section 21.1 and the suspension effect of a submission to alternative
dispute resolution, Section 21.1 shall be applied as if the Transmission Owners
Committee were the Participants Committee.



                                   SECTION 11C
                                LIAISON COMMITTEE

11C.1 Organization; Duties. There shall be a Liaison Committee which shall be an
advisory committee only responsible to act as a steering committee for managing
NEPOOL business through the committee process and facilitating communications
between NEPOOL and the System Operator and among Participants. The Liaison
Committee's duties as a steering committee include, without limitation,
recommending that matters be assigned to particular committees for action where
the subject matter of a proposed rule or other action potentially falls in the
purview of more than one committee and assuring appropriate input from other
committees as needed.

11C.2 Membership. The Liaison Committee shall have the following members: the
Chair and Vice-Chair of each of the Principal Committees; the Chair of the
Transmission Owners Committee; a Participant representative of each Sector that
is not otherwise represented on the Liaison Committee; the chief executive
officer of the System Operator; and two members of the System Operator's Board
of Directors.

11C.3 Regular and Special Meetings. The Liaison Committee shall hold meetings in
accordance with a schedule adopted by the Committee or at the call of the
Co-Chairs.

11C.4 Notice of Meetings. Written notice of each meeting of the Liaison
Committee shall be given to each member of the Committee and all members of the
Participants Committee not less than five business days prior to the date of the
meeting.

11C.5 Attendance. Regular and special meetings may be conducted in person, by
telephone, or other electronic means by means of which all persons participating
in the meeting can communicate in real time with each other. Participants
Committee members and alternates may attend meetings of the Liaison Committee.
Any individual that is not a member of the Liaison Committee may participate at
a meeting at the invitation of a Co-Chair.

11C.6 Officers. The Co-Chairs of the Liaison Committee shall be the chief
executive officer of the System Operator and the Chair of the Participants
Committee. The Liaison Committee shall elect a Secretary who need not be a
member of the Committee. These officers shall have the powers and duties usually
incident to such offices.

[Next Sheet is 135]



                                   PART THREE
                                MARKET PROVISIONS

                                   SECTION 12
                              INSTALLED CAPABILITY
                            OBLIGATIONS AND PAYMENTS

12.1  Continuing Reliability Measures.

(a) Commencing in 2000 the System Operator shall perform, and furnish to
Participants, an annual, independent "Regional Resource Adequacy Assessment" to
determine whether adequate generation and transmission resources are in place or
under development to assure that regional and subregional reliability standards
established for NEPOOL can be met.

(b) During 2000, the Participants Committee shall commence development of
alternative, market-based reliability assurance mechanisms. A status report on
this development effort shall be submitted to the Commission and furnished to
Participants on or before January 1, 2001

(c) Certain provisions of the Agreement that impose obligations on Participants,
including Participants with generation and transmission resources, were
contained within the Agreement at a time when wholesale power and transmission
services were subject to very different regulatory rules and an Operable
Capability market and Installed Capability auction market were included within
the Agreement. During 2000, concurrent with the review pursuant to Section
12.0(b) and in recognition of the implementation of CMS and MSS, the
Participants Committee shall also identify those of such obligations, if any,
that should be eliminated, modified, or replaced.

12.1 Obligations to Provide Installed Capability. Each Participant shall have
Installed System Capability during each hour of each month at least sufficient
to satisfy its Installed Capability Responsibility for the month.

12.2  Computation of Installed Capability Responsibilities.

(a) (1) At the conclusion of each month, the System Operator under the direction
of the Participants Committee shall determine each Participant's tentative
Installed Capability Responsibility in Kilowatts for such month in accordance
with the following formula:

X   = (P(A-N)+Np)(1+T) - C(Dp)

As used in this Section 12.2(a)(1), the symbols used in the formula and the
additional symbols defined below have the following meanings:

X  is the Participant's tentative Installed Capability Responsibility for
the month.

P is the value of the Participant's fraction for the month as determined in
accordance with the following formula:

P = (Fp + Dp) / (F + D), wherein:

Fp is the Participant's Adjusted Monthly Peak for the month less any Kilowatts
received by such Participant pursuant to a contract of a type that traditionally
has been treated by NEPOOL as a firm contract for the purposes of this Section
prior to January 1, 1999, but which does not constitute a Firm Contract as
defined in this Agreement.

Dp is the Participant's actual or potential load reduction resulting from its
NEPOOL Interruptible and Dispatchable Loads for the month.

F is the aggregate for the month of the Adjusted Monthly Peaks for all
Participants less any Kilowatts received by any Participant pursuant to a
contract of a type that traditionally has been treated by NEPOOL as a firm
contract for the purposes of this Section prior to January 1, 1999, but which
does not constitute a Firm Contract as defined in this Agreement.

D is the aggregate for the month of the actual or potential load reduction
resulting from all Participants' NEPOOL Interruptible and Dispatchable Loads.

C is the factor, which when multiplied by D in megawatts, results in the
reduction to NEPOOL Objective Capability that would result from including D in
the determination of NEPOOL Objective Capability. The value for C shall be
adopted by the Participants Committee each time it fixes NEPOOL Objective
Capability pursuant to Section 7.5(e).

A is the NEPOOL Objective Capability in megawatts for the month as fixed by the
Participants Committee pursuant to Section 7.

N is the aggregate of the New Unit Adjustments for all Participants for the
month as determined by the Participants Committee in accordance with Section
12.2(a)(2).

Np is the aggregate of the Participant's New Unit Adjustments for the month, as
determined by the Participants Committee, and is equal to the aggregate of the
Participant's adjustments for each New Unit included in its Installed System
Capability during the hour of the coincident peak load of the Participants for
the month. The Participant's adjustment for each New Unit may be positive or
negative and shall be the product of (i) the Participant's Installed Capability
Entitlement in the New Unit during the hour of the coincident peak load of the
Participants for the month, times (ii) the New Unit Adjustment Factor applicable
to the New Unit as determined in accordance with Section 12.2(a)(2).

T is the Participant's Unit Availability Adjustment Factor for the month. T may
be positive or negative and shall be determined in accordance with the following
formula:

T = (I-H) x J x R, wherein:
         100

I for the Participant for the month is the percentage which represents the
weighted average (using the Installed Capability of each Installed Capability
Entitlement for such month for the weighting) of the Four Year Installed
Capability Target Availability Rates of the Installed Capability Entitlements
which are included in the Participant's Installed System Capability during the
hour of the coincident peak load of the Participants for the month. The Four
Year Target Availability Rate for an Installed Capability Entitlement for any
month is the average of the monthly Target Availability Rates for the
forty-eight months which comprise the period of four consecutive calendar years
ending within the Power Year which includes such month, as determined on the
basis of the Target Availability Rates for each of the forty-eight months, and
as applied on a basis which is consistent with the fuel or maturity status of
the unit for each of the forty-eight months; provided, however, that for the
purpose of determining the Four Year Target Availability Rate (i) for months
included within the Power Year which commences June 1, 1999, the determination
shall be made for the months of June through October on the basis of the
calendar years 1995 through 1998, and shall be made for the months of November
through May on the basis of the calendar years 1996 through 1999, and (ii) for
months included within the Power Year which commences June 1, 2000, the
determination shall be made on the basis of the calendar years 1996 through
1999. The Target Availability Rates shall be those utilized by the Participants
Committee in its most recent determination of NEPOOL Objective Capability
pursuant to Section 7.

H for the Participant for the month is the percentage which represents the
weighted average (using the Installed Capability of each Installed Capability
Entitlement for such month for the weighting) of the Four Year Actual
Availability Rates of the Installed Capability Entitlements which are included
in the Participant's Installed System Capability during the hour of the
coincident peak load of the Participants for the month. The Four Year Actual
Availability Rate for an Installed Capability Entitlement for any month is the
percentage which represents the average of the amounts determined for H1 for the
four applicable Twelve-Month Measurement Periods within the forty-eight months
which comprise the period of four consecutive calendar years ending within the
Power Year which includes such month; provided, however, that for the purpose of
determining the Four Year Actual Availability Rate (i) for months included
within the Power Year which commences June 1, 1999, the determination shall be
made for the months of June through October on the basis of the calendar years
1995 through 1998, and shall be made for the months of November through May on
the basis of the calendar years 1996 through 1999, and (ii) for months included
within the Power Year which commences June 1, 2000, the determination shall be
made on the basis of the calendar years 1996 through 1999. A Twelve-Month
Measurement Period is a period of twelve sequential months. For purposes of this
sequence, the first month in the four years and the immediately succeeding
months shall be considered to follow the forty-eighth month in the four-year
period. The four applicable Twelve-Month Measurement Periods to be used in the
determination of H1 for an Installed Capability Entitlement shall be the four
sequential Twelve-Month Measurement Periods out of the twelve possible
combinations which yield the highest H1.

H1 for an Installed Capability Entitlement in a unit or combination of units for
a Twelve-Month Measurement Period is its Actual Availability Rate. The Actual
Availability Rate of an Installed Capability Entitlement for a Twelve-Month
Measurement Period is a percentage and shall be the greater of:

(i) the percentage of (a) the amount of generation which could have been
received with respect to the Installed Capability Entitlement if the unit or
combination of units had been fully available at its full Installed Capability
throughout the Twelve-Month Measurement Period, which is represented by (b) the
amount of generation which was actually available during such period, or

(ii) the average Target Availability Rate expressed as a percentage for the
Installed Capability Entitlement for the Twelve-Month Measurement Period less
twenty percentage points. The average Target Availability Rate of an Installed
Capability Entitlement for a Twelve-Month Measurement Period is a percentage and
is the average of the monthly Target Availability Rates for the months which
comprise the Twelve-Month Measurement Period, as determined on the basis of the
Target Availability Rates for each of the twelve months, and as applied on a
basis which is consistent with the fuel or maturity status of the unit or
combination of units for each month in the Twelve-Month Measurement Period. The
Target Availability Rates shall be those utilized by the Participants Committee
in its most recent determination of NEPOOL Objective Capability pursuant to
Section 7.

J for the month is the estimated percentage point change in NEPOOL Objective
Capability which would be required as a result of a one percentage point change
in the weighted average equivalent availability rate of the generating units in
which the Participants have Installed Capability Entitlements. The value for J
shall be adopted by the Participants Committee each time it fixes NEPOOL
Objective Capability pursuant to Section 7.

R for the month is the phase-out factor for the month, which shall be as
follows:

R=0.75 for the Power Year beginning November 1, 1997. R=0.50 for the 12 month
period beginning November 1, 1998. R=0.25 for the 12 month period beginning
November 1, 1999. R=0 for the 12 month period beginning November 1, 2000 and all
subsequent 12 month periods.

(2) A New Unit Adjustment Factor for a New Unit shall be determined to assign
the effects of the New Unit on NEPOOL

Objective Capability to those Participants with Entitlements in the New Unit.
The New Unit Adjustment Factor for each New Unit for each month shall be
determined by the System Operator under the direction of the Participants
Committee in accordance with the following formula:

n = R(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) + K5(f-F)c2)

As used in this Section 12.2(a)(2), the symbols used in the formula have the
following meanings:

R is the phase out factor as defined in Section 12.2(a)(1) above.

n  is the New Unit Adjustment Factor, expressed as a fraction, for the
month for a New Unit.

c  is the Winter Capability of the New Unit.

C is the Winter Capability of the Proxy Unit, which shall be the number of
Kilowatts, as determined by the Participants Committee, which would result in
the NEPOOL Objective Capability being approximately the same if the generating
units in which the Participants have Installed Capability Entitlements were all
units possessing Proxy Unit characteristics.

f is the equivalent forced outage rate of the New Unit, expressed as a fraction
of a year, utilized in the determination by the Participants Committee of NEPOOL
Objective Capability for the month.

F is the equivalent forced outage rate of the Proxy Unit. F, a fraction, shall
be the weighted average equivalent forced outage rate (using the Winter
Capability of each generating unit for such weighting) of the generating units
in which the Participants have Installed Capability Entitlements, adjusted to
compensate for the rounding of the annual maintenance outage requirement of the
Proxy Unit.

m is the four-year average annual maintenance outage requirement of the New
Unit, expressed as a fraction of a year. The data used to determine m shall
include the annual maintenance outage requirements for the current Power Year
and the next three Power Years, as utilized for the New Unit in the most recent
determination by the Participants Committee of NEPOOL Objective Capability
pursuant to Section 7.

M is the annual maintenance outage requirement of the Proxy Unit. M shall be a
fraction, the numerator of which shall be the number of weeks (rounded to the
nearest full number) that most closely approximates the weighted four- year
average annual maintenance outage requirement (using the Winter Capability of
each generating unit for such weighting) for the generating units in which the
Participants have Installed Capability Entitlements, and the denominator of
which shall be 52 weeks.

d is the summer derating of the New Unit, expressed as a fraction of the Winter
Capability of the New Unit.

D is the summer derating of the Proxy Unit. D shall be a fraction and shall be
equal to the weighted average fractional summer derating (using the Winter
Capability of each generating unit for such weighting) of the generating units
in which the Participants have Installed Capability Entitlements.

K1, K2, K3, K4, and K5

are conversion coefficients for each of the Summer and Winter Periods,
determined by regression analysis such that the product for the Installed
Capability of a New Unit times its New Unit Adjustment Factor approximates the
effect on NEPOOL Objective Capability of the New Unit.

Proxy Unit characteristics and conversion coefficients contained in the formula
shall be adopted by the Participants Committee and reviewed every five years (or
more frequently if the Participants Committee determines that exceptional
circumstances require an earlier review) and revised as necessary.

If a New Unit has unique characteristics affecting NEPOOL Objective Capability
which are not adequately reflected in the New Unit Adjustment Factor formula,
the Participants Committee shall determine for such New Unit a New Unit
Adjustment Factor which accounts for the New Unit's unique characteristics.

The New Unit Adjustment Factor for any Restricted Unit (as defined in Section
15.37B of the Prior NEPOOL Agreement) for which proposed plans were submitted
subsequent to November 1, 1990 for review pursuant to Section 18.4 or its
predecessor section in the Prior NEPOOL Agreement (or, in the case of a unit
with a rated capacity of less than 5 MW, for which notification was first given
to NEPOOL subsequent to November 1, 1990) and for the Peabody Municipal Light
Plant's Waters River #2 unit shall be determined in accordance with the formula
previously specified in Section 12.2(a)(2), modified as follows:

n = R(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) +K5(f-F)c2) + K6(2500-a)

The symbols used in the above formula, as modified, shall have the meanings
previously specified, except that the symbols "K6" and "a" shall have the
following meanings:

K6 is a scaling factor of 0.0001.

a is as follows:

for units with more than 2500 annual hours available for operation, "a" =
2500,

for units with annual hours available for operation between 500 and 2500,
inclusive, "a" = annual hours available for operation,

and for units with annual hours available for operation less than 500 hours,
"a" = -7500;

provided, however, that a Participant may elect to avoid, in whole or part, the
effect on its Installed Capability Responsibility of a Restricted Unit's
availability being limited to 2500 hours or less a year by agreeing to leave
unfilled a portion of its dispatchable load allocation in accordance with rules
adopted by the Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter.

(b) The tentative Installed Capability Responsibilities of the Participants for
any month, as determined in accordance with Section 12.2(a), shall be adjusted
in accordance with this Section 12.2(b) in the event the value of H for any
Participant for any of the Twelve-Month Measurement Periods applicable to the
Participant for the month is increased in accordance with Section 12.2(a)
because of the application of paragraph (ii) of the definition of H1. In such
event the System Operator under the direction of the Participants Committee
shall determine each Participant's tentative Installed Capability Responsibility
for the month with and without the application of said paragraph (ii). The
difference between the sum of all Participants' tentative Installed Capability
Responsibilities, with and without the application of said paragraph (ii) for
the month, shall be added to the tentative Installed Capability Responsibilities
of the Participants, as determined in accordance with Section 12.2(a), in
proportion to said tentative Installed Capability Responsibilities, thereby
establishing each Participant's adjusted tentative Installed Capability
Responsibility for the month.

(c) For each month, the System Operator under the direction of the Participants
Committee shall determine the sum of all Participants' adjusted tentative
Installed Capability Responsibilities, as initially determined in accordance
with Section 12.2(a) and as adjusted in accordance with Section 12.2(b), if
Section 12.2(b) is applicable for such month. If the sum is less than, or equal
to, the minimum NEPOOL Installed Capability during the month, then the adjusted
tentative Installed Capability Responsibility as determined pursuant to Section
12.2(a) or 12.2(b), whichever is applicable, for each Participant is the final
Installed Capability Responsibility for each Participant. If the sum is greater
than such minimum NEPOOL Installed Capability, then each Participant's final
Installed Capability Responsibility shall be its adjusted tentative Installed
Capability Responsibility as determined pursuant to Section 12.2(a) or 12.2(b),
whichever is applicable, multiplied by the ratio of the minimum NEPOOL Installed
Capability during the month to the sum of the adjusted tentative Installed
Capability Responsibilities for the month.

(d) It is recognized that the treatment of fuel conversions, dual fuel units,
immature units, new Installed Capability Entitlements, cogeneration and small
power-producing facilities, Unit Contracts and other contract arrangements,
units with unusual maintenance cycles, and various other matters can result in
special problems in the determination of Unit Availability Adjustment Factors
and New Unit Adjustments. Accordingly, the Markets Committee shall analyze such
special problems and recommend to the Participants Committee for approval
appropriate Market Rules to be applied in taking such matters into account in
the determination of Unit Availability Adjustment Factors and New Unit
Adjustments.

12.3  [Deleted.].

12.4  [Deleted.].

12.5  Consequences of Deficiencies in Installed Capability Responsibility.

(a) At the conclusion of each month, the System Operator shall determine whether
each Participant has satisfied its Installed Capability Responsibility
obligation for the month. If the minimum monthly Installed System Capability of
a Participant during the month was less than its Installed Capability
Responsibility, the number of Kilowatts of its deficiency shall be computed and
the Participant shall be deemed to purchase from other Participants through
NEPOOL Kilowatts of surplus Installed System Capability equal to the amount of
its deficiency and shall pay to NEPOOL for the month any applicable fees for
services assessed pursuant to Section 19.2 plus the product of its total
Kilowatts of deficiency and the Installed Capability deficiency charge. For
purposes of this Section 12, the minimum monthly Installed System Capability of
a Participant for a month is the Participant's lowest Installed System
Capability for any hour during the month. Retirements made on the last day of
any month shall not be deducted from Installed System Capability for that month.

(b) The Installed Capability deficiency charge shall be an administratively-
determined charge approved by the Participants Committee, except that, if the
Participants Committee is unable to finally approve such a charge on or before
July 28, 2000, the Installed Capability deficiency charge shall be the charge
determined by the System Operator, until such time as the Participants Committee
finally approves a different charge.

(c) The Installed Capability deficiency charge that is to become effective on
August 1, 2000 is subject to the acceptance and/or approval by the Commission of
the materials filed in compliance with the Commission's June 28, 2000 order in
Docket Nos. EL00-62-000, et al. Pending Commission action on such charge, any
collections for deficiencies in Installed Capability on and after August 1, 2000
shall be subject to refund or surcharge back to August 1, 2000 if the deficiency
charge accepted and/or approved by the Commission is different from the charge
identified in the compliance filing.

(d) The Installed Capability Responsibility deficiency charges for each month
shall be divided among and paid to those Participants whose minimum monthly
Installed System Capabilities during such month exceeded their Installed
Capability Responsibilities, in proportion to the amounts of their respective
excesses over their Installed Capability Responsibilities.

12.6  [Deleted].

12.7 Payments to Participants Furnishing Installed Capability. Participants that
are deemed pursuant to Section 12.5 to furnish any surplus in their Installed
System Capability to other Participants shall receive therefor their pro rata
shares on a Kilowatt basis of all payments made by Participants for the month
under Section 12.5, excluding any applicable fees for services assessed pursuant
to Section 19.2. If two or more Participants with excess Installed System
Capability have bid Kilowatts at the Installed Capability Clearing Price, but
not all the excess Installed System Capability bid at such price is required to
meet shortages of Installed System Capability, then the excess Installed System
Capability bid at the Installed Capability Clearing Price that each such
Participant shall be deemed to have furnished shall be the Kilowatts of excess
Installed System Capability bid by the Participant at that price multiplied by
the ratio of (i) the total Kilowatts of excess Installed System Capability bid
at the Installed Capability Clearing Price needed to meet the shortages to (ii)
the total Kilowatts of excess Installed System Capability bid by all
Participants at the Installed Capability Clearing Price.

[Next Sheet is 157]

Sheet 157 is intentionally blank.

[Next Sheet is 158]



                                  SECTION 13
                   OPERATION, GENERATION, OTHER RESOURCES,
                           AND INTERRUPTIBLE CONTRACTS

13.1 Maintenance and Operation in Accordance with Accepted Electric Industry
Practice. Each Participant shall, to the fullest extent practicable, cause all
generating facilities and other resources owned or controlled by it to be
designed, constructed, maintained and operated in accordance with Accepted
Electric Industry Practice.

13.2 Central Dispatch. Subject to the following sentence, each Participant
shall, to the fullest extent practicable, subject all generating facilities and
other resources owned or controlled by it to central dispatch by the System
Operator; provided, however, that each Participant shall at all times be the
sole judge as to whether or not and to what extent safety requires that at any
time any of such facilities will be operated at less than full capacity or not
at all. Each Participant may remove from central dispatch a generating facility
or other resources owned or controlled by it if and to the extent such removal
is permitted by rules and standards approved by the Participants Committee

13.3 Maintenance and Repair. Each Participant shall, to the fullest extent
practicable: (a) cause generating facilities and other resources owned or
controlled by it to be withdrawn from operation for maintenance and repair only
in accordance with maintenance schedules reported to and published by the System
Operator from time to time in accordance with procedures established or approved
by the Markets Committee prior to the activation of the Participants Committee
or the Participants Committee thereafter, (b) restore such facilities to good
operating condition with reasonable promptness, and (c) accelerate or delay
maintenance and repair at the reasonable request of the System Operator in
accordance with market operation rules approved by the Markets Committee prior
to the activation of the Participants Committee or the Participants Committee
thereafter.

13.4 Objectives of Day-to-Day System Operation. The day-to-day scheduling and
coordination through the System Operator of the operation of generating units
and other resources shall be designed to assure the reliability of the bulk
power system of the NEPOOL Control Area. Such activity shall:

(a)  satisfy the NEPOOL Control Area's Operating Reserve requirements,
including the proper distribution of those Operating Reserves

(b)  satisfy the Automatic Generation Control requirements of the NEPOOL
Control Area; and

(c)  satisfy the Energy requirements of all Electrical Load of the
Participants,

all at the lowest practicable aggregate dispatch costs to the NEPOOL Control
Area based upon Participant-directed schedules and Bids until the CMS/MSS
Effective Date and based upon Self-Schedules, Self-Supplies, Supply Offers and
Demand Bids on and after that Date.

13.5 Satellite Membership. Each Participant which is responsible for the
operation of transmission facilities rated 69 kV or above in the NEPOOL Control
Area or generating units and other resources which are subject to central
dispatch by NEPOOL, or which is responsible for implementing voltage reduction
and load shedding procedures in the NEPOOL Control Area, shall become a member
of the appropriate satellite dispatching center; provided that by mutual
agreement among the affected Participants and the appropriate satellite, a
Participant may be excused from joining the satellite if it has arranged with a
satellite member to assume responsibility to the satellite for its facilities or
obligations



                                   SECTION 14
                            INTERCHANGE TRANSACTIONS

14.1  Obligation for Energy, Operating Reserve and Automatic Generation
Control.

This Section 14 shall remain in effect for service under this Agreement until
the CMS/MSS Effective Date and shall be superseded by the provisions of Section
14A of this Agreement for service on and after the CMS/MSS Effective Date.

(a) Each Participant shall have for each hour an Energy obligation equal to its
Electrical Load plus the kilowatthours delivered by such Participant to other
Participants in the hour pursuant to Firm Contracts or System Contracts,
together with any associated electrical losses.

(b) Each Participant shall have for each hour Operating Reserve obligations
equal to its share of the quantity of each category of Operating Reserve
required for the NEPOOL Control Area in the hour.

Subject to adjustment pursuant to Section 14.6, a Participant's share of each
category of Operating Reserve required for any hour shall be determined in
accordance with the following formula:

ORp=SAp + [(OR-SA) (ELp/EL)], wherein

Orp is the Participant's share of that category of Operating Reserve for the
hour.

Sap is the number of Kilowatts, if any, of that category of Operating Reserve
for the hour that the Participants Committee determines should be assigned
specifically to such Participant and not be shared by all Participants.

OR is the aggregate number of Kilowatts of that category of Operating Reserve
determined by the System Operator in accordance with the directions of the
Participants Committee to be required for the NEPOOL Control Area for the hour
that is not assigned to Non-Participants.

SA is the aggregate number of Kilowatts of that category of Operating Reserve
for the hour that the Participants Committee determines should not be shared by
all Participants, but not including Operating Reserve assigned to
Non-Participants.

Elp is the Participant's Electrical Load for the hour.

EL  is the sum of ELp for all Participants.

(c) Each Participant shall have for each hour an AGC obligation equal to its
share of AGC required for the NEPOOL Control Area in the hour. Subject to
adjustment pursuant to Section 14.6, a Participant's share of AGC required for
any hour shall be determined in accordance with the following formula:

AGCp=AGC (ELp/EL), wherein

AGCp is the Participant's share of AGC for the hour.

AGC is the total amount of AGC determined by the System Operator in accordance
with market operation rules approved by the Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter to be required for the NEPOOL Control Area for the hour that is not
assigned to Non-Participants.

ELp and EL are as defined in Section 14.1(b).

14.2  Obligation to Bid or Schedule, and Right to Receive Energy, Operating
Reserve and Automatic Generation Control.

(a) A Participant which has Energy Entitlements shall submit to or have on file
with the System Operator, in accordance with the market operation rules approved
by the Markets Committee prior to the activation of the Participants Committee
or the Participants Committee thereafter, one or more bids for the Energy
Entitlements for which the Participant is permitted to bid specifying the Bid
Price at which it will furnish Energy through NEPOOL to other Participants under
this Agreement or to Non- Participants for ancillary services under the Tariff,
or pursuant to arrangements with Non-Participants entered into under Section
14.6, except to the extent such Entitlements are scheduled by the Participant
consistent with Section 14.2(d).

(b) A Participant which has Operating Reserve Entitlements or AGC Entitlements
shall also submit to or have on file with the System Operator, in accordance
with the market operation rules approved by the Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter, one or more bids for each such Entitlement for which the Participant
is permitted to bid specifying the Bid Prices at which it will furnish 10-Minute
Spinning Reserve, 10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve
and/or AGC through NEPOOL to other Participants under this Agreement or to
Non-Participants for ancillary services under the Tariff, except to the extent
such Entitlements are scheduled by the Participant consistent with Section
14.2(d).

(c) Except as emergency circumstances may result in the System Operator
requiring load curtailments by Participants, each Participant shall be entitled
to receive from the other Participants (or from the service made available from
Non-Participants pursuant to arrangements entered into under Section 14.6) such
amounts, if any, of Energy, Operating Reserve, and AGC as it requires and
Non-Participants shall be entitled to receive from Participants the amount of
ancillary services to which they are entitled pursuant to the Tariff. If, for
any hour, load curtailments are required, the amount that Participants and
Non-Participants with shortages are entitled to receive shall be proportionally
reduced by the System Operator in a fair and non-discriminatory manner in light
of the circumstances.

(d) All Bid Prices for Entitlements shall be submitted in accordance with market
operation rules approved by the Markets Committee prior to the activation of the
Participants Committee or the Participants Committee thereafter. If a Bid Price
is not submitted for any such Entitlement, the Bid Price shall be deemed to be
zero. For a generating unit in which there are multiple Entitlement holders,
only one Participant shall be permitted to submit Bid Prices for Energy,
Operating Reserve and/or AGC Entitlements for such unit or to direct the
scheduling of the unit for any Scheduled Dispatch Period. The Entitlement
holders in each unit with multiple Entitlement holders shall designate a single
Participant that will be permitted to submit Bid Prices and/or to direct the
scheduling of the unit. In the event that more than one Participant is
designated, or if the Entitlement holders do not designate a single Participant,
then Bid Prices for the unit shall be based on its replacement cost of fuel,
which shall be furnished to the System Operator by the Participant responsible
for furnishing such information as of December 1, 1996. Further, any schedules
for the unit will be submitted to the System Operator by such Participant.
Nothing in this Agreement shall affect the rights of any Entitlement holder
under the contractual arrangements among such Entitlement holders relating to
the unit. Prior to the Third Effective Date, Bid Prices must be submitted for
the next Scheduled Dispatch Period for all Energy, Operating Reserve and AGC
Entitlements in generating unit or units and Energy Entitlements pursuant to
Firm Contracts or System Contracts which may be scheduled by the buyer in
accordance with Section 14.7(b) no later than noon on the preceding day or such
later time as is specified in the market operation rules approved by the Markets
Committee prior to the activation of the Participants Committee or the
Participants Committee thereafter. On and after the Third Effective Date, such
Bid Prices shall be submitted for each hour of the day and the notice period for
such Bid Prices shall be reduced to one hour or such shorter time as the System
Operator determines from time to time is practical while maintaining reliability
and meeting its other obligations to the Participants, except that such notice
period shall be longer than one hour if and to the extent that the System
Operator reasonably determines that such notice is the shortest notice that is
technically feasible at that time to maintain reliability and meet its other
obligations to the Participants. The System Operator shall notify the
Participants following its receipt of all Bid Prices of the expected dispatch
schedule for the next Scheduled Dispatch Period. The System Operator shall
reduce the notice required for Bid Prices and the applicable Scheduled Dispatch
Period to the minimum time technically and practically feasible while
maintaining reliability and meeting its other obligations to the Participants.

Energy, Operating Reserve and/or AGC Entitlements in a generating unit or units
may also be scheduled directly by the Participants permitted to submit Bid
Prices for such Entitlements, but only in accordance with this Section 14.2(d)
and market operation rules approved by the Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter consistent herewith. Subject to the right of the System Operator to
direct changes to schedules in order to ensure reliability in the NEPOOL Control
Area or any neighboring control area, a Participant permitted to bid its Energy,
Operating Reserve, and/or AGC Entitlements in a generating unit or units, or
required to make Energy deliveries, may submit an hour-to-hour schedule for the
operation or dispatch of such Entitlements during a Scheduled Dispatch Period at
or before the time that Bid Prices are required to be submitted for such period.
In addition, prior to the Third Effective Date, a Participant permitted to bid a
unit or units may submit a short- notice schedule for the operation or dispatch
of any or all of the Energy available from such unit or units during the current
or a subsequent Scheduled Dispatch Period following the time that the System
Operator notifies the appropriate Participants of their expected Entitlement
commitments for that Scheduled Dispatch Period; provided that, for each such
short-notice schedule, the Participant has not been advised by the System
Operator that the Energy, Operating Reserve or AGC Entitlements from the unit or
units covered by the Participant's schedule are expected to be used during the
Scheduled Dispatch Period to meet the region's Energy, Operating Reserve and/or
AGC requirements, and provided further that the Participant short- notice
schedule is only to facilitate transactions during such period from resources or
to load located outside the NEPOOL Control Area; and provided further that such
schedule is furnished at least one hour in advance of the start of the
transaction. In addition, a Participant may, on the same short notice, schedule
System Contracts with Non-Participants from resources or to load located outside
of the NEPOOL Control Area.

14.3  Amount of Energy, Operating Reserve and Automatic Generation Control
Received or Furnished.

(a) For purposes of Sections 14.4, 14.5, and 14.8, the amount of Energy which a
Participant is deemed to receive or furnish in any hour shall be the amount of
its Adjusted Net Interchange. If the Adjusted Net Interchange is negative, the
Participant shall be deemed to be receiving Energy in the hour. If the Adjusted
Net Interchange is positive, the Participant shall be deemed to be furnishing
Energy in the hour.

(b) For purposes of Sections 14.4, 14.5, and 14.9, prior to the Third Effective
Date: the amount of each category of Operating Reserve which a Participant is
deemed to receive in any hour is the Kilowatts of such Operating Reserve
assigned to the Participant for the hour under Section 14.1(b) less any
Kilowatts provided in the hour by the Participant in accordance with the market
operation rules approved by the Markets Committee prior to the activation of the
Participants Committee or the Participants Committee thereafter to meet any
Operating Reserve requirements that were specifically assigned to it and not
shared by all Participants; the amount of Operating Reserve of each category
that the Participant is deemed to have furnished under the Agreement in the hour
is the amount of such Operating Reserve designated by the System Operator to be
provided in the hour by the Participant's applicable Operating Reserve
Entitlements, minus any Kilowatts used in the hour by the Participant in
accordance with the market operation rules to meet any Operating Reserve
requirements that were specifically assigned to it and not shared by all
Participants. For purposes of Sections 14.4, 14.5, and 14.9, on and after the
Third Effective Date, the amount of each category of Operating Reserve which a
Participant is deemed to have received or furnished in any hour is the
difference between the Kilowatts of such Operating Reserve assigned to the
Participant for the hour under Section 14.1(b) and the Kilowatts of such
Operating Reserve designated by the System Operator to be provided in the hour
by the Participant's applicable Operating Reserve Entitlements.

(c) For purposes of Sections 14.4, 14.5, and 14.10, prior to the Third Effective
Date, the amount of AGC which a Participant is deemed to have received in an
hour is the AGC assigned to the Participant for the hour under Section 14.1(c),
and the amount a Participant is deemed to have furnished in the hour is the AGC
designated by the System Operator to be provided in the hour by the
Participant's AGC Entitlements. For purposes of Sections 14.4, 14.5, and 14.10,
on and after the Third Effective Date, the amount of AGC which a Participant is
deemed to have received or furnished in an hour is the difference between the
AGC assigned to the Participant for the hour under Section 14.1(c) and the AGC
designated by the System Operator to be provided in the hour by the
Participant's AGC Entitlements.

14.4 Payments by Participants Receiving Energy Service, Operating Reserve and
Automatic Generation Control.

(a) For every hour in which a Participant's Adjusted Net Interchange is
negative, the number of megawatthours of its Energy deficiency shall be computed
and the Participant shall pay for the hour the product of its total
megawatthours of deficiency and the Energy Clearing Price applicable for the
hour as determined in accordance with Section 14.8, together with any applicable
uplift charges assessed to the Participant under Sections 14.14 and 14.15 of
this Agreement and Section 24 of the Tariff and any applicable fees for services
assessed pursuant to Section 19.2.

(b) For every hour in which a Participant is deemed to receive Operating Reserve
of any category in accordance with Section 14.3(b), the number of Kilowatts it
is deemed to receive for the hour in each category shall be computed. The
Participant shall pay therefor for the hour any applicable uplift charge
assessed under Section 14.15 and any applicable fees for services assessed
pursuant to Section 19.2 plus the product of (i) the aggregate amount paid to
Participants for that category of Operating Reserve for the hour pursuant to
Section 14.5(b) and (ii) a fraction of which the numerator is the Kilowatts of
that category of Operating Reserve deemed under Section 14.3(b) to have been
received by the Participant for the hour and the denominator is the aggregate
Kilowatts of that category of Operating Reserve deemed under Section 14.3(b) to
have been received by all Participants for the hour.

(c) For every hour in which a Participant is deemed under Section 14.3(c) to
have received AGC, the amount it is deemed to receive shall be computed and the
Participant shall pay therefor any applicable uplift charge assessed under
Section 14.15 and any applicable fees for services assessed pursuant to Section
19.2 plus the product of (i) the aggregate amount paid to Participants for AGC
for the hour pursuant to Section 14.5(c) and (ii) a fraction of which the
numerator is the AGC the Participant is deemed under Section 14.3(c) to have
received for the hour and the denominator is the aggregate amount of AGC all
Participants are deemed under Section 14.3(c) to have received for the hour.

14.5  Payments to Participants Furnishing Energy Service, Operating Reserve,
and Automatic Generation Control.

(a) Subject to the provisions of Section 14.12, a Participant that is deemed in
an hour to furnish Energy service to other Participants pursuant to Section
14.3, or to Non-Participants for ancillary services under the Tariff or pursuant
to arrangements entered into under Section 14.6, shall receive for each
megawatthour furnished by it the Energy Clearing Price for the hour determined
in accordance with Section 14.8 or the Bid Price for that megawatthour, if
higher than the Energy Clearing Price and the unit is either within the Energy
Clearing Price Block (as defined in Section 14.8(c)) or is operated out of merit
if such higher Bid Price is appropriately paid pursuant to market operation
rules governing out-of-merit generation approved by the Markets Committee prior
to the activation of the Participants Committee or the Participants Committee
thereafter. In addition, to the extent that the System Operator reduces Energy
production from a generating unit or units in order to provide VAR support,
Participants with Entitlements in such unit or units may receive their lost
opportunity costs if and to the extent provided for by market operation rules
approved by the Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter.

(b) A Participant that is deemed in an hour to furnish Operating Reserve under
the Agreement shall receive for each Kilowatt of each category of Operating
Reserve furnished by it the applicable Operating Reserve Clearing Price as
defined and determined in accordance with Section 14.9 or the Bid Price to
provide such Kilowatt, if higher than the Operating Reserve Selling Price for
the hour.

(c) A Participant that is deemed in an hour to furnish AGC under the Agreement
shall receive therefor an amount calculated as follows:

(i) the AGC Clearing Price for the hour as defined and determined in accordance
with Section 14.10, times the change in AGC output of the Participant's AGC
Entitlements which the System Operator requested in the hour, times an
appropriate unit conversion factor as determined in accordance with market
operation rules approved by the Markets

Committee prior to the activation of the Participants Committee or the
Participants Committee thereafter; plus

(ii) an AGC reservation payment for each AGC Entitlement that the System
Operator designated for AGC in the hour calculated as (A) the AGC Clearing Price
in effect for the hour, times (B) the level of AGC the System Operator
determines to be available in the hour from the Entitlement, times (C) the
portion of the hour during which the System Operator had designated the
Entitlement for AGC; plus

(iii) a payment that compensates the Participant for its lost opportunity cost,
if any, for the operation of the generating unit or combination of units
designated for AGC in the hour below the desired level of output in order to
provide AGC, as determined in accordance with Market Rules approved by the
Markets Committee prior to the activation of the Participants Committee or the
Participants Committee thereafter.

(d) In no event shall Participants be paid for lost opportunity costs resulting
from a generating unit being dispatched down or off to accommodate transmission
constraints, and nothing in this Agreement or the Market Rules shall provide for
any such payment

14.6  Energy Transactions with Non-Participants.

(a) The Participants Committee is authorized to enter into contracts on behalf
of and in the names of all Participants (i) with power pools or other entities
in one or more other control areas to purchase or furnish emergency Energy (and
related services) that is available for the System Operator to schedule in order
to ensure reliability in the NEPOOL Control Area or neighboring control areas,
and (ii) with Non-Participants pursuant to which ancillary services will be
provided by the Participants pursuant to the Tariff. The terms of any such
contractual arrangement shall not require the furnishing of emergency service to
any other control area until the service needs of all Participants have been
provided for with the least expensive resources practicable. Energy purchased in
any hour from Non-Participants under a contract entered into pursuant to this
Section 14.6(a) shall be deemed to be furnished to, and paid for by,
Participants entitled to or requiring such Energy in the hour pursuant to this
Section 14 at the higher of the Energy Clearing Price for the hour or the price
paid to the Non- Participant for the Energy.

(b) The Participants Committee is authorized to provide for the day-to-day
scheduling through the System Operator of the HQ Phase II Firm Energy Contract,
in accordance with the HQ Use Agreement, as if the Contract were a contract
covering Energy transactions with a Non-Participant entered into pursuant to
Section 14.6(a). The HQ Phase II Firm Energy Contract shall not be deemed a Firm
Contract for purposes of this Agreement. Energy received in an hour from
Hydro-Quebec pursuant to the HQ Energy Banking Agreement, and Energy purchased
in any hour from Hydro-Quebec pursuant to the HQ Phase II Firm Energy Contract
or any other HQ Contract shall be deemed to be Energy furnished to each
Participant entitled to such Energy for the hour in the amount reflected for the
Participant in the System Operator's scheduling of Energy deliveries in the hour
from Hydro-Quebec; except that emergency Energy received from Hydro-Quebec under
the HQ Interconnection Agreement shall be deemed to be Energy provided to (and
shall be paid for by) Participants requiring such emergency Energy in the hour.
The System Operator shall schedule such Energy deliveries to accommodate, to the
maximum extent possible, the schedule of Energy deliveries from Hydro-Quebec
requested by the Participant. The Participants deemed to have received such
Energy shall pay therefor the higher of the Energy Clearing Price (together with
any applicable uplift charges under Sections 14.14 and/or 14.15 of this
Agreement and/or Section 24 of the Tariff and any applicable fees for services
assessed pursuant to Section 19.2) or the price paid to Hydro-Quebec for the
Energy (or in the case of Energy received under the HQ Energy Banking Agreement,
the price paid for the related Energy deliveries to Hydro-Quebec under the
Agreement and any amount payable to Hydro-Quebec with respect to the
transaction).

14.7  Participant Purchases Pursuant to Firm Contracts and System Contracts.

(a) A Participant may undertake to transfer all or select portions of its
settlement rights and obligations under this Agreement to or from another
Participant with respect to any of the NEPOOL markets pursuant to a Bilateral
Transaction. Such transfer of settlement rights and obligations under this
Agreement shall be as agreed to between the two parties to the Bilateral
Transaction and shall be submitted to the System Operator in accordance with the
Market Rules. If and to the extent necessary to implement the agreement between
the parties, such Market Rules, upon approval by the Participants Committee,
shall supersede the provisions of the Agreement that otherwise apply for
determination of the respective settlement rights and obligations of the
parties.

(b) In the event a Participant has the right to receive Energy, Operating
Reserve and/or AGC from a Non-Participant under a System Contract or a Firm
Contract, such Contract shall be treated as nearly as possible as if it were a
Unit Contract for an Energy Entitlement, Operating Reserve Entitlement and/or
AGC Entitlement, as applicable, provided that, in the case of Energy, Operating
Reserve, and/or AGC, the System Contract or Firm Contract permits the scheduling
of deliveries of such Energy, Operating Reserve and/or AGC to be subject in
whole or part to central dispatch through the System Operator in accordance with
Market Rules approved by the Markets Committee prior to the activation of the
Participants Committee or the Participants Committee thereafter.

14.8  Determination of Energy Clearing Price.  For each hour, the System
Operator shall determine the Energy Clearing Price as follows:

(a) The System Operator shall rank in the order of lowest to highest (i) the
Dispatch Prices derived from the Bid Prices to furnish Energy in the hour and
(ii) the cost to NEPOOL of any Energy received from Non-Participants in the hour
pursuant to contracts referenced in Section 14.6.

(b) The Energy Clearing Price shall be the weighted average of the Dispatch
Prices (or NEPOOL cost) of the "Energy Clearing Price Block" as defined in the
next sentence. The Energy Clearing Price Block shall be identified for each hour
in accordance with market operation rules approved by the Markets Committee
prior to the activation of the Participants Committee or the Participants
Committee thereafter to reflect those resources with the highest Dispatch Prices
or NEPOOL cost that were centrally dispatched by the System Operator for Energy
deemed to have been furnished to the Participants, excluding resources that were
dispatched out of merit as determined in accordance with market operation rules
approved by the Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter.

14.9  Determination of Operating Reserve Clearing Price.

(a) For each hour as necessary, the System Operator shall determine the
Operating Reserve Clearing Price for each category of Operating Reserve as
follows:

(i) The System Operator shall determine the aggregate Kilowatts of the
applicable category of Operating Reserve that are deemed pursuant to Section
14.3(b) to have been received by Participants for the hour.

(ii) For 10-Minute Non-Spinning Reserve and 30-Minute Operating Reserve, the
System Operator shall rank in the order of lowest to highest the Bid Prices of
the resources designated by the System Operator for that category of Operating
Reserve for the hour. The applicable Operating Reserve Clearing Price for
10-Minute Non-Spinning Reserve or 30-Minute Operating Reserve shall be the
weighted average of the highest Bid Prices for the 1000 Kilowatts (or such other
number as may be specified by the Markets Committee prior to the activation of
the Participants Committee or the Participants Committee thereafter) of that
category of Operating Reserve that are designated by the System Operator for use
in the hour.

(iii) For 10-Minute Spinning Reserve the System Operator shall rank in order of
lowest to highest the 10-Minute Spinning Reserve Lost Opportunity Prices (as
defined in Section 14.9(b)) of the resources designated by the System Operator
for the hour. The Operating Reserve Clearing Price for 10- Minute Spinning
Reserve shall be the weighted average for the 1000 Kilowatts (or such other
number as may be specified by the Markets Committee prior to the activation of
the Participants Committee or the Participants Committee thereafter) of the
highest 10-Minute Spinning Reserve Lost Opportunity Prices for the hour of the
Entitlements that were designated by the System Operator for use in the hour.

(b) The System Operator shall determine a 10-Minute Spinning Reserve Lost
Opportunity Price for each hour for use in determining the Operating Reserve
Clearing Price for 10-Minute Spinning Reserve. For the purposes of Section 14.9,
the 10-Minute Spinning Reserve Lost Opportunity Price for a Participant's
resource shall be the amount by which the Energy Clearing Price for the hour
exceeds the resource's Dispatch price (not less than zero), plus the Bid Price
in the hour for each resource to provide 10-Minute Spinning Reserve.

14.10 Determination of AGC Clearing Price. For each hour, the System Operator
shall determine the AGC Clearing Price. The AGC Clearing Price shall be the
weighted average "AGC Capability Price" for the "AGC Clearing Price Block," as
both terms are defined below in this Section 14.10. The AGC Capability Price for
each hour for each AGC Entitlement designated by the System Operator to provide
AGC in the hour shall be a cost per unit of AGC capability based on the Bid
Price for the Entitlement for the hour divided by the amount of AGC available in
the hour from that Entitlement. The AGC Clearing Price Block shall be identified
by the System Operator for each hour in accordance with market operation rules
approved by the Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter to reflect those AGC
resources with the highest Bid Prices that were designated by the System
Operator to provide AGC in the hour and were deemed pursuant to Section 14.3(c)
to have been received by Participants for the hour.

14.11  Funds to or from which Payments are to be Made.

(a) All payments for Energy, Operating Reserves or AGC furnished or received,
all uplift charges paid pursuant to this Section 14 of this Agreement and
Section 24 of the Tariff, and all fees for services paid pursuant to Section
19.2, and any payments by Non-Participants for ancillary services under
Schedules 2-7 to the Tariff or pursuant to arrangements referenced in Section
14.6, shall be allocated each month through the Pool Interchange Fund as
follows:

Step One. For each week in which Energy is delivered or received under the HQ
Energy Banking Agreement, all payments with respect to transactions under that
Agreement shall be made to or from the Energy Banking Fund provided for in
Section 14.11(b).

Step Two. (i) For each week in which Pre-Scheduled Energy (as defined in the HQ
Phase I Energy Contract) is purchased pursuant to the HQ Phase I Energy
Contract, the aggregate amount which is paid pursuant to Section 14.6(b) for
such Energy by each Participant which is a participant in the Phase I
arrangements with Hydro-Quebec shall be determined and paid on the Participant's
account into the Phase I Savings Fund.

(ii) For each week in which Energy is purchased pursuant to the HQ Phase II Firm
Energy Contract, the aggregate amount which is paid pursuant to Section 14.6(b)
for such Energy by each Participant which is a participant in the Phase II
arrangements with Hydro-Quebec shall be determined and paid on the Participant's
account into the Phase II Savings Fund.

Step Three. For each week in which Other HQ Energy is purchased pursuant to the
HQ Phase I Energy Contract or Energy is purchased pursuant to the HQ
Interconnection Agreement, the aggregate amount paid pursuant to Section 14.6(b)
for such Energy shall be determined for each Participant which is a participant
in the Phase I or Phase II arrangements with Hydro-Quebec. Such amount shall be
allocated between the Participant's share of the Phase I Savings Fund and the
Participant's share of the Phase II Savings Fund created under the HQ Use
Agreement in the same ratio as (A) the sum of (x) the number of kilowatthours of
Other HQ Energy deemed to be purchased by the Participant during the week and
(y) the HQ Phase I Percentage of the number of kilowatthours deemed to be
purchased by the Participant under the HQ Interconnection Agreement during the
week, bears to (B) the HQ Phase II Percentage of the number of kilowatthours
purchased under the HQ Interconnection Agreement during the week.

Step Four. The balance remaining in the Pool Interchange Fund after Steps One
through Three shall be retained in the Pool Interchange Fund for the month and
shall be used and disbursed after each month in the following order:

(i) (A) amounts owed to Non-Participants (other than Hydro-Quebec) for the month
under contracts entered into with them pursuant to Section 14.6(a) shall be
paid, and (B) amounts owed to Hydro-Quebec for the month for Energy deemed to be
furnished pursuant to Section 14.6(b) to Participants which are not participants
in the Phase I or Phase II arrangements with Hydro-Quebec shall be paid and, in
the event the price paid by any such Participant for such Energy is the Energy
Clearing Price, the excess, if any, of the Energy Clearing Price over the amount
owed to Hydro-Quebec shall be paid to the Participant;

(ii) amounts paid by Participants for applicable fees for services assessed
pursuant to Section 19.2 shall be used to reduce NEPOOL expenses; and

(iii) amounts owed to Participants for the month pursuant to Section 14.5 shall
then be paid.

(b)  HQ Energy Banking Fund.  All amounts allocated to the HQ Energy Banking
Fund for each month shall be used and disbursed as follows:

(i) Participants which furnish Energy for delivery to Hydro-Quebec under the HQ
Energy Banking Agreement shall receive therefor from their share of the Energy
Banking Fund the amount to which they are entitled for such service in
accordance with Section 14.5.

(ii) amounts required to be paid to Hydro-Quebec under the HQ Energy Banking
Agreement shall be paid from the shares of the Fund of the Participants engaging
in transactions under the HQ Energy Banking Agreement for the month in
accordance with their respective interests in the transactions for the month. If
there is not enough in any such share, the Participants with the deficient
shares shall be billed and pay into their shares of the Fund the amounts
required for payments to Hydro-Quebec.

(iii) subject to the remaining provisions of this Section, at the end of each
month any balance remaining in each Participant's share of the HQ Energy Banking
Fund shall (I) in the case of any Participant which is not a participant in the
Phase I or Phase II arrangements with Hydro-Quebec, be paid to such Participant,
and (II) in the case of any Participant which is a participant in the Phase I or
Phase II arrangements with Hydro-Quebec, be paid to the Escrow Agent under the
HQ Use Agreement to be held and disbursed by it through the Phase I Savings Fund
and Phase II Savings Fund created under the HQ Use Agreement, and shall be
allocated between the Participant's share of said Funds as follows:

(A) the balance remaining in the Participant's share of the HQ Energy Banking
Fund for the month shall be divided by the number of kilowatthours deemed to be
received by the Participant under the HQ Energy Banking Agreement during the
month to determine an average savings amount per kilowatthour;

(B) for any hour during the month in which the number of kilowatthours received
by NEPOOL under the HQ Energy Banking Agreement exceeded the HQ Phase I Transfer
Capability, an amount equal to (A) the Participant's share of the excess of (1)
the number of kilowatthours received over (2) the HQ Phase I Transfer Capability
times (B) the average savings amount per kilowatthour determined for that
Participant under (i) above shall be allocated to the Phase II Savings Fund; and

(C) the remaining balance of the Participant's share of the HQ Energy Banking
Fund for the month shall be allocated to the Phase I Savings Fund.

It is recognized that, in view of the time which may elapse between the delivery
of Energy to or by Hydro-Quebec in an Energy Banking transaction under the HQ
Energy Banking Agreement and the return of the Energy, the amounts of Energy
delivered to and received from Hydro-Quebec, after adjustment for losses, may
not be in balance at the end of a particular month.

Further, if as of the end of any month and after adjustment for electrical
losses, the cumulative amount of Energy so received from Hydro-Quebec exceeds
the amount so delivered, the aggregate amount paid by Participants for the
excess Energy pursuant to Section 14.6(b) shall be paid to the Energy Banking
Fund. The Escrow Agent under the HQ Use Agreement shall hold and invest these
funds. On the return of the excess Energy to Hydro-Quebec, the amount so held by
the Escrow Agent shall be repaid to Hydro-Quebec and Participants in accordance
with the Energy Banking Agreement.

(c) Phase I HQ Savings Fund. The aggregate amount allocated to each
Participant's share of the Phase I HQ Savings Fund for each month shall be used,
first, to pay to Hydro-Quebec the amount owed to it for the month for Energy
furnished under the Phase I HQ Energy Contract and the HQ Phase I Percentage of
the amount owed to it for the month for Energy furnished to the Participants
under the HQ Interconnection Agreement. The balance of the amount allocated to
the Fund for the month shall be paid to the Escrow Agent under the HQ Use
Agreement to be held and disbursed by it through the Phase I HQ Savings Fund
created thereunder in accordance with each Participant's contribution to such
balance.

(d) Phase II HQ Savings Fund. The aggregate amount allocated to the Phase II HQ
Savings Fund for each month shall be used, first, to pay to Hydro- Quebec the
amount owed to it for the month for Energy deemed to be furnished to the
Participant under the Phase II HQ Firm Energy Contract and the HQ Phase II
Percentage of the amount owed to it for the month for Energy deemed to be
furnished to the Participant under the HQ Interconnection Agreement. The balance
of the amount allocated to the Fund for the month shall be paid to the Escrow
Agent under the HQ Use Agreement to be held and disbursed by it through the
Phase II HQ Savings Fund created thereunder in accordance with each
Participant's contribution to such balance.

14.12  Development of Rules Relating to Nuclear and Hydroelectric
Generating Facilities, Limited-Fuel Generating Facilities, and Interruptible
Loads.

It is recognized that the central dispatch of Energy available from nuclear
generating facilities and from pondage associated with hydroelectric generating
facilities and from interruptible loads and of pumping Energy for pumped storage
hydroelectric generating facilities and other limited-fuel generating facilities
involves special problems which must be resolved to assure fair and
non-discriminatory treatment of Participants having Entitlements in such
generating facilities or having such interruptible loads or any other
Participants involved in such transactions. Accordingly, the Markets Committee
shall analyze such special problems and recommend to the Participants Committee
for approval appropriate rules for dispatching such facilities (including, but
not limited to, bids for dispatchable pumping load at pumped storage
facilities), for handling such interruptible loads and for paying for Energy,
Operating Reserve and AGC involved in such transactions on a basis consistent
with the principles underlying this Section 14; and upon approval by the
Participants Committee such rules shall supersede the provisions of Sections 12
and 14 to the extent of any conflict.

14.13 Dispatch and Billing Rules During Energy Shortages. It is recognized that
Energy shortages can result in special problems which must be resolved to assure
that dispatch and billing provisions do not prevent achievement of the
objectives specified in Section 13.4. Accordingly, the Markets Committee shall
analyze such special problems and recommend to the Participants Committee for
approval appropriate dispatch and billing rules to be applied during periods
when the Participants Committee determines that there is, or is anticipated to
be, an Energy shortage which adversely affects the bulk power supply of the
NEPOOL Control Area and any adjoining areas served by Participants.

Upon approval by the Participants Committee, such rules shall supersede the
economic dispatch and billing provisions of this Agreement to the extent of any
conflict therewith for the duration of such Energy shortage period.

14.14  Congestion Uplift.

(a) It shall be the responsibility of the Participants Committee to review prior
to January 1, 2000 the Congestion Costs incurred with the new market
arrangements contemplated by Section 14 of this Agreement and with retail
access, and to determine whether subsection (b) of this Section, together with
an amendment specifying the rights of Participants and Non-Participants across a
constrained interface within the NEPOOL Control Area and to make other necessary
or appropriate changes in subsection (b), all of the provisions of which shall
be considered for modification, or some other modified or substitute provision
dealing with the allocation of Congestion Costs in a constrained transmission
area, should be made effective on March 1, 2000 and after the preparation of
necessary implementing rules and computer software or on an earlier or later
effective date. If the Participants Committee determines that such a provision
should be made effective, it shall recommend to the Participants any required
amendment to the Agreement and/or the Tariff and a schedule for implementation
which will permit sufficient time for the development of necessary rules and
computer software. If the Participants Committee is unable to agree on such a
determination prior to January 1, 2000 any Participant or group of Participants
may propose such an amendment and schedule in a filing with the Commission.

(b) Commencing on the implementation effective date of an order by the
Commission directing a different allocation of congestion costs, whenever
limitations in available transmission capacity in any hour require that the
System Operator dispatch out-of-merit resources that are bid by the Participants
in any area which is determined to be a constrained transmission area in
accordance with Market Rules, the System Operator shall determine for the
constrained transmission area the aggregate Congestion Costs for the hour.

[Next Sheet is 196]

Such Congestion Costs for each hour shall be allocated to and paid by
Participants and Non-Participants as a congestion uplift as follows:

(i) In accordance with market operation rules approved by the Regional Market
Operations Committee and the Regional Transmission Operations Committee prior to
the activation of the Participants Committee or the Participants Committee
thereafter, the System Operator shall identify for each Participant and
Non-Participant the difference in megawatt hours, if any, between (A) Electrical
Load served by the Participant or Non-Participant in the constrained area and
transactions by the Participant or Non- Participant occurring in the hour which
utilized the constrained interface to move Energy through the constrained area
and (B) the Participant's or Non- Participant's in-merit Energy Entitlements
located in

[Next Sheet is 197]

the constrained area that were used in the hour to serve such Electrical Load,
taking into account Firm Contracts and System Contracts between Participants and
electrical losses, if and as appropriate.

(ii) The System Operator shall identify for each Participant and Non-
Participant the megawatt hours, if any, of the rights of that Participant or
Non-Participant to use the then effective transfer capability across the
constrained interface.

(iii) The System Operator shall identify for each Participant and Non-
Participant the megawatt hours, if any, by which the amount determined pursuant
to clause (i) above for that Participant or Non-Participant exceeds the amount
determined for that Participant or Non-Participant pursuant to clause (ii)
above. If the clause (i) amount exceeds the clause (ii) amount, the Participant
or Non-Participant shall be responsible for paying a share of the aggregate
Congestion Costs in proportion to the Participant's or Non- Participant's share
of the aggregate amount of such excesses for all Participants and
Non-Participants, and such Congestion Costs shall be included, as a transmission
charge, in the Regional Network Service,

Internal Point-to-Point Service or Through or Out Service charge, whichever is
applicable.

(c) As used in this Section 14.14, the "Congestion Cost" of an out-of-merit
resource for an hour means the product of (i) the difference between its
Dispatch Price and the Energy Clearing Price for the hour, times (ii) the number
of megawatt hours of out-of-merit generation produced by the resource for the
hour.

14.14A  CMS/MSS Implementation Studies Related to Congestion.

(a) Study of Transmission Constraints and Reliability Regions. The Participants
Committee shall commission a study to determine whether the implementation of
CMS and MSS is likely to result in substantial, adverse impacts on any load
pockets within New England. As an additional component of this study, there
shall be an initial determination of the existence or lack of workable
competition in the NEPOOL Markets in Reliability Regions, Load Zones and any
load pockets. This study shall commence on or before July 1, 2000 and shall be
completed no later than December 31, 2000. If the results of this study
determine that there is likely to be substantial adverse impacts on any load
pocket due to the implementation CMS and MSS, the Participants Committee shall
undertake to develop new measures to mitigate such impacts. Unless or until new
measures are implemented to replace or supplement existing measures, the System
Operator shall apply existing NEPOOL System Rules to mitigate such impacts to
the extent possible and appropriate. In evaluating whether there will be
substantial adverse impacts, the study shall take into account planned
transmission enhancements to increase transfer capability into any load pocket,
the anticipated operation of new or expanded generating units and anticipated
retirements of existing generating units, the anticipated value of FCRs and
revenues from the sale thereof that will be available to load in any load
pocket, the concentration of ownership of generation and responsibilities for
serving load in the load pocket, and the anticipated load response to such
adverse impacts.

(b) Study of Market Rule and Procedure 17 ("Market Rule 17"). Before the CMS/MSS
Effective Date, the System Operator and Participants shall review Market Rule 17
and consider changes, where appropriate, to that Market Rule in light of the
implementation of CMS and MSS. The review shall be supervised and assisted by
persons who have recognized antitrust expertise and experience and are retained
by or on behalf of the Participants Committee. At a minimum, before the CMS/MSS
Effective Date, Market Rule 17 shall be amended to prescribe the process to
determine whether a Reliability Region or load pocket within a Reliability
Region is workably competitive and, if a Reliability Region or load pocket is
determined not to be workably competitive, the types of mitigation measures
available to be applied to remedy such situation.

14.15 Additional Uplift Charges. It is recognized that the System Operator may
be required from time to time to dispatch resources out of merit for reasons
other than those covered by Section 14.14 of this Agreement and Section 24 of
the Tariff. Accordingly, if and to the extent appropriate, feasible and
practical, dispatch and operational costs shall be categorized and allocated as
uplift costs to those Participants and Non-Participants that are responsible for
such costs. Such allocations shall be determined in accordance with Market Rules
that are consistent with this Agreement and any applicable regulatory
requirements and approved by the Regional Market Operations Committee prior to
the activation of the Participants Committee or the Participants Committee
thereafter.



                              SECTION 14A

                    PARTICIPANT MARKET TRANSACTIONS
                 ON AND AFTER THE CMS/MSS EFFECTIVE DATE


This Section 14A shall become effective, and shall supersede Section 14 in its
entirety, for service under this Agreement on and after the CMS/MSS Effective
Date. Certain provisions of this Section 14A are subject to further modification
to comply with requirements of the Commission's June 28, 2000 order in Docket
Nos. EL00-62-000, et al. and further Commission orders with respect thereto.
This Section 14A shall have no effect for service or charges under this
Agreement prior to the CMS/MSS Effective Date unless specific provisions are
made applicable earlier pursuant to the Market Rules. This Section 14A specifies
the rights and obligations of Participants under the Agreement with respect to
the supply of, and payment for, Energy, Operating Reserve, 4-Hour Reserve and
AGC.

14A.1 Supply Obligations and Settlement Obligations for Energy, Operating
Reserve, 4-Hour Reserve and Automatic Generation Control.

(a) Supply Obligation. Each Participant with a Resource or an Entitlement in a
Resource that is scheduled in the Day-Ahead Market by the System Operator, in
accordance with an applicable Supply Offer, Self-Schedule or designation for
Self-Supply, to provide Energy at a Node or External Node, Operating Reserve,
4-Hour Reserve and/or AGC shall have a Day-Ahead Market Supply Obligation for
the service scheduled in the amount so scheduled. The Day-Ahead Market Supply
Obligation shall be satisfied by the Participant for each hour in one of the
following two ways: (i) the Participant shall furnish or cause to be furnished
in Real-Time such service under this Section 14A each hour pursuant to the
schedule; or (ii) the Participant shall pay at the applicable Real-Time Nodal
Price or Clearing Price for such amounts which it has not furnished or caused to
be furnished in accordance with clause (i). Each Participant with a Resource or
an Entitlement in a Resource that is scheduled in the Day-Ahead Market or that
submits a Supply Offer, or that is scheduled pursuant to a Self-Schedule or
designated pursuant to a Self-Supply in the Real-Time Market, for Energy at a
Node or External Node, Operating Reserve or AGC, shall have a Real-Time Market
Supply Obligation for each hour for which it is so scheduled or designated. Its
Real-Time Market Supply Obligation for Energy shall be equal to the amounts of
Energy at a Node or External Node it provides in the Real-Time Market in
response to dispatch instructions by the System Operator (including dispatch
instructions pursuant to a Self-Schedule or Self-Supply). Its Real-Time Market
Supply Obligations for each category of Operating Reserve and/or AGC shall be
equal to the amount of such service it is designated by the System Operator to
provide in the Real-Time Market (including service designated by the Participant
for Self-Supply and accepted by the System Operator).

(b) Energy Settlement Obligation. Each Participant shall have for each hour a
Day-Ahead Market Settlement Obligation for Energy at each Location equal to the
megawatthours, if any, of its Demand Bid accepted by the System Operator in the
Day-Ahead Market for Energy at that Location, adjusted up or down, as
appropriate, to reflect Bilateral Transactions entered into by the Participant
that transfer for the hour all or part of a Day-Ahead Market Settlement
Obligation for Energy at that Location to or from another Participant. Each
Participant also shall have for each hour a Real-Time Market Settlement
Obligation for Energy at each Location equal to the megawatthours, if any, of
its Electrical Load at that Location for the hour, adjusted up or down, as
appropriate, to reflect Bilateral Transactions entered into by the Participant
that transfer for the hour all or part of a Real-Time Market Settlement
Obligation for Energy at that Location to or from another Participant. A
Settlement Obligation for Energy shall require the Participant to pay, or
entitle the Participant to be paid, in accordance with the provisions of Section
14A.8(a) and applicable Market Rules.

(c) Operating Reserve Settlement Obligation. Settlement Obligations for each
category of Operating Reserve for each hour are established by allocating the
total Megawatts of that category designated for the hour in Real-Time by the
System Operator to Participants under the Agreement and to Non-Participants
under the Tariff. Each Participant shall have for each hour a Settlement
Obligation for each category of Operating Reserve that, subject to adjustment
pursuant to Section 14A.11, shall be the number of Megawatts determined in
accordance with the following formula:

ORp = SAp + [(OR-SA) (ELp/EL)] + ADJor, wherein

Orp is the Megawatts of the Participant's Settlement Obligation for that
category of Operating Reserve for the hour.

Sap is the number of Megawatts, if any, of that category of Operating Reserve
for the hour that is determined pursuant to applicable Market Rules as properly
being assigned specifically to such Participant and not shared by all
Participants.

OR is the aggregate number of Megawatts of that category of Operating Reserve
designated by the System Operator in the Real-Time Market in accordance with
applicable NEPOOL System Rules to be required for the NEPOOL Control Area for
the hour.

SA is the aggregate number of Megawatts of that category of Operating Reserve
for the hour that is determined pursuant to applicable Market Rules as properly
not being shared by all Participants, including Operating Reserve assigned to
Non-Participants.

Elp is the Participant's Electrical Load for the hour.

EL  is the sum of ELp for all Participants.

ADJor is the adjustment required to reflect the amount of that category of
Operating Reserve that the Participant has Self-Supplied and all Bilateral
Transactions entered into by the Participant that transfer for the hour all or
part of a Settlement Obligation for that category of Operating Reserve to or
from another Participant but have not been reflected in the Participant's
Electrical Load for the hour.

A Settlement Obligation for Operating Reserve shall require the Participant to
pay in accordance with the provisions of Section 14A.8(b) and applicable Market
Rules.

(d) 4-Hour Reserve Settlement Obligation. Each Participant shall have for each
hour a Settlement Obligation for 4-Hour Reserve to the extent provided for in
Section 14A.8(d), adjusted up or down as appropriate to reflect all Bilateral
Transactions entered into by the Participant that transfer all or a part of the
Settlement Obligation for 4-Hour Reserve to or from another Participant. A
Settlement Obligation for 4-Hour Reserve shall require the Participant to pay in
accordance with Section 14A.8(d) and applicable Market Rules.

(e) AGC Settlement Obligation. Settlement Obligations for AGC for each hour are
established by allocating the total AGC designated for the hour in the Real-Time
Market by the System Operator to Participants under the Agreement and
Non-Participants under the Tariff. Each Participant shall have for each hour a
Settlement Obligation for AGC that, subject to adjustment pursuant to Section
14A.11, shall be determined in accordance with the following formula:

AGCp = AGC (ELp/EL) + ADJAGC, wherein

AGCp is the Participant's share of AGC for the hour.

AGC is the total amount of AGC determined by the System Operator in accordance
with applicable NEPOOL System Rules to be required for the NEPOOL Control Area
for the hour that is not assigned to Non-Participants.

ELp and EL are as defined in Section 14A.1(c).

ADJAGC is the adjustment required to reflect all Bilateral Transactions entered
into by the Participant to transfer all or part of a Settlement Obligation for
AGC to or from another Participant but that have not been reflected in the
Participant's Electrical Load for the hour and the amount, if any, that the
Participant has, in accordance with applicable Market Rules, Self-Supplied.

A Settlement Obligation for AGC shall require the Participant to pay in
accordance with Section 14A.8(c) and applicable Market Rules.

14A.2 Right to Receive Service. Except as emergency circumstances may result in
the System Operator requiring load curtailments by Participants, and subject to
the availability of transmission capacity, each Participant shall be entitled to
receive from other Participants (or from the service made available from
Non-Participants pursuant to arrangements entered into under Section 14A.11)
such amounts, if any, of Energy, Operating Reserve, 4-Hour Reserve and AGC as it
requires. If, for any hour, load curtailments or other emergency measures are
required, the amount of services that Participants are entitled to receive shall
be reduced by the System Operator in a fair and non-discriminatory manner in
light of the circumstances and applicable NEPOOL System Rules.

14A.3 Participation in the Day-Ahead Market.

(a) Demand Bids and Supply Offers for the Day-Ahead Market shall be submitted by
Participants for each hour of the Dispatch Day, in accordance with this
Agreement and applicable Market Rules. Such Demand Bids and Supply Offers shall
include the information required by the Market Rules.

(b) Any Participant with authority to submit a Supply Offer in accordance with
Section 14A.4 for a Resource that is eligible to supply Energy at a Node or
External Node, Operating Reserve, 4-Hour Reserve or AGC, or for load that is
capable of reducing its consumption within four hours to supply 4-Hour Reserve,
may submit in the Day-Ahead Market to, or have on file with, the System
Operator, a Supply Offer for each such Resource or load reduction, to the extent
permitted by and in accordance with Section 14A.4 and applicable Market Rules;
provided that as one alternative to submitting Supply Offers for Operating
Reserve and/or 4-Hour Reserve, a Participant desiring to provide such services
may enter into a Reserve Contract with the System Operator pursuant to Section
14A.10(c) covering such services.

(c) Any Participant wishing to purchase Energy in the Day-Ahead Market may
submit to, or have on file with, the System Operator in accordance with
applicable Market Rules a Day-Ahead Demand Bid or Bids specifying Demand Bid
Prices for such Energy in each hour of the Dispatch Day at any Location,
including the Hub.

(d) Any Participant wishing to sell Energy into the Day-Ahead Market from a
Control Area outside the NEPOOL Control Area may do so by submitting a Supply
Offer for Energy in the Day-Ahead Market at an External Node. Participants
wishing to purchase Energy in the Day-Ahead Market for sale outside of the
NEPOOL Control Area may do so by submitting a Demand Bid in the Day-Ahead Market
at an External Node.

(e) Any Participant seeking to Self-Schedule a Resource in the Day-Ahead Market
or to affect its Day-Ahead Settlement Obligation through a Bilateral
Transaction, a Self-Supply of Operating Reserve, or a Self-Supply of AGC to the
extent permitted by applicable Market Rules, shall submit or cause to be
submitted all necessary information with respect thereto to the System Operator
in accordance with Section 14A.4(i) or Section 14A.11 and applicable Market
Rules.

(f) In accordance with Market Rules, any Participant seeking to effect a
transaction that moves Energy through or out of the NEPOOL Control Area by
combining a Demand Bid at an External Node with a Supply Offer at any other Node
may elect to specify the maximum Congestion Cost it is willing to pay to have
its transaction scheduled or, once scheduled, to keep that transaction from
being wholly or partially curtailed.

14A.4 Nature of Demand Bids and Supply Offers; Limitations; Self- Schedules and
Self-Supplies.

(a) Carry Over Procedures: If a Supply Offer or Demand Bid is not submitted for
a Resource in the Day-Ahead Market, the Supply Offer or Demand Bid shall be
deemed to be the last valid Supply Offer or Demand Bid on file with the System
Operator, except for Supply Offers and Demand Bids at External Nodes, which
shall be deemed to be unavailable. If a Supply Offer or Demand Bid for
Dispatchable Load is not submitted for a Resource in the Real-Time Market, the
Supply Offer or Demand Bid shall be deemed to be the Supply Offer or Demand Bid
submitted in the Day-Ahead Market, except for Supply Offers and Demand Bids at
External Nodes which shall not carry over and must be submitted in accordance
with applicable Market Rules.

For a generating unit in which there are multiple Entitlement holders, only one
Participant shall be permitted to submit Supply Offers for such unit. The
Entitlement holders in each unit with multiple Entitlement holders shall
designate a single Participant that will be permitted to submit Supply Offers
and/or to direct the scheduling of the unit. In the event that more than one
Participant is designated, or if the Entitlement holders do not designate a
single Participant, then the Supply Offer Price for Energy for the unit shall be
based on the replacement cost of fuel. Such Supply Offer Price, operational
parameters and other information required under the Market Rules to be furnished
to the System Operator shall be furnished to the System Operator by the
Participant validly furnishing replacement cost of fuel as of December 31, 1996.
Nothing in this Agreement shall affect the rights of any Entitlement holder
under the contractual arrangements among such Entitlement holders relating to a
generating unit.

(b) Each Supply Offer for Energy shall specify the Node or External Node where
the Energy will be provided. Each Demand Bid shall specify the Location where
the Energy will be received. Supply Offers and Demand Bids at External Nodes
shall be adjusted as appropriate by the System Operator to account for
transmission losses on Non-PTF, if any, between the PTF and the transmission
facilities of the neighboring Control Area. Metered values for Electrical Load
on the Non-PTF shall be adjusted as appropriate by the System Operator to
account for transmission losses on the Non-PTF, if any, between the PTF and the
transmission facilities of the neighboring Control Area. The System Operator
shall post on its Internet website loss factors for each External Node.

(c) Each Supply Offer for Energy from a generating unit or Supply Offer at an
External Node in the Day-Ahead Market shall contain the information required by
applicable Market Rules and shall, at a minimum, specify the offered incremental
Energy prices, and may include a Start-Up Price and No- Load Price, if any, and
operational parameters. Each Supply Offer for Energy from Resources in the
Real-Time Market shall specify, in addition to the Node or External Nodes, only
incremental Energy prices. Each Supply Offer Price for incremental Energy from a
segment of a Resource shall be equal to or greater than the Supply Offer Price
for any lesser quantity of Energy.

Each Demand Bid shall contain the information required by the applicable Market
Rules and shall at a minimum state the bid decremental prices of Energy. Each
Demand Bid Price for a block of Energy shall be equal to or less than the Price
for any lesser quantity of Energy.

(d) Supply Offers may be submitted in the Day-Ahead Market for 10-Minute
Spinning Reserve, 10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve,
4-Hour Reserve, and AGC. Each Supply Offer shall specify a separate Supply Offer
Price for the service offered.

(e) Supply Offers for 10-Minute Spinning Reserve, 10-Minute Non-Spinning
Reserve, and/or 30-Minute Operating Reserve may be submitted in the Real-Time
Market only for fast start resources, as defined in the Market Rules. Each
Supply Offer shall specify a separate Supply Offer Price for the service
offered. Supply Offers for AGC also may be submitted in the Real-Time Market
from a generating unit and shall specify the Supply Offer Price for such
service.

(f) To the extent a Resource qualifies to provide Operating Reserve or 4- Hour
Reserve and is not self-scheduled or has not submitted a Supply Offer to provide
such service(s), a Supply Offer to provide Energy from a Resource in any hour in
the Day-Ahead Market may also be considered in accordance with the Market Rules
to be a Supply Offer to provide Operating Reserve or 4-Hour Reserve at the
Resource's Lost Opportunity Cost for such hour based on its Day-Ahead Supply
Offer Price for Energy. The Supply Offer Price for a category of Operating
Reserve or 4-Hour Reserve from a Resource in an hour shall be the greater for
such hour of the submitted Supply Offer Price for such service or the Lost
Opportunity Cost.

Each Supply Offer to provide Energy from a Resource other than a Dispatchable
Load in any hour in the Real-Time Market is also a Supply Offer to provide
Operating Reserve at the Resource's Lost Opportunity Cost for such hour based on
its Real-Time Energy Supply Offer Price if and to the extent such Resource
qualifies to provide Operating Reserve under the applicable Market Rules. For
Resources submitting Supply Offers for Operating Reserve in the Real-Time Market
pursuant to Section 14A.4(e) or as otherwise permitted under the Agreement or
the Market Rules, the Supply Offer Price for service from the

Resource in each hour shall be the greater of the submitted Supply Offer Price
or the Lost Opportunity Cost for such hour.

(g) Each Real-Time Supply Offer Price for Energy from the portion of a Resource
scheduled to provide Operating Reserve, 4-Hour Reserve or AGC in the Day-Ahead
Market shall be less than or equal to the Day-Ahead Supply Offer Price for
Energy for such portion.

Each Real-Time Supply Offer Price for AGC from the portion of a generating unit
eligible to provide AGC and scheduled to provide Energy, Operating Reserve, AGC
or 4-Hour Reserve in the Day-Ahead Market shall be less than or equal to the
Day-Ahead Supply Offer Price for AGC from such generating unit.

Each Real-Time Supply Offer Price for any category of Operating Reserve for the
portion of a Resource scheduled to provide Operating Reserve Day-Ahead and
eligible to submit a Supply Offer Price for that portion of the Resource for
that category of Operating Reserve in the Real-Time Market shall be less than or
equal to the Day-Ahead Supply Offer Price for such category of Operating Reserve
from such portion of that Resource.

(h) If there are multiple Supply Offers for Energy submitted by Participants in
the Day-Ahead or Real-Time Market specifying the same effective Supply Offer
Price (as adjusted for Marginal Losses), and no lower Supply Offer Prices (as
adjusted for Marginal Losses) are available in the applicable Market to meet the
next decrement of load at that Node or External Node, then ties will be broken
in accordance with or scheduled amounts pro rated in accordance with the Market
Rules.

(i) Each Participant with authority to submit Supply Offers for a Resource may
submit a Self-Schedule for Energy from its Resources in either the Day- Ahead or
Real-Time-Market in accordance with applicable Market Rules. The Self-Schedule
defines the Participant's plan to provide Energy from a given generating unit or
to consume Energy for a Dispatchable Load (e.g., a pumped storage facility in
the pumping mode), or to import or export Energy at an External Node. The
Self-Scheduled Energy from a generating unit or consumed by a Dispatchable Load
must satisfy the operating parameters included in the applicable Supply Offer or
Demand Bid. For a Self-Schedule of a Resource other than a Dispatchable Load to
be accepted, the Participant submitting that Self-Schedule must also submit at
least one or more Supply Offer Prices, each equal to or less than zero, for the
Energy associated with the entire Self-Scheduled portion of that Resource.

14A.5 Scheduling Procedures in the Day-Ahead Market.

(a) The System Operator shall perform for each Dispatch Day in accordance with
the NEPOOL System Rules a security constrained unit commitment schedule using a
computer algorithm which simultaneously minimizes the total cost for: (i)
supplying Energy to satisfy accepted Demand Bids in the Day-Ahead Market; (ii)
providing the quantity of Operating Reserves and AGC required by NEPOOL System
Rules; and (iii) providing any necessary 4-Hour Reserves in accordance with
Section 14A.5(f) and applicable NEPOOL System Rules. The schedule shall take
into account all Self-Schedules and Self-Supplies submitted by Participants for
the Day-Ahead Market. In accordance with the NEPOOL System Rules, the schedule
shall also take into account, among other things, phase shifters and other power
flow control devices, transmission system limitations, including but not limited
to internal system limitations and external interface limits, and contingencies
reasonably identified pursuant to criteria posted on the System Operator's
Internet website that may constrain outputs or require additional supply in
specific locations.

(b) The amount of each category of Operating Reserve scheduled in the Day- Ahead
Market by the System Operator shall be in accordance with the NEPOOL System
Rules, shall take into account the grid and generator configuration for the
Dispatch Day, and may be price sensitive in whole or in part such that the
required amount of Operating Reserve decreases as the price for Operating
Reserve increases. Any NEPOOL System Rule in effect before the CMS/MSS Effective
Date designed to maintain reliability while producing just and reasonable
charges and payments for Operating Reserves during times of emergency or
shortages of available Energy and/or Operating Reserves shall remain in effect
on and after the CMS/MSS Effective Date unless and until subsequently amended,
and may be in addition to or in lieu of the establishment of price sensitive
Operating Reserve requirements.

(c) The simultaneous optimization process used to determine schedules in the
Day- Ahead Market shall ensure that all portions of Resources with Supply Offers
not scheduled to provide Energy shall cascade to the markets for AGC, Operating
Reserves and 4-Hour Reserves to the extent such Resources are eligible to
provide those services and consistent with the Supply Offer Prices established
in accordance with Section 14A.4. This process shall also ensure that all
portions of Resources with Supply Offers not scheduled to provide Energy may be
considered for meeting the requirements to provide AGC, Operating Reserves and
4-Hour Reserves.

(d) In the scheduling of Resources for Operating Reserves, 4-Hour Reserves and
AGC in the Day-Ahead Market, the simultaneous optimization process shall use the
following principles: Resources that are Self-Scheduled pursuant to applicable
Market Rules to provide Energy shall be reflected in the schedule in accordance
with the Self-Schedule except as provided below; Resources that are designated
for Self-Supply in accordance with applicable Market Rules shall be reflected in
the schedules to the extent they are so designated except as provided below;
Resources, to the extent not scheduled or Self- Scheduled for Energy or
designated for Self-Supply and eligible to provide Operating Reserve, shall be
scheduled by the System Operator based on the higher of their Lost Opportunity
Costs, if any, or their applicable Day-Ahead Supply Offer Prices; and Resources,
to the extent not scheduled or Self- Scheduled for Energy or designated for
Self-Supply and eligible to provide AGC, shall be scheduled based on their Lost
Opportunity Costs, if any, plus their Day-Ahead Supply Offer Prices for AGC. The
System Operator may direct changes to any Self-Schedule and/or Self-Supply if,
but only to the extent, necessary for reliability.

(e) At the conclusion of the scheduling process set forth in Section 14A.5(a),
the System Operator shall publish each day in accordance with the Market Rules
and in a way that is consistent with the NEPOOL Information Policy the
information required by Section 14A.18. The System Operator's schedule for the
Day-Ahead Market shall identify to each Entitlement holder, the expected start
and shut down times for all of its Resources or Entitlements that are scheduled
in the Day-Ahead Market

(f) If the System Operator's Day-Ahead forecast of the NEPOOL load exceeds the
aggregate of the Participants' Demand Bids accepted in the Day-Ahead Market for
any hour of the Dispatch Day, the System Operator may schedule, in accordance
with the applicable NEPOOL System Rules, 4-Hour Reserves to be available to
cover part or all of the difference.

14A.6 Participation in the Real-Time Market.

(a) Supply Offers and Demand Bids for the Real-Time Market shall be submitted by
Participants for each hour of the Dispatch Day of the Real-Time Market, to the
extent permitted by and in accordance with Section 14A.4 and applicable Market
Rules. Such Supply Offers and Demand Bids shall include the information required
by the Market Rules.

(b) Each Participant with authority to submit a Supply Offer in accordance with
Section 14A.4 for a Resource that is eligible to supply Energy, Operating
Reserve, or AGC, may submit in the Real-Time Market to, or have on file with,
the System Operator, or modify, a Supply Offer for each such Resource, to the
extent permitted by and in accordance with applicable Market Rules and subject
to the limitations of Section 14A.4(g). New or modified Supply Offers may, among
other matters, (i) offer Energy at a Node or External Node, Operating Reserves
and AGC from a generating unit not scheduled in the Day-Ahead Market which can
be dispatched by the System Operator in the Real-Time Market, (ii) increase or
decrease the Supply Offer Price for Energy from a Resource scheduled in the
Day-Ahead Market, (iii) reduce the Supply Offer Price for Energy from a
generating unit scheduled to provide AGC, Operating Reserves, or 4-Hour Reserves
in the Day-Ahead Market, and (iv) propose new Supply Offers and/or Demand Bids
at External Nodes.

(c) Each Participant seeking to Self-Schedule its Resource in the Real-Time
Market or to affect its Real-Time Settlement Obligation through a Bilateral
Transaction, a Self-Supply of Operating Reserve, or a Self-Supply of AGC to the
extent permitted by applicable Market Rules, shall submit or cause to be
submitted all necessary information with respect thereto to the System Operator
in accordance with Section 14A.4(i) or Section 14A.11 and applicable Market
Rules.

14A.7 Scheduling Procedures in the Real-Time Market.

(a) A Participant at its own cost may bring on line a generating unit not
scheduled to operate in the Day-Ahead Market, after giving such notice as is
required by the Market Rules, and receiving the System Operator's approval, so
that the generating unit can be dispatched by the System Operator based on the
Participant's Real-Time Energy Supply Offer. The Participant electing to bring
its generating unit on line in accordance with this Section 14A.7 shall not be
entitled to any uplift under Section 14A.19 with respect to its costs in this
instance, although such Participant may qualify for uplift under other
provisions of this Agreement or applicable Market Rules.

(b) The System Operator shall centrally dispatch all available Resources,
including Self-Scheduled Resources, in Real-Time in accordance with NEPOOL
System Rules, based on the schedule in the Day-Ahead Market, increases or
decreases in load, the occurrence of contingencies, and the submission of new or
modified Real-Time Demand Bids or Supply Offers, new or modified Self- Schedules
and new or modified Self-Supply designations made in accordance with applicable
Market Rules. This dispatch shall also include adjustments to the Day-Ahead
Market schedule to reflect the activation of resources scheduled for 4-Hour
Reserve if necessary to maintain system reliability.

(c) The amount of each category of Operating Reserve designated in the Real-
Time Market by the System Operator shall be in accordance with the NEPOOL System
Rules, shall take into account the grid and generator configuration for the
Dispatch Day, and may be price sensitive in whole or in part such that the
required amount of Operating Reserve decreases as the price for Operating
Reserve increases. Any NEPOOL System Rule in effect before the CMS/MSS Effective
Date designed to maintain reliability while producing just and reasonable
charges and payments for Operating Reserves during times of emergency or
shortages of available Energy and/or Operating Reserves shall remain in effect
on and after the CMS/MSS Effective Date unless and until subsequently amended,
and may be in addition to or in lieu of the establishment of price sensitive
Operating Reserve requirements.

(d) A simultaneous optimization process shall be used to determine the Energy,
AGC and Operating Reserve to be provided by each Resource in the Real-Time
Market. This process shall ensure that all portions of Resources with Supply
Offers not scheduled to provide Energy shall cascade to the markets for AGC and
Operating Reserves to the extent such Resources are eligible to provide those
services and consistent with Supply Offer Prices established in accordance with
Section 14A.4. This process shall also ensure that all portions of Resources
with Supply Offers not dispatched to provide Energy may be considered for
meeting the requirements to provide AGC and Operating Reserves.

(e) In selecting Resources to provide Operating Reserves and AGC in Real- Time,
the simultaneous optimization process shall use the following principles:
Resources that are Self-Scheduled to provide Energy in accordance with
applicable Market Rules shall be reflected in the dispatch to the extent they so
perform, except as provided below; Resources that are permitted by Market Rules
to be designated for Self-Supply and are so designated shall be reflected in the
dispatch to the extent they are so designated and perform or remain available,
except as provided below; Resources, to the extent not scheduled or
Self-Scheduled for Energy or designated for Self-Supply and eligible to provide
10-Minute Spinning Reserve in the Real-Time Market, shall be designated by the
System Operator based on their Lost Opportunity Costs, if any. Resources, to the
extent not scheduled or Self-Scheduled for Energy or designated for Self-Supply
and eligible to provide 10-Minute Non-Spinning Reserves or 30 Minute Operating
Reserves shall be designated based on the higher of their Lost Opportunity
Costs, if any, or their applicable Supply Offer Prices. Generating units, to the
extent they are not scheduled or Self-Scheduled for Energy or designated for
Self-Supply and eligible to provide AGC, shall be designated based on their Lost
Opportunity Costs, if any, plus their Real-Time Supply Offer Prices for AGC. The
System Operator may direct changes to any Self-Schedule and/or Self- Supply if,
but only to the extent, necessary for reliability.

(f) Supply Offers and Demand Bids at External Nodes will be dispatched in the
Real-Time Market based on the Real-Time Supply Offer Price and Demand Bid Price,
respectively, for the hour. If the net aggregate amount of service pursuant to
eligible Supply Offers or Demand Bids at an External Node would exceed the
applicable interface limit, then Supply Offers with the lowest price or the
Demand Bids with the highest price shall be scheduled. If such competing Supply
Offers and/or Demand Bids have the same prices, ties will be broken or
transactions pro rated in accordance with the Market Rules.

14A.8 Settlement Obligation Payments for Energy, Operating Reserves, 4- Hour
Reserves and Automatic Generation Control.

(a) For each hour in which a Participant has a Settlement Obligation for Energy
at a Location in the Day-Ahead Market pursuant to Section 14A.1(b), the
Participant shall pay or receive for the megawatthours of the Settlement
Obligation at that Location at the applicable Day-Ahead Market Locational Price
for that hour, as determined in accordance with Section 14A.12. For each hour in
which a Participant has a Settlement Obligation for Energy at a Location in the
Real-Time Market pursuant to Section 14A.1(b), the Participant either (i) shall
pay the applicable hourly Real-Time Market Locational Price for the number of
megawatthours, if any, by which the Participant's Settlement Obligation for
Energy received at that Location in the Real-Time Market is more than the
Participant's Settlement Obligation for Energy received at that Location in the
Day-Ahead Market, or (ii) shall receive the applicable hourly Real-Time Market
Locational Price for the number of megawatthours, if any, by which the
Participant's Settlement Obligation for Energy received at that Location in the
Real-Time Market is less than the Participant's Settlement Obligation for Energy
received at that Location in the Day-Ahead Market, as determined in accordance
with Section 14A.12. The Participant shall also pay any applicable uplift
charges under Section 14A.19. A Participant shall pay the Zonal Price for Energy
received in a Load Zone unless it elects, in accordance with applicable Market
Rules, to pay the Nodal Price for such Energy.

(b) For each hour in which a Participant has a Settlement Obligation for
Operating Reserve pursuant to Section 14A.1(c), the Participant shall pay for
Operating Reserve in each category in which it has an obligation a percentage
share of the aggregate payments to Participants pursuant to Section 14A.9 for
satisfying their Supply Obligations for each such category of Operating Reserve
for the hour equal to the Participant's percentage share of the total Settlement
Obligations for Operating Reserve of such category for the hour, as determined
pursuant to Section 14A.1(c). In addition, the Participant shall pay any
applicable uplift charge assessed under Section 14A.19.

(c) For each hour in which a Participant has a Settlement Obligation for AGC
pursuant to Section 14A.1(e), the Participant shall pay a percentage of the
aggregate payments to Participants pursuant to Section 14A.9 for satisfying
their Supply Obligations for AGC for the hour equal to the Participant's
percentage share of the total Settlement Obligation for AGC for the hour as
determined pursuant to Section 14A.1(e).

(d) For any hour in which the System Operator schedules 4-Hour Reserves in the
Day-Ahead Market, the aggregate payment to Participants pursuant to Section
14A.9 for satisfying their Supply Obligations for 4-Hour Reserves for the hour
shall be allocated to Participants and paid by them as follows:

Step 1. The hourly per Megawatt cost for 4-Hour Reserve for the hour shall be
determined by dividing the total 4-Hour Reserve payments pursuant to Section
14A.9 for the hour by the number of Megawatts of 4-Hour Reserve scheduled in the
Day-Ahead Market to be available in the hour.

Step 2. If a Participant's Net Hourly Load Obligation for Energy for the hour is
positive and exceeds the Participant's accepted Demand Bids for the hour in the
Day-Ahead Market, it shall pay for each Megawatt of such excess the per Megawatt
cost determined in accordance with Step 1 above, but not more than its pro rata
share of the 4-Hour Reserve cost for the hour.

Step 3. If the allocation in Step 2 above is insufficient to recover the full
4-Hour Reserve cost for the hour, the remaining cost shall be allocated to all
Participants for the hour, including those required to make payments in
accordance with Step 2, in proportion to their shares of the aggregate Net
Hourly Load Obligation for Energy for the hour.

The provisions of Step 2 and Step 3 above are subject to future modifications to
comply with the Commission's June 28, 2000 order in Docket Nos. EL00-62- 000, et
al., and future orders pertaining thereto, with respect to the allocation of
uplift costs and in light of filings concerning the use of Net Hourly Load
Obligation for Energy as an allocation factor, and Steps 2 and 3 do not become
effective except pursuant to a future Commission order.

14A.9 Supply Obligation Payments For Energy, Operating Reserves, 4-Hour Reserves
and Automatic Generation Control.

(a) Subject to the provisions of Section 14A.16, each Participant with a Supply
Obligation for Energy in an hour in the Day-Ahead Market at any Node or External
Node shall receive for each megawatthour scheduled at the Node or External Node
in the Day-Ahead Market the Day-Ahead Nodal Price for the hour at that Node or
External Node, as determined in accordance with Section 14A.12. Subject to the
provisions of Section 14A.16, a Participant with a Supply Obligation for Energy
at any Node or External Node in an hour in the Real-Time Market that is more
than the Participant's Supply Obligation for Energy at that Node or External
Node for the hour in the Day-Ahead Market, shall receive for each additional
megawatthour of such excess the Real-Time Market Nodal Price for the hour at
that Node or External Node, as determined in accordance with Section 14A.12.
Subject to the provisions of Section 14A.16, each Participant with a Supply
Obligation for Energy at any Node or External Node in an hour in the Real-Time
Market that is less than the Participant's Supply Obligation for Energy at that
Node or External Node for the hour in the Day-Ahead Market shall pay for each
megawatthour of such deficiency the Real-Time Market Nodal Price for the hour at
that Node or External Node, as determined in accordance with Section 14A.12. In
addition, Participants may receive or be required to pay applicable uplift
charges, if any, pursuant to Section 14A.19 or the Market Rules and to pay for
4-Hour Reserves pursuant to Section 14A.8(d).

(b) Each Participant with a Supply Obligation for Operating Reserve or 4- Hour
Reserve in an hour in the Day-Ahead Market shall receive for each Megawatt of
each category of Operating Reserve and/or 4-Hour Reserve scheduled the
applicable Day-Ahead Market Operating Reserve Clearing Price or 4-Hour Reserve
Clearing Price, as appropriate, as determined in accordance with Section 14A.13.
For any hour in which the Participant's Supply Obligation for Operating Reserve
of any category in the Real-Time Market exceeds the Participant's Supply
Obligation for such service for the hour in the Day-Ahead Market, the
Participant shall receive for the additional Megawatts the applicable Real-Time
Market Operating Reserve Clearing Price for the hour, as determined in
accordance with Section 14A.13. For any hour in which the Participant's Supply
Obligation for Operating Reserve of any category in the Real-Time Market is less
than the Participant's Supply Obligation for such service for the hour in the
Day-Ahead Market, the Participant shall pay for each Megawatt of such deficiency
the applicable Real-Time Market Operating Reserve Clearing Price for the hour,
as determined in accordance with Section 14A.13. If a Participant has a Supply
Obligation for 4-Hour Reserve in any hour in the Day-Ahead Market and fails to
provide all or a portion of the Energy from its 4-Hour Reserve in response to
the System Operator's dispatch instructions, the Participant shall pay the Real-
Time Market 30-Minute Operating Reserve Clearing Price for each Megawatt not
provided, in addition to any payments required under Section 14A.8(d).

(c) Each Participant with a Supply Obligation for AGC in an hour in the Day-
Ahead Market shall receive for the scheduled amount the Day-Ahead Market AGC
Clearing Price for the hour, as determined in accordance with Section 14A.14.
For any hour in which the Participant's Supply Obligation for AGC in the
Real-Time Market exceeds the Participant's Supply Obligation for AGC for the
hour in the Day-Ahead Market, the Participant shall receive for such excess the
Real-Time Market AGC Clearing Price for the hour, as determined in accordance
with Section 14A.14. For any hour in which the Participant's Supply Obligation
for AGC in the Real-Time Market is less than the Participant's Supply Obligation
for AGC for the hour in the Day-Ahead Market, the Participant shall pay for such
deficiency the Real-Time Market AGC Clearing Price for the hour, as determined
in accordance with Section 14A.14.

(d) In no event shall Participants be paid lost opportunity costs resulting from
a generating unit being dispatched down or off to accommodate transmission
constraints, and nothing in this Agreement or the Market Rules shall provide for
any such payment.

14A.10  Contract and Scheduling Authority.

(a) The Participants Committee is authorized to enter into contracts on behalf
of and in the names of all Participants with Non-Participants to purchase or
furnish emergency Energy that is available for the System Operator to schedule
in order to ensure reliability in the NEPOOL Control Area or neighboring Control
Areas. For sales to another Control Area, the terms of any such contractual
arrangement shall not require the furnishing of such emergency service until the
service needs of all Participants have been provided for with the least
expensive resources practicable. Emergency purchases pursuant to this Section
14A.10 should not be required unless the Participants have been unable to
furnish such Supply Offers as the System Operator determines are required to
ensure reliability. For emergency purchases and sales pursuant to this Section
14A.10, the treatment of the transaction with the Non-Participant in the
determination of a Locational Price shall be in accordance with applicable
Market Rules. Energy (and related services) from any such emergency purchases
shall be deemed to be furnished to and shall be paid for by Participants with
Settlement Obligations in the Real-Time Market, in accordance with this Section
14A.10(a) and applicable Market Rules.

(b) The NEU Management Committee (as defined in the HQ Use Agreement) is
authorized to provide for the day-to-day scheduling through the System Operator
of the HQ Phase II Firm Energy Contract, in accordance with the HQ Use
Agreement, as if the Contract were a contract covering Energy transactions with
a Non-Participant entered into pursuant to Section 14A.10(a). Energy received in
an hour from Hydro-Quebec pursuant to the HQ Energy Banking Agreement, and
Energy purchased in any hour from Hydro-Quebec pursuant to the HQ Phase II Firm
Energy Contract any other HQ Contract shall be deemed to be Energy furnished at
the appropriate External Node to each Participant which has submitted a Supply
Offer at the appropriate External Node for such Energy for the hour in the
amount reflected for the Participant in the System Operator's scheduling of
Energy deliveries in the hour from Hydro-Quebec; except that emergency Energy
received from Hydro-Quebec under the HQ Interconnection Agreement shall be
deemed to be Energy provided to (and shall be paid for by) Participants
requiring such emergency Energy in the hour. The System Operator shall schedule
such Energy deliveries to accommodate, to the extent possible, the schedule of
Energy deliveries from Hydro-Quebec requested by the Participants within their
Supply Offers. The Participants deemed to have received such Energy shall have a
corresponding Supply Obligation and shall satisfy this and all other Supply
Obligations at this External Node and all other Nodes in accordance with Section
14A.1, 14A.8 and 14A.9. The Participants are responsible for paying to
Hydro-Quebec the price for Energy deliveries under the HQ Phase II Firm Energy
Contract and under the HQ Energy Banking Agreement.

(c) The System Operator is authorized in accordance with applicable Market Rules
to enter into Reserve Contracts with individual Participants under which the
System Operator pays for and receives options or rights to all or a portion of
10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve and/or 4-Hour
Reserve from generating units or Dispatchable Loads for forward periods, such as
a week or a month, as determined by the System Operator. Such Reserve Contracts
shall be in accordance with applicable Market Rules and shall be entered into
with Participants which offer the service in response to a request for
proposals, shall include the Reserve Price at which the Operating Reserve or
4-Hour Reserve will be made available and the price at which Energy will be
furnished on the activation of the Operating Reserve or 4-Hour Reserve, and
shall contain standard terms and conditions specified by the System Operator in
accordance with the Market Rules.

14A.11  Bilateral Transactions and Participant Transactions with Non-
Participants.

(a) Two Participants may undertake to transfer all or select portions of the
Settlement Obligations of one of them under this Agreement to the other
Participant with respect to any of the NEPOOL Markets pursuant to a Bilateral
Transaction. Such transfer of Settlement Obligations under this Agreement shall
be as agreed to between the two parties to the Bilateral Transaction and shall
be submitted to the System Operator in accordance with the Market Rules. Each
Bilateral Transaction submitted shall specify whether the transaction is to
settle in the Day-Ahead Market or the Real-Time Market and, if it is for Energy,
a Location.

(b) In the event a Participant has the right to receive Energy, Operating
Reserve, 4-Hour Reserve and/or AGC from a Non-Participant under a System
Contract, such Contract may be submitted to the System Operator in a Supply
Offer as a proposal to furnish Energy, Operating Reserve, 4-Hour Reserve, and/or
AGC, to the extent the System Contract permits central dispatch by the System
Operator in accordance with the Market Rules and otherwise qualifies for such
service.

14A.12  Determination of Locational Prices.

The System Operator shall calculate Locational Prices for the Day-Ahead and
Real-Time Markets as described below.

(a) Nodal Prices. The System Operator shall calculate the Nodal Price at each
Node for each hour of the Dispatch Day for the Day-Ahead Market using the
Day-Ahead unit commitment model, and for the Real-Time Market using the
Real-Time scheduling software. In calculating Nodal Prices the System Operator
shall use the Demand Bids and Supply Offers submitted pursuant to Sections
14A.3, 14A.4 and 14A.6. The Real-Time Nodal Price at each Node for each hour
shall be the time interval weighted-average of the Clearing Prices calculated at
that Node for each time interval within that hour, except as noted in subsection
(d) below with respect to the prices used for Real-Time settlements at External
Nodes.

The System Operator shall calculate Nodal Prices for an hour for the Day- Ahead
Market or the Real-Time Market at a given Node i using the following formula, or
a formula similar in substance and effect:

(EQUATION)

where:

(EQUATION)      the Nodal Price at Node i in $/megawatthour;

(EQUATION)      the marginal cost in $/megawatthour, based on Demand Bids and
Supply Offers, to serve additional load at the Reference Node;

(EQUATION)      the Marginal Loss Component of the Nodal Price at Node i in
$/megawatthour; and

(EQUATION) the Congestion Component of the Nodal Price at Node i in
$/megawatthour.

The Marginal Loss Component of the Nodal Price at any Node i on the NEPOOL
Transmission System is calculated using the equation

(EQUATION)

in which WFi, the Withdrawal Factor at Node i relative to the system Reference
Node, is calculated using the following equation:

(EQUATION)

where:

L = NEPOOL Transmission System losses;

Pi = the net amount of Energy injected into the NEPOOL Transmission System at
Node i; and

(EQUATION)  = the ratio of: (1) the amount by which NEPOOL Transmission

System losses occurring in the Day-Ahead Schedule or Real-Time dispatch would
have increased, as calculated by the System Operator's Day-Ahead or Real-Time
computer algorithm, if a very small additional amount of Energy had been
injected at Node i (in addition to the injections and withdrawals already
scheduled to occur on the NEPOOL Transmission System in the Day-Ahead schedule
or occurring on the NEPOOL Transmission System in the Real-Time dispatch), to
(2) the size of the additional injection of Energy at Node i.

The Congestion Component of the Nodal Price at Node i is calculated using the
equation:

(EQUATION),

where:

K = the set of thermal or interface constraints;

GFik = the Shift Factor for the generator at Node i on constraint k in the pre-
or post-contingency case that limits flows across that constraint; and

(EQUATION) = the reduction in system cost that results from an incremental
relaxation of constraint k, expressed in $/megawatthour.

Substituting the equations for calculating the Marginal Loss Component and the
Congestion Component of the Nodal Price for the terms and into the equation for
calculating the Nodal Price for a given Node i yields:

(EQUATION)

(b) Zonal Prices. For Congestion pricing purposes, Load Zones based on
Reliability Regions have been established and Zonal Prices shall be calculated
by the System Operator for each Load Zone. Each Load Zone shall be coterminous
with a Reliability Region, except that a Participant which owns and operates
distribution lines and other facilities used for the distribution of Energy to
retail customers in a single state in New England and which is subject to
regulation by the public utility regulatory authority in that state (a
"Distribution Company"), which (i) serves retail customers in more than one
Reliability Region in a single state and (ii) is subject to a state-imposed
obligation to provide its retail customers with a power supply at fixed prices
for a limited time period following the commencement of retail access ("Standard
Offer Obligation"), may elect, by notice to the System Operator and the
Secretary of the Participants Committee, within the time prescribed by the
Market Rules, to have its entire service territory treated as a single Load Zone
(a "Distribution Company Load Zone") until its Standard Offer Obligation ends.
In addition, Vermont shall be a single Load Zone for those Distribution
Companies in Vermont that maintain their single Participant status for
settlement purposes with other Distribution Companies in Vermont pursuant to
Section 4 of the Agreement even if Vermont spans more than one Reliability
Region. The election by one or more Distribution Companies in Vermont not to be
treated as a single Participant with other Vermont Participants shall not affect
the Load Zone for the remaining Distribution Companies in Vermont maintaining
the single Participant election.

After consulting with the Participants, the System Operator may reconfigure
Reliability Regions and add or subtract Reliability Regions as necessary over
time to reflect changes to the grid, patterns of usage and intrazonal
Congestion. The System Operator shall file any such changes with the Commission.

The System Operator shall calculate Zonal Prices for each Reliability Region for
both the Day-Ahead and Real-Time Markets for each hour using a load- weighted
average of the Nodal Prices for the Nodes within that Reliability Region. The
load weights used in calculating the Day-Ahead Zonal Prices for the Reliability
Region shall be determined in accordance with applicable Market Rules and shall
be based on the Demand Bids for the Nodes that make up that Reliability Region.
The System Operator shall determine, in accordance with applicable Market Rules,
the load weights used in Real-Time based on the calculated Real-Time load
distribution. The System Operator shall calculate Zonal Prices for Reliability
Regions using the following formula, or a formula similar in substance and
effect, where the Zonal Price for a Reliability Region j can be written as:

(EQUATION),

where:

(EQUATION)  = Zonal Price for Reliability Region j in $/megawatthour;

(EQUATION)   is as defined in Section 14A.12(a);

(EQUATION)   is the Marginal Loss Component of the Zonal Price for

Reliability Region j in $/megawatthour;

(EQUATION)   is the Congestion Component of the Zonal Price for Reliability

Region j in $/megawatthour;

Nj = the set of Nodes that make up the Reliability Region j; and

Wij = the load-weighting factor for Node i used to calculate the Zonal Price for
Reliability Region j, determined such that the weighting factors for any given
Reliability Region sum to one.

For a Distribution Company Load Zone, the Zonal Price shall be determined by the
weighted average of the Zonal Prices for the Reliability Regions making up the
Load Zone, with the weights equal to that Distribution Company's share of the
load in each of those Reliability Regions. The load weights used in calculating
the Day-Ahead Zonal Prices for the Distribution Company Load Zones shall be
determined in accordance with applicable Market Rules and shall be based on the
Demand Bids for the Nodes that make up the Distribution Company Load Zones.

The System Operator shall determine, in accordance with applicable Market Rules,
the load weights used in Real-Time based on the calculated Real-Time load
distribution. The System Operator shall calculate Zonal Prices for each hour of
the Dispatch Day for Distribution Company Load Zones using the following
formula: Zonal Price equals the Distribution Company's load in each Reliability
Region making up the Distribution Company Load Zone times the Zonal Price for
each such Reliability Region summed for all such Reliability Regions making up
the Distribution Company Load Zone, divided by the sum of the Distribution
Company's load in each Reliability Region making up the Distribution Company
Load Zone. The Congestion and Marginal Loss Components of the Zonal Price for
each Distribution Company Load Zone shall be calculated as the weighted average
of the Congestion and Marginal Loss Components, respectively, of the Zonal
Prices in the Reliability Regions making up that Load Zone, using the same
weights that are used to calculate the Zonal Price for that Distribution Company
Load Zone.

(c) Hub Prices. On behalf of the Participants, the System Operator shall
maintain and facilitate the use of a Hub or Hubs for the Energy market,
comprised of a set of Nodes within NEPOOL, which Nodes shall be identified by
the System Operator on its Internet website. The System Operator has used the
following criteria to establish an initial Hub and shall use the same criteria
to establish any additional Hubs:

(i) each Hub shall contain a sufficient number of Nodes to try to ensure that a
Hub Price can be calculated for that Hub at all times;

(ii) each Hub shall contain a sufficient number of Nodes to ensure that the
unavailability of, or an adjacent line outage to, any one Node or set of Nodes
would have only a minor impact on the Hub Price;

(iii)  each Hub shall consist of Nodes with a relatively high rate of service
availability;

(iv) each Hub shall consist of Nodes among which transmission service is
relatively unconstrained; and

(v) no Hub shall consist of a set of Nodes for which directly connected load
and/or generation at that set of Nodes is dominated by any one entity or its
affiliates.

The System Operator shall calculate hourly Hub Prices for both the Day-Ahead and
Real-Time Markets using a fixed-weighted average of the Nodal Prices that
comprise the Hub. The System Operator shall calculate Hub Prices using the
following formula, or a formula similar in substance and effect, where the Hub
Price for a Hub j can be written as:

(EQUATION)

where:

(EQUATION) =  Hub Price for Hub j in $/megawatthour;

(EQUATION)  is as defined in Section 14A.12(a);

(EQUATION)  is the Marginal Loss Component of the Hub Price for Hub j in
$/megawatthour;

(EQUATION)  is the Congestion Component of the Hub Price for Hub j in
$/megawatthour;

Hj = the set of Nodes in Hub j; and

WijH = the load weighting factor for Node i used to calculate the Hub Price for
Hub j, determined such that the weighting factors for any given Hub sum to one.

Participants may transfer their Settlement Obligations at the Hub Price in the
Day-Ahead and Real-Time Markets pursuant to Bilateral Transactions. In
accordance with Section 14A.8 of the Agreement, Participants with Settlement
Obligations for Energy at the Hub shall pay or be charged the Hub Price for such
Settlement Obligations.

(d)  Nodal Prices for External Nodes.  The System Operator shall calculate
Nodal Prices for External Nodes.  The External Nodes shall be identified in
applicable Market Rules.  External Nodes shall be used for pricing Energy
transactions by

Participants receiving Energy from or delivering Energy to neighboring Control
Areas. The Nodal Prices for External Nodes shall be calculated in the same way
as Nodal Prices for Nodes, with the exception of the calculation of the Marginal
Loss Component of the price.

The Marginal Loss Component of Nodal Prices for External Nodes shall be
calculated so as to ensure that it does not include the effect of withdrawals at
a Node or External Node on the cost of losses incurred outside the NEPOOL
Control Area. In order to accomplish this, a hypothetical transaction will be
modeled, in which an increment of load at each External Node is served by an
increment of generation at the Reference Node. The amount of Energy that would
flow out of the NEPOOL Transmission System over each interconnection point
between the NEPOOL Transmission System and an adjoining Control Area or the
Non-PTF transmission system will be calculated next. Finally, the Marginal Loss
Component of the Nodal Price at each External Node will be calculated as the
weighted average of the Marginal Loss Components at each of the interconnection
points between the NEPOOL Transmission System and an adjoining Control Area or
the Non-PTF transmission system. The weight assigned to each interconnection
will be equal to the proportion of the total amount of Energy delivered off of
the NEPOOL Transmission System in association with this hypothetical transaction
that flows over that interconnection. As a result, the Marginal Loss Component
of the price at each External Node will only include the effects on Marginal
Losses on the NEPOOL Transmission System.

The Shift Factors for each External Node determine the proportion of the Energy
in such a transaction that would flow over each interconnection point between
the NEPOOL Transmission System and external Control Areas or the Non- PTF
transmission system and, therefore, the Marginal Loss Component of the Nodal
Price at an External Node i shall be calculated using the following equation, or
a formula similar in substance and effect:

(EQUATION)

where:

(EQUATION) = the Marginal Loss Component of the Nodal Price at an External Node
i in $/megawatthour;

I      = the set of interconnection points between the NEPOOL Transmission
System and adjacent Control Areas or the Non-PTF transmission system;

GFin = Shift Factor at External Node i for the interconnection line that passes
through Node n; and

(WFn - 1) (EQUATION) = the Marginal Loss Component of the Nodal Price at Node n
in $/megawatthour, where WFn is the withdrawal factor at Node n and (EQUATION)
is as defined in Section 14A.12(a).

The price used for Real-Time settlements at External Nodes will be the Real-
Time price as determined based on the Real-Time dispatch except in the
circumstance in which imports or exports were constrained in the hour ahead
scheduling process either by constraints that are not monitored in Real-Time or
by closed interface constraints that are not affected by internal dispatchable
generators. In this special circumstance, the price used for Real-Time
settlements of imports from External Nodes will be the lower of the Real-Time
price at the External Node or the hour ahead price at the External Node.
Similarly, in this situation, the price used for Real-Time settlements of
exports to External Nodes will be the higher of the Real-Time price at the
External Node or the hour ahead price at the External Node.

(e)  Additional Rules and Procedures.  Consistent with this Section 14A.12,
the implementation of its provisions shall further be detailed, defined and
carried out pursuant to Market Rules.

14A.13  Determination of Operating Reserve and 4-Hour Reserve Clearing
Prices.

(a) Operating Reserve and 4-Hour Reserve shall be scheduled in the Day-Ahead
Market and designated in the Real-Time Market in accordance with the
simultaneous optimization processes described in Sections 14A.5 and 14A.7,
respectively, and the NEPOOL System Rules. As a result, in the Day-Ahead Market
and Real-Time Market, the respective Clearing Price for an hour for 10-Minute
Spinning Reserve shall equal or exceed the Clearing Price for 10-
Minute-Non-Spinning Reserve, which shall equal or exceed the Clearing Price for
30-Minute Operating Reserve, which shall equal or exceed the Clearing Price for
4-Hour Reserve.

(b) For each hour, in accordance with the NEPOOL System Rules, the System
Operator shall calculate the Operating Reserve Clearing Price for each category
of Operating Reserve in the Day-Ahead Market and the Real-Time Market as
follows:

(i) The System Operator shall determine the aggregate Megawatts of the
applicable category of Operating Reserve that are scheduled for the hour in the
Day-Ahead Market or designated for the hour in the Real-Time Market.

(ii) For each category of Operating Reserve in each of the Day-Ahead Market and
Real-Time Market, the System Operator shall rank in the order of lowest to
highest the Reserve Prices, Lost Opportunity Costs and Supply Offer Prices, as
applicable, of the Resources scheduled by the System Operator for that category
of Operating Reserve for the hour for the Day-Ahead Market or designated each
interval during the hour in the Real-Time Market.

(iii) The Operating Reserve Clearing Price per Megawatt for each category of
Operating Reserve in each Market shall be the time-weighted average of the
highest Reserve Prices, Lost Opportunity Costs or Supply Offer Prices, as
applicable, for that category of Operating Reserve that are scheduled for the
hour in the Day-Ahead Market or designated each interval during the hour in the
Real-Time Market by the System Operator, as determined in accordance with the
applicable Market Rules.

(c) For each hour in the Day-Ahead Market for which the System Operator
calculates it requires 4-Hour Reserves, the System Operator shall determine the
4-Hour Reserve Clearing Price as follows:

(i) The System Operator shall determine the aggregate Megawatts of 4-Hour
Reserves scheduled for the hour in the Day-Ahead Market.

(ii) The System Operator shall rank from lowest to highest the Reserve Prices,
Lost Opportunity Costs and Supply Offer Prices, as applicable, of the Resources
scheduled for 4-Hour Reserves for the hour in the Day-Ahead Market.

(iii) The 4-Hour Reserve Clearing Price per Megawatt in the Day-Ahead Market
shall be the highest Reserve Prices, Lost Opportunity Costs or Supply Offer
Prices, as applicable, for 4-Hour Reserves that are scheduled by the System
Operator for the hour in accordance with applicable Market Rules.

(d) The System Operator shall calculate a Lost Opportunity Cost for each hour
for a Resource, other than Dispatchable Load, which shall, for each increment of
Supply Offer Megawatts, be equal to the product of (i) the amount, if any, by
which the Nodal Price for the hour at the Node or External Node where Energy
from the Resource would be supplied in the Day-Ahead Market or Real-Time Market
exceeds the Resource's Energy Supply Offer Price, for that increment of Supply
Offer Megawatts, for that market and (ii) the additional Megawatts, in that
increment of Supply Offer Megawatts, the Resource would have been scheduled or
dispatched to in the Day-Ahead Market or Real-Time Market, respectively, had it
been scheduled or dispatched to supply Energy at the Megawatt level specified in
its Supply Offer relating to its Supply Offer Price and operating parameters.

14A.14 Determination of AGC Clearing Price.

For each hour, the System Operator shall determine an AGC Clearing Price for the
Day-Ahead Market and for the Real-Time Market. In the case of each Market, the
AGC Clearing Price shall be the time-weighted average "AGC Capability Price," as
defined below in this Section 14A.14. The AGC Capability Price for a generating
unit furnishing AGC per the System Operator's schedule for the hour in the
Day-Ahead Market or designated each interval during the hour in the Real-Time
Market shall be equal to (A) the cost per unit of making the AGC capability of a
generating unit available based on the AGC Supply Offer Price for the
Entitlement for the hour, plus any Lost Opportunity Cost, divided by (B) the
amount of AGC scheduled in the hour in the Day-Ahead Market or designated in the
interval in the Real-Time Market from that Resource. The AGC Capability Price
used to determine the AGC Clearing Price shall be the highest AGC Supply Offer
for the generating units that, in the case of the Day-Ahead Market, were
scheduled by the System Operator to provide AGC for the hour, or, in the case of
the Real-Time Market, were designated each interval during the hour to provide
AGC beyond their Supply Obligations for AGC in the Day-Ahead Market.

14A.15 Funds to or from which Payments are to Be Made.

(a) All payments for Energy (except for payments to or from the Congestion
Revenue Fund and the Marginal Loss Revenue Fund), Operating Reserve, 4-Hour
Reserve and AGC furnished or received, all uplift charges paid pursuant to this
Section 14A of this Agreement, and any payments by Non-Participants for
ancillary services under Schedules 2 through 7 to the Tariff or pursuant to
arrangements referenced in Section 14A.10, shall be allocated each month through
the Pool Interchange Fund as follows:

Step One. For each week in which Energy is delivered or received under the HQ
Energy Banking Agreement, all payments with respect to transactions under that
Agreement shall be made to or from the Energy Banking Fund provided for in
Section 14A.15(b).

Step Two. (i) For each week in which Pre-Scheduled Energy (as defined in the HQ
Phase I Energy Contract) is purchased pursuant to the HQ Phase I Energy
Contract, the aggregate amount which is paid pursuant to Section 14A.10(b) for
such Energy by each Participant which is a participant in the Phase I
arrangements with Hydro-Quebec shall be determined and paid on the Participant's
account into the Phase I Savings Fund.

(ii) For each week in which Energy is purchased pursuant to the HQ Phase II Firm
Energy Contract, the aggregate amount which is paid pursuant to Section
14A.10(b) for such Energy by each Participant which is a participant in the
Phase II arrangements with Hydro-Quebec shall be determined and paid on the
Participant's account into the Phase II Savings Fund.

Step Three. For each week in which Other HQ Energy is purchased pursuant to the
HQ Phase I Energy Contract or Energy is purchased pursuant to the HQ
Interconnection Agreement, the aggregate amount paid pursuant to Section
14A.10(b) for such Energy shall be determined for each Participant which is a
participant in the Phase I or Phase II arrangements with Hydro-Quebec. Such
amount shall be allocated between the Participant's share of the Phase I Savings
Fund and the Participant's share of the Phase II Savings Fund created under the
HQ Use Agreement in the same ratio as (A) the sum of (x) the number of
kilowatthours of Other HQ Energy deemed to be purchased by the Participant
during the week and (y) the HQ Phase I Percentage of the number of kilowatthours
deemed to be purchased by the Participant under the HQ Interconnection Agreement
during the week, bears to (B) the HQ Phase II Percentage of the number of
kilowatthours purchased under the HQ Interconnection Agreement during the week.

Step Four. The balance remaining in the Pool Interchange Fund after Steps One
through Three shall be retained in the Pool Interchange Fund for the month and
shall be used and disbursed after each month in the following order:

(i) (A) amounts owed to Non-Participants (other than Hydro-Quebec) for the month
under contracts entered into with them pursuant to Section 14A.10(a) shall be
paid, and (B) amounts owed to Hydro-Quebec for the month for Energy deemed to be
furnished pursuant to Section 14A.10(b) to Participants which are not
participants in the Phase I or Phase II arrangements with Hydro- Quebec shall be
paid and, in the event the price paid by any such Participant for such Energy is
the applicable Locational Price, the excess, if any, of such Locational Price
over the amount owed to Hydro-Quebec shall be paid to the Participant; and

(ii) amounts owed to Participants for the month pursuant to this Section 14A
shall then be paid.

(b) HQ Energy Banking Fund.  All amounts allocated to the HQ Energy Banking
Fund for each month shall be used and disbursed as follows:

(i) Participants which furnish Energy for delivery to Hydro-Quebec under the HQ
Energy Banking Agreement shall receive from their share of the Energy Banking
Fund the amount to which they are entitled for such service in accordance with
Section 14A.9.

(ii) amounts required to be paid to Hydro-Quebec under the HQ Energy Banking
Agreement shall be paid from the shares of the Fund of the Participants engaging
in transactions under the HQ Energy Banking Agreement for the month in
accordance with their respective interests in the transactions for the month. If
there is not enough in any such share, the Participants with the deficient
shares shall be billed and pay into their shares of the Fund the amounts
required for payments to Hydro-Quebec.

(iii) subject to the remaining provisions of this Section, at the end of each
month any balance remaining in each Participant's share of the HQ Energy Banking
Fund shall (I) in the case of any Participant which is not a participant in the
Phase I or Phase II arrangements with Hydro-Quebec, be paid to such Participant,
and (II) in the case of any Participant which is a participant in the Phase I or
Phase II arrangements with Hydro-Quebec, be paid to the Escrow Agent under the
HQ Use Agreement to be held and disbursed by it through the Phase I Savings Fund
and Phase II Savings Fund created under the HQ Use Agreement, and shall be
allocated between the Participant's share of said Funds as follows:

(A) the balance remaining in the Participant's share of the HQ Energy Banking
Fund for the month shall be divided by the number of kilowatthours deemed to be
received by the Participant under the HQ Energy Banking Agreement during the
month to determine an average savings amount per kilowatthour;

(B) for any hour during the month in which the number of kilowatthours received
by NEPOOL under the HQ Energy Banking Agreement exceeded the HQ Phase I Transfer
Capability, an amount equal to (a) the Participant's share of the excess of (1)
the number of kilowatthours received over (2) the HQ Phase I Transfer Capability
times (b) the average savings amount per kilowatthour determined for that
Participant under (A) above shall be allocated to the Phase II Savings Fund; and

(C) the remaining balance of the Participant's share of the HQ Energy Banking
Fund for the month shall be allocated to the Phase I Savings Fund.

It is recognized that, in view of the time which may elapse between the delivery
of Energy to or by Hydro-Quebec in an Energy Banking transaction under the HQ
Energy Banking Agreement and the return of the Energy, the amounts of Energy
delivered to and received from Hydro-Quebec, after adjustment for losses, may
not be in balance at the end of a particular month.

Further, if as of the end of any month and after adjustment for electrical
losses, the cumulative amount of Energy so received from Hydro-Quebec exceeds
the amount so delivered, the aggregate amount paid by Participants for the
excess Energy pursuant to Section 14A.10(b) shall be paid to the Energy Banking
Fund. The Escrow Agent under the HQ Use Agreement shall hold and invest these
funds. On the return of the excess Energy to Hydro-Quebec, the amount so held by
the Escrow Agent shall be repaid to Hydro-Quebec and Participants in accordance
with the Energy Banking Agreement.

(c) Phase I HQ Savings Fund. The aggregate amount allocated to each
Participant's share of the Phase I HQ Savings Fund for each month shall be used,
first, to pay to Hydro-Quebec the amount owed to it for the month for Energy
furnished under the Phase I HQ Energy Contract and the HQ Phase I Percentage of
the amount owed to it for the month for Energy furnished to the Participants
under the HQ Interconnection Agreement. The balance of the amount allocated to
the Fund for the month shall be paid to the Escrow Agent under the HQ Use
Agreement to be held and disbursed by it through the Phase I HQ Savings Fund
created thereunder in accordance with each Participant's contribution to such
balance.

(d) Phase II HQ Savings Fund. The aggregate amount allocated to the Phase II HQ
Savings Fund for each month shall be used, first, to pay to Hydro-Quebec the
amount owed to it for the month for Energy deemed to be furnished to the
Participant under the Phase II HQ Firm Energy Contract and the HQ Phase II
Percentage of the amount owed to it for the month for Energy deemed to be
furnished to the Participants under the HQ Interconnection Agreement. The
balance of the amount allocated to the Fund for the month shall be paid to the
Escrow Agent under the HQ Use Agreement to be held and disbursed by it through
the Phase II HQ Savings Fund created thereunder in accordance with each
Participant's contribution to such balance.

14A.16  Marginal Losses.

(a) Marginal Loss Cost. Marginal Loss cost shall be reflected in and recovered
through the Marginal Loss Components of Locational Prices. Participants pay for
Marginal Loss cost by paying the Locational Price for Energy. Locational Prices
shall be calculated in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.

(b) Marginal Loss Revenue. To the extent that there is any Marginal Loss Revenue
in any settlement period, such revenue shall be collected in a Marginal Loss
Revenue Fund and allocated to load-serving entities in proportion to their Net
Hourly Load Obligations for Energy in accordance with the Market Rules.

(c)  Additional Rules and Procedures.  Consistent with this Section 14A.16,
the implementation of its provisions shall further be detailed, defined and
carried out pursuant to Market Rules.

14A.17  Congestion Cost and Revenues.

(a) Congestion Cost. When Congestion exists, Congestion Cost shall be reflected
in and recovered through the Congestion Components of Locational Prices.
Participants pay for Congestion Costs by paying the Locational Price for Energy.
Locational Prices shall be calculated in accordance with Section 14A.12 of the
Agreement and Schedule 13 of the Tariff.

(b) Congestion Revenue. For each hour of the Dispatch Day in the Day-Ahead and
Real-Time Markets, the System Operator shall calculate and collect Congestion
Revenue and maintain a Congestion Revenue Fund.

(c)  Additional Rules and Procedures.  Consistent with this Section 14A.17,
the implementation of its provisions shall further be detailed, defined and
carried out pursuant to Market Rules.

14A.18  Market Monitoring and Reports.

(a) The System Operator shall complete and circulate to the Participants
Committee and post on its Internet website for each month a market monitoring
report. The monthly report shall be completed no later than sixty (60) days
after the close of the calendar month of market activities covered by the report
and shall contain the following information for each Load Zone and Reliability
Region: (a) separately identified Congestion Costs, RMR Uplift and any other
amounts that are paid for by Load Zone and/or Reliability Region, (b) the number
of Supply Offers from Participants that were not Related Persons of each other
and that were capable of meeting the marginal load within the Load Zone and/or
Reliability Region to the extent that the number falls below limits prescribed
in the Market Rules, (c) the aggregate import limitation to the Load Zone and/or
Reliability Region, (d) the existence and a description of internal transmission
constraints within the Load Zone and/or Reliability Region and (e), to the
extent disclosure can be made consistent with the NEPOOL Information Policy,
patterns of behavior that the System Operator has identified in the course of
market monitoring that may affect price or other charges that are paid for
Energy in the Load Zone and/or Reliability Region in a manner not consistent
with the conditions that would prevail in a competitive market. If the System
Operator has not commenced or taken corrective action with respect to Supply
Offers, Demand Bids, or other behavior inconsistent with the conditions that
would prevail in a competitive market identified in one of its monthly reports
within thirty (30) days of the issuance of that report, any Participant may
commence a complaint proceeding at the Commission to seek remediation of such
behavior. The Participant or Participants initiating such a complaint proceeding
shall, upon the issuance of a protective order by the Commission covering
confidentiality and other relevant matters and subject to the terms of such
protective order, be entitled to access to the data underlying the System
Operator's conclusions as to behavior inconsistent with conditions that would
prevail in a competitive market. The ability to initiate such a complaint
proceeding at the Commission shall not prejudice the ability of such complaining
Participant or Participants to pursue market power issues in any other forum.
Nothing in this section shall preclude any Participant from contesting, in the
context of a proceeding involving the issuance of a protective order by the
Commission, the disclosure or other release of confidential information.

(b) Studies Related to Congestion. The System Operator shall perform, on an
ongoing basis, an evaluation of the effectiveness, efficiency and workability of
the each of the main components of the CMS, including, without limitation, the
system of Locational Prices and FCRs. Within sixty (60) days after the first
anniversary of the CMS/MSS Effective Date, the System Operator shall issue a
written report to the Participants Committee at least ten (10) business days
prior to a Participants Committee meeting for discussion and shall not further
distribute that report publicly until after the Participants Committee meeting.
Such report shall contain in detail the System Operator's evaluations,
conclusions and recommendations, if any, for changes to the CMS. To the extent
practicable, the System Operator shall retain all data necessary to analyze the
CMS.

(c) Day-Ahead Market Information Reports. The System Operator shall make
available as provided below for the Day-Ahead Market each day in accordance with
the Market Rules and in a way that is consistent with the NEPOOL Information
Policy the following items, but not limited to:

(i)  Each Participant shall be notified of the following:

(A) The set of accepted Supply Offers for Resources, including Supply Offers at
External Nodes, that will define the prices and quantities of the Participant's
Supply Obligations for the Dispatch Day with respect to Energy, Operating
Reserve, 4-Hour Reserve and AGC for each hour in the Day-Ahead Market. These
schedules shall define expected start-up, loading levels, and shut down
schedules for the Participant's Resources.

(B) The set of accepted Demand Bids, including Demand Bids at External Nodes,
that will define the Participant's Settlement Obligations to pay for a specified
quantity of Energy at each specified Location for each hour in the Day-Ahead
Market.

(ii)  the System Operator shall publish on a daily basis the following
information:

(A) Day-Ahead Locational Prices for each hour of the Dispatch Day determined in
accordance with Section 14A.12, as well as all non-confidential data and
assumptions used by the System Operator to calculate each such price. These
prices will include Nodal Prices at all Nodes and External Nodes for Resources,
Zonal Prices for each Load Zone, and Hub Prices for each Hub. In posting
Locational Prices, the System Operator shall include all components of such
prices, including the Nodal Price at the Reference Node, the Marginal Loss
Component, and the Congestion Component.

(B) The aggregate quantities of Supply Offers and Demand Bids accepted in each
hour of the Day-Ahead Market.

(C) Hourly Clearing Prices and the amounts scheduled in the Day-Ahead Market for
Operating Reserves, 4-Hour Reserves, and AGC.

(D) The System Operator's load forecast for each hour of the Dispatch Day
compared to accepted Demand Bids.

(E) The projected Net Supply Offer Shortfall Uplift as determined pursuant to
Section 14A.19(a) and RMR Uplift and costs for voltage support for each
Reliability Region.

(d) Real-Time Market Information Reports. The System Operator shall publish for
the Real-Time Market during the Dispatch Day, in a way that is consistent with
the NEPOOL Information Policy the following items, but not limited to:

(i) Real-Time Market Locational Prices, including the Nodal Prices (including
External Nodes), Zonal Prices, and Hub Prices, as well as all non- confidential
data and assumptions used by the System Operator to calculate each such price.
As far in advance of each hour of the Real-Time Market as is feasible, the
System Operator shall post its estimate of the Locational Prices for the
remainder of the Dispatch Day.

(ii) As far in advance of each hour of the Real-Time Market as is feasible,
updates to the load forecast.

(iii) Hourly Clearing Prices and amounts designated in the Real-Time Market for
Operating Reserves and AGC.

(iv) Actual loads compared to forecasted load and accepted Demand Bids.

(e) Special Reporting. The System Operator shall publish with the Real-Time
Market information the following data concerning emergency purchases and sales
and Reserve Contracts entered into pursuant to Section 14A.10:

(i)  The hourly price and schedule for Energy under the emergency purchase or
sale.

(ii) Prices and quantities at which the Operating Reserve or 4-Hour Reserve are
scheduled or designated by the System Operator for the hour pursuant to Reserve
Contracts.

14A.19  Additional Uplift Charges.

(a) Net Supply Offer Shortfall Uplift. It is anticipated that a generating unit
may be scheduled by the System Operator in the Day-Ahead Market for all or part
of a day when the Supply Offer Costs (as defined below) exceed the aggregate
revenues received pursuant to this Section 14A for the generating unit from all
Day-Ahead Markets. A Net Supply Offer Shortfall Uplift shall be calculated as
provided in this Section 14A.19 to provide for payment of this shortfall to the
affected generator and allocation of such difference. Except as provided below,
each generating unit scheduled by the System Operator in the Day-Ahead Market
shall be entitled to receive its Supply Offer Costs, provided that the foregoing
evaluation shall be made only on an aggregate basis for the total hours
scheduled to supply Energy, Operating Reserves, 4-Hour Reserves, and/or AGC in
the Dispatch Day and not on an individual hour-by-hour basis, and shall be made
only on a single Day-Ahead Market basis, so that, for example, the net shortfall
for a unit scheduled for a particular Dispatch Day shall be entitled to this
treatment only for the hours in that first Dispatch Day in that Day-Ahead Market
even if the unit's minimum run time extends beyond the Dispatch Day. Any
shortfall between Supply Offer Costs and aggregate market revenues in the
subsequent period during uninterrupted operation of the Resource for hours that
extend beyond the satisfaction of the Resource's minimum run time, will be
addressed through the Net Supply Offer Shortfall Uplift determined for that
Dispatch Day. Cost responsibility for this difference shall be allocated among
Participants in accordance with subsection (c) of this Section 14A.19 for those
hours in which the generating unit is scheduled to provide service during the
Dispatch Day, with the allocation among such hours determined in accordance with
applicable Market Rules.

For purposes of this Section 14A.19, "Supply Offer Costs" for a generating unit
shall mean the aggregate of the Start-Up Price, if applicable, plus the
summation for the Dispatch Day of the No Load Price in each applicable hour and
the product in each applicable hour of the applicable Supply Offer Prices and
the amounts of Energy, Operating Reserve, 4-Hour Reserve and AGC scheduled from
the unit in the Day-Ahead Market.

The Net Supply Offer Shortfall Uplift is calculated as the Supply Offer Costs of
a generating unit minus the aggregate revenues received by a Participant for the
amounts of Energy, Operating Reserve, 4-Hour Reserve and AGC scheduled from the
unit in the Day-Ahead Market for that Dispatch Day.

A Participant with an Entitlement in a generating unit that is Self-Scheduled in
the Day-Ahead Market shall only be entitled to receive payment of a Net Supply
Offer Shortfall Uplift associated with the unit during hours that the unit is
not Self-Scheduled. The calculation of Net Supply Offer Shortfall Uplift for a
Self Scheduled unit shall exclude No-Load costs for the hours the unit is
Self-Scheduled and include revenues associated with the difference between the
applicable Clearing Price and Supply Offer Price for the service from the unit
beyond the Self-Scheduled service. If the System Operator schedules a generating
unit to start-up and operate in the hours immediately prior to, and/or continue
operation for a period beyond, the hours for which the unit was Self-Scheduled
in the Day-Ahead Market, the Start-Up Price shall not be included in Supply
Offer Costs for the purpose of determining whether the generating unit is
entitled to receive a Net Supply Offer Shortfall Uplift for the hours of the
Dispatch Day for which the unit was not Self-Scheduled.

(i) Real-Time Uplift. There may be circumstances where the Real-Time Nodal Price
for Energy paid to a generating unit in the Real-Time Market is less than the
Real-Time Supply Offer Price for the generating unit. These circumstances may be
caused by the time-weighted averaging calculation of the Real-Time Market Nodal
Prices or as a result of the System Operator dispatching certain fast response
generating units within an hour in response to anticipated system conditions in
that hour. In such circumstances, the generating unit shall receive a Real-Time
Uplift equal to the difference between the Real-Time Nodal Price and the
corresponding Supply Offer Price for those megawatthours produced at the higher
Supply Offer Price but only to the extent those megawatthours were produced
pursuant to the dispatch instructions of the System Operator as described in the
Market Rules.

(ii) Allocation of Net Supply Offer Shortfall Uplift. Where payment is due to a
Participant under Section 14A.19(a), the aggregate amount of such payments shall
be recovered from Participants, including the Participant to which such payment
is made, as an uplift charge to be paid in accordance with this Section
14A.19(c).

Net Supply Offer Shortfall Uplift will first be allocated among the Energy
market and the three Operating Reserve Markets based on cost causation
principles in accordance with applicable Market Rules. Net Supply Offer
Shortfall Uplift will be allocated to specific markets to the extent that the
benefit of incurring the uplift is recognized in that market because incurring
the uplift relieved an otherwise binding constraint affecting the Clearing Price
in that market. To the extent that incurrance of the uplift benefits more than
one market such uplift will be allocated pro rata to all four markets in
accordance with the aggregate Settlemen

Obligations (in dollars) in the Energy and Operating Reserve markets adjusted as
specified in the Market Rules.

Charges for Net Supply Offer Shortfall Uplift allocated to the Day-Ahead Energy
Market ("Regional Energy Uplift") shall be determined for each hour and paid by
each Participant in accordance with the following formula:

(EQUATION)

in which

DACH is the amount to be paid by the Participant pursuant to this Section
14A.19(c) provided that if this amount is negative the Participant shall neither
pay nor receive credit for such amount.

UCa is the sum for the hour of uplift payments to generators made pursuant to
Section 14A.19(a) in the Day-Ahead Market.

XDAi is the Settlement Obligation for Energy of the Participant for the hour in
the Day-Ahead Market adjusted for Bilateral Transactions as to which both the
buyer(s) and the seller(s) elect or have elected to transfer Regional Energy
Uplift obligations in the Day-Ahead Market with respect to any Bilateral
Transaction in accordance with the Market Rules.

XDA is the aggregate Settlement Obligation for Energy of all Participants for
the hour in the Day-Ahead Market adjusted for Bilateral Transactions as to which
both the buyer(s) and the seller(s) elect or have elected to transfer Regional
Energy Uplift obligations in the Day-Ahead Market with respect to any Bilateral
Transactions in accordance with the Market Rules.

SSDAi is the amount of the Participant's Self-Supply of its Day-Ahead Settlement
Obligation for Energy that is actually supplied in the Real-Time Market from the
Self-Scheduled Resources of the Participant.

SSDA is the aggregate of Participants' Self-Supply of their Day-Ahead Settlement
Obligations for Energy that are supplied in the Real-Time Market from the
Self-Scheduled Resources of those Participants.

Charges for Net Supply Offer Shortfall Uplift allocated to each Operating
Reserve Market ("Regional Operating Reserve Uplift") shall be determined for
each hour and paid by each Participant in accordance with an equivalent
calculation to that specified for the Energy Market, as follows. The calculation
for each Operating Reserve Market will be specified in the Market Rules and will
be based on the Settlement Obligation for the relevant category of Operating
Reserve after accounting for those Bilateral Transactions described in the
definitions of XDAi and XDA above with respect to the relevant category of
Operating Reserve.

(iii) Allocation of Real-Time Uplift. Where payment is due to a Participant
under Section 14A.19(b), the aggregate amount of such payments shall be
recovered from Participants, including the Participant to which such payment is
made, as an uplift charge to be paid in accordance with this Section 14A.19(d).

Charges for Real-Time Uplift allocated to Participants in the Real-Time Energy
Market ("Real-Time Energy Uplift") shall be determined for each hour and paid by
each Participant in accordance with the following formula:

(EQUATION)

in which

RTCH is the amount to be paid by the Participant pursuant to this Section
14A.19(d) provided that if this amount is negative the Participant shall neither
pay nor receive credit for such amount.

UCb is the sum for the hour of uplift payments to generators made pursuant to
Section 14A.19(b) in the Real-Time Market.

XRTi is the Settlement Obligation for Energy of the Participant for the hour in
the Real-Time Market adjusted for Bilateral Transactions as to which both the
buyer(s) and the seller(s) elect or have elected to transfer Real-Time Energy
Uplift obligations in the Real-Time Market with respect any Bilateral
Transaction in accordance with the Market Rules.

XRT is the aggregate Settlement Obligation for Energy of all Participants for
the hour in the Real-Time Market adjusted for Bilateral Transactions as to which
both the buyer(s) and the seller(s) elect or have elected to transfer Real-Time
Energy Uplift obligations in the Real-Time Market with respect to any Bilateral
Transactions in accordance with the Market Rules.

SSRTi is the amount of the Participant's Self-Supply of its Real-Time Settlement
Obligation for Energy that is actually supplied in the Real-Time Market from the
Self-Scheduled Resources of the Participant.

SSRT is the aggregate of Participants' Self-Supply of their Real-Time Settlement
Obligations for Energy that are supplied in the Real-Time Market from the
Self-Scheduled Resources of those Participants.

(iv) Uplift Allocation And Pre-Existing Contracts. With respect to any Bilateral
Transaction entered into prior to September 26, 2000 (the "Effective Date"), the
allocation of Regional Energy Uplift cost responsibility, Regional Operating
Reserve Uplift cost responsibility and Real-Time Energy Uplift cost
responsibility provided for in Sections 14A.19(c) and 14A.19(d) shall not alter
the obligations of either the buyer or seller under such Bilateral Transaction
as of the date immediately prior to the Effective Date without the agreement of
both the buyer and seller.

(v) RMR Uplift. It is also anticipated that it may be necessary from time to
time to schedule a Participant's generating unit or Dispatchable Load to provide
Operating Reserve in one or more hours at prices for Operating Reserve that
exceed the applicable Clearing Price for that Operating Reserve service in the
Day-Ahead Market in order to satisfy locational Operating Reserve requirements
in a particular Reliability Region or Reliability Regions in accordance with
applicable Market Rules. When this occurs the Participant providing such service
shall be entitled to receive for the Dispatch Day the aggregate of the
applicable Supply Offer Prices for Operating Reserve to provide the requested
Operating Reserve service for all of the scheduled hours in the Dispatch Day.
This comparison of Supply Offer Price against Clearing Price for the applicable
Operating Reserve products shall be made on an aggregate basis for all hours
scheduled in the Day-Ahead Market for that Dispatch Day, and not on an
individual hour-by-hour basis.

Where payment is made to a Participant under these circumstances, the amount by
which the payment to the Participant exceeds the amount that would be paid if
the Participant had only received the applicable Day-Ahead Market Operating
Reserve Clearing Prices for the scheduled service during the hours in question
shall be recovered as RMR Uplift from Participants which are obligated to pay
under the Settlement Obligations for Operating Reserve associated with load in
the affected Reliability Region or Reliability Regions for the hours during
which the service is scheduled in the Dispatch Day.

Except as provided below, RMR Uplift shall be paid by each Participant for each
hour in accordance with the following formula:

(EQUATION)

in which

CHd is the amount to be paid by a Participant pursuant to this Section 14A.19(f)
for RMR Uplift for the affected Reliability Region(s).

UCd is the aggregate RMR Uplift payments to Participants for the hour for out of
merit services for the affected Reliability Region(s) to be allocated and paid
pursuant to this Section 14A.19(f).

Eli is the number of kilowatthours of Electrical Load of the Participant for the
hour in the affected Reliability Region(s).

ELRR is the aggregate number of kilowatthours of Electrical Load of all
Participants for the hour in the affected Reliability Region(s).

ADJRR is the total uplift charge adjustment for the Participant required to
reflect Operating Reserve that the Participant has Self-Supplied and all
Bilateral Transactions entered into by the Participant for the transfer of
Settlement Obligations for Operating Reserve pursuant to Section 14A.1(c) for
the hours to the extent that each Bilateral Transaction is not reflected in the
Participant's Electrical Load for the hour. The adjustment for each Bilateral
Transaction shall equal the pro rata portion of the transferring Participant's
Operating Reserve Settlement Obligations covered by such Bilateral Transaction.
The adjustment shall be negative for all Bilateral Transactions under which the
Participant transfers its Settlement Obligations for Operating Reserve to
another Participant; the adjustment shall be positive for all Bilateral
Transactions under which the Participant assumes the Settlement Obligations for
Operating Reserve of another Participant.

Notwithstanding the foregoing, the first six million dollars ($6,000,000) of the
RMR Uplift under this Section 14A.19(f) shall be allocated for each hour among
and paid by all Participants which have Settlement Obligations for Operating
Reserve for the hour in accordance with the formula in Section 14A.1(c) for each
of the following two periods:

(i)  the twelve-month period commencing on the CMS/MSS  Effective Date; and

(ii) the period commencing on the first anniversary of the CMS/MSS Effective
Date and ending on December 31, 2004.

Any such RMR Uplift in excess of six million dollars ($6,000,000) with respect
to either period shall be allocated among and paid by the Participants with
Settlement Obligations for Operating Reserve associated with load in the
affected Reliability Region(s) in accordance with the formula of this Section
14A.19(f).

[Next Sheet is 199]



                                    PART FOUR
                             TRANSMISSION PROVISIONS

                                   SECTION 15
                      OPERATION OF TRANSMISSION FACILITIES

15.16 Definition of PTF. PTF or pool transmission facilities are the
transmission facilities owned by Participants rated 69 kV or above required to
allow energy from significant power sources to move freely on the New England
transmission network, and include:

1. All transmission lines and associated facilities owned by Participants rated
69 kV and above, except for lines and associated facilities that contribute
little or no parallel capability to the NEPOOL Transmission System (as defined
in the Tariff). The following do not constitute PTF:

(a) Those lines and associated facilities which are required to serve local load
only.

(b) Generator leads, which are defined as radial transmission from a generation
bus to the nearest point on the NEPOOL Transmission System.

(c)  Lines that are normally operated open.

2. Parallel linkages in network stations owned by Participants (including
substation facilities such as transformers, circuit breakers and associated
equipment) interconnecting the lines which constitute PTF.

3. If a Participant with significant generation in its transmission and
distribution system (initially 25 MW) is connected to the New England network
and none of the transmission facilities owned by the Participant qualify to be
included in PTF as defined in (1) and (2) above, then such Participant's
connection to PTF will constitute PTF if both of the following requirements are
met for this connection:

(a)  The connection is rated 69 kV or above.

(b) The connection is the principal transmission link between the Participant
and the remainder of the New England PTF network.

4. Rights of way and land owned by Participants required for the installation of
facilities which constitute PTF under (1), (2) or (3) above. The Reliability
Committee shall review at least annually the status of transmission lines and
related facilities and determine whether such facilities constitute PTF and
shall prepare and keep current a schedule or catalogue of PTF facilities.

The following examples indicate the intent of the above definitions:

(i)  Radial tap lines to local load are excluded.

(ii) Lines which loop, from two geographically separate points on the NEPOOL
Transmission System, the supply to a load bus from the NEPOOL Transmission
System are included.

(iii) Lines which loop, from two geographically separate points on the NEPOOL
Transmission System, the connections between a generator bus and the NEPOOL
Transmission System are included.

(iv) Radial connections or connections from a generating station to a single
substation or switching station on the NEPOOL Transmission System are excluded,
unless the requirements of paragraph (3) above are met.

Transmission facilities owned by a Related Person of a Participant which are
rated 69 kV or above and are required to allow Energy from significant power
sources to move freely on the New England transmission network shall also
constitute PTF provided (i) such Related Person files with the Secretary of the
Participants Committee its consent to such treatment; and (ii) the Participants
Committee determines that treatment of the facility as PTF will facilitate
accomplishment of NEPOOL's objectives. If a facility constitutes PTF pursuant to
this paragraph, it shall be treated as "owned" by a Participant for purposes of
the Tariff and the other provisions of Part Four of the Agreement.

15.17 Maintenance and Operation in Accordance with Accepted Electric Industry
Practice. Each Participant which owns or operates PTF or other transmission
facilities rated 69 kV or above shall, to the fullest extent practicable, cause
all such transmission facilities owned or operated by it to be designed,
constructed, maintained and operated in accordance with Accepted Electric
Industry Practice.

15.18 Central Dispatch. Each Participant which owns or operates PTF or other
transmission facilities rated 69 kV or above shall, to the fullest extent
practicable, subject all such transmission facilities owned or operated by it to
central dispatch by the System Operator; provided, however, that each
Participant shall at all times be the sole judge as to whether or not and to
what extent safety requires that at any time any of such facilities will be
operated at less than their full capability or not at all.

15.19 Maintenance and Repair. Each Participant shall, to the fullest extent
practicable: (a) cause transmission facilities owned or operated by it to be
withdrawn from operation for maintenance and repair only in accordance with
maintenance schedules reported to and published by the System Operator in
accordance with procedures approved or established by the Tariff Committee from
time to time, (b) restore such facilities to good operating condition with
reasonable promptness, and (c) in emergency situations, accelerate maintenance
and repair at the reasonable request of the System Operator in accordance with
rules approved by the Tariff Committee.

15.20 Additions to or Upgrades of PTF. The possible need for an addition to or
upgrade of PTF may be identified in connection with the planning process of
Section 51 of the Tariff, an application or request for service under the
Tariff, or a request for the installation of or material change to a generation
or transmission facility, or may be separately identified by a NEPOOL committee,
a Participant or the System Operator. In such cases, a study, if necessary, to
assess available transmission capacity and, if necessary, a System Impact Study
and a Facility Study, shall be performed by the affected Participant(s) in whose
Local Network(s) the addition or upgrade would or might be effected or their
designee(s), or the Reliability Committee and/or the System Operator, in the
case of a System Impact Study, or the Committee's or the System Operator's
designee(s), with review of the study by the System Operator if it does not
perform the study. Studies to assess available transmission capacity and System
Impact Studies and Facilities Studies shall be conducted, as appropriate, in
accordance with the affected Participant's Local Network Service Tariff, or in
accordance with the applicable methodology specified in Attachments C and D to
the Tariff, and the provisions of the Local Network Service Tariff or the
applicable provisions of Attachments I and J to the Tariff shall apply, as
appropriate, with respect to the payment of the costs of the study and the other
matters covered thereby.

Responsibility for the costs of new PTF or any modification or other upgrade of
PTF shall be determined, to the extent applicable, in accordance with Parts V
and VI and Schedules 11 and 12 of the Tariff, including without limitation the
provisions relating to responsibility for the costs of new PTF or modifications
or other upgrades to PTF exceeding regional system, regulatory or other public
requirements set forth in Section (3)(b) of Schedule 11 to the Tariff and
Schedule 12 of the Tariff

Sheet 206 is intentionally blank.



                                   SECTION 16
                              SERVICE UNDER TARIFF

16.1 Effect of Tariff. The Tariff specifies the terms and conditions under which
the Participants will provide regional transmission service through NEPOOL. This
Section 16 specifies various rights and obligations with respect to the revenues
to be collected by NEPOOL for the Participants under the Tariff and related
matters.

16.2 Obligation to Provide Regional Service. The Participants which own PTF
shall collectively provide through NEPOOL regional transmission service over
their PTF facilities, and the facilities of their Related Persons which
constitute PTF in accordance with Section 15.1, to other Participants and other
Eligible Customers pursuant to the Tariff. The Tariff provides open access for
all of the types of regional transmission service required by Participants and
other Eligible Customers over PTF and it is intended to be the only source of
such service, except for service provided for Excepted Transactions.

16.3 Obligation to Provide Local Network Service. Each Participant which owns
transmission facilities other than PTF shall provide service over such
facilities to other Participants or other Eligible Customers connected to the
Transmission Provider's transmission system pursuant to a tariff (a "Local
Network Service Tariff") filed by the Transmission Provider with the Commission.
A Participant is also obligated to provide service under its Local Network
Service Tariff or otherwise (i) to permit a Participant or other Entity with an
Entitlement in a generating unit in the Participant's local network to deliver
the output of the generating unit to an interconnection point on PTF and (ii) to
permit the delivery to an Eligible Customer taking Internal Point-to-Point
Service under the Tariff of the Energy and/or capacity covered by its Completed
Application for that Internal Point-to-Point Service.

A Local Network Service Tariff shall provide:

(i) for a pro rata allocation of monthly revenue requirements not otherwise paid
for through charges to Eligible Customers for Local Point-to-Point Service among
the Transmission Provider's Network Customers receiving service under the tariff
on the basis of their loads during the hour in the month in which the total
connected load to the Local Network is at its maximum, without any adjustment
for credits for generation;

(ii) for the recovery under the Local Network Service Tariff from Eligible
Customers taking Regional Network Service and Internal Point-to-Point Service of
that portion of the Transmission Provider's annual transmission revenue
requirements with respect to PTF which is not recovered through the distribution
of revenues from Regional Network Service or Internal Point-to- Point Service
pursuant to Section 16.6;

(iii) that where all or a part of the load of a Participant or other Eligible
Customers taking service under the tariff is connected directly to PTF, the
Participant or other Eligible Customers receiving the service shall pay each
Year during the Transition Period for such service with respect to the load
directly connected to PTF the percentage specified in the schedule below of the
applicable Local Network Service Tariff charge for service across non-PTF
transmission facilities and shall have no obligation to pay charges for service
across non-PTF transmission facilities with respect to that portion of the
connected load after the Transition Period, but shall continue to pay its share
of any other Local Network Service costs directly associated with the
PTF-connected load; provided that in the event of any inconsistency between the
foregoing provisions and the terms of any Excepted Transaction which is listed
in Attachment G-1 to the Tariff, the Excepted Transaction shall control:

            Year One   Year Two   Year Three   Year Four   Years Five and Six

% of charge
to be paid    100%      80%         60%          40%            20%

(iv) that if the Transmission Provider receives a distribution pursuant to
Section 16.6 from NEPOOL out of revenues paid for Through or Out Service, the
amounts received shall reduce its Local Network Service revenue requirements;
and

(v) that if the Transmission Provider receives transmission revenues from an
Eligible Customer taking Local Network Service from that Transmission Provider
with respect to an Excepted Transaction, the amounts received shall reduce the
amount due from such Eligible Customer connected to the Transmission Provider's
transmission system for Local Network Service provided thereto by the
Transmission Provider rather than reducing the

Transmission Provider's total cost of service, except that any reductions to the
amount due from Eligible Customers for Excepted Transactions identified in
Section 25(1) and (2) of the Tariff shall be made only for service rendered
through February 28, 1999, and such reductions shall cease and shall be replaced
thereafter in their entirety with the credits under the NEPOOL Tariff, provided
in accordance with Sections 25A and 25B of the Tariff.

16.4 Transmission Service Availability. The availability of transmission
capacity to provide transmission service under the Tariff shall be determined in
accordance with the Tariff. In determining the availability of transmission
capacity, existing committed uses of the Participants' transmission facilities
shall include uses for existing firm loads and reasonably forecasted changes in
such loads, and for Excepted Transactions.

16.5 Transmission Information. Information concerning (i) available transmission
capacity, (ii) transmission rates and (iii) system conditions that may give rise
to Interruptions or Curtailments shall be made available to all Participants and
Non-Participants through the OASIS on a timely and non-discriminatory basis. All
Participants owning PTF or other transmission facilities rated 69 kV or higher
shall make available to the System Operator the information required to permit
the maintenance of the OASIS in compliance with Commission Order 889 and any
other applicable Commission orders; provided that no Participant shall be
required to furnish information which is required to be treated as confidential
in accordance with NEPOOL policy without appropriate arrangements to protect the
confidentiality of such information.

16.6 Distribution of Transmission Revenues. Payments required by the Tariff for
the use of the NEPOOL Transmission System shall be made to NEPOOL and shall be
distributed by it in accordance with this Section 16.6.

A. Regional Network Service Revenues. Revenues received by NEPOOL for providing
Regional Network Service each month during the Transition Period shall be
distributed to those Participants owning PTF or those load-serving Participants
supporting PTF which are obligated to take and pay for Regional Network Service
and/or Internal Point-to-Point Service in accordance with the Tariff, in part on
the basis of allocated flows for the region as determined in accordance with the
methodology specified in Attachment A to this Agreement and in part in
proportion to the respective Annual Transmission Revenue Requirements for PTF of
such owners and supporters, in accordance with the following Schedule:

             Year One  Year Two  Year Three  Year Four  Year Five   Year Six

Allocated
Flows:         25%       20%        15%        10%         5%        2.5%
Annual
Transmission

Revenue
Requirements: 75%       80%         85%       90%         95%       97.5%

Revenues received by NEPOOL for providing Regional Network Service each month
after the Transition Period shall be distributed to the Participants owning or
supporting PTF in proportion to their respective Annual Transmission Revenue
Requirements for PTF.

B. Through or Out Service Revenues. The revenues received by NEPOOL each month
for providing Through or Out Service shall be distributed among the Participants
owning PTF on the basis of allocated flows for the transaction determined in
accordance with the methodology specified in Attachment A to this Agreement;
provided that for service provided during the Transition Period but not
thereafter, for an "Out" transaction which originates on the system of a
Participant which owns the PTF interconnection facilities on the New England
side of the interface with the other Control Area over which the transaction is
delivered, 100% of the megawatt mile flows with respect to the transaction shall
be deemed to occur on such Participant's system.

C. Internal Point-to-Point Service Revenues. The revenues received by NEPOOL
each month for providing Internal Point-to-Point Service shall be distributed
among those load-serving Participants owning or supporting PTF which are
obligated to take and pay for Regional Network Service and/or Internal
Point-to-Point Service in accordance with the Tariff, in proportion to their
respective Annual Transmission Revenue Requirements for PTF under Attachment F
to the Tariff.

D. Ancillary Service Payments. The revenues received by NEPOOL pursuant to
Schedule 1 to the Tariff (scheduling, system control and dispatch service) will
be used to reimburse NEPOOL, the System Operator (if the System Operator does
not receive revenues for that service under a separate tariff) and Participants
for the costs which are reflected in the charges for such service. The revenues
received by NEPOOL pursuant to Schedules 2-7 to the Tariff shall be distributed
prior to the Second Effective Date in accordance with the continuing provisions
of the Prior NEPOOL Agreement and the rules adopted thereunder, and shall be
distributed on or after the Second Effective Date in accordance with Section 14.

E.  Congestion Payments.  Any congestion uplift charge received as a payment
for transmission service pursuant to Section 24 of the Tariff for any hour
shall be applied in accordance with Section 14.5(a) in payment for Energy
service.

[Next Sheet is 216]


                                   SECTION 17
                            POOL-PLANNED UNIT SERVICE

17.1 Effective Period. The provisions contained in this Section 17 shall
continue in effect for the period to and including February 28, 2001, and shall
be of no effect after that date.

17.2 Obligation to Provide Service. Until February 28, 2001, each Participant
shall provide service over its PTF facilities under this Section 17 rather than
under the Tariff, for the following purposes:

(a) the transfer to a Participant's system of its ownership interest or its Unit
Contract Entitlement under a contract entered into by it before November 1, 1996
in a Pool-Planned Unit which is off its system;

(b) the transfer to a Participant's system of its Entitlement in a purchase
under a contract entered into by it before November 1, 1996 (including a
purchase under the HQ Phase II Firm Energy Contract) from Hydro-Quebec where the
line over which the transfer is made into New England is the HQ Interconnection;
and

(c) the transfer to a Non-Participant of its Entitlement in a Pool-Planned Unit
pursuant to an arrangement which has been approved prior to November 1, 1996 by
the Participants Committee.

17.3 Rules for Determination of Facilities Covered by Particular Transactions.
It is anticipated that it may be necessary with respect to a particular
transmission use under subsection (a), (b) or (c) of Section 17.2 to determine
whether the transaction is effected entirely over PTF, entirely over facilities
that are not PTF, or partially over each.

The following rules shall be controlling in the determination of the facilities
required to effect the use:

(a) To the extent that EHV PTF is available to effect the transaction, over all
or part of the distance to be covered, the use shall be deemed to be effected on
such EHV PTF over such portion of the distance to be covered.

(b) To the extent that EHV PTF is not available for the entire distance to be
covered by the use, but Lower Voltage PTF is available to cover all or part of
the distance not covered by EHV PTF, the transaction shall be deemed to be
effected on such Lower Voltage PTF.

If a Participant has ownership or contractual rights with respect to an Excepted
Transaction which are independent of this Agreement and the Tariff and are
adequate to provide for a transfer of the types specified in subsections
17.2(a), (b) or (c), and such rights are not limited to the transfer in
question, the transfer shall be deemed to have been effected pursuant to such
rights and not pursuant to the provisions of this Agreement. A copy of each
instrument establishing such rights, or an opinion of counsel describing and
authenticating such rights, shall be filed with the Secretary of the
Participants Committee.

17.4  Payments for Uses of EHV PTF During the Transition Period.

(a) Each Participant shall pay each month for its uses of EHV PTF for transfers
of Entitlements pursuant to subsections (a) or (b) of Section 17.2, one-twelfth
of the NEPOOL EHV PTF Participant Summer or Winter Wheeling Rate in effect for
the calendar year ending December 31, 1996, as determined in accordance with the
Prior NEPOOL Agreement, for each Kilowatt of its current Entitlements which
qualify for transfer pursuant to subsections (a) or (b) of Section 17.2, except
as otherwise provided in Section 17.3; provided that such payment shall be
required with respect to only one-half the Kilowatts covered by a NEPOOL
Exchange Arrangement (as hereinafter defined).

Each Participant which is a party to the HQ Phase II Firm Energy Contract (other
than a Participant (i) whose system is directly interconnected to the HQ
Interconnection or (ii) which has contractual rights independent of this
Agreement and the Tariff which give it direct access to the HQ Interconnection
and which are not limited to transfers of Energy delivered over the HQ
Interconnection) shall also pay each month for the use of EHV PTF for deliveries
under the Phase II Firm Energy Contract during the Base Term of the HQ Phase II
Firm Energy Contract, one-twelfth of the NEPOOL EHV PTF Participant Summer or
Winter Wheeling Rate in effect for the calendar year ending December 31, 1996,
as determined in accordance with the Prior NEPOOL Agreement, for each Kilowatt
of its HQ Phase II Net Transfer Responsibility for the month. If, and to the
extent that, such Responsibility continues for any period by which the term of
said Contract extends beyond the Base Term, each such Participant shall continue
to pay the above rate during the extension period with respect to its continuing
Responsibility. A Participant shall not be deemed to be directly interconnected
to the HQ Interconnection for purposes of this paragraph solely because of its
participation in arrangements for the support and/or use of PTF facilities
installed or modified to effect reinforcements of the New England AC
transmission system required in connection with the HQ Interconnection. A copy
of each contract establishing rights independent of this Agreement and the
Tariff which provides direct access to the HQ Interconnection, or an opinion of
counsel describing and authenticating such rights, shall be filed with the
Secretary of the Participants Committee.

The NEPOOL EHV PTF Participant Summer Wheeling Rate for any calendar year shall
be applicable to the months in the Summer Period.

The NEPOOL EHV PTF Participant Winter Wheeling Rate for any calendar year shall
be applicable to the months in the Winter Period.

A NEPOOL Exchange Arrangement is one entered into by two Participants each of
which has an ownership interest in a Pool-Planned Unit on its own system
pursuant to which each sells out of its ownership interest, a Unit Contract
Entitlement to the other for a period of time which is, in whole or part, the
same for both sales. Such an arrangement shall constitute a NEPOOL Exchange
Arrangement even though the beginning and ending dates of the two Unit Contract
sale periods are different, but only for the period for which both sales are in
effect. If for any period the number of Kilowatts covered by the two Unit
Contract Entitlements of a NEPOOL Exchange Agreement are not the same, the
portion of the larger Entitlement which exceeds the amount of the smaller
Entitlement shall not be deemed to be covered by such NEPOOL Exchange
Arrangement for purposes of this Section 17.4.

(b) Each Participant shall pay each month for its use of EHV PTF for a transfer
of an Entitlement in a Pool-Planned Unit to a Non-Participant pursuant to
Section 17.2(c) such charge as is fixed by the Participants Committee at the
time of its approval of the sale, and filed with the Commission.

(c) Fifty percent of all amounts required to be paid with respect to transfers
by a Participant pursuant to subsection (a) or (b) of Section 17.2 shall be paid
to a pool transmission fund and distributed monthly among the Participants in
proportion to the respective amounts of their costs with respect to EHV PTF for
the calendar year 1996 as determined in accordance with the Prior NEPOOL
Agreement.

(d) The remaining 50% of all amounts required to be paid with respect to
transfers by a Participant pursuant to subsections (a) or (b) of Section 17.2
shall be paid to, and retained by, the Participant on whose system the transfer
originates, or in the event the EHV PTF system of such Participant is supported
in part by other Participants, then to the Participant on whose system the
transfer originates and such other Participants in proportion to the respective
shares of the costs of such EHV PTF system borne by each of them or in such
other manner as the Participants involved may jointly direct; provided that the
Participant on whose system the transfer originates shall have the right to
waive such 50% payment in whole or part as to a particular transfer except that
no such waiver may adversely affect the payments to any other Participant which
is supporting in part the originating system's EHV PTF system.

17.5 Payments for Uses of Lower Voltage PTF. Each Participant which uses another
Participant's Lower Voltage PTF pursuant to this Section 17 shall pay each month
to the owner of such Lower Voltage PTF (1) for each Kilowatt of its use of such
Lower Voltage PTF for transfer of Entitlements pursuant to Subsections 17.2(a),
(b) or (c) during the month, and (2) during the Base Term of the HQ Phase II
Firm Energy Contract (and during any extension of the term of said Contract if
and to the extent its HQ Phase II Net Transfer Responsibility continues during
the extension period) for each Kilowatt of its HQ Phase II Net Transfer
Responsibility for the month, the owner's Lower Voltage PTF Winter Wheeling Rate
or Summer Wheeling Rate for the 1996 calendar year, as determined in accordance
with the Prior NEPOOL Agreement; except that the requirements for such payments
shall terminate on March 1, 1999 for Participants receiving network service
under both the Tariff and applicable Local Network Service Tariff.

17.6 Use of Other Transmission Facilities by Participants. For the period to and
including February 28, 1999, each Participant which has no direct connection
between its system and PTF shall be entitled to use the non-PTF transmission
facilities of any other Participant required to reach its system for any of the
purposes for which PTF may be used under Section 17.2. Such use shall be
effected, and payment made, in accordance with the other Participant's filed
open access tariff.

17.7 Limits on Individual Transmission Charges. Any charges for transmission
service pursuant to this Section 17 by any Participant to another Participant
shall be just, reasonable and not unduly discriminatory or preferential. No
provision of this Section 17 shall be construed to waive the right of any
Participant to seek review of any charge, term or condition applicable to such
transmission service by another Participant by the Commission or any other
regulatory authority having jurisdiction of the transaction.

[Next Sheet is 225]



                             SECTION 17A
                       TRANSMISSION OWNERS RESERVED RIGHTS

Notwithstanding any other provision of this Agreement, or any other agreement or
amendment made in connection with the restructuring of NEPOOL, each Transmission
Owner shall retain all of the rights set forth in this Section 17A; provided,
however, that such rights shall be exercised in a manner consistent with the
Transmission Owner's rights and obligations under the Federal Power Act and the
Commission's rules and regulations thereunder.

17A.1 Each Transmission Owner shall have the right at any time unilaterally to
file pursuant to Section 205 of the Federal Power Act to change the revenue
requirements underlying its component of the rates for service under the NEPOOL
Tariff and the transmission-related provisions of this Agreement.

17A.2 Nothing in this Agreement shall restrict any rights, to the extent such
rights exist: (a) of Transmission Owners that are parties to a merger,
acquisition or other restructuring transaction to make a filing under Section
205 of the Federal Power Act with respect to the reallocation or redistribution
of revenues among such Transmission Owners; or (b) of any Transmission Owner to
terminate its participation in NEPOOL pursuant to Section 21.2 of this
Agreement, notwithstanding any effect its withdrawal from NEPOOL may have on the
distribution of transmission revenues among other Transmission Owners. Further,
nothing in this Agreement shall be interpreted to permit the adoption of a rate
design change that is inconsistent with any settlement under the Tariff accepted
by the Commission without the consent of all signatories to the settlement.

17A.3 Each Transmission Owner retains all rights that it otherwise has incident
to its ownership of its assets, including, without limitation, its PTF and
non-PTF, including the right to build, acquire, sell, merge, dispose of, retire,
use as security, or otherwise transfer or convey all or any part of its assets,
including, without limitation, the right, individually or collectively, to amend
or terminate the Transmission Owner's relationship with the ISO in connection
with the creation of an alternative arrangement for the ownership and/or
operation of its transmission facilities on an unbundled basis (e.g., a
transmission company), subject to necessary regulatory approvals and to any
approvals required under applicable provisions of this Agreement. This section
is not intended to reduce or limit any other rights of a Transmission Owner as a
signatory to this Agreement.

17A.4 The obligation of any Transmission Owner to expand or modify its
transmission facilities in accordance with the Tariff shall be subject to the
Transmission Owners' right to recover, pursuant to appropriate financial
arrangements contained in Commission-accepted tariffs or agreements, all
reasonably incurred costs, plus a reasonable return on investment, associated
with constructing and owning or financing such expansions or modifications to
its facilities.

17A.5 Each Transmission Owner shall have the right to adopt and implement
procedures it deems necessary to protect its electric facilities from physical
damage or to prevent injury or damage to persons or property.

17A.6 Each Transmission Owner retains the right to take whatever actions it
deems necessary to fulfill its obligations under local, state or federal law.

17A.7 In addition to having the rights reserved under other provisions of this
Section 17A, all Participants retain the right to take any position before the
Commission, and any appellate court with jurisdiction to review a Commission
determination, or to seek a determination by the Commission, regarding whether,
and the extent to which, the Transmission Owners may retain the exclusive right
to make unilateral filings under Section 205 of the Federal Power Act to amend
the Tariff and the transmission related provisions of this Agreement. If and to
the extent the Commission rules that the Transmission Owners do not retain such
rights, then any such amendment that is not subject to any of Section 17A.1
through 17A.6 may be filed with the Commission only upon the approval by the
Participants Committee of the amendment under Section 6.11, including Section
6.11(d). If and to the extent the Commission rules that the Transmission Owners
do retain such rights, then the Transmission Owners, acting through the
Transmission Owners Committee, shall have the exclusive right to make unilateral
filings under Section 205 of the Federal Power Act to amend the Tariff and the
transmission-related provisions of this Agreement, other than filings subject to
Sections 17A.1 or 17A.2.

17A.8 (a) Notwithstanding anything to the contrary in this Agreement, the rights
of each Participant under the Federal Power Act shall be preserved.

(a) Any dispute over whether a matter falls within the scope of any of the
rights reserved under this Section 17A will be subject to resolution pursuant to
Section 11.A.

(b) No amendment to any provision of this Section 17A or Section 11B may be
adopted without the agreement of the Transmission Owners specified in Section
11B.

(c) Any agreement entered into between NEPOOL and a System Operator shall
require the System Operator to respect the rights reserved under this Section
17A.

[Next Sheet is 230]




                                    PART FIVE
                                     GENERAL

                                   SECTION 18
                    GENERATION AND TRANSMISSION FACILITIES

18.8 Designation of Pool-Planned Facilities. At the request of a Participant,
the Participants Committee shall designate as "pool-planned" a generating or
transmission facility, for purposes of Chapter 164, Sections 11-22 of the
Massachusetts General Laws, to be constructed by the Participant or its Related
Person if the Participants Committee determines that the facility is consistent
with NEPOOL planning. Designation of a transmission facility as a Pool-Planned
Facility does not determine whether or not the facility is PTF. The Participants
Committee may not unreasonably withhold designation as a Pool-Planned Facility
of a generation unit or other facility proposed by one or more Participants.

18.9 Construction of Facilities. Subject to Sections 13.1, 15.2, 15.5, 18.3,
18.4 and 18.5, and to the provisions of the Tariff, each Participant shall have
the right to determine whether, and to what extent, additions to and
modifications in its generating and transmission facilities shall be made.
However, each Participant shall give due consideration to recommendations made
to it by the Participants Committee or the System Operator for any such
additions or modifications and shall follow such recommendations unless it
determines in good faith that the recommended actions would not be in its best
interest.

18.10 Protective Devices for Transmission Facilities and Automatic Generation
Control Equipment. Each Participant shall install, maintain and operate such
protective equipment and switching, voltage control, load shedding and emergency
facilities as the Participants Committee may determine to be required in order
to assure continuity of service and the stability of the interconnected
transmission facilities of the Participants. Until the Second Effective Date,
each Participant shall also install, maintain and operate such Automatic
Generation Control equipment as the Participants Committee may determine to be
required in order to maintain proper frequency for the interconnected bulk power
system of the Participants and to maintain proper power flows into and out of
the NEPOOL Control Area.

18.11 Review of Participant's Proposed Plans. Each Participant shall submit to
the System Operator, Participants Committee, the Reliability Committee, and the
Markets Committee or the Tariff Committee, as appropriate, for review by them,
in such form, manner and detail as the Participants Committee may reasonably
prescribe, (i) any new or materially changed plan for additions to, retirements
of, or changes in the capacity of any supply and demand-side resources or
transmission facilities rated 69 kV or above subject to control of such
Participant, and (ii) any new or materially changed plan for any other action to
be taken by the Participant which may have a significant effect on the
stability, reliability or operating characteristics of its system or the system
of any other Participant. No significant action (other than preliminary
engineering action) leading toward implementation of any such new or changed
plan shall be taken earlier than sixty days (or ninety days, if the System
Operator or the Participants Committee determines that it requires additional
time to consider the plan and so notifies the Participant in writing within the
sixty days) after the plan has been submitted to the Committees. Unless prior to
the expiration of the sixty or ninety days, whichever is applicable, the
Participants Committee notifies the Participant in writing that it has
determined that implementation of the plan will have a significant adverse
effect upon the reliability or operating characteristics of its system or of the
systems of one or more other Participants, the Participant shall be free to
proceed. The time limits provided by this Section 18.4 may be changed with
respect to any such submission by agreement between the Participants Committee
and the Participant required to submit the plan.

18.12 Participant to Avoid Adverse Effect. If the Participants Committee
notifies a Participant pursuant to Section 18.4 that implementation of the
Participant's plan has been determined to have a significant adverse effect upon
the reliability or operating characteristics of its system or the systems of one
or more other Participants, the Participant shall not proceed to implement such
plan unless the Participant or the Non-Participant on whose behalf the
Participant has submitted its plan takes such action or constructs at its
expense such facilities as the Participants Committee determines to be
reasonably necessary to avoid such adverse effect; provided that if the plan is
for the retirement of a supply or demand-side resource, the Participant may
proceed with its plan only if, after engaging in good faith negotiations with
persons designated by the Participants Committee to address the adverse effects
on reliability or operating characteristics, the negotiations either address the
adverse effects to the satisfaction of the Participants Committee, or no
satisfactory resolution can be achieved on terms acceptable to the parties
within 90 days of the Participant's receipt of the Participants Committee's
notice. Any agreement resulting from such negotiations shall be in writing and
shall be filed in accordance with the Commission's filing requirements if it
requires any payment.



                                   SECTION 19
                                    EXPENSES

19.1  Annual Fee. Each Participant shall pay to NEPOOL in January of each year
an annual fee, which shall be applied toward NEPOOL expenses, as follows:

(a) Each End User Participant which is a Small End User or an End User
Organization shall pay an annual fee of $500.

(b) Each End User Participant which is a Large End User shall pay an annual fee
of $500; plus an additional fee of $500 per megawatt hour of its highest Energy
use during any hour in the preceding year (net of any use of on-site generation)
up to a maximum of $5,000; plus an additional fee of $200 per megawatt hour for
each megawatt hour by which its highest Energy use during any hour in the
preceding year (net of any use of on-site generation during such hour) exceeded
20 megawatt hours.

(c) Each Participant which is a Publicly Owned Entity and a member of the
Publicly Owned Entity Sector shall pay an annual fee of $5,000, except that any
such Participant which is engaged in electricity distribution and had annual
Energy sales of less than 30,000 megawatt hours in the preceding year shall pay
an annual fee of $500, and the difference between $5,000 and $500 for each such
Participant shall be paid, as an additional fee, by the remaining Participants
which are Publicly Owned Entities and members of the Publicly Owned Entity
Sector.

(d) Each Participant other than an End User Participant or a Publicly Owned
Entity shall pay an annual fee of $5,000.

19.2 NEPOOL Expenses. Commencing on January 1, 1999, most expenses of the System
Operator are recovered by it directly from Participants and Non- Participants
under the ISO's Tariff for Transmission Dispatch and Power Administration (the
"ISO Tariff") or through direct charges for services rendered by the ISO, and
have ceased to be NEPOOL expenses. At that time, the payment of a portion of
NEPEX expenses from the Savings Fund in accordance with the Prior NEPOOL
Agreement also terminated.

Further, commencing on January 1, 1999 through June 30, 1999, the balance of
NEPOOL expenses remaining to be paid after the application of (i) the annual fee
to be paid pursuant to Section 19.1 and (ii) any fees or other charges for
services or other revenues received by NEPOOL, or collected on its behalf by the
System Operator, shall, except as otherwise provided in Section 19.3, be
allocated among and paid monthly by the Participants in accordance with their
respective voting shares, as determined in accordance with the Agreement
provisions in effect during such period.

Commencing as of July 1, 1999, such balance of NEPOOL expenses for July and
subsequent months shall be divided equally into as many shares as there are
active Sectors pursuant to Sector 6.2 (other than an End User Sector) and each
Sector's share shall be paid monthly by the Participants in each such Sector
(other than an End User Sector) in such manner as the Participants in each
Sector may determine by unanimous vote and advise the ISO, provided that if the
Participants in a Sector fail to agree unanimously on the allocation of their
Sector's share, the Participants in the Sector shall pay for such Sector share
in the same proportion as the vote they are entitled to in the Sector.
Participants in the Sector that are represented by a group voting member shall
subdivide their portion of the Sector's share of expenses in such a manner as
they may determine by unanimous agreement; provided that if there is not
unanimous agreement among the Participants represented by a group member as to
how to allocate their portion of the Sector's share of expenses, such portion
shall be allocated among the Participants represented by that group member as
follows: (i) for each Participant in the Generation Sector represented by a
group voting member, the portion will be allocated in the same proportion that
the Megawatts of generation owned by the Participants represents of the total
Megawatts owned by Participants represented by the group voting member; and (ii)
for Participants in the Transmission Sector, the portion will be allocated
equally among the Participants represented by the group member. Notwithstanding
the foregoing, no portion of such balance shall be paid by End User Participants
and, until such time as an End User Sector is activated, the monthly share
allocated to the Publicly Owned Entity Sector shall be reduced by one-twelfth of
the aggregate annual fees paid by End Users for the year pursuant to Section
19.1 and one-third of the amount of such reduction shall be allocated to each of
the other three Sectors.

19.3  Restructuring Costs.

(a) The expense of restructuring NEPOOL ("Restructuring Expense"), including but
not limited to (i) software development, hardware and system software costs for
implementation of the Tariff and the new market system, (ii) the costs of the
formation of the Independent System Operator and related separation costs, (iii)
legal and consultant costs related to the amendment of the NEPOOL Agreement
(including the Tariff) and the proceeding with respect thereto at the Federal
Energy Regulatory Commission, and (iv) capital expenditures and capitalized
project costs of the Independent System Operator, shall be funded (to the extent
not already funded or funded separately by the ISO) and amortized according to
this Section 19.3.

(b) The Restructuring Expense incurred (other than certain capital expenditures
and capitalized project costs funded separately by the ISO) before the Second
Effective Date (the "Early Restructuring Expense") has been funded during the
period prior to such date by those entities which have been the Participants
during such period. Commencing at the Second Effective Date, the Early
Restructuring Expense shall be amortized in equal monthly amounts and repaid
over the next 60 months with interest thereon from the date of payment to August
18, 2000 at the rate of 8% per annum, and thereafter at the rate of 10.78% per
annum. Each month during the first twenty months of such period each Participant
shall pay its percentage "X", as determined below, of 1/60th of the Early
Restructuring Expense, plus accumulated interest, and each Participant or other
Entity which previously paid an unreimbursed portion of the aggregate Early
Restructuring Expense shall be entitled to receive each month its percentage
"Y", as determined below, of the aggregate amount to be paid for the month
including accumulated interest. "X" and "Y" shall be determined in accordance
with the following formulas:


(EQUATION)       in which

X is the percentage to be paid for a month by a Participant of the aggregate
amount payable pursuant to this subsection (b) by all Participants for the
month.

A is the amount payable by the Participant for the month under Schedule 2
(Energy Administration Services) of the ISO Tariff (as defined in Section 19.2)
as amended or revised from time to time.

A1 is the aggregate amount payable by all Participants for the month under
Schedule 2 (Energy Administration Services) of the ISO Tariff as amended or
revised from time to time.

(EQUATION) in which

Y is the percentage to be received for a month by a Participant or other Entity
of the aggregate amount to be received pursuant to this subsection (b) by all
Participants or other Entities for the month.

B is the amount of Early Restructuring Expense paid by the Participant or other
Entity which has not previously been reimbursed.

B1 is the aggregate amount of Early Restructuring Expense paid by all
Participants and other Entities which has not previously been reimbursed.

Each month commencing on or after January 1, 2001 and continuing until the Early
Restructuring Expense has been fully amortized and repaid (including the payment
of all interest thereon), each Participant shall pay its percentage "W", as
determined below, of 1/60th of the Early Restructuring Expense, plus accumulated
interest, and each Participant or other Entity which previously paid an
unreimbursed portion of the aggregate Early Restructuring Expense shall be
entitled to receive each month its percentage "Y", as determined in accordance
with the formula set forth therefor in this Section 19.3(b), of the aggregate of
the amount paid for the month, including accumulated interest. "W" shall be
determined in accordance with the following formula:

(EQUATION)

W is the percentage to be paid for the month by a Participant of the aggregate
amount payable pursuant to this subsection (b) by all Participants for the
month.

EL is the Participant's total Electrical Load, expressed in total kilowatthours,
for the month.

G is the sum, expressed in total kilowatthours, of (i) the Participant's share
of the amount of energy that is generated in the month by generating units in
which the Participant has a direct ownership interest as a sole or joint owner
and which is subject to NEPOOL central dispatch, (ii) the Participant's share of
the amount of energy generated in the month by generating units in which the
Participant has an indirect ownership interest as a shareholder, as a general or
limited partner or as a member of a limited liability company and which is
subject to NEPOOL central dispatch, provided that the corporation, partnership
or limited liability company is not itself a Participant, (iii) the
Participant's share of the amount of energy generated in the month by any other
generating unit in which the Participant has an interest under a lease or other
contractual arrangement, provided that the other party to the arrangement is
itself not a Participant, (iv) the share of any Related Person of the
Participant of the amount of energy generated in the month by any other
generating unit which is subject to NEPOOL central dispatch in which such
Related Person has one of the interests described in clauses (i), (ii) and (iii)
above, provided that such Related Person is not itself a Participant, and (v)
the amount of energy imported into the NEPOOL Control Area in the month by the
Participant or any Related Person of the Participant, provided that the Related
Person is not itself a Participant (the items described in this subparagraph are
collectively referred to as a Participant's "Generating Shares"); provided,
however, that if two or more Participants have entered into a Unit Contract for
Energy, the purchasing Participant(s), and not the selling Participant(s),
thereunder shall be credited with the amount of energy to which the purchasing
Participant(s) are entitled under that Unit Contract for purposes of calculating
the Generating Shares of each such Participant.

PEL is the maximum Electrical Load, expressed in total kilowatts, of the
Participant during any hour in the month (the "Peak Electrical Load").

GP is the maximum Generating Shares, expressed in total kilowatts, of the
Participant during any hour in the month (the "Generating Peak").

EL1 is the aggregate Electrical Load, expressed in total kilowatts, of all
Participants for the month.

G1 is the aggregate Generating Shares, expressed in total kilowatthours, of all
Participants for the month.

PEL1 is the aggregate Peak Electrical Load, expressed in total kilowatts, of all
Participants for the month.

GP1 is the aggregate Generating Peak, expressed in total kilowatts, of all
Participants for the month.

[Next Sheet is 241

(c) The Restructuring Expense incurred on the Second Effective Date and to but
not including January 1, 2000 or thereafter shall be funded each month by the
Participants in proportion to the Member Fixed Voting Shares (as defined in
Section 6.9(c)) of each Participant as in effect at the beginning of the month
provided, however, that in calculating the allocation of this portion of the
Restructuring Expense, the Member Fixed Voting Shares of End User Participants
that participate in NEPOOL for governance purposes only in accordance with
NEPOOL's Standard Membership Conditions, Waivers and Reminders ("Governance Only
End User Participants") shall not be included in such calculations and the
amounts that would otherwise have been payable by such Governance Only End User
Participants will be allocated to all of the other Participants on the basis of
their Member Fixed Voting Shares.

(d) The Restructuring Expense incurred on or after January 1, 2000 (the "Late
Restructuring Expense") shall be funded for each month, on an as incurred basis,
by the Participants to the extent that the ISO does not obtain an alternative
source of funds for certain portions of the Late Restructuring Expense. In 2000,
such Late Restructuring Expense shall initially be funded for each month by the
Participants in proportion to their charges under the ISO Tariff for the prior
month. In 2001 and thereafter, on an as-incurred basis, the ISO shall allocate
the incrementally incurred Late Restructuring Expense among the various
schedules to the ISO Tariff that is in effect at that time in a manner that best
matches the elements comprising the incrementally incurred Late Restructuring
Costs to the types of service to be covered by each schedule to the ISO Tariff,
and the portion of the Late Restructuring Expense to be funded by the
Participants that has been allocated to each such schedule to the ISO Tariff for
such year shall be funded in each month by the Participants in proportion to
their charges under such schedule for the prior month; provided, however, that
in the event that the Commission accepts (i) an amendment to the ISO Agreement
(as defined in Section 20(a) hereof) providing that in the event of a
termination or resignation of the ISO, all assets purchased by the ISO with
funds provided by the Participants for which the Participants have not been
reimbursed shall be transferred without further consideration to the
Participants or their designee (which amendment shall be mutually acceptable to
the ISO and the Participants Committee) and (ii) an amendment to the ISO Tariff
or a separate tariff for the ISO pursuant to which the ISO collects certain
portions of the Late Restructuring Expense thereunder, such portions of the Late
Restructuring Expense shall be funded directly under the ISO Tariff or such
separate tariff for the ISO and shall not be initially collected hereunder. Each
item of the Late Restructuring Expense funded by the Participants in each
calendar year (either hereunder, under the ISO Tariff or under a separate tariff
for the ISO) shall be amortized in equal monthly amounts and repaid over a
period of time determined by the ISO in accordance with generally accepted
accounting principles in effect at the time of determination and taking into
consideration the depreciation period, if any, of the particular asset giving
rise to such item of the Late Restructuring Expense, such repayment to include
interest thereon from the date of payment at the rate of 10.78% per annum. For
each item of the Late Restructuring Expense funded by the Participants
(regardless of whether it was incurred before, on or after January 1, 2001 and
whether it was funded hereunder, under the ISO Tariff or under a separate tariff
for the ISO) and during the time in which amounts are being amortized and repaid
for such item, the ISO shall determine to which schedule or schedules of the
then effective ISO Tariff such item relates, and the ISO, acting as agent for
the Participants initially providing the funding for such item, shall recover
the amounts being repaid that are associated with such item plus accrued
interest from the Participants using the allocation methodology set forth in
such schedule or schedules to the ISO Tariff. The ISO shall provide the amounts
recovered to the applicable Participants according to which Participants funded
the item of the Late Restructuring Expense for which the subject amounts have
been recovered.

(e) The funding methodology set forth in subsection (d) shall terminate
automatically upon the implementation of a permanent restructuring funding
methodology acceptable to the Participants Committee and the ISO, to the extent
superseded by such permanent restructuring funding methodology.



                              SECTION 20
                     INDEPENDENT SYSTEM OPERATOR

(a) The Participants Committee is authorized and directed to approve one or more
agreements to be entered into with the ISO (the "ISO Agreement") and any
amendments to the ISO Agreement which the Committee may deem necessary or
appropriate from time to time. The ISO Agreement shall specify the rights and
responsibilities of NEPOOL and the ISO, for the continued operation of the
NEPOOL control center by the ISO as the control center operator for the NEPOOL
Control Area and the administration of the Tariff. In addition, the ISO shall be
responsible for the furnishing of billing and other services required by NEPOOL.

(b) The fees and charges of the ISO (other than those recovered under the ISO
Tariff, as defined in Section 19.2, and fees and charges for services which are
separately billed), and any indemnification payable under the ISO Agreement,
shall be shared by the Participants in accordance with Section 19.

(c) The Participants shall provide to the ISO the financial support, information
and other resources necessary to enable the ISO to provide the services
specified in the ISO Agreement, or in this Agreement, in accordance with
Accepted Electric Industry Practice and subject to the budgeting, approval and
dispute resolution provisions of the ISO Agreement and this Agreement.

(d) The Participants shall provide appropriate funding for the acquisition of
land, structures, fixtures, equipment and facilities, and other capital
expenditures and capitalized project expenditures for the ISO, which are
included in the annual budget for the ISO in accordance with the provisions of
the ISO Agreement, or otherwise specifically approved by the Participants
Committee, but only to the extent that the ISO does not obtain such funding from
other sources. All such land, structures, fixtures, equipment and facilities,
and other capital assets, and all software or other intellectual property or
rights to intellectual property or other assets acquired or developed by the ISO
with funding provided by the Participants pursuant to this Agreement in order to
carry out its responsibilities under the ISO Agreement shall be the property of
the Participants or shall be acquired by the Participants under lease in
accordance with arrangements approved by the Participants Committee. For those
Participants subject to the Public Utility Holding Company Act of 1935
("PUHCA"), any such acquisition by those

Participants is subject to PUHCA approval to the extent such acquisition
requires approval under PUHCA. Unless otherwise agreed by the Participants, any
funding by the Participants of the acquisition, or lease, of land, structures,
fixtures, equipment and facilities, and other capital and/or capitalized project
related expenditures, or the acquisition of other assets, and the ownership
thereof, or the obligations of Participants as lessees, shall be in accordance
with Section 19.3 of this Agreement, the ISO Tariff or a separate tariff for the
ISO. The Participants shall make all such assets (including the assets of the
existing NEPOOL headquarters and control center) available for use by the ISO in
carrying out its responsibilities under the ISO Agreement. The ISO Agreement
shall require the ISO, on behalf of the Participants, to maintain and care for,
insure as appropriate, and pay any property taxes relating to, assets made
available for its use.

(e) The ISO Agreement shall require the ISO to refrain from any action that
would create any lien, security interest or encumbrance of any kind upon the
facilities, equipment or other assets of any Participant, or upon anything that
becomes affixed to such facilities, equipment or other assets. The Participants
and the ISO shall include in the ISO Agreement a provision that, upon the
request of an Participant, the ISO shall (i) provide a written statement that it
has taken no action that would create any such lien, security interest or
encumbrance, and (ii) take all actions within the control of the ISO, at the
direction and expense of the requesting Participant, required for compliance by
such Participant with the provisions of its mortgage relating to such
facilities, equipment or other assets.

(f) The ISO shall have the right to appoint a non-voting member and an alternate
to each NEPOOL committee other than the Participants Committee. The member
appointed to each committee shall have all of the rights of any other member of
the committee except the right to vote.

(g) The ISO shall have the same rights as a Participant to appeal to the
Participants Committee any action taken by any other NEPOOL committee, and shall
be entitled to appear before the Participants Committee on any such appeal.
Further, the ISO shall be entitled to submit any dispute with respect to a vote
of the Participants Committee to approve, modify, or reject a proposed action to
resolution in accordance with Section 21.1, whether or not the action could have
been submitted by a Participant in accordance with Section 21.1A. In addition,
the ISO shall be entitled to submit any dispute with respect to a vote of the
Participants Committee which denies an appeal to the Participants Committee by
the ISO or which takes action on any rulemaking issue to the Board of Directors
of the ISO for determination, subject to the right of the Participants Committee
to seek a review in accordance with the Alternate Dispute Resolution procedures
or by the Commission. The ISO shall give notice of any such submission to the
Secretary of the Participants Committee within ten days of the action of the
Participants Committee and shall mail a copy of such notice to each member of
the Participants Committee. Pending final action on the submission in accordance
with Section 21.1 or by the Board of Directors of the ISO or the Commission, as
appropriate, the giving of notice of the submission shall suspend the
Participants Committee's action. Unless the Board of Directors of the ISO acts
within 60 days of the ISO's notice to the Participants Committee, the
Participants Committee action will be deemed to be approved.

(h) The ISO Agreement shall specify the ISO's independent authority with respect
to rulemaking.

(i) NEPOOL and its committees and the ISO shall consult and coordinate from time
to time with the relevant state regulatory, siting and other authorities of the
six New England states on operating, planning and other issues of concern to the
states. The New England Conference of Public Utilities Commissioners, Inc.
("NECPUC") or its designee shall be furnished notices of meetings of all NEPOOL
committees and the Board of Directors of the ISO, and minutes of their meetings.
NECPUC and other state authorities shall be provided an appropriate opportunity
to appear at meetings of the NEPOOL committees and the Board of Directors of the
ISO and to present their views. Representatives of NEPOOL and the ISO shall be
designated to attend meetings of NECPUC or any committee or task force of
NECPUC, to the extent NECPUC or its committee or task force may deem such
attendance appropriate.

(j) Appointment of Technical Committee Officers. The System Operator shall,
after its chief executive officer has conferred with the Participant members of
the Liaison Committee regarding such appointment(s), appoint the Chair and
Secretary of each of the Technical Committees. Each individual appointed by the
System Operator shall be an independent person not affiliated with any
Participant. Before appointing an individual to the position of Chair or
Secretary, the System Operator shall notify the Committee to which such officer
is being appointed of the proposed assignment and, consistent with its personnel
practices, provide any other information about the individual reasonably
requested by the Committee. In the event that a Technical Committee determines
that the performance of the Chair or Secretary of the Committee is not
satisfactory, the Committee shall provide notice to the System Operator that
such performance deficiencies must be corrected within 60 days. If the Committee
determines that the performance deficiencies have not been corrected within the
60-day period, the Committee may vote to remove the officer, subject to appeal
to the Participants Committee. A vote of the Technical Committee to remove its
officer shall be immediately effective and binding on the System Operator and
shall cause the System Operator to appoint a replacement officer in accordance
with the provisions of this Section 20(j) unless an appeal to the Participants
Committee has been taken prior to the end of the tenth business day following
the vote to remove the officer in which case the vote for removal shall be
subject to the outcome of such appeal. A vote of the Participants Committee with
respect to any such appeal shall be immediately effective and binding on the
System Operator and not subject to any further appeals.


                                   SECTION 21
                            MISCELLANEOUS PROVISIONS

21.1  Alternative Dispute Resolution.

A.  General:

If the ISO is aggrieved by a vote of the Participants Committee to approve,
modify or reject a proposed action under this Agreement, including the Tariff,
it may submit the matter for resolution hereunder. If the Participants Committee
is aggrieved by an action of the ISO Board of Directors ("ISO Board") under this
Agreement, including the Tariff or the ISO Agreement (as defined in Section
20(a)), the Participants Committee may submit the matter for resolution
hereunder; provided, however, that if the action of the ISO relates to
rulemaking, the Participants Committee may submit the matters for resolution
under this Section 21.1 only with the concurrence of the ISO. Any Participant
which is aggrieved by a vote of the Participants Committee to approve, modify or
reject a proposed action under this Agreement, including the Tariff, may, as
provided below, submit the matter for resolution hereunder if the vote:

(1)  requires such Participant to make a payment or to take any action
pursuant to this Agreement; or

(2)  reduces the amount of any receipt or forbids, pursuant to this
Agreement, the taking of any action by the Participant; or

(3) fails to afford it any right to which it is entitled under the provisions of
this Agreement or imposes on it a burden to which it is not subject under the
provisions of this Agreement; or

(4)  results in the termination of the Participant's status as a Participant
or imposes any penalty on the Participant; or

(5)  results in an allocation of transmission or other facilities support
obligations; or

(6)  fails to grant in full an application for transmission service pursuant
to the Tariff.

No legal or regulatory proceeding (except those reasonably necessary to toll
statutes of limitations, claims for laches or other bars to later legal or
regulatory action) shall be initiated by any Participant with respect to any
such matter while proceedings are pending under this Section with respect to the
matter.

B.  Procedure:

(1) Submission of a Dispute: The ISO or a Participant seeking review of a vote
of the Participants Committee shall give written notice to the Secretary of the
Participants Committee within ten business days of the vote, and shall mail or
telecopy a copy of its notice to each member of the Participants Committee.
Where the Participants Committee is seeking review of an action of the ISO
Board, the Participants Committee shall give written notice to the Secretary of
the ISO Board. The provider of notice under this Section shall be referred to
herein as the "Aggrieved Party."

(2) Suspension of Action: If the ISO seeks review of a vote of the Participants
Committee pursuant to this Section, the vote to be reviewed shall be suspended
pending resolution of such review by the arbitrator or the Commission if raised
in regulatory proceedings. If a Participant seeks such a review, the vote to be
reviewed shall be suspended for up to 90 days following the giving of the
Participant's notice pending resolution of any arbitration proceeding unless the
Participants Committee determines that the suspension will imperil the stability
or reliability of the NEPOOL Control Area bulk power supply.

(3) Aggrieved Party Options: (i) If the notice is to seek review of a vote of
the Participants Committee, the Aggrieved Party's notice to the Participants
Committee shall invoke arbitration as described herein in its notice pursuant to
paragraph B(1), and may also initiate mediation with the agreement of the
Participants Committee, while reserving such Party's right to proceed with the
arbitration if mediation does not resolve the matter within 20 days of the
giving of the Party's notice or such longer period as may be fixed by mutual
agreement of the Participants Committee and the Aggrieved Party. Notwithstanding
the initiation of mediation, the arbitration proceeding shall proceed
concurrently with the selection of the arbitrator pursuant to paragraph C(1) of
this Section 21.1.

(i) If the notice is to seek review of an ISO action, the Participants
Committee's notice to the ISO Board shall (subject to the concurrence of the ISO
for actions relating to rulemaking as provided in Section 21.1A) invoke
arbitration as described herein in its notice pursuant to paragraph B(1), and
may also initiate mediation with the agreement of the ISO Board, while reserving
the Participants Committee's right to proceed with the arbitration if mediation
does not resolve the matter within 20 days of the giving of the Participants
Committee's notice or such longer period as may be fixed by mutual agreement of
the ISO Board and the Participants Committee. Notwithstanding the initiation of
mediation, the arbitration proceeding shall proceed concurrently with the
selection of the arbitrator pursuant to paragraph C(1) of this Section 21.1.

(4) Mediation Positions not to be Used Elsewhere: All mediation proceedings
pursuant to this Section are confidential and shall be treated as compromise and
settlement negotiations for purposes of applicable rules of evidence.

(5) Time Limits; Duration: Any other Participant that wishes to participate in
an arbitration proceeding hereunder shall give signed written notice to the
Secretary of the Participants Committee, and to the Secretary of the ISO Board
if the ISO is involved in such arbitration, no later than ten calendar days
after the giving of the notice of arbitration. The arbitration procedure shall
not exceed 90 calendar days from the date of the Aggrieved Party's notice
invoking arbitration to the arbitrator's decision unless the parties agree upon
a longer or shorter time. All agreements by the ISO or the aggrieved Participant
and the Participants Committee to use mediation shall establish a schedule which
will control unless later changed by mutual agreement.

C.  Arbitration:

(1) Selection of Arbitrator: The ISO or the aggrieved Participant and the
Participants Committee shall attempt to choose by mutual agreement a single
neutral arbitrator to hear the dispute. If the ISO or the Participant and the
Participants Committee fail to agree upon a single arbitrator within ten
calendar days of the giving of notice of arbitration to the Secretary of the
Participants Committee or the Secretary of the ISO Board, as the case may be,
the American Arbitration Association shall be asked to appoint an arbitrator. In
either case, the arbitrator shall be knowledgeable in matters involving the
electric power industry, including the operation of control areas and bulk power
systems, and shall not have any substantial business or financial relationships
with the ISO, NEPOOL or its Participants (other than previous experience as an
arbitrator) unless otherwise mutually agreed by the ISO or the aggrieved
Participant and the Participants Committee.

(2) Costs: NEPOOL shall be responsible for all of the costs of the proceeding if
it is initiated by the ISO or by the Participants Committee. If a proceeding is
initiated by an aggrieved Participant, each party shall be responsible for the
following costs, if applicable:

(i) its own costs incurred during the arbitration process (except that this does
not preclude billing the aggrieved Participant for its share of NEPOOL Expenses
that may include the Participants Committee's arbitration costs); plus

(ii) One half of the common costs of the arbitration including, but not limited
to, the arbitrator's fee and expenses, the rental charge for a hearing room and
the cost of a court reporter and transcript, if required.

(3)  Hearing Location:  Unless otherwise mutually agreed, the site for all
arbitration hearings shall be NEPOOL counsel's office.

D.  Rules and Procedures:

(1) Procedure and Discovery: The procedural rules (if any), the conduct of the
arbitration and the availability, extent and duration of pre-hearing discovery
(if any), which shall be limited to the minimum necessary to resolve the matters
in dispute, shall be determined by the arbitrator in his/her sole discretion at
or prior to the initial hearing.

(2) Pre-hearing Submissions: The Aggrieved Party shall provide the arbitrator
with a brief written statement of its complaint and a statement of the remedy or
remedies it seeks, accompanied by copies of any documents or other materials it
wishes the arbitrator to review. The Participants Committee will provide the
arbitrator with a copy of this Agreement and all relevant implementing
documents, a brief description of the action being arbitrated, copies of the
minutes of all NEPOOL committee meetings at which the matter was discussed, a
brief statement explaining why the Participants Committee believes its decision
should be upheld by the arbitrator, and copies of any documents or other
materials the Participants Committee wishes the arbitrator to review. If the
Participants Committee is the Aggrieved Party, the ISO Board will provide copies
of minutes of the ISO Board meetings at which the matter was discussed, a brief
statement explaining why the ISO Board believes its decision should be upheld by
the arbitrator, and copies of any documents or other materials the ISO Board
wishes the arbitrator to review. These submissions shall be made within five
days after the selection of the arbitrator.

In addition, each party shall designate one or more individuals to be available
to answer questions the arbitrator may have on the documents or other materials
submitted by that party. The answers to all such questions shall be reduced to
writing by the party providing the answer and a copy shall be furnished to the
other party.

(3) Initial Hearing: An initial hearing will be held no later than 10 days after
the selection of the arbitrator and shall be limited to issues raised in the
pre-hearing filings. The scheduling of further hearings at the request of either
party or on the arbitrator's own motion shall be within the sole discretion of
the arbitrator.

(4) Decision: The arbitrator's decision shall be due, unless the deadline is
extended by mutual agreement of the ISO or the aggrieved Participant and the
Participants Committee, within sixty days of the initial hearing or within
ninety days of the Aggrieved Party's initiation of arbitration, whichever occurs
first. The arbitrator shall be authorized only to interpret and apply the
provisions of this Agreement and the arbitrator shall have no power to modify or
change the Agreement in any manner.

(5) Effect of Arbitration Decision: The decision of the arbitrator will be
conclusive in a subsequent regulatory or legal proceeding as to the facts
determined by the arbitrator but will not be conclusive as to the law or
constitute precedent on issues of law in any subsequent regulatory or legal
proceedings.

An aggrieved party may initiate a proceeding with a court or with the Commission
with respect to the arbitration or arbitrator's decision only:

if the arbitration process does not result in a decision within the time period
specified and the proceeding is initiated within thirty days after the
expiration of such time period; or

on the grounds specified in Sections 10 and 11 of Title 9 of the United States
Code for judicial vacation or modification of an arbitration award and the
proceeding is initiated within thirty days of the issuance of the arbitrator's
decision.

(6) Other Disputes: In the event a dispute arises with a Non-Participant which
receives or is eligible to receive service under this Agreement or the Tariff
with respect to such service, the Non-Participant shall have the right to have
the dispute considered by the Participants Committee. In the event the
Non-Participant is aggrieved by the Participants Committee's vote on the
dispute, and the vote has any of the effects specified in paragraph A of this
Section 21.1, the aggrieved Non-Participant may require that the dispute be
resolved in accordance with this Section 21.1. To the extent that NEPOOL
provides services to Non-Participants under separate agreements, the
Participants Committee shall incorporate the provisions of this Section by
reference in any such agreement, in which case the term "Participant" shall be
deemed for purposes of the dispute resolution provisions to include such
Non-Participant purchasers of NEPOOL services.

21.2  Payment of Pool Charges; Termination of Status as Participant.

(a) Any Participant shall have the right to terminate its status as a
Participant upon no less than six months' prior written notice given to the
Secretary of the Participants Committee.

(b) If at any time during the term of this Agreement a receiver or trustee of a
Participant is appointed or a Participant is adjudicated bankrupt or an order
for relief is entered under the Federal Bankruptcy Code against a Participant or
if there shall be filed against any Participant in any court (pursuant to the
Federal Bankruptcy Code or any statute of Canada or any state or province) a
petition in bankruptcy or insolvency or for reorganization or for appointment of
a receiver or trustee of all or a portion of the Participant's property, and
within ninety days after the filing of such a petition against the Participant,
the Participant shall fail to secure a discharge thereof, or if any Participant
shall file a petition in voluntary bankruptcy or seeking relief under any
provision of any bankruptcy or insolvency law or shall make an assignment for
the benefit of creditors, the Participants Committee may terminate such
Participant's status as a Participant as of any time thereafter.

(c) Each Participant is obligated to pay when due in accordance with NEPOOL
procedures all amounts invoiced to it by NEPOOL, or by the ISO on behalf of
NEPOOL. If the Participant fails to meet this requirement for continuation of
service, the actions described in subsection (d) of this Section 21.2 may be
taken. If a Participant disputes a NEPOOL invoice with respect to charges for
transmission service in whole or part, it shall be entitled to continue to
receive service under the Agreement and the Tariff, so long as the Participant
(i) continues to make all payments not in dispute, and (ii) pays into an
independent escrow account the portion of the invoice in dispute, pending
resolution of the dispute.

(d) In the event a Participant fails to pay when due in accordance with NEPOOL
System Rules (including, without limitation, the NEPOOL Billing Policy attached
to the Tariff (the "Billing Policy")) all amounts invoiced to it by NEPOOL, or
by the ISO on behalf of NEPOOL (a "Payment Default"), or the Participant fails
to comply with the Financial Assurance Policy for NEPOOL Members attached to the
Tariff (the "Member Financial Assurance Policy"), or the Participant fails to
perform any other obligations under the Agreement or the Tariff, and such
failure continues for at least ten days, NEPOOL, or the ISO on behalf of NEPOOL,
may (but shall not be required to) notify such Participant in writing,
electronically and by first class mail sent in each case to such Participant's
member or alternate on the Participants Committee or billing contact, that it is
in default, and NEPOOL may initiate a proceeding before the Commission to
terminate such Participant's status as a Participant. Either simultaneously with
the giving of the notice described in the preceding sentence or within ten days
thereafter (unless the default or failure giving rise to such notice is cured
during such period), NEPOOL, or the ISO on behalf of NEPOOL, shall notify each
other member and alternate on the Participants Committee and each Participant's
billing contact of the identity of the Participant receiving such notice,
whether such notice relates to a Payment Default, to a failure to comply with
the Member Financial Assurance Policy, or to another failure to perform
obligations under the Agreement or the Tariff, and the actions the ISO plans to
take and/or has taken in response to such default or failure. Pending Commission
action on such termination, NEPOOL may suspend service, in whole or part, to the
Participant on or after 50 days after the giving of notice and the initiation of
such proceeding, in accordance with

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Commission policy, unless the Participant cures the default within such 50- day
period.

(e) If the status of a Participant as a Participant is terminated pursuant to
this Section 21.2 or any other provision of this Agreement, such former
Participant's generation and transmission facilities shall continue to be
subject to such NEPOOL or other requirements relating to reliability as the
Commission may approve in acting on the termination, for so long as the
Commission may direct. Further, if any of such former Participant's transmission
facilities are required in order to permit transactions among any of the
remaining Participants pursuant to this Agreement or the Tariff, all pending
requests for transmission service under the Tariff relating to such
Participant's facilities shall be followed to completion under the Participant's
own tariff and all existing service over the Participant's facilities shall
continue to be provided under the Tariff for a period of three years. It is the
intent of this subsection that no such termination should be allowed to
jeopardize the reliability of the bulk power facilities of any remaining
Participant or should be allowed to impose any unreasonable financial burden on
any remaining Participant.

(f) No such termination of a Participant's status as a Participant shall affect
any obligation of, or to, such former Participant incurred prior to the
effective time of such termination.

21.3 Assignment. The Agreement shall inure to the benefit of, and shall be
binding upon, the successors and assigns of the respective signatories hereto,
but no assignment of a signatory's interests or obligations under the Agreement
or any portion thereof shall be made without the written consent of the
Participants Committee, except as otherwise permitted by the Tariff, or except
in connection with a sale, merger, or consolidation which results in the
transfer of all or a portion of a signatory's generation or transmission assets
to, and the assumption of all of the obligations of the signatory under this
Agreement (or in the case of a transfer of a portion of a signatory's generation
or transmission assets, the assumption of obligations of the signatory under
this Agreement with respect to such assets) by, an acquiring or surviving Entity
which either is, or concurrently becomes, a Participant, or agrees to assume
such of the signatory's obligations with respect to such assets as the
Participants Committee may reasonably require, or except in connection with the
grant of a security interest in a Participant's assets as security for bonds or
other financing.

21.4 Force Majeure. A Participant shall not be considered to be in default in
respect of any obligation hereunder if prevented from fulfilling such obligation
by an event of Force Majeure. An event of Force Majeure means any act of God,
labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm
or flood, explosion, breakage or accident to machinery or equipment, any
Curtailment, any order, regulation or restriction imposed by a court or
governmental military or lawfully established civilian authorities, or any other
cause beyond a Participant's control, provided that no event of Force Majeure
affecting any Participant shall excuse that Participant from making any payment
that it is obligated to make under this Agreement. A Participant whose
performance under this Agreement is hindered by an event of Force Majeure shall
make all reasonable efforts to perform its obligations under this Agreement, and
shall promptly notify the Participants Committee of the commencement and end of
any event of Force Majeure.

21.5 Waiver of Defaults. No waiver of the performance by a Participant of any
obligation under this Agreement or with respect to any default or any other
matter arising in connection with this Agreement shall be effective unless given
by the Participants Committee. Any such waiver by the Participants Committee in
any particular instance shall not be deemed a waiver with respect to any
subsequent performance, default or matter.

21.6  Other Contracts. No Participant shall be a party to any other agreement
which in any manner is inconsistent with its obligations under this Agreement.

21.7  Liability and Insurance.

(a) Each Participant will indemnify and save each of the other Participants, its
officers, directors and Related Persons (each an "Indemnified Party") harmless
from and against all actions, claims, demands, costs, damages and liabilities
asserted by a third party against the Indemnified Party seeking indemnification
and arising out of or relating to bodily injury, death or damage to property
caused by or sustained on facilities owned or controlled by such Participant
that are the subject of this Agreement, or caused by a failure to act in
accordance with this Agreement by the Participant from which indemnification is
sought, except (i) to the extent that such liabilities result from the
negligence or willful misconduct of the Participant seeking indemnification, and
(ii) each Participant shall be responsible for all claims of its own employees,
agents and servants growing out of any workmen's compensation law. The amount of
any indemnity payment under the provisions of this Section 21.7 shall be reduced
(including, without limitation, retroactively) by any insurance proceeds or
other amounts actually recovered by the Indemnified Party in respect of the
indemnified action, claim, demand, cost, damage or liability. Notwithstanding
the foregoing, no Participant shall be liable to any Indemnified Party for any
claim for loss of profits or revenues, attorneys' fees or costs, cost of capital
or financing, loss of goodwill or cost of replacement power arising from a
Participant's carrying out, or failing to carry out, any obligations
contemplated by this Agreement or for any other indirect, incidental, special,
consequential, punitive, or multiple damages or loss; provided, however, that
nothing herein shall reduce or limit the obligations of any Participant to
Non-Participants.

(b) Each Participant shall furnish, at its sole expense, such insurance coverage
as the Participants Committee may reasonably require with respect to its
obligation pursuant to Section 21.7(a).

21.8 Records and Information. Each Participant shall keep such records as may
reasonably be required by a NEPOOL committee or the System Operator, and shall
furnish to such committee or the System Operator such records, reports and
information (including forecasts) as it may reasonably require, provided the
confidentiality thereof is protected in accordance with NEPOOL's information
policy.

21.9 Consistency with NPCC and NERC Standards. The standards, criteria and rules
adopted by NEPOOL committees under this Agreement shall be consistent with those
adopted by the NPCC and NERC or any successor to either.

21.10  Construction.

(a) The Table of Contents contained in this Agreement and the headings of the
Sections of this Agreement are intended for convenience only and shall not be
deemed to be part of this Agreement or considered in construing it.

(b) This Agreement shall be interpreted, construed and governed in accordance
with the laws of the State of Connecticut.

21.11 Amendment. Subject to Section 17A and the provisions of this Section, this
Agreement, including the Tariff, and any attachment or exhibit hereto may be
amended from time to time by vote of the Participants in accordance with Section
6.11.

Any amendment to this Agreement approved in accordance with Section 6.11 and/or
Section 17A shall be in writing and shall become effective, and shall bind all
Participants regardless of whether they have executed a ballot in favor of such
amendment, on the date specified in the amendment, subject to acceptance or
approval by the Commission. Nothing herein shall be construed to prevent any
Participant from challenging any proposed amendment before a court or regulatory
agency on the ground that the proposed amendment or its application to the
Participant is in violation of law or of this Agreement.

21.12 Termination. This Agreement shall continue in effect until terminated, in
accordance with the Commission's regulations, by Participants represented by
members of the Participants Committee having Member Fixed Voting Shares equal to
at least 70% of the Member Fixed Voting Shares of all Participants. No such
termination shall relieve any party of any obligation arising prior to the
effective time of such termination.

21.13  Notices to Participants, Committees, Committee Members, or the
System Operator.

(a) Any notice, demand, request or other communication required or authorized by
this Agreement to be given to any Participant shall be in writing, and shall be
(1) personally delivered to the Participants Committee member or alternate
representing that Participant; (2) mailed, postage prepaid, to the Participant
at the address of its member on the Participants Committee as set out in the
NEPOOL roster; (3) sent by facsimile ("faxed") to the Participant at the fax
number of its member on the Participants Committee as set out in the NEPOOL
roster; or (4) delivered electronically to the Participant at the electronic
mail address of its member on the Participants Committee or at the address of
its principal office. The designation of any such address may be changed at any
time by written notice delivered to the Secretary of the Participants Committee,
who shall cause such change to be reflected in the NEPOOL roster.

(b) Any notice, demand, request or other communication required or authorized by
this Agreement to be given to any NEPOOL committee shall be in writing and shall
be delivered to the Secretary of the committee. Each such notice shall either be
personally delivered to the Secretary, mailed, postage prepaid, or sent by
facsimile ("faxed") to the Secretary at the address or fax number set out in the
NEPOOL roster, or delivered electronically to the Secretary. The designation of
such address may be changed at any time by written notice delivered to each
Participant.

(c) Any notice, demand, request or other communication required or authorized by
this Agreement to be given to a member or alternate to that member of a
Principal Committee (for the purposes of this Section 21.13, individually or
collectively, the "Committee Member") shall be (1) personally delivered to the
Committee Member; (2) mailed, postage prepaid, to the Committee Member at the
address of the Committee Member set out in the NEPOOL roster; (3) sent by
facsimile ("faxed") to the Committee Member at the fax number of the Committee
Member set out in the NEPOOL roster; or (4) delivered electronically to the
Committee Member at the electronic mail address of the Committee Member set out
in the NEPOOL roster. The designation of any such address may be changed at any
time by written notice delivered to the Secretary of the Principal Committee on
which the Committee Member serves, who shall cause such change to be reflected
in the NEPOOL roster.

(d) Any notice, demand, request or other communication required or authorized by
this Agreement to be given to the System Operator shall be in writing, and shall
be (1) personally delivered to the Participants Committee member or alternate
appointed by the System Operator; (2) mailed, postage prepaid, to the System
Operator at the address of its member on the Participants Committee as set out
in the NEPOOL roster; (3) sent by facsimile ("faxed") to the System Operator at
the fax number of its member on the Participants Committee as set out in the
NEPOOL roster; or (4) delivered electronically to the System Operator at the
electronic mail address of its member on the Participants Committee or at the
address of its principal office. The designation of any such address may be
changed at any time by written notice delivered to the Secretary of the
Participants Committee, who shall cause such change to be reflected in the
NEPOOL roster.

(e) To the extent that the Participants Committee is required to serve upon any
Participant a copy of any document or correspondence filed with the Commission
under the Federal Power Act or the Commission's rules and regulations
thereunder, by or on behalf of any Principal Committee, such service may be
accomplished by electronic delivery to the Participant at the electronic mail
address of its Participants Committee member and alternate. The designation of
any such address may be changed at any time by written notice delivered to the
Secretary of the Participants Committee.

(f) Any such notice, demand or request so addressed and mailed by registered or
certified mail shall be deemed to be given when so mailed. Any such notice,
demand, request or other communication sent by regular mail or by facsimile
("faxed") or delivered electronically shall be deemed given when received by the
Participant, Committee Member, System Operator, or Secretary of the NEPOOL
committee, whichever is applicable.

21.14 Severability and Renegotiation. If any provision of this Agreement is held
by a court or regulatory authority of competent jurisdiction to be invalid, void
or unenforceable, the remainder of the terms, provisions, covenants and
restrictions of this Agreement shall continue in full force and effect and shall
in no way be affected, impaired or invalidated, except as otherwise explicitly
provided in this Section.

If any provision of this Agreement is held by a court or regulatory authority of
competent jurisdiction to be invalid, void or unenforceable, or if the Agreement
is modified or conditioned by a regulatory authority exercising jurisdiction
over this Agreement, the Participants shall endeavor in good faith to negotiate
such amendment or amendments to this Agreement as will restore the relative
benefits and obligations of the Participants under this Agreement immediately
prior to such holding, modification or condition. If after sixty days such
negotiations are unsuccessful the Participants may exercise their withdrawal or
termination rights under this Agreement.

21.15 No Third-Party Beneficiaries. Except for the provisions of this Agreement
and the Tariff which provide for service to Non-Participants, this Agreement is
intended to be solely for the benefit of the Participants and their respective
successors and permitted assigns and, unless expressly stated herein, is not
intended to and shall not confer any rights or benefits on any third party
(other than successors and permitted assigns) not a signatory hereto.

21.16 Counterparts. This Agreement may be executed in any number of
counterparts, and each executed counterpart shall have the same force and effect
as an original instrument and as if all the parties to all of the counterparts
had signed the same instrument. Any signature page of this Agreement may be
detached from any counterpart of this Agreement without impairing the legal
effect of any signatures thereon, and may be attached to another counterpart of
this Agreement identical in form hereto but having attached to it one or more
signature pages.

IN WITNESS WHEREOF, the signatories have caused this Agreement to be executed by
their duly authorized officers or representatives.


Sheet Nos. 279 through 299 are reserved for future use.



                                  ATTACHMENT A

                                 METHODOLOGY FOR
                                DETERMINATION OF
                               TRANSMISSION FLOWS

The methodology for determining parallel path transmission flows to be used in
determining the distribution of revenues received for Regional Network Service
provided during the Transition Period, or for Through or Out Service, is as
follows, and shall be determined (1) on the basis of the flows for all
transactions in the NEPOOL Control Area ("Regional Flows") for the purpose of
allocating during the Transition Period Regional Network Service revenues, and
(2) on the basis of the flows for the particular transaction ("Transaction
Flows") for the purpose of allocating revenues during or after the Transition
Period from the furnishing of Through or Out Service:

A.  Responsibility for Calculations

The calculation of megawatt mile allocations in accordance with this methodology
shall be performed under the direction of the Reliability Committee.

B.  Periodic Review

Calculations of MW-Mile allocations shall be performed whenever significant
changes to the transmission system load flows, as determined by the Reliability
Committee, occur.

C.  Facilities Included in the Analysis

1.  Transmission Lines

A calculation of MW-miles shall be determined for all PTF lines.

2.  Generators

The analysis shall include all generators with a Winter Capability equal to or
greater than 10.0 MW. Multiple generators connected to a single bus with a total
Winter Capability equal to or greater than 10.0 MW shall also be included.

3.  Transformers

All transformers connecting PTF transmission lines shall be included in the
analysis.

D.  Determination of Rate Distribution

1.  General

Modeling of the transmission system shall be performed using a system simulation
program and associated cases as approved by the Reliability Committee.

2.  Determination of Regional Flows

The change in real power flow (MW) over each transmission line and transformer
shall be determined for each generator (or group of generators on a single bus)
by determining the absolute value of the difference between the flows on each
facility with the generator(s) modeled off and while operating at its net Winter
Capability. In addition, a generator shall be simulated at each transmission
line tie to the NEPOOL Control Area and changes in flow determined for this
generator off or while generating at a level of 100 MW. Loads throughout the
NEPOOL Control Area shall be proportionally scaled to account for differences in
generator output and electrical losses. The changes in flow shall be multiplied
by the length of each respective line. Changes in flow through transformers
shall be multiplied by a factor of five. Changes in flow through phase-shifting
transformers shall be multiplied by a factor of ten. The resulting values
represent the MW-miles associated with each facility.

3.  Determination of Transaction Flows

a.  Definition of Supply and Receipt Areas

For the purposes of these calculations, areas of supply and receipt shall be
determined by the Reliability Committee.

These areas shall be based on the system boundaries of each Local Network.

b.  Calculation of MW-Miles

The change in real power flow (MW) over each transmission line and transformer
shall be determined for each combination of supply and receipt areas by
determining the absolute value of the difference between the flows on each
facility following a scaled increase of the supplying areas generation by 100
MW. Loads in the area of receipt shall be scaled to account for changes in
generation and electrical losses. In instances where the areas of supply and/or
receipt are outside the NEPOOL Control Area, the changes in real power flow will
be determined only for facilities within the NEPOOL Control Area. The changes in
flow shall then be multiplied by the length of each respective line. Changes in
flow through transformers shall be multiplied by a factor of five.

Changes in flow through phase-shifting transformers shall be multiplied by a
factor of ten. The resulting values represent the MW-miles associated with each
facility.

4.  Assignment of MW-Miles to Participants

Each Participant shall have assigned to it the MW-miles associated with each PTF
facility for which it has full ownership and for which there are no arrangements
in effect by which other Participants support the facility. For facilities that
are jointly owned and/or supported, each Participant shall be assigned MW-miles
in proportion to the percentage of its ownership of jointly-owned facilities
and/or the percentage of its support for facilities that are jointly supported
to the extent such support payments are included in the determination of Annual
Transmission Revenue Requirements


                                  ATTACHMENT B

                   NEPOOL OPEN ACCESS TRANSMISSION TARIFF

               See FERC Electric Tariff, Fourth Revised Volume 1.




                                  ATTACHMENT C

                               RELIABILITY REGIONS

<PAGE>


                             NEW ENGLAND POWER POOL


                           RESTATED NEPOOL OPEN ACCESS
                               TRANSMISSION TARIFF


           FERC ELECTRIC TARIFF, FOURTH REVISED VOLUME NO. 1







             (As amended through the Sixty-Ninth Agreement
               Amending New England Power Pool Agreement)




I.     COMMON SERVICE PROVISIONS
1     Definitions
1.1     Administrative Costs
1.2     Agreement
1.3     Ancillary Services
1.4     Annual Transmission Revenue Requirements
1.5     Application
1.6     ARR
1.7     ARR Allocation
1.8     Auction Revenue Right
1.9     Auction Revenue Right Holder
1.10     Backyard Generation
1.11     Business Day
1.12     CMS
1.13     CMS/MSS Effective Date
1.14     Commission
1.15     Completed Application
1.16     Compliance Effective Date
1.17     Congestion
1.18     Congestion Component
1.19     Congestion Cost
1.20     Congestion Paying Entity
1.21     Congestion Revenue
1.22     Congestion Revenue Fund
1.23     Congestion Revenue Shortfall
1.24     Congestion Revenue Surplus
1.25     Control Area
1.26     Curtailment
1.27     Day-Ahead
1.28     Day-Ahead Market
1.29     Delivering Party
1.30     Demand Bid
1.31     Demand Bid Price
1.32     Designated Agent
1.33     Direct Assignment Facilities
1.34     Direct Interconnection Transmission Costs
1.35     Dispatch Day
1.36     Distribution Company
1.37     Distribution Company Load Zone
1.38     Economic Upgrade
1.39     Elective Transmission Upgrade
1.40     Eligible Customer
1.41     Energy
1.42     Energy Imbalance Service
1.43     Entitlement
1.44     Excepted Transaction
1.45     External Node
1.46     Facilities Study
1.47     FCR
1.48     FCR Auction
1.49     FCR Auction Revenue
1.50     FCR Auction Revenue Fund
1.51     FCR Holder
1.52     FCR Payment
1.53     Financial Congestion Right
1.54     Firm Contract
1.55     Firm Point-To-Point Transmission Service
1.56     Firm Transmission Service
1.57     Generator Interconnection Related Upgrade
1.58     Generator Owner
1.59     Good Utility Practice
1.60     Hub
1.61     Hub Price
1.62     HQ Interconnection
1.63     HQ Phase II Firm Energy Contract
1.64     Import Transaction
1.65     Interchange Transactions
1.66     Interest
1.67     Internal Point-to-Point Service
1.68     Internal Point-to-Point Service Rate
1.69     Interruption
1.70     ISO
1.71     Load Asset Contract
1.72     Load Ratio Share
1.73     Load Shedding
1.74     Load Zone
1.75     Local Network
1.76     Local Network Service
1.77     Local Point-To-Point Service
1.78     Location
1.79     Locational Price
1.80     Long-Term Firm Service
1.81     Marginal Loss
1.82     Marginal Loss Component
1.83     Marginal Loss Revenue
1.84     Marginal Loss Revenue Fund
1.85     Market Rules
1.85     A Merchant Transmission Facility
1.86     Minimum Interconnection Standard
1.87     Monthly Network Load
1.88     Monthly Peak
1.89     Monthly Peak Load
1.90     Native Load Customers
1.91     NEMA
1.92     NEMA ARRs
1.93     NEMA Contract
1.94     NEMA LSE
1.95     NEMA or "Northeast Massachusetts" Upgrade
1.96     NEPOOL
1.97     NEPOOL Control Area
1.98     NEPOOL System Rules
1.99     NEPOOL Transmission Plan
1.100     NEPOOL Transmission System
1.101     NERC
1.102     Network Customer
1.103     Network Integration Transmission Service
1.104     Network Load
1.105     Network Operating Agreement
1.106     Network Operating Committee
1.107     Network Resource
1.108     Network Upgrades
1.109     Nodal Price
1.110     Node
1.111     Non-Firm Point-To-Point Transmission Service
1.112     Non-Participant
1.113     Non-PTF
1.114     Northeast Massachusetts Upgrade
1.115     NPCC
1.116 Open Access Same-Time Information System (OASIS) 1.117 Operating Reserve -
10-Minute Non-Spinning Reserve Service 1.118 Operating Reserve - 10-Minute
Spinning Reserve Service 1.119 Operating Reserve - 30-Minute Reserve Service
1.120 Participant 1.121 Participant RNS Rate 1.122 Participants Committee 1.123
Point(s) of Delivery 1.124 Point(s) of Receipt 1.125 Point-To-Point Transmission
Service 1.126 Pool-Planned Unit 1.127 Pool PTF Rate 1.128 Pool RNS Rate 1.129
Pool-Supported PTF 1.130 Power Purchaser 1.131 Prior NEPOOL Agreement 1.132 PTF
or Pool Transmission Facilities 1.133 Pre-1997 PTF Rate 1.134 Publicly Owned
Entity 1.135 Quick Fix Upgrade 1.136 Reactive Supply and Voltage Control From
Generation Sources Service 1.137 Real-Time 1.138 Real-Time Market 1.139
Receiving Party 1.140 Reference Node 1.141 Regional Network Service 1.142
Regulation and Frequency Response Service 1.143 Reliability Region 1.144
Reliability Upgrade 1.145 Reserved Capacity 1.146 Scheduling, System Control and
Dispatch Service 1.147 Second Effective Date 1.148 Service Agreement 1.149
Service Commencement Date 1.150 Settlement Obligation 1.151 Shift Factor 1.152
Short-Term Firm Service 1.153 Standard Offer Obligation 1.154 Supply Obligation
1.155 Supply Offer 1.156 System Contract 1.157 System Impact Study 1.158 System
Operator 1.159 Target FCR Payment 1.160 Tariff 1.161 Third-Party Sale 1.162
Through or Out Service 1.163 Third Effective Date 1.164 Ties 1.165 Transition
Period 1.166 Transmission Customer 1.167 Transmission Owner 1.168 Transmission
Owners Committee 1.169 Transmission Provider 1.170 Transmission System Upgrade
1.171 Unit Contract 1.172 Use 1.173 Withdrawal Factor 1.174 Year 1.175 Zonal
Price 2 Purpose of This Tariff 3 Initial Allocation and Renewal Procedures 3.1
Initial Allocation of Available Transmission Capability 3.2 Reservation Priority
for Existing Firm Service Customers 3.3 Initial Election of Optional Internal
Point-to-Point Service 4 Ancillary Services 4.1 Scheduling, System Control and
Dispatch Service 4.2 Reactive Supply and Voltage Control from Generation Sources
Service 4.3 Regulation and Frequency Response Service 4.4 Energy Imbalance
Service 4.5 Operating Reserve - 10-Minute Spinning Reserve Service 4.6 Operating
Reserve - 10-Minute Non-Spinning Reserve Service 4.7 Operating Reserve -
30-Minute Reserve Service 4.8 System Restoration and Planning Service 5 Open
Access Same-Time Information System (OASIS) 6 Local Furnishing and Other
Tax-Exempt Bonds 6.1 Participants That Own Facilities Financed by Local
Furnishing or Other Tax-Exempt Bonds 6.2 Alternative Procedures for Requesting
Transmission Service - Local Furnishing Bonds 6.3 Alternative Procedures for
Requesting Transmission Service - Other Tax-Exempt Bonds 7 Reciprocity 8 Billing
and Payment; Accounting 8.1 Participant Billing Procedure 8.2 Non-Participant
Billing Procedure 8.3 Interest on Unpaid Balances 8.4 Customer Default 8.5 Study
Costs and Revenues 9 Regulatory Filings 10 Force Majeure and Indemnification
10.1 Force Majeure 10.2 Indemnification 11 Creditworthiness 12 Dispute
Resolution Procedures 12.1 Internal Dispute Resolution Procedures 12.2 Rights
Under The Federal Power Act 13 Stranded Costs 13.1 General 13.2 Commission
Requirements 13.3 Wholesale Contracts 13.4 Right to Seek or Contest Recovery
Unimpaired II. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION
SERVICE) 14 Nature of Regional Network Service 14.1 Rules for Import
Transactions Conducted in Conjunction with Regional Network Service: 15
Availability of Regional Network Service 15.1 Provision of Regional Network
Service 15.2 Eligibility to Receive Regional Network Service 16 Payment for
Regional Network Service 17 Procedure for Obtaining Regional Network Service
III. THROUGH OR OUT SERVICE; INTERNAL POINT-TO-POINT SERVICE 18 Through or Out
Service 18.1 Provision of Through or Out Service 18.2 Use of Through or Out
Service 19 Internal Point-to-Point Service 19.1 Provision of Internal
Point-to-Point Service 19.2 Use of Internal Point-to-Point Service 19.3 Use by a
Transmission Customer 20 Payment for Through or Out Service 21 Payment for
Internal Point-to-Point Service 22 Reservation of Capacity for Point-to-Point
Transmission Service IV. SERVICE DURING THE TRANSITION PERIOD; CONGESTION COSTS;
EXCEPTED TRANSACTIONS 23 Transition Arrangements 24 Congestion Costs and
Congestion Revenue 25 Excepted Transactions 25A Phase I Credit and Uplift Charge
With Respect to Excepted Transactions 25B Phase II Credit and Uplift Charge With
Respect to Certain Excepted Transactions V. POINT-TO-POINT TRANSMISSION SERVICE
Preamble 26 Scope of Application of Part V 27 Nature of Firm Point-To-Point
Transmission Service 27.1 Term 27.2 Reservation Priority 27.3 Use of Firm
Point-To-Point Transmission Service by the Participants That Own PTF 27.4
Service Agreements 27.5 Transmission Customer Obligations for Facility Additions
or Redispatch Costs 27.6 Curtailment of Firm Transmission Service 27.7
Classification of Firm Point-To-Point Transmission Service 27.8 Scheduling of
Firm Point-To-Point Transmission Service 28 Nature of Non-Firm Point-To-Point
Transmission Service 28.1 Term 28.2 Reservation Priority 28.3 Use of Non-Firm
Point-To-Point Transmission Service by the Transmission Provider 28.4 Service
Agreements 28.5 Classification of Non-Firm Point-To-Point Transmission Service
28.6 Scheduling of Non-Firm Point-To-Point Transmission Service 28.7 Curtailment
or Interruption of Service 29 Service Availability 29.1 General Conditions 29.2
Determination of Available Transmission Capability 29.3 Initiating Service in
the Absence of an Executed Service Agreement 29.4 Obligation to Provide
Transmission Service that Requires Expansion or Modification of the Transmission
System 29.5 Deferral of Service 29.6 Real Power Losses 29.7 Load Shedding 30
Transmission Customer Responsibilities 30.1 Conditions Required of Transmission
Customers 30.2 Transmission Customer Responsibility for Third-Party Arrangements
31 Procedures for Arranging Firm Point-To-Point Transmission Service 31.1
Application 31.2 Completed Application 31.3 Deposit 31.4 Notice of Deficient
Application 31.5 Response to a Completed Application 31.6 Execution of Service
Agreement 31.7 Extensions for Commencement of Service 32 Procedures for
Arranging Non-Firm Point-To-Point Transmission Service 32.1 Application 32.2
Completed Application 32.3 Reservation of Non-Firm Point-To-Point Transmission
Service 32.4 Determination of Available Transmission Capability 33 Additional
Study Procedures For Firm Point-To-Point Transmission Service Requests 33.1
Notice of Need for System Impact Study 33.2 System Impact Study Agreement and
Cost Reimbursement 33.3 System Impact Study Procedures 33.4 Facilities Study
Procedures 33.5 Facilities Study Modifications 33.6 Due Diligence in Completing
New Facilities 33.7 Partial Interim Service 33.8 Expedited Procedures for New
Facilities 34 Procedures if New Transmission Facilities for Firm Point-To-Point
Transmission Service Cannot be Completed 34.1 Delays in Construction of New
Facilities 34.2 Alternatives to the Original Facility Additions 34.3 Refund
Obligation for Unfinished Facility Additions 35 Provisions Relating to
Transmission Construction and Services on the Systems of Other Utilities 35.1
Responsibility for Third-Party System Additions 35.2 Coordination of Third-Party
System Additions 36 Changes in Service Specifications 36.1 Modifications on a
Non-Firm Basis 36.2 Modification on a Firm Basis 37 Sale, Assignment or Transfer
of Transmission Service 37.1 Procedures for Sale, Assignment or Transfer of
Service 37.2 Limitations on Assignment or Transfer of Service 37.3 Information
on Assignment or Transfer of Service 38 Metering and Power Factor Correction at
Receipt and Delivery Points(s) 38.1 Transmission Customer Obligations 38.2
NEPOOL Access to Metering Data 38.3 Power Factor 39 Compensation for New
Facilities and Redispatch Costs VI. REGIONAL NETWORK SERVICE (NETWORK
INTEGRATION TRANSMISSION SERVICE) 40 Nature of Regional Network Service 40.1
Scope of Service 40.2 Transmission Provider Responsibilities 40.3 Network
Integration Transmission Service 40.4 Secondary Service 40.5 Real Power Losses
40.6 Restrictions on Use of Service 41 Initiating Service 41.1 Condition
Precedent for Receiving Service 41.2 Application Procedures 41.3 Technical
Arrangements to be Completed Prior to Commencement of Service 41.4 Network
Customer Facilities 41.5 Filing of Service Agreement 42 Network Resources 42.1
Designation of Network Resources 42.2 Designation of New Network Resources 42.3
Termination of Network Resources 42.4 Network Customer Redispatch Obligation
42.5 Transmission Arrangements for Network Resources Not Physically
Interconnected With The NEPOOL Transmission System 42.6 Limitation on
Designation of Resources 42.7 Use of Interface Capacity by the Network Customer
43 Designation of Network Load 43.1 Network Load 43.2 New Network Loads
Connected With the NEPOOL Transmission System 43.3 Network Load Not Physically
Interconnected with the NEPOOL Transmission System 43.4 New Interconnection
Points 43.5 Changes in Service Requests 43.6 Annual Load and Resource
Information Updates 44 Additional Study Procedures For Network Integration
Transmission Service Requests 44.1 Notice of Need for System Impact Study 44.2
System Impact Study Agreement and Cost Reimbursement 44.3 System Impact Study
Procedures 44.4 Facilities Study Procedures 45 Load Shedding and Curtailments
45.1 Procedures 45.2 Transmission Constraints 45.3 Cost Responsibility for
Relieving Transmission Constraints 45.4 Curtailments of Scheduled Deliveries
45.5 Allocation of Curtailments 45.6 Load Shedding 45.7 System Reliability 46
Rates and Charges 46.1 Determination of Network Customer's Monthly Network Load
47 Operating Arrangements 47.1 Operation under The Network Operating Agreement
47.2 Network Operating Agreement 47.3 Network Operating Committee 48 Scope of
Application of Part VI to Participants VII. TRANSMISSION PLANNING, ADDITIONS AND
MODIFICATIONS 49 General 50 Interconnection Procedures and Requirements 50.1
Interconnection of Generating Unit Under the Minimum Interconnection Standard
50.2 Interconnection of Elective Transmission Upgrades 51 Regional Transmission
Planning and Expansion 51.1 General 51.2 Responsibilities of the Transmission
Expansion Advisory Committee, Transmission Planning Committee and System
Operator 51.3 NEPOOL Transmission Plan: Principles, Scope, and Contents 51.4
Procedures for Developing a NEPOOL Transmission Plan 51.5 Procedures for the
Conduct of Enhancement and Expansion Studies 51.6 Request for Proposals ("RFP")
Process For Upgrades 51.7 Obligations of Transmission Owners to Build 51.8
Merchant Transmission Facilities; Compliance 51.9 Alternative Remedies 52 "Quick
Fix" Measures SCHEDULE 1 Scheduling, System Control and Dispatch Service
SCHEDULE 2 Reactive Supply and Voltage Control from Generation Sources Service
SCHEDULE 3 Regulation and Frequency Response Service (Automatic Generation
Control) SCHEDULE 4 Energy Imbalance Service SCHEDULE 5 Operating Reserve -
10-Minute Spinning Reserve Service SCHEDULE 6 Operating Reserve - 10-Minute
Non-Spinning Reserve Service SCHEDULE 7 Operating Reserve - 30-Minute Reserve
Service SCHEDULE 8 Through or Out Service - The Pool PTF Rate SCHEDULE 9
Regional Network Service SCHEDULE 10 Internal Point-to-Point Service SCHEDULE 11
Generator Interconnection Related Upgrade Costs SCHEDULE 12 Reliability Upgrade,
Economic Upgrade and Elective Transmission Upgrade Costs SCHEDULE 13 Locational
Prices; Congestion Cost; Congestion Revenue; Marginal Loss Cost; Marginal Loss
Revenue
     A.     Calculation of Locational Prices
B.     Congestion Cost
C.     Congestion Revenue
D.     Marginal Loss Cost and Marginal Loss Revenue
E.     Additional Rules and Procedures
SCHEDULE 14  Financial Congestion Rights ("FCRs")
A.     FCR Holder Status and Transfer of FCRs
     B.     FCR Designation and Simultaneous Feasibility
     C.     FCR Payments
     D.     FCR Settlements
     E.     Congestion Revenue Shortfalls or Surpluses
     F.     FCR Auctions
     G.     FCRs as Options
     H.     Additional Rules and Procedures
SCHEDULE 15  Auction Revenue Rights
     A.     First Stage of ARR Allocation
     B.     Second Stage of ARR Allocation
     C.     Third Stage of ARR Allocation
     D.     Fourth Stage of ARR Allocation
     E.     Payments to ARR Holders
     F.     Annual and Monthly ARR Adjustments
     G.     Incremental ARRs
     H     Additional Rules and Procedures
SCHEDULE 16 System Restoration and Planning Service from Generators ATTACHMENT A
Form of Service Agreement for Through or Out Service or Internal Point-To-Point
Service ATTACHMENT B Form Of Service Agreement For Regional Network Service
ATTACHMENT C Methodology To Assess Available Transmission Capability ATTACHMENT
D Methodology for Completing a System Impact Study ATTACHMENT E Local Networks
ATTACHMENT F Annual Transmission Revenue Requirements ATTACHMENT G: List of
Excepted Transaction Agreements ATTACHMENT G-1: List of Excepted Agreements
ATTACHMENT G-2: List of Certain Arrangements over External Ties ATTACHMENT H
Form of Network Operating Agreement ATTACHMENT I Form of System Impact Study
Agreement ATTACHMENT J Form of Facilities Study Agreement ATTACHMENT K 1997
Twelve CP Network Load Data NEPOOL 1997 12 CP Network Load ATTACHMENT L
Financial Assurance Policy for NEPOOL Members ATTACHMENT M Financial Assurance
Policy for NEPOOL Non-Participant Transmission Customers ATTACHMENT N New
England Power Pool Billing Policy IMPLEMENTATION RULE - SCHEDULE 1 Scheduling,
System Control and Dispatch Service IMPLEMENTATION RULE - SCHEDULE 2 Reactive
Supply and Voltage Control from Generation Sources Service IMPLEMENTATION RULE -
ATTACHMENT F Annual Transmission Revenue Requirements



I.     COMMON SERVICE PROVISIONS

1     Definitions

Whenever used in this Tariff, in either the singular or the plural number, the
terms contained in this Section shall have the meanings set forth herein. If a
term includes language in brackets ([ ]), such language shall become effective
automatically on the CMS/MSS Effective Date. Certain definitions and language
within definitions are included in braces ({ }). Such definitions and language
are still subject to further modification or deletion and will not become
effective except pursuant to a further Commission order. To the extent
appropriate to reflect the understandings of this introductory text, future
composite copies of this Tariff may remove brackets ([ ]), braces ({ }) and text
included therein, and this explanatory introductory language, and may renumber
the definitions, without further specific amendment to or restatement of this
Tariff. Terms used in this Tariff that are not defined in this Tariff shall have
the meanings customarily attributed to such terms by the electric utility
industry in New England.

1.1  Administrative Costs:  Those costs incurred in connection with the
review of Applications for transmission service and the carrying out of
System Impact Studies and Facilities Studies.

1.2 Agreement: The Restated New England Power Pool Agreement dated as of
September 1, 1971, as amended and restated from time to time, of which this
Tariff forms a part.

1.3 Ancillary Services: Those services that are necessary to support the
transmission of electric capacity and energy from resources to loads while
maintaining reliable operation of the NEPOOL Transmission System in accordance
with Good Utility Practice.

1.4 Annual Transmission Revenue Requirements: The annual revenue requirements of
a Participant's PTF or of all Participants' PTF for purposes of this Tariff
shall be the amount determined in accordance with Attachment F to this Tariff.

1.5  Application:  A written request by an Eligible Customer for transmission
service pursuant to the provisions of this Tariff.

1.6   ARR:  An Auction Revenue Right.

1.7  ARR Allocation:  The allocation of ARRs described in Schedule 15.

1.8  Auction Revenue Right:  The right to receive FCR Auction Revenues in
accordance with Schedule 15 and Section 49 of the Tariff.

1.9  Auction Revenue Right Holder:  An entity which is the record holder of
an Auction Revenue Right in the register maintained by the System Operator.

1.10 Backyard Generation: Generation which interconnects directly with
distribution facilities dedicated solely to load not designated as Network Load.
Any distribution facilities which are shared with Network Load will not qualify.

1.11  Business Day:  Any day other than a Saturday or Sunday or a national or
Massachusetts holiday.

1.12 CMS: The Congestion management system under the NEPOOL arrangements,
including Locational Prices for Energy and Financial Congestion Rights.

1.13 CMS/MSS Effective Date: The date on which the provisions of Section 14A of
the Agreement shall become fully effective and supersede the provisions of
Section 14 of the Agreement. The CMS/MSS Effective Date shall be a date fixed by
the Participants Committee which occurs after NEPOOL System Rules and computer
programs to fully implement Section 14A of the Agreement and Schedules 13, 14
and 15 of the Tariff are in place and at least thirty (30) days have elapsed
since the Participants Committee has provided notice to the Commission of the
proposed CMS/MSS Effective Date.

1.14  Commission:  The Federal Energy Regulatory Commission.

1.15  Completed Application:  An Application that satisfies all of the
information and other requirements of this Tariff, including any required
deposit.

1.16  Compliance Effective Date:  October 1, 1998.

1.17 Congestion: A condition of the NEPOOL Transmission System in which
transmission limitations prevent unconstrained regional economic dispatch of the
power system. Following the CMS/MSS Effective Date, Congestion is the condition
that results in the Congestion Component of the Locational Price at one Location
being different from the Congestion Component of the Locational Price at another
Location during any given hour of the Dispatch Day in the Day-Ahead Market and
Real-Time Market.

1.18 Congestion Component: The component of the Nodal Price that reflects the
marginal cost of Congestion at a given Node or External Node relative to the
Reference Node. When used in connection with Zonal Price and Hub Price, the term
Congestion Component refers to the Congestion Components of the Nodal Prices
that comprise the Zonal Price and Hub Price averaged or weighted in the same way
that Nodal Prices are averaged or weighted to determine the Zonal Price and Hub
Price, respectively.

1.19 Congestion Cost: The cost of Congestion as defined in Section 14.14 of the
Agreement and Section 24 of the Tariff for services until the CMS/MSS Effective
Date. On and after the CMS/MSS Effective Date, Congestion Cost is the cost of
Congestion as measured by the difference between the Congestion Components of
the Locational Prices at different Locations and/or Reliability Regions on the
NEPOOL Transmission System.

1.20 Congestion Paying Entity: For the purpose of the allocation of FCR Auction
Revenues to ARR Holders as provided for in Schedule 15, a Participant, other
than a Transmission Customer, that is responsible for paying for both (i) the
Congestion Cost associated with supplying Energy to serve load, and (ii) the RMR
Charge for RMR Uplift (as defined in Section 14A.19 of the Agreement) associated
with serving load. The term Congestion Paying Entity shall be deemed to include,
but not be limited to, the Load Asset Contract purchaser.

1.21 Congestion Revenue: For each hour is the surplus revenue, if any, for each
hour after netting the revenues paid and collected for the Congestion Components
of Locational Price for all Energy transactions on the NEPOOL Transmission
System, including Energy deliveries by Non-Participant Transmission Customers
taking service under the Tariff, as settled in accordance with the Market Rules.
Congestion Revenue is calculated for each hour of the Dispatch Day in the
Day-Ahead Market and Real-Time Market as provided in Section E of Schedule 14 of
the Tariff and the applicable Market Rules.

1.22 Congestion Revenue Fund: The fund of Congestion Revenue administered by the
System Operator in accordance with Section 14A.17 of the Agreement, Schedules 13
and 14 of the Tariff, and the applicable Market Rules.

1.23 Congestion Revenue Shortfall: The amount, if any, by which Congestion
Revenues collected by the System Operator in a month are less than the sum of
the Target FCR Payments for that month. A Congestion Revenue Shortfall is
managed in accordance with Schedule 14.

1.24 Congestion Revenue Surplus: The amount, if any, by which Congestion
Revenues collected by the System Operator in a month exceed the sum of the
Target FCR Payments for that month. A Congestion Revenue Surplus is managed in
accordance with Schedule 14.

1.25  Control Area:  An electric power system or combination of electric
power systems to which a common automatic generation control scheme is
applied in order to:

(1) match, at all times, the power output of the generators within the electric
power system(s) and capacity and energy purchased from entities outside the
electric power system(s), with the load within the electric power system(s);

(2)   maintain scheduled interchange with other Control Areas, within the
limits of Good Utility Practice;

(3) maintain the frequency of the electric power system(s) within reasonable
limits in accordance with Good Utility Practice and the criteria of the
applicable regional reliability council or the North American Electric
Reliability Council; and

(4) provide sufficient generating capacity to maintain operating reserves in
accordance with Good Utility Practice.

1.26 Curtailment: A reduction in firm or non-firm transmission service in
response to a transmission capacity shortage as a result of system reliability
conditions.

1.27 Day-Ahead: The calendar day immediately preceding a Dispatch Day for which
Participants submit Demand Bids and Supply Offers in accordance with applicable
NEPOOL System Rules and the System Operator schedules Resources for Energy,
Operating Reserve, 4-Hour Reserve and AGC (as defined in the Agreement) in
accordance with applicable NEPOOL System Rules.

1.28 Day-Ahead Market: The market provided for in Section 14A of the Agreement
and conducted in the calendar day immediately preceding a Dispatch Day in which
Energy, Operating Reserve, 4-Hour Reserve and AGC (as defined in the Agreement)
are scheduled for a Dispatch Day, based on the Day-Ahead Demand Bids and Supply
Offers and applicable NEPOOL System Rules.

1.29  Delivering Party:  The entity supplying capacity and/or energy to be
transmitted at Point(s) of Receipt under this Tariff.

1.30 Demand Bid: A proposal by a Participant to receive and pay for Energy, at a
specified Location and at a specified Demand Bid Price, that is submitted to the
System Operator pursuant to the Agreement and applicable Market Rules, and
includes information with respect to the quantity to be received and paid for
and other matters complying with the Market Rules.

1.31  Demand Bid Price:  The price specified by a Participant to the System
Operator in a Demand Bid for Energy at a specified Location.

1.32  Designated Agent:  Any entity that performs actions or functions
required under the Tariff on behalf of NEPOOL, an Eligible Customer, or a
Transmission Customer.

1.33 Direct Assignment Facilities: Facilities or portions of facilities that are
Non-PTF and are constructed for the sole use/benefit of a particular
Transmission Customer requesting service under this Tariff or a Generator Owner
requesting an interconnection. Direct Assignment Facilities shall be specified
in a separate agreement with the Transmission Provider whose transmission system
is to be modified to include and/or interconnect with said Facilities, shall be
subject to applicable Commission requirements and shall be paid for by the
Transmission Customer or a Generator Owner or in accordance with the separate
agreement and not under this Tariff.

1.34  Direct Interconnection Transmission Costs:  Has the meaning specified
in Section 2 of Schedule 11 of the Tariff.

1.35  Dispatch Day:  The period beginning at the minute ending 0001 and
ending at 2400 each day.

1.36  Distribution Company:  Has the meaning specified in Section (A)(2) of
Schedule 13.

1.37  Distribution Company Load Zone:  Has the meaning specified in Section
(A)(2) of Schedule 13.

1.38 Economic Upgrade: Those additions and upgrades that are not related to the
interconnection of a generator, and are designed to reduce or eliminate
Congestion Cost, where the net present values of the reduction in, or
elimination of, Congestion Cost exceeds the net present value of the cost of the
transmission addition or upgrade.

1.39 Elective Transmission Upgrade: An addition to or modification of the NEPOOL
Transmission System that is not: (i) a Generator Interconnection Related
Upgrade; (ii) a Reliability Upgrade (including a NEMA Upgrade, as appropriate);
(iii) an Economic Upgrade (including a NEMA Upgrade, as appropriate); (iv) a
Quick Fix Upgrade; or (v) initially proposed in an Elective Transmission Upgrade
Application filed with the System Operator in accordance with Section 50.2 on a
date after the addition or modification already has been otherwise identified in
the current NEPOOL Transmission Plan (other than as an Elective Transmission
Upgrade) in publication as of the date of that application. An Elective
Transmission Upgrade may increase transfer capability of the NEPOOL Transmission
System, may increase the reliability or stability of the NEPOOL Transmission
System above the requirements and criteria established by NERC, NPCC or the
NEPOOL Reliability Committee, or may reduce Congestion Costs into Load Zones or
at Nodes into or within the NEPOOL Control Area.

1.40 Eligible Customer: (i) Any Participant that is engaged, or proposes to
engage, in the wholesale or retail electric power business is an Eligible
Customer under the Tariff. (ii) Any electric utility (including any power
marketer), Federal power marketing agency, or any other entity generating
electric energy for sale or for resale is an Eligible Customer under the Tariff.
Electric energy sold or produced by such entity may be electric energy produced
in the United States, Canada or Mexico. However, with respect to transmission
service that the Commission is prohibited from ordering by Section 212(h) of the
Federal Power Act, such entity is eligible only if the service is provided
pursuant to a state requirement that the Transmission Provider with which that
entity is directly interconnected offer the unbundled transmission service, or
pursuant to a voluntary offer of such service by the Transmission Provider with
which that entity is directly interconnected. (iii) Any end user taking or
eligible to take unbundled transmission service pursuant to a state requirement
that the Transmission Provider with which that end user is directly
interconnected offer the transmission service, or pursuant to a voluntary offer
of such service by the Transmission Provider with which that end user is
directly interconnected, is an Eligible Customer under the Tariff.

1.41  Energy:  Is electrical energy measured in kilowatthours or
megawatthours.

1.42  Energy Imbalance Service:  This service is the form of Ancillary
Service described in Schedule 4.

1.43 Entitlement: An Installed Capability Entitlement, Energy Entitlement,
Operating Reserve Entitlement[, 4-Hour Reserve Entitlement], or AGC Entitlement,
in each case as defined in the Agreement. When used in the plural form, it may
be any or all such Entitlements or combinations thereof, as the context
requires.

1.44  Excepted Transaction:  A transaction specified in Section 25 for the
applicable period specified in that Section, or in Sections 25A and 25B.

1.45  External Node:  A bus or buses used for establishing a Locational Price
for Energy received by Participants from, or delivered by Participants to, a
neighboring Control Area.

1.46 Facilities Study: An engineering study conducted pursuant to the Agreement
or this Tariff by the System Operator and/or one or more affected Participants
to determine the required modifications to the NEPOOL Transmission System,
including the cost and scheduled completion date for such modifications, that
will be required to provide a requested transmission service or interconnection.

1.47  FCR:  A Financial Congestion Right.

1.48 FCR Auction: The periodic auction of FCRs conducted by the System Operator
or another authorized agent of the NEPOOL Participants in accordance with
Schedule 14.

1.49: The revenue collected from the sale of FCRs in FCR Auctions. FCR Auction
Revenue is payable to FCR Holders who submit their FCRs for sale in the FCR
Auction in accordance with Schedule 14 and to ARR Holders in accordance with
Schedule 15.

1.50  FCR Auction Revenue Fund:  The fund containing the FCR Auction Revenue.

1.51 FCR Holder: An entity that acquires an FCR through the FCR Auction or a
subsequent bilateral arrangement pursuant to Schedule 14 of the Tariff and
registers with the System Operator as the holder of the FCR in accordance with
Schedule 14 of the Tariff and applicable NEPOOL System Rules.

1.52 FCR Payment: The payment made either from the Congestion Revenue Fund to an
FCR Holder or to the Congestion Revenue Fund by an FCR Holder in accordance with
Schedule 14 of the Tariff and applicable NEPOOL System Rules.

1.53  Financial Congestion Right:  A financial instrument that evidences the
rights and obligations specified in Schedule 14 of the Tariff.

1.54 Firm Contract: Any contract, other than a Unit Contract, for the purchase
of Installed Capability, Energy [at a Location], Operating Reserves[, 4-Hour
Reserves], and/or AGC (as defined in the Agreement) pursuant to which the
purchaser's right to receive such Installed Capability, Energy, Operating
Reserves[, 4-Hour Reserves] and/or AGC is subject only to the supplier's
inability to make deliveries thereunder as the result of events beyond the
supplier's reasonable control.

1.55 Firm Point-To-Point Transmission Service: Point-To-Point Transmission
Service which is reserved and/or scheduled between specified Points of Receipt
and Delivery in accordance with the applicable procedure specified in Part V of
this Tariff.

1.56  Firm Transmission Service:  Service for Native Load Customers, firm
Regional Network Service (Network Integration Transmission Service), service
for Excepted Transactions, Firm Internal Point-To-Point Transmission Service,
or Firm Through or Out Service.

1.57 Generator Interconnection Related Upgrade: An addition to or modification
of the NEPOOL Transmission System pursuant to Section 50.1 to effect the
interconnection of a new generating unit or an existing generating unit whose
capacity is being materially changed and increased, whether or not the
interconnection is being effected to meet the Minimum Interconnection Standard.
As to Category A Projects (as defined in Schedule 11), a Generator
Interconnection Related Upgrade also includes an upgrade beyond that required to
satisfy the Minimum Interconnection Standard for which the Generator Owner has
committed to pay prior to October 29, 1998.

1.58 Generator Owner: Any Participant or Non-Participant that owns, in whole or
part, a generating unit whether located within or outside the NEPOOL Control
Area. As used in Section 50 and Schedules 11 and 12 of this Tariff, Generator
Owner also includes any Participant or Non-Participant that proposes to site a
new generating unit at a site owned or controlled by it, or which it has the
right to acquire or control, located in the NEPOOL Control Area.

1.59 Good Utility Practice: Any of the practices, methods and acts engaged in or
approved by a significant portion of the electric utility industry during the
relevant time period, or any of the practices, methods and acts which, in the
exercise of reasonable judgment in light of the facts known at the time the
decision was made, could have been expected to accomplish the desired result at
a reasonable cost consistent with good business practices, reliability, safety
and expedition. Good Utility Practice is not intended to be limited to the
optimum practice, method, or act to the exclusion of all others, but rather
includes all acceptable practices, methods, or acts generally accepted in the
region.

1.60 Hub: A specific set of pre-defined Nodes, approved by the Participants
Committee, for which a Locational Price will be calculated and which can be used
to establish a reference price for Energy purchases and the transfer of Energy
Settlement Obligations and for the designation of FCRs in accordance with
Schedule 14.

1.61 Hub Price: In each hour of the Dispatch Day in the Day-Ahead Market and the
Real-Time Market is the price used for Settlement Obligations for Energy which
are treated as being transferred at a Hub in the hour. Hub Prices are calculated
in accordance with Section 14A.12 of the Agreement and Schedule 13 of the
Tariff.

1.62 HQ Interconnection: The United States segment of the transmission
interconnection which connects the systems of Hydro-Quebec and the Participants.
"Phase I" is the United States portion of the 450 kV HVDC transmission line from
a terminal at the Des Cantons Substation on the Hydro- Quebec system near
Sherbrooke, Quebec to a terminal having an approximate rating of 690 MW at a
substation at the Comerford Generating Station on the Connecticut River. "Phase
II" is the United States portion of the facilities required to increase to
approximately 2000 MW the transfer capacity of the HQ Interconnection, including
an extension of the HVDC transmission line from the terminus of Phase I at the
Comerford Station through New Hampshire to a terminal at the Sandy Pond
Substation in Massachusetts. The HQ Interconnection does not include any PTF
facilities installed or modified to effect reinforcements of the New England AC
transmission system required in connection with the HVDC transmission line and
terminals.

1.63 HQ Phase II Firm Energy Contract: The Firm Energy Contract dated as of
October 14, 1985 between Hydro-Quebec and certain of the Participants, as it may
be amended from time to time.

1.64 Import Transaction: An energy delivery originating outside the NEPOOL
Control Area that uses the PTF to deliver energy to Network Load within the
NEPOOL Control Area, except for a delivery that uses a direct interconnection
between the NEPOOL Control Area and the Hydro-Quebec transmission system that
existed as of January 1, 2000.

1.65 Interchange Transactions: Are transactions deemed to be effected under
Section 14 of the Agreement prior to the CMS/MSS Effective Date, and under
Section 14A on and after the CMS/MSS Effective Date.

1.66  Interest:  Interest calculated in the manner specified in Section 8.3.

1.67  Internal Point-to-Point Service:

(1) Until the CMS/MSS Effective Date, Point-to-Point Transmission Service with
respect to a transaction where the Point of Receipt is at the boundary of or
within the NEPOOL Transmission System and the Point of Delivery is within the
NEPOOL Transmission System.

(2) On and after the CMS/MSS Effective Date, Internal Point-to-Point Service is
Point-to-Point Transmission Service with respect to a transaction where the
Point of Receipt is within the NEPOOL Transmission System and the Point of
Delivery is within the NEPOOL Transmission System.

1.68 Internal Point-to-Point Service Rate: The rate applicable to Internal
Point-to-Point Service, which shall be equal for each delivery to the
Participant RNS Rate per Kilowatt for the current Year for the Participant which
owns the Local Network from which the Customer's load is served.

1.69  Interruption:  A reduction in non-firm transmission service due to
economic reasons pursuant to Section 28.7.

1.70 ISO: The Independent System Operator which is responsible for the continued
operation of the NEPOOL Control Area from the NEPOOL control center and the
administration of this Tariff, subject to regulation by the Commission.

1.71 Load Asset Contract: A transaction for the transfer of responsibility for
Electrical Load (and may include Electrical Load qualifying as Dispatchable
Load), Installed Capability, or the rights to compensation for Operating Reserve
to the extent the transfer relates to Dispatchable Load, the terms of which
shall conform to the requirements of applicable Market Rules.

1.72 Load Ratio Share: Ratio of a Transmission Customer's most recently reported
Monthly Network Load in the case of Network Customers and including where
applicable Point-to-Point Customers' Reserved Capacity, to the total load of
Network Customers and Point-to-Point customers, computed in accordance with Part
VI of the Tariff.

1.73 Load Shedding: The systematic reduction of system demand by temporarily
decreasing load in response to transmission system or area capacity shortages,
system instability, or for voltage control considerations under Part VI of the
Tariff.

1.74  Load Zone:  A Reliability Region, except as otherwise provided in
Section 14A.12(b) of the Agreement and Schedule 13 of the Tariff.

1.75 Local Network: The transmission facilities constituting a local network
identified on Attachment E, and any other local network or change in the
designation of a Local Network as a Local Network which the Management Committee
may designate or approve from time to time. The Management Committee may not
unreasonably withhold approval of a request by a Participant that it effect such
a change or designation.

1.76 Local Network Service: Local Network Service is the service provided, under
a separate tariff or contract, by a Participant that is a Transmission Provider
to another Participant or other entity connected to the Transmission Provider's
Local Network to permit the other Participant or entity to efficiently and
economically utilize its resources to serve its load.

1.77 Local Point-To-Point Service: Local Point-To-Point service is Point-
to-Point Transmission Service provided, under a separate tariff or contract, by
a Participant that is a Transmission Provider over Non-PTF or distribution
facilities to permit deliveries to or from an interconnection point on the
NEPOOL Transmission System.

1.78  Location:  A Node, External Node, Load Zone, or Hub.

1.79 Locational Price: The price of Energy at a Location or Reliability Region,
calculated in accordance with Section 14A.12 of the Agreement and Schedule 13 of
the Tariff. The Locational Price for a Node is the Nodal Price at that Node; the
Locational Price for an External Node is the Nodal Price at that External Node;
the Locational Price for a Load Zone or Reliability Region is the Zonal Price
for that Load Zone or Reliability Region, respectively; and the Locational Price
for a Hub is the Hub Price for that Hub.

1.80  Long-Term Firm Service:  Firm Transmission Service with a term of one
year or more.

1.81 Marginal Loss: The additional Energy required to overcome transmission
losses or the decrease in Energy consumed through losses on the NEPOOL
Transmission System associated with serving a small increment of demand at a
Node or External Node. The cost of Marginal Losses at each Location, relative to
the cost of Marginal Losses at the Reference Node, is reflected in the Marginal
Loss Component of the Locational Price at that Location.

1.82 Marginal Loss Component: The component of the Nodal Price at a given Node
or External Node that reflects the Marginal Loss at that Node or External Node.
When used in connection with Hub Price or Zonal Price, the term Marginal Loss
Component refers to the Marginal Loss Components of the Nodal Prices that
comprise the Hub Price or Zonal Price, which Marginal Loss Components are
averaged or weighted in the same way that Nodal Prices are averaged or weighted
to determine the Hub Price and Zonal Price, respectively.

1.83 Marginal Loss Revenue: For each hour is the surplus revenue, if any, after
netting the revenues paid and collected for the Marginal Loss Components of
Locational Prices for all Energy transactions on the NEPOOL Transmission System,
including Energy deliveries by Non-Participant Transmission Customers taking
service under this Tariff, as settled in accordance with the Market Rules.

1.84 Marginal Loss Revenue Fund: The fund of Marginal Loss Revenue administered
by the System Operator in accordance with Section 14A.16 of the Agreement,
Schedule 13 of the Tariff, and the applicable Market Rules.

1.85  Market Rules:  Are the system rules and operating procedures adopted
pursuant to the System Operator Agreement in connection with the
administration of the NEPOOL Market.

1.85A  Merchant Transmission Facility:  Has the meaning specified in Section
51.8.

1.86  Minimum Interconnection Standard:  Has the meaning specified in Section
50.1.

1.87  Monthly Network Load:  Has the meaning specified in Section 46.1.

1.88  Monthly Peak:  Has the meaning specified in Section 46.1.

1.89 Monthly Peak Load: For purposes of Schedule 15, the Monthly Peak Load of
the Transmission Customer is the Transmission Customer's Monthly Peak less any
portion of such Monthly Peak served by a Congestion Paying Entity. For purposes
of Schedule 15, the Monthly Peak Load of a Congestion Paying Entity includes the
portion of any Transmission Customer's Monthly Peak served by the Congestion
Paying Entity.

1.90 Native Load Customers: The wholesale and retail power customers of a
Participant or other entity which is a Transmission Provider on whose behalf the
Participant or other entity, by statute, franchise, regulatory requirement, or
contract, has undertaken an obligation to construct and operate its system to
meet the reliable electric needs of such customers.

1.91   NEMA:  The Northeast Massachusetts Reliability Region.

1.92 NEMA ARRs: The ARRs allocated in accordance with Schedule 15 to certain
entities serving load in NEMA.

1.93 NEMA Contract: A contract described in Section C of Schedule 15 and listed
in Attachment 1 to Schedule 15.

1.94   NEMA LSE:  A NEMA LSE is a Transmission Customer or Congestion Paying
Entity that serves load within NEMA.

1.95 NEMA or "Northeast Massachusetts" Upgrade: Is an addition to or
modification of the NEPOOL Transmission System into or within the Northeast
Massachusetts Reliability Region that is not, as of December 31, 1999, the
subject of a System Impact Study or application filed pursuant to Section 18.4
of the Restated NEPOOL Agreement; that is not related to generation
interconnections; and that will be completed and placed in service by June 30,
2004. Such upgrades include, but are not limited to, new transmission facilities
and related equipment and/or modifications to existing transmission facilities
and related equipment.

1.96 NEPOOL: The New England Power Pool, the power pool created under and
governed by the Agreement, and the entities collectively participating in the
New England Power Pool.

1.97  NEPOOL Control Area:  The Control Area (as defined in Section 1.25)
for NEPOOL.

1.98 NEPOOL System Rules: The Market Rules, the NEPOOL Information Policy, the
Administrative Procedures, the Reliability Standards and any other system rules,
procedures or criteria for the operation of the NEPOOL System and administration
of the NEPOOL Market, the NEPOOL Agreement and the NEPOOL Tariff.

1.99 NEPOOL Transmission Plan: A five-year plan for the expansion or
modification of the NEPOOL Transmission System which has been developed pursuant
to Section 51.

1.100  NEPOOL Transmission System:  The PTF transmission facilities.

1.101  NERC:  The North American Electric Reliability Council.

1.102 Network Customer: A Participant or Non-Participant receiving transmission
service pursuant to the terms of the Network Integration Transmission Service
under Part II and Part VI of the Tariff.

1.103 Network Integration Transmission Service: Regional Network Service, which
may be used with respect to Network Resources or Network Load not physically
interconnected with the NEPOOL Transmission System.

1.104 Network Load: The load that a Network Customer designates for Network
Integration Transmission Service under Part II and Part VI of the Tariff. The
Network Customer's Network Load shall include all load designated by the Network
Customer (including losses) and shall not be credited or reduced for any
behind-the-meter generation. A Network Customer may elect to designate less than
its total load as Network Load but may not designate only part of the load at a
discrete Point of Delivery. Where an Eligible Customer has elected not to
designate a particular load at discrete Points of Delivery as Network Load, the
Eligible Customer is responsible for making separate arrangements under Part III
and Part V of the Tariff for any Point-to-Point Transmission Service that may be
necessary for such non-designated load.

1.105 Network Operating Agreement: An executed agreement in the form of
Attachment H, or any other form that is mutually agreed to, that contains the
terms and conditions under which the Network Customer shall operate its
facilities and the technical and operational matters associated with the
implementation of Network Integration Transmission Service under Part II and
Part VI of this Tariff. The Agreement and the rules adopted thereunder shall
constitute the Network Operating Agreement for Participants.

1.106 Network Operating Committee: A group made up of representatives from the
Network Customer(s) and the System Operator established to coordinate operating
criteria and other technical considerations required for implementation of
Network Integration Transmission Service under Part II and Part VI of this
Tariff. The Network Operating Committee for Network Customers that are
Participants shall be the NEPOOL Regional Transmission Operations Committee and
the NEPOOL Regional Transmission Planning Committee, meeting jointly in a
meeting designated as the annual Network Operating Committee meeting. Notice of
each meeting of the Committee pursuant to Section 47.3 shall be given to each
Non-Participant receiving Regional Network Service under this Tariff and the
Non-Participant shall have the right to be represented at each of such meetings.

1.107 Network Resource: (a) With respect to Participants, (i) any generating
resource located in the NEPOOL Control Area which has been placed in service
prior to the Compliance Effective Date (including a unit that has lost its
capacity value when its capacity value is restored and a deactivated unit which
may be reactivated without satisfying the requirements of Section 49 of this
Tariff in accordance with the provisions thereof) until retired; (ii) any
generating resource located in the NEPOOL Control Area which is placed in
service after the Compliance Effective Date until retired, provided that (1) the
Generator Owner has complied with the requirements of Section 49 of the Tariff,
and (2) the output of the unit shall be limited in accordance with Section 49,
if required; and (iii) any generating resource or combination of resources
(including bilateral purchases) located outside the NEPOOL Control Area for so
long as any Participant has an Entitlement in the resource or resources which is
being delivered to it in the NEPOOL Control Area to serve Network Load located
in the NEPOOL Control Area or other designated Network Loads contemplated by
Section 43.3 of this Tariff taking Regional Network Service. (b) With respect to
Non-Participant Network Customers, any generating resource owned, purchased or
leased by the Network Customer which it designates to serve Network Load.

1.108 Network Upgrades: Modifications or additions to transmission-related
facilities that are integrated with and support the overall NEPOOL Transmission
System for the general benefit of all users of such Transmission System.

1.109 Nodal Price: In each hour of the Dispatch Day in the Day-Ahead Market and
Real-Time Market is the price for Energy received or furnished at a Node or
External Node in the hour, as calculated in accordance with Section 14A.12 of
the Agreement and Schedule 13 of the Tariff.

1.110 Node: A point on the NEPOOL Transmission System where Energy is received
or furnished, and for which Nodal Prices are calculated.

1.111 Non-Firm Point-To-Point Transmission Service: Point-To-Point Transmission
Service under this Tariff that is subject to Curtailment or Interruption under
the circumstances specified in Section 28.7 of this Tariff.

1.112   Non-Participant:  Any entity that is not a Participant.

1.113   Non-PTF:  The transmission facilities owned by the Participants that
do not constitute PTF.

1.114  Northeast Massachusetts Upgrade:  Has the meaning specified in
Schedule 12.

1.115  NPCC:  The Northeast Power Coordinating Council.

1.116  Open Access Same-Time Information System (OASIS):  The NEPOOL
information system and standards of conduct responding to requirements of 18
C.F.R. 37 of the Commission's regulations and all additional requirements
implemented by subsequent Commission orders dealing with OASIS.

1.117 Operating Reserve - 10-Minute Non-Spinning Reserve Service: This service
is the form of Ancillary Service described in Schedule 6.

1.118  Operating Reserve - 10-Minute Spinning Reserve Service:  This
service is the form of Ancillary Service described in Schedule 5.

1.119  Operating Reserve - 30-Minute Reserve Service:  This service is the
form of Ancillary Service described in Schedule 7.

1.120  Participant:  A participant in NEPOOL under the Agreement.

1.121 Participant RNS Rate: The rate applicable to Regional Network Service to
effect a delivery to load in a particular Local Network, as determined in
accordance with Schedule 9 to this Tariff.

1.122 Participants Committee: The committee whose responsibilities are specified
in Section 7 of the Agreement. To the extent applicable, references in the
Tariff to the Participants Committee shall include the prior Management
Committee or Executive Committee as the predecessor of the Participants
Committee if not inconsistent with Section 17A of the Agreement.

1.123 Point(s) of Delivery: Point(s) where capacity and/or energy transmitted by
the Participants will be made available to the Receiving Party under this
Tariff. Until the CMS/MSS Effective Date, but not thereafter, the Point of
Delivery may be designated as the NEPOOL power exchange. The Point(s) of
Delivery shall be specified in the Service Agreement, if applicable, for
Long-Term Firm Point-to-Point Transmission Service.

1.124 Point(s) of Receipt: Point(s) of interconnection where capacity and/or
energy to be transmitted by the Participants will be made available to NEPOOL by
the Delivering Party under this Tariff. Until the CMS/MSS Effective Date, but
not thereafter, the Point of Receipt may be designated as the NEPOOL power
exchange in circumstances where the System Operator does not require greater
specificity. The Point(s) of Receipt shall be specified in the Service
Agreement, if applicable, for Long-Term Firm Point-To-Point Transmission
Service.

1.125 Point-To-Point Transmission Service: The transmission of capacity and/or
energy on either a firm or non-firm basis from the Point(s) of Receipt to the
Point(s) of Delivery under this Tariff. NEPOOL Point-to-Point Transmission
Service includes both Internal Point-to-Point Service and Through or Out
Service.

1.126 Pool-Planned Unit: One of the following units: New Haven Harbor Unit 1
(Coke Works), Mystic Unit 7, Canal Unit 2, Potter Unit 2, Wyman Unit 4, Stony
Brook Units 1, 1A, 1B, 1C, 2A and 2B, Millstone Unit 3, Seabrook Unit 1 and
Waters River Unit 2 (to the extent of 7 megawatts of its Summer Capability and
12 megawatts of its Winter Capability).

1.127 Pool PTF Rate: The transmission rate determined in accordance with
Schedule 8 to this Tariff.

1.128 Pool RNS Rate: The transmission rate determined in accordance with
paragraph (2) of Schedule 9 to this Tariff.

1.129 Pool-Supported PTF: (i) PTF first placed in service prior to January 1,
2000; (ii) Generator Interconnection Related Upgrades with respect to Category A
and B Projects (as defined in Schedule 11), but only to the extent not paid for
by the interconnecting Generator Owner; (iii) Quick Fix Upgrades, in accordance
with Section 52; and (iv) other PTF upgrades, but only to the extent the costs
therefor are determined to be Pool-Supported PTF in accordance with Schedule 12.

1.130  Power Purchaser:  The entity that is purchasing the capacity and/or
energy to be transmitted under the Tariff.

1.131  Prior NEPOOL Agreement:  The NEPOOL Agreement as in effect on
December 1, 1996.

1.132 PTF or Pool Transmission Facilities: (i) The transmission facilities owned
by the Participants and their Related Persons which constitute PTF pursuant to
the Agreement, and (ii) the static VAR compensator installed at Chester, Maine
at the request of the Participants.

1.133 Pre-1997 PTF Rate: The transmission rate of a Participant determined in
accordance with paragraph (5) of Schedule 9 to this Tariff.

1.134 Publicly Owned Entity: An Entity which is either a municipality or an
agency thereof, or a body politic and public corporation created under the
authority of one of the New England states, authorized to own, lease and operate
electric generation, transmission or distribution facilities, or an electric
cooperative, or an organization of any such entities.

1.135  Quick Fix Upgrade:  Has the meaning specified in Section 52.

1.136  Reactive Supply and Voltage Control From Generation Sources
Service:  This service is the form of Ancillary Service described in Schedule
2.

1.137 Real-Time: A current period of a Dispatch Day for which the System
Operator dispatches Resources for Energy and AGC, designates Resources for AGC
and Operating Reserve and, if necessary, activates 4-Hour Reserves.

1.138 Real-Time Market: The market provided for in Section 14A of the Agreement
in which obligations and prices with respect to Energy, Operating Reserve,
4-Hour Reserve and AGC are determined from the actual dispatch and designations
by the System Operator during a Dispatch Day, based on applicable Demand Bids
and Supply Offers and NEPOOL System Rules.

1.139  Receiving Party:  The entity receiving the capacity and/or energy
transmitted to Point(s) of Delivery under this Tariff.

1.140 Reference Node: The Node identified by the System Operator in accordance
with the NEPOOL System Rules relative to which all mathematical quantities
pertaining to physical operation, including Shift Factors and Withdrawal
Factors, shall be calculated with respect to the dispatch of the system and the
derivation of Locational Prices.

1.141  Regional Network Service:  The transmission service described in
Part II and Part VI of this Tariff.

1.142  Regulation and Frequency Response Service:  This service is the
form of Ancillary Service described in Schedule 3.

1.143 Reliability Region: As of March 31, 2000, any one of the regions
identified in Attachment C to the Agreement. Subsequent to March 31, 2000, the
System Operator, in a filing with the Commission and following consultation with
the NEPOOL Reliability Committee, may reconfigure Reliability Regions and add or
subtract Reliability Regions as necessary over time to reflect changes to the
grid or changes in patterns of usage and intra-zonal Congestion. Reliability
Regions reflect the operating characteristics of, and the major transmission
constraints on, the NEPOOL Transmission System.

1.144 Reliability Upgrade: Those additions and upgrades not required by the
interconnection of a generator that are nonetheless necessary to ensure the
continued reliability of the NEPOOL system, taking into account load growth and
known resource changes, and include those upgrades necessary to provide
acceptable stability response, short circuit capability and system voltage
levels, and those facilities required to provide adequate thermal capability and
local voltage levels that cannot otherwise be achieved with reasonable
assumptions for certain amounts of generation being unavailable (due to
maintenance or forced outages) for purposes of long-term planning studies. Good
Utility Practice, applicable reliability principles, guidelines, criteria,
rules, procedures and standards of NERC and NPCC and any of their successors,
applicable publicly available local reliability criteria, and the NEPOOL System
Rules, as they may be amended from time to time, will be used to define the
system facilities required to maintain reliability in evaluating proposed
Reliability Upgrades.

1.145 Reserved Capacity: The maximum amount of capacity and energy that is
committed to the Transmission Customer for transmission over the NEPOOL
Transmission System between the Point(s) of Receipt and the Point(s) of Delivery
under Part V of this Tariff. Reserved Capacity shall be expressed in terms of
whole kilowatts on a sixty-minute interval (commencing on the clock hour) basis.

1.146  Scheduling, System Control and Dispatch Service:  This service is
the form of Ancillary Service described in Schedule 1.

1.147  Second Effective Date:  May 1, 1999.

1.148  Service Agreement:  The initial agreement and any amendments or
supplements thereto entered into by the Transmission Customer and the System
Operator for service under this Tariff.

1.149 Service Commencement Date: The date service is to begin pursuant to the
terms of an executed Service Agreement, or the date service begins in accordance
with Section 29.3 or Section 41.1 under this Tariff, or in the case of Regional
Network Service which is not required to be furnished under a Service Agreement
pursuant to Section 48 of this Tariff, the date service actually commences.

1.150 Settlement Obligation Prior to the CMS/MSS Effective Date, an obligation
as defined in Section 14.1(a) of the Agreement for Energy, Section 14.1(b) of
the Agreement for Operating Reserve and Section 14.1(c) of the Agreement for
AGC, and all applicable Market Rules and, on and after the CMS/MSS Effective
Date, an obligation as defined in Section 14A.1(b) of the Agreement for Energy,
Section 14A.1(c) of the Agreement for Operating Reserve, Section 14A.1(d) of the
Agreement for 4-Hour Reserve and Section 14A.1(e) of the Agreement for AGC, and
all applicable Market Rules.

1.151 Shift Factor: The factor which relates to the change in power flow over
the PTF that results from an increment of generation at a given Node or External
Node and a corresponding increment of load at the Reference Node, relative to
the size of the increment of generation. Shift Factors are used to calculate
Locational Prices in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.

1.152  Short-Term Firm Service:  Firm Transmission Service with a term of less
than one year.

1.153  Standard Offer Obligation:  Has the meaning specified in Section
14A.12(b)(ii) of the Agreement and Schedule 13 of the Tariff.

1.154  Supply Obligation:  Is an obligation as defined in Section 14A.1(a) of
the Agreement for Energy, Operating Reserve, 4-Hour Reserve, and/or AGC.

1.155 Supply Offer: A proposal to furnish Energy at a Node or External Node,
Operating Reserve, 4-Hour Reserve and/or AGC (as defined in the Agreement) from
a Resource that meets the applicable requirements set forth in the Market Rules
that a Participant with Supply Offer authority for the Resource submits to the
System Operator pursuant to the Agreement and applicable Market Rules, and
includes a price for the Supply Offer and information with respect to the
quantity proposed to be furnished, technical parameters for the Resource, timing
and other matters.

1.156 System Contract: Any Contract for the purchase of Installed Capability,
Energy [at a Location], Operating Reserves[, 4-Hour Reserves] and/or AGC (as
defined in the Agreement), other than a Unit Contract, pursuant to which the
purchaser is entitled to a specifically determined or determinable amount of
such Installed Capability, Energy, Operating Reserves[, 4-Hour Reserves] and/or
AGC.

1.157 System Impact Study: An assessment pursuant to Part V, VI or VII of this
Tariff of (i) the adequacy of the NEPOOL Transmission System to accommodate a
request for the interconnection of a new or materially changed generating unit
or a new or materially changed interconnection to another Control Area or new
Regional Network Service, Internal Point-to-Point Service or Through or Out
Service, and (ii) whether any additional costs may be required to be incurred in
order to provide the interconnection or transmission service.

1.158 System Operator: The central dispatching agency provided for in the
Agreement which has responsibility for the operation of the NEPOOL Control Area
from the control center and the administration of this Tariff. The System
Operator is the ISO.

1.159 Target FCR Payment: The amount of an FCR Payment that an FCR Holder is
entitled to in the absence of a Congestion Revenue Shortfall when the Congestion
Component of the Locational Price at the Location and/or Reliability Region of a
given FCR's Point of Delivery is higher than the Congestion Component of the
Locational Price at the Location and/or Reliability Region of the given FCR's
Point of Receipt. Target FCR Payments are calculated and Congestion Revenue
Shortfalls are managed in accordance with Schedule 14.

1.160 Tariff: This NEPOOL Open Access Transmission Tariff and accompanying
schedules and attachments, as modified and amended from time to time.

1.161 Third-Party Sale: Any sale for resale in interstate commerce to a Power
Purchaser that is not designated as part of Network Load under the Regional
Network Service.

1.162 Through or Out Service: Point-to-Point Transmission Service provided by
NEPOOL with respect to a transaction which requires the use of PTF and which
goes through the NEPOOL Control Area, as, for example, from the Maine Electric
Power Company line or New Brunswick to New York, or from one point on the NEPOOL
Control Area boundary with New York to another point on the Control Area
boundary with New York, or with respect to a transaction which goes out of the
NEPOOL Control Area from a point in the NEPOOL Control Area, as, for example,
from Boston to New York.

1.163 Third Effective Date: The date on which all Interchange Transactions shall
begin to be effected on the basis of separate Bid Prices for each type of
Entitlement. The Third Effective Date shall be fixed at the discretion of the
Management Committee to occur within six months to one year after the Second
Effective Date, or at such later date as the Commission may fix on its own or
pursuant to a request by the Management Committee.

1.164 Ties: (i) The PTF lines and facilities which connect the NEPOOL
Transmission System to the transmission line owned by Maine Electric Power
Company, which is in turn connected to the transmission system in New Brunswick,
(ii) the PTF lines and facilities which connect the NEPOOL Transmission System
to the transmission system in New York and (iii) any new PTF lines and
facilities which connect the NEPOOL Transmission System to the transmission
system in another Control Area.

1.165  Transition Period:  The six-year period commencing on March 1, 1997.

1.166 Transmission Customer: Any Eligible Customer that (i) is a Participant
which is not required to sign a Service Agreement with respect to a service to
be furnished to it in accordance with Section 48 of this Tariff, or (ii)
executes, on its own behalf or through its Designated Agent, a Service
Agreement, or (iii) requests in writing, on its own behalf or through its
Designated Agent, that NEPOOL file with the Commission, a proposed unexecuted
Service Agreement in order that the Eligible Customer may receive transmission
service under this Tariff. This term is used in Part I to include customers
receiving transmission service under this Tariff.

1.167 Transmission Owner: A Transmission Provider that makes its PTF available
under the Tariff and owns a Local Network listed in Attachment E to the Tariff
which is not a Publicly Owned Entity and includes any affiliate of a
Transmission Provider that owns transmission facilities that are made available
as part of the Transmission Provider's Local Network; provided that if a
Transmission Provider is not listed in Attachment E to the Tariff on May 10,
1999, the Transmission Provider must also (1) own, or lease with rights
equivalent to ownership, PTF with an original capital investment in its PTF of
at least $30,000,000, and (2) provide transmission service to non- affiliated
customers pursuant to an open access transmission tariff on file with the
Commission.

1.168  Transmission Owners Committee:  The committee established pursuant to
Section 11B of the Agreement.

1.169 Transmission Provider: The Participants, collectively, which own PTF and
are in the business of providing transmission service or provide service under a
local open access transmission tariff, or in the case of a state or municipal or
cooperatively-owned Participant, would be required to do so if requested
pursuant to the reciprocity requirements specified in the Tariff, or an
individual such Participant, whichever is appropriate.

1.170  Transmission System Upgrade:  Has the meaning specified in Section 51.

1.171 Unit Contract: A purchase contract pursuant to which the purchaser is in
effect currently entitled, at a specified Location, either (i) to a specifically
determined or determinable portion of the capacity of a specific electric
generating unit or units, or (ii) to a specifically determined or determinable
amount of Installed Capability, Energy, Operating Reserves and/or AGC (as
defined in the Agreement) if, or to the extent that, a specific electric
generating unit or units is or can be operated.

1.172 Use: For a Transmission Customer which has exercised its option to take
Internal Point-to-Point Service to serve all or a portion of its load at any
Point of Delivery, the greater for the hour of (i) the maximum amount of Energy
that it will receive in any hour, as determined from meters and adjusted for
losses, plus, in the case of a Participant, the maximum amount of Operating
Reserve assigned to the Participant by the System Operator in any hour during
the month, at that Point of Delivery from the resources covered by its Completed
Applications and from Interchange Transactions, or (ii) the portion of its
Installed Capability Responsibility which must be satisfied with the resources
covered by its Completed Applications and from Interchange Transactions. Use
shall be expressed in terms of whole Kilowatts on a sixty-minute interval
(commencing on the clock hour) basis.

1.173 Withdrawal Factor: The factor which measures the proportion of a small
increment of power injected at a given Node that can be withdrawn at the
Reference Node (with any difference between the amounts injected and withdrawn
attributable to Marginal Losses). Withdrawal Factors are used to calculate
Locational Prices in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.

1.174 Year: A period of 365 or 366 days, whichever is appropriate, commencing
on, or on the anniversary of March 1, 1997. Year One is the Year commencing on
March 1, 1997, and Years Two and higher follow it in sequence.

1.175 Zonal Price: In each hour of the Dispatch Day in the Day-Ahead Market and
the Real-Time Market, the price for Energy received in a Load Zone or
Reliability Region in the hour, as calculated in accordance with Section 14A.12
of the Agreement and Schedule 13 of the Tariff.

3   Purpose of This Tariff

This Tariff, together with the transmission provisions in Part Four of the
Agreement, is intended to provide a regional arrangement which will cover new
uses of the NEPOOL Transmission System. The arrangement is designed and shall be
operated in such a manner as to encourage and promote competition in the
electric market to the benefit of ultimate users of electric energy. New uses of
transmission facilities which require the use of a single Participant Local
Network will continue to be provided in part under that Participant's filed
tariff. Any new regional use of the NEPOOL Transmission System must be obtained
from NEPOOL pursuant to this Tariff and not from individual Participants.
Ancillary Services will be supplied in accordance with Section 4 of this Tariff.

A five-year transitional arrangement, which is described in Part IV of this
Tariff, and continuing service for Excepted Transactions, have been negotiated
to phase in the financial impacts of the change from the historic regime in
which uses of the NEPOOL Transmission System had to be obtained and paid for
under the individual tariffs of the Participants to a regime in which the
service will be obtained from the Participants through NEPOOL at a rate which
will not vary with distance. This Tariff is intended to provide for comparable,
non-discriminatory treatment of all similarly situated Transmission Providers
and all Participants and Non-Participants that are transmission users, and it
shall be construed in the manner which best achieves this objective.

This Tariff, and the provisions of Part Four of the Agreement, provide for a
two-tier transmission arrangement integrating regional service which is provided
under this Tariff, and local service which is provided under the Participants'
individual system tariffs.

This Tariff is also intended to provide a system of Congestion management.

4   Initial Allocation and Renewal Procedures

4.1 Initial Allocation of Available Transmission Capability: For purposes of
determining whether existing capability on the NEPOOL Transmission System is
adequate to accommodate a request for new Through or Out Service under Part V of
this Tariff, all Completed Applications for new service received during the
initial sixty-day period of the Transition Period will be deemed to have been
filed simultaneously. A lottery system conducted by an independent accounting
firm shall be used to assign priorities for Completed Applications filed
simultaneously. All Completed Applications for Through or Out Service received
after the initial sixty-day period shall be assigned a priority pursuant to
Section 27.2.

4.2 Reservation Priority for Existing Firm Service Customers: Existing firm
service customers receiving service with respect to Excepted Transactions and
any other existing firm service customers of the Participants (wholesale
requirements customers and transmission-only customers) with a contract term of
one year or more have the right to continue to take transmission service at the
same or a reduced level under this Tariff at the time when the existing contract
terminates during or after the Transition Period. This transmission reservation
priority is independent of whether the existing customer continues to purchase
capacity and energy from its existing supplier or elects to purchase capacity
and energy from another supplier. If, at the end of the contract term, the
NEPOOL Transmission System cannot accommodate all of the requests for
transmission service, the existing firm service customer must agree to accept a
contract term at least equal to a competing request by any new Eligible Customer
and to pay the current just and reasonable rate, filed with the Commission, for
such service. This transmission reservation priority for existing firm service
customers is an ongoing right that may be exercised as to any firm contract with
a term of one year or longer by filing an Application in accordance with this
Tariff at least sixty days in advance of the first day of the calendar month in
which the existing contract term is to terminate.

4.3 Initial Election of Optional Internal Point-to-Point Service: Participants
and Non-Participants receiving Regional Network Service under the Tariff on the
Compliance Effective Date shall have sixty days to make an initial election to
receive Internal Point-to-Point Service in lieu of, in whole or part, Regional
Network Service. The election shall take effect as to such service at the end of
such sixty-day period and shall be made by delivering an application to the
System Operator, together with a deposit, if required, pursuant to Part V of
this Tariff.

Participants and Non-Participants receiving Regional Network Service which do
not make such an initial election within such sixty-day period shall continue to
receive Regional Network Service, subject to their right to elect at any time
later to receive Internal Point-to-Point Service.

5   Ancillary Services

Ancillary Services are needed with transmission service to maintain reliability
within the NEPOOL Control Area. The Participants are required to provide through
NEPOOL, and the Transmission Customer is required to purchase from NEPOOL,
Scheduling, System Control and Dispatch Service, and Reactive Supply and Voltage
Control from Generation Sources Service. The Participants offer to provide or
arrange for, through NEPOOL, the following Ancillary Services, but only to a
Transmission Customer serving load within the NEPOOL Control Area (i) Regulation
and Frequency Response (Automatic Generator Control), (ii) Energy Imbalance,
(iii) Operating Reserve - 10-Minute Spinning, (iv) Operating Reserve - 10-Minute
Non-Spinning and (v) Operating Reserve - 30-Minute. A Participant or other
Transmission Customer serving load within the NEPOOL Control Area is required to
provide these Ancillary Services, whether from the System Operator, from a third
party, or by self- supply. A Transmission Customer may not decline NEPOOL's
offer of these Ancillary Services unless the Transmission Customer demonstrates
to the System Operator that the Transmission Customer has acquired Ancillary
Services of equal quality from another source. The Transmission Customer that is
not a Participant must list in its Application which Ancillary Services it will
purchase through NEPOOL.

In the event of an unauthorized use of any Ancillary Service by the Transmission
Customer, the Transmission Customer will be required to pay 200% of the charge
which would otherwise be applicable.

The specific Ancillary Services, prices and/or compensation methods are
described on the Schedules that are attached to and made a part of this Tariff.
Three principal requirements apply to discounts for Ancillary Services provided
by NEPOOL in conjunction with its provision of transmission service as follows:
(1) any offer of a discount made by NEPOOL must be announced to all Eligible
Customers solely by posting on the OASIS, (2) any customer-initiated requests
for discounts (including requests for use by one's wholesale merchant or an
affiliate's use) must occur solely by posting on the OASIS, and (3) once a
discount is negotiated, details must be immediately posted on the OASIS. A
discount agreed upon for an Ancillary Service must be offered for the same
period to all Eligible Customers on the NEPOOL Transmission System. Sections 4.1
through 4.7 below list the seven Ancillary Services.

5.1  Scheduling, System Control and Dispatch Service:  The rates and/or
methodology are described in Schedule 1.

5.2  Reactive Supply and Voltage Control from Generation Sources Service: The
rates and/or methodology are described in Schedule 2.

5.3  Regulation and Frequency Response Service:  Where applicable, the rates
and/or methodology are described in Schedule 3.

5.4  Energy Imbalance Service: Where applicable, the rates and/or methodology
are described in Schedule 4.

5.5  Operating Reserve - 10-Minute Spinning Reserve Service: Where applicable,
the rates and/or methodology for this service are described in Schedule 5.

5.6 Operating Reserve - 10-Minute Non-Spinning Reserve Service: Where
applicable, the rates and/or methodology for this service are described in
Schedule 6.

5.7  Operating Reserve - 30-Minute Reserve Service:  Where applicable, the
rates and/or methodology for this service are described in Schedule 7.

5.8  System Restoration and Planning Service:  Where applicable, the rates
and/or methodology for this service are described in Schedule 16.

6  Open Access Same-Time Information System (OASIS)

Terms and conditions regarding the NEPOOL Open Access Same-Time Information
System and standards of conduct are set forth in 18 C.F.R. 37 of the
Commission's regulations (Open Access Same-Time Information System and Standards
of Conduct for Public Utilities). In the event available transmission
capability, as posted on OASIS, is insufficient to accommodate a request for
firm transmission service, additional studies may be required as provided by
this Tariff pursuant to Sections 33 and 44.

7   Local Furnishing and Other Tax-Exempt Bonds

7.1 Participants That Own Facilities Financed by Local Furnishing or Other
Tax-Exempt Bonds: This provision is applicable only to Participants that have
financed facilities for the local furnishing of electric energy with tax-exempt
bonds, as described in Section 142(f) of the Internal Revenue Code ("local
furnishing bonds") or other tax-exempt bonds, as described in Section 103(b) of
the Internal Revenue Code ("other tax-exempt bonds"). Notwithstanding any other
provision of this Tariff, a Participant shall not be required to provide service
to any Eligible Customer pursuant to this Tariff if the provision of such
transmission service would jeopardize the tax-exempt status of any local
furnishing bond(s) or other tax-exempt bonds used to finance the Participant's
facilities that would be used in providing such Transmission Service.

7.2  Alternative Procedures for Requesting Transmission Service - Local
Furnishing Bonds:

(i) If a Participant determines that the provision of transmission service to be
provided under this Tariff would jeopardize the tax-exempt status of any local
furnishing bond(s) used to finance the Participant's facilities that would be
used in providing such transmission service, the Management Committee shall be
advised within thirty days of receipt of a Completed Application by an Eligible
Customer requesting such service, or the date on which this Tariff becomes
effective, whichever is applicable.

(ii) If an Eligible Customer thereafter renews its request for the same
transmission service referred to in (i) by tendering an application under
Section 211 of the Federal Power Act, or the Management Committee tenders such
an application requesting that service be provided under this Tariff, the
Participant, within ten days of receiving a copy of the Section 211 application,
will waive its rights to receive a request for service under Section 213(a) of
the Federal Power Act and to the issuance of a proposed order under Section
212(c) of the Federal Power Act. The Commission, upon receipt of the
Transmission Provider's waiver of its rights to a request for service under
Section 213(a) of the Federal Power Act and to the issuance of a proposed order
under Section 212(c) of the Federal Power Act, shall issue an order under
Section 211 of the Federal Power Act. Upon issuance of the order under Section
211 of the Federal Power Act, the Transmission Provider shall be required to
provide the requested transmission service in accordance with the terms and
conditions of this Tariff.

7.3 Alternative Procedures for Requesting Transmission Service - Other Tax-
Exempt Bonds: If a Participant determines that the provision of transmission
service to be provided under the Tariff would jeopardize the tax-exempt status
of any other tax-exempt bonds used to finance the Participant's facilities that
would be used in furnishing such transmission service, it shall notify the
Management Committee within thirty days of the date on which this Tariff becomes
effective, and shall elect in its notice either to comply with the procedure
specified in Section 6.2(ii) or to make its facilities unavailable under the
Tariff and thereby waive its right to share in the distribution of revenues
received under the Tariff derived from such facilities. Any such election may be
changed at any time.

8   Reciprocity

A Transmission Customer receiving transmission service under this Tariff,
whether a Participant or a Non-Participant, agrees to provide comparable
transmission service that it is capable of providing to the Participants on
similar terms and conditions over facilities used for the transmission of
electric energy in Canada or used for such transmission in the United States and
that are owned, controlled or operated by, or on behalf of the Transmission
Customer and over facilities used for the transmission of electric energy owned,
controlled or operated by the Transmission Customer's corporate affiliates.
Transmission of power on the Transmission Customer's system to the border of the
NEPOOL Control Area and transfer of ownership at that point shall not satisfy,
or relieve the Transmission Customer of, the obligation to provide reciprocal
service.

This reciprocity requirement applies not only to the Transmission Customer that
obtains transmission service under the Tariff, but also to all parties to a
transaction that involves the use of transmission service under the Tariff,
including the power seller, buyer and any intermediary, such as a power
marketer. This reciprocity requirement also applies to any Eligible Customer
that owns, controls or operates transmission facilities that uses an
intermediary, such as a power marketer, to request transmission service under
the Tariff. If the Transmission Customer does not own, control or operate
transmission facilities, the Transmission Customer must include in its
Application a sworn statement of one of its duly authorized officers or other
representatives that the purpose of its Application is not to assist an Eligible
Customer to avoid the requirements of this provision.

9   Billing and Payment; Accounting

9.1 Participant Billing Procedure: Billings to Transmission Customers shall be
made in accordance with this Section 8 and the NEPOOL Billing Policy set forth
in Attachment N hereto, as such Billing Policy with respect to Participants may
be amended, modified or supplemented by other billing procedures established
pursuant to the Agreement.

9.2 Non-Participant Billing Procedure: Within a reasonable time after the first
day of each month, the System Operator will submit on behalf of the Participants
an invoice to each Non-Participant Transmission Customer for the charges for all
services furnished under this Tariff during the preceding month. The invoice
shall be paid by the Non-Participant Transmission Customer to the System
Operator for NEPOOL within ten days of receipt. All payments shall be made, in
accordance with the procedure specified by the System Operator, in immediately
available funds payable to the System Operator or by wire transfer to a bank
account designated by the System Operator.

9.3 Interest on Unpaid Balances: Interest on any unpaid amounts (including
amounts placed in escrow) will be calculated in accordance with the methodology
specified for interest on refunds in 18 C.F.R. 35.19a(a)(2)(iii) of the
Commission's regulations. Interest on delinquent amounts will be calculated from
the due date of the bill to the date of payment. When payments are made by mail,
bills will be considered as having been paid on the date of receipt of payment
by the System Operator or by the bank designated by the System Operator.

9.4 Customer Default: In the event a Non-Participant Transmission Customer fails
to make payment to the ISO on or before the due date as described above, and
such failure of payment is not corrected within thirty calendar days after the
ISO notifies the Transmission Customer to cure such failure, a default by the
Transmission Customer will be deemed to exist. Upon the occurrence of a default,
NEPOOL may initiate a proceeding with the Commission to terminate service but
shall not terminate service until the Commission approves such termination. In
the event of a billing dispute between NEPOOL and the Transmission Customer,
service will continue to be provided under the Service Agreement and service
termination proceedings will not be initiated as long as the Transmission
Customer continues to make all payments invoiced by NEPOOL, including any
disputed amounts, subject to resolution of such dispute in favor of such
Transmission Customer. If the Transmission Customer fails to meet this
requirement for continuation of service, then the ISO may provide notice to the
Transmission Customer of NEPOOL's intention to suspend service in sixty days, in
accordance with applicable Commission rules and regulations, and may proceed
with such suspension.
In the event a Transmission Customer that is a Participant fails to perform its
obligations under the Tariff, Section 21.2 of the Agreement shall be applicable
to that failure. That section of the Agreement addresses defaults under both the
Tariff and the Agreement and also addresses termination of an entity's status as
a Participant.

9.5 Study Costs and Revenues: A Participant which is a Transmission Provider
shall (i) include in a separate operating revenue account or subaccount the
revenues, if any, it receives from transmission service when making Third-Party
Sales under Part V of this Tariff, and (ii) include in a separate transmission
operating expense account or subaccount, costs properly chargeable to expense
that are incurred to perform any System Impact Studies or Facilities Studies
which the Transmission Provider conducts to determine if it must construct new
transmission facilities or upgrades necessary for its own uses, including
Third-Party Sales, if any, under this Tariff; and include in a separate
operating revenue account or subaccount the revenues received for System Impact
Studies or Facilities Studies performed when such amounts are separately stated
and identified in a billing under the Tariff.

10  Regulatory Filings

Nothing contained in this Tariff or any Service Agreement shall be construed as
affecting in any way the right of the Participants to file with the Commission
under Section 205 of the Federal Power Act and pursuant to the Commission's
rules and regulations promulgated thereunder for a change in any rates, terms
and conditions, charges, classification of service, Service Agreement, rule or
regulation.

Nothing contained in this Tariff or any Service Agreement shall be construed as
affecting in any way the ability of any Transmission Customer receiving service
under this Tariff or for an Excepted Transaction to exercise its rights under
the Federal Power Act and pursuant to the Commission's rules and regulations
promulgated thereunder.

11   Force Majeure and Indemnification

11.1 Force Majeure: An event of Force Majeure means any act of God, labor
disturbance, act of the public enemy, war, insurrection, riot, fire, storm or
flood, explosion, breakage or accident to machinery or equipment, any
Curtailment, any order, regulation or restriction imposed by a court or
governmental military or lawfully established civilian authorities, or any other
cause beyond a party's control. A Force Majeure event does not include an act of
negligence or intentional wrongdoing. Neither the Participants, NEPOOL, the
System Operator nor the Transmission Customer will be considered in default as
to any obligation under this Tariff if prevented from fulfilling the obligation
due to an event of Force Majeure; provided that no event of Force Majeure
affecting any entity shall excuse that entity from making any payment that it is
obligated to make hereunder or under a Service Agreement. However, an entity
whose performance under this Tariff is hindered by an event of Force Majeure
shall make all reasonable efforts to perform its obligations under this Tariff,
and shall promptly notify the System Operator or the Transmission Customer,
whichever is appropriate, of the commencement and end of each event of Force
Majeure.

11.2 Indemnification: The Transmission Customer shall at all times indemnify,
defend, and save harmless the System Operator, NEPOOL and each Participant from
any and all damages, losses, claims, including claims and actions relating to
injury to or death of any person or damage to property, demands, suits,
recoveries, costs and expenses, court costs, attorney fees, and all other
obligations by or to third parties, arising out of or resulting from the
performance by the System Operator, NEPOOL or any Participant of their
obligations under this Tariff on behalf of the Transmission Customer, except in
cases of negligence or intentional wrongdoing by the System Operator, NEPOOL or
a Participant, as the case may be.

12  Creditworthiness

For the purpose of determining the ability of a Transmission Customer which is a
Non-Participant to meet its obligations related to service hereunder, NEPOOL may
require reasonable credit review procedures. This review shall be made in
accordance with standard commercial practices. In addition, NEPOOL may require
the Transmission Customer to provide and maintain in effect during the term of
the Service Agreement an irrevocable letter of credit as security to meet its
responsibilities and obligations under this Tariff, or an alternative form of
security proposed by the Transmission Customer and acceptable to NEPOOL and
consistent with commercial practices established by the Uniform Commercial Code
that protects the Participants against the risk of non-payment. The Financial
Assurance Policy for NEPOOL Non-Participant Transmission Customers set forth in
Attachment M hereto provides in greater detail NEPOOL's credit review procedures
and the types of security that are acceptable to NEPOOL to protect against the
risk of non-payment.

13  Dispute Resolution Procedures

13.1 Internal Dispute Resolution Procedures: Any dispute between an Eligible
Customer or Transmission Customer which is a Participant and NEPOOL involving
transmission service under the Tariff may be submitted to mediation and/or
arbitration and resolved in accordance with the alternate dispute resolution
procedures set forth in Section 21.1 of the Agreement. Any dispute between a
Non-Participant Eligible Customer or Transmission Customer and NEPOOL involving
this Tariff (excluding applications for rate changes or other changes to this
Tariff, or to any Service Agreement entered into under this Tariff, which shall
be presented directly to the Commission for resolution) shall be referred to a
designated senior representative of the Eligible Customer or Transmission
Customer and a representative of the Management Committee for resolution on an
informal basis as promptly as practicable. In the event the designated
representatives are unable to resolve the dispute within thirty days or such
other period as the parties may fix by mutual agreement, such dispute may be
submitted to mediation and/or arbitration and resolved in accordance with the
alternate dispute resolution procedures set forth in Section 21.1 of the
Agreement, with any Non-Participant being treated as if it were a Participant
for purposes of such procedures.

13.2 Rights Under The Federal Power Act: Nothing in this section shall restrict
the rights of any party to file a complaint with the Commission, or seek any
other available remedy, under relevant provisions of the Federal Power Act.

14  Stranded Costs

14.1 General: This Tariff shall not be used to evade or enhance in whole or in
part the stranded cost policies or charges established by law or by the
regulatory commission with jurisdiction.

14.2 Commission Requirements: A Participant which seeks to recover stranded
costs from a Transmission Customer pursuant to this Tariff may do so in
accordance with the terms, conditions and procedures in the Commission's Order
No. 888 or other relevant Commission orders. However, the Participant must
separately file any specific proposed stranded cost charge under Section 205 of
the Federal Power Act.

14.3  Wholesale Contracts: Nothing in this Section 13 is intended to affect or
alter the rights or obligations of parties under wholesale requirements
contracts.

14.4 Right to Seek or Contest Recovery Unimpaired: No provision in this Tariff
shall impair a Participant's right to seek stranded cost relief from the
appropriate regulatory body or court or the right of any Participant or other
entity to contest such relief.

II. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION SERVICE) Regional
Network Service or Network Integration Transmission Service will be provided by
the Participants through NEPOOL during and after the Transition Period to
Transmission Customers pursuant to the applicable terms and conditions of this
Tariff. Local Network Service will be provided during and after the Transition
Period pursuant to the applicable terms and conditions of tariffs filed by an
individual Participant that is a Transmission Provider and/or pursuant to an
agreement between a Participant that is a Transmission Provider and a
Transmission Customer. This Tariff does not prescribe the methodology to be used
by the individual Participant in developing its Local Network Service rate, but
the Agreement prescribes certain requirements with respect thereto.

15  Nature of Regional Network Service

Regional Network Service or Network Integration Transmission Service is the
service provided under Parts II and VI of this Tariff over the NEPOOL
Transmission System which is provided to Network Customers to serve their loads.
It includes firm transmission service for the delivery to a Network Customer of
its energy and capacity in Network Resources and secondary service for the
delivery to or by Network Customers of energy and capacity in Interchange
Transactions.

1.1   Rules for Import Transactions Conducted in Conjunction with Regional
Network Service:

For purposes of scheduling and curtailment of Import Transactions over
interconnections between the NEPOOL Control Areas and neighboring Control Areas,
the following rules shall apply:

(a) Excepted Transactions, and those service agreements covering the importation
over the PTF of the allocation of New York Power Authority power and energy that
were in effect as of the date that the NEPOOL Tariff became effective, shall
have highest priority, and shall be scheduled first and curtailed last;

(b) other than as provided in 14.1(a), Import Transactions shall, to the maximum
extent practicable, be scheduled and curtailed on the basis of economic merit
order and in accordance with NEPOOL System Rules, except that Short Notice
External Transactions (as defined in the Market Rules) shall be scheduled and
curtailed in accordance with the Market Rules governing such transactions;

(c) other than as provided in 14.1(a), to the extent that Import Transactions
cannot be scheduled and curtailed on the basis of economic merit order, such
transactions shall be scheduled in order of submittal time (first submitted,
first served) and curtailed in reverse order of submittal time (last submitted,
first curtailed);

(d) to the extent that multiple schedules for Import Transactions submitted at
the same time have the same economic merit order, the System Operator shall
curtail the schedules on a non-discriminatory basis in accordance with NEPOOL
System Rules; and

(e) market participants wishing to schedule Import Transactions shall comply
with applicable NEPOOL System Rules. The System Operator shall apply the
above-listed rules consistent with maintaining the reliability of the NEPOOL
Transmission System. The System Operator shall develop and post procedures on
its Internet website reflecting the above-listed Import Transaction rules.

16   Availability of Regional Network Service

16.1  Provision of Regional Network Service: Regional Network Service shall be
provided by the Participants through NEPOOL, and shall be available to each
Eligible Customer.

16.2 Eligibility to Receive Regional Network Service: Regional Network Service
shall be taken and paid for by (i) each Eligible Customer which has a load
within the NEPOOL Control Area and has not elected to take Internal
Point-to-Point Service at all of its Point(s) of Delivery, and (ii) each Non-
Participant which is an Eligible Customer and has a load within the NEPOOL
Control Area unless such Non-Participant operates its own Control Area or has
elected to take Internal Point-to-Point Service at all of its Point(s) of
Delivery. Participants and Non-Participants which take Regional Network Service
must also take Local Network Service except as otherwise provided in Section 25.

17  Payment for Regional Network Service

Each Participant or Non-Participant which has a load in the NEPOOL Control Area
and takes Regional Network Service for a month shall pay to NEPOOL for such
month an amount equal to its Monthly Network Load for the month times the
applicable Participant RNS Rate, and shall pay in addition any amount which it
is required to pay for the service pursuant to Section 43.3 of this Tariff. It
shall also be obligated to pay any ancillary service charges and any applicable
congestion or other uplift charge required to be paid pursuant to Sections 24,
25A and 25B of this Tariff. The applicable Participant RNS Rate shall be the
rate, determined in accordance with Schedule 9, which is applicable to a
delivery to load in the particular Local Network in which the load served by the
Participant or Non-Participant is located. In the event the Participant or
Non-Participant serves Network Load located on more than one Local Network, the
amount to be paid by it shall be separately computed for the Network Load
located on each Local Network.

18   Procedure for Obtaining Regional Network Service

A Participant or Non-Participant which takes Regional Network Service shall be
subject to the applicable provisions of Part II and Part VI of this Tariff,
except to the extent otherwise specifically provided in Section 48 of this
Tariff

III.   THROUGH OR OUT SERVICE; INTERNAL POINT-TO-POINT SERVICE

Point-to-Point Transmission Service as Through or Out Service or Internal
Point-to-Point Service will be provided during and after the Transition Period
pursuant to the applicable terms and conditions of this Tariff.

19   Through or Out Service

19.1 Provision of Through or Out Service: Through or Out Service shall be
provided by the Participants through NEPOOL, and shall be available to any
Participant and to any Non-Participant which is an Eligible Customer.

19.2 Use of Through or Out Service: A Participant or Non-Participant shall take
Through or Out Service as Firm or Non-Firm Point-To-Point Transmission Service
for the transmission of any Unit Contract Entitlement or System Contract
transaction with respect to a transaction which requires the use of PTF if
either (i) the transaction goes through the NEPOOL Control Area and the Point(s)
of Receipt for NEPOOL are at one point on the NEPOOL Control Area boundary and
the Point(s) of Delivery for NEPOOL are at another point on the NEPOOL Control
Area boundary, as, for example, from the Maine Electric Power Company line or
New Brunswick to New York or from one point on the NEPOOL Control Area boundary
with New York to another point on the Control Area boundary with New York, or
(ii) the transaction goes out of the NEPOOL Control Area and the Point(s) of
Receipt are within the NEPOOL Control Area and the Point(s) of Delivery for
NEPOOL are at a NEPOOL Control Area boundary, as, for example, from Boston to
New York.

20  Internal Point-to-Point Service

20.1 Provision of Internal Point-to-Point Service: Internal Point-to-Point
Service shall be provided by the Participants through NEPOOL, and shall be
available to any Participant and to any Non-Participant which is an Eligible
Customer.

20.2 Use of Internal Point-to-Point Service: A Participant or Non-Participant
which is an Eligible Customer may take Internal Point-to-Point Service as Firm
or Non-Firm Point-to-Point Transmission Service with respect to any transaction
if the Point(s) of Receipt are at the NEPOOL Control Area boundary or within the
NEPOOL Control Area, and the Point(s) of Delivery are within the NEPOOL Control
Area, including Interchange Transactions meeting these requirements. Non-Firm
Internal Point-to-Point Service shall be available to an entity to serve its
load only if the entity (i) demonstrates to the satisfaction of the System
Operator a physical ability to interrupt its receipt of energy and/or capacity
and (ii) gives the System Operator physical control over such an interruption.

20.3 Use by a Transmission Customer: If a Transmission Customer elects to take
Internal Point-to-Point Service with respect to any Points of Delivery, it may
reserve transmission capacity for the service to cover both the delivery to it
of Energy and capacity covered by the Entitlements or System Contracts
designated by it in Completed Applications and the delivery to or from it in
Interchange Transactions of Energy and/or capacity. A transmission Customer
which takes Internal Point-to-Point Service to serve its load must also take
point-to-point service under the applicable Local Network Service tariff. A
load-serving Participant or Non-Participant which takes Internal Point-to-Point
Service in this manner must reserve each month sufficient Reserved Capacity,
after adjusting for any Backyard Generation, at a Point of Delivery to cover (i)
the maximum amount of Energy that it will receive in any hour, as determined
from meters and adjusted for losses, plus, in the case of a Participant, the
maximum amount of Operating Reserve assigned to that Participant by the System
Operator in any hour during the month, or (ii) the portion of its Installed
Capability Responsibility which must be satisfied with the resources covered by
its Completed Applications and from Interchange Transactions if such portion
exceeds the amount determined in accordance with clause (i) of this sentence.
Any load-serving entity may use Internal Point-to-Point Service to effect sales
in bilateral arrangements, whether or not it elects to take Point-to-Point
Service to serve its load.

21   Payment for Through or Out Service

Each Participant or Non-Participant which takes Firm or Non-Firm Through or Out
Service shall pay to NEPOOL a charge per Kilowatt of Reserved Capacity based on
an annual rate (the "T or O Rate") which shall be the highest of (i) the Pool
PTF Rate, or (ii) a rate which is derived from the annual incremental cost, not
otherwise borne by the Transmission Customer or a Generation Owner, of any new
facilities or upgrades that would not be required but for the need to provide
the requested service or (iii) a rate which is equal to the Pool's opportunity
cost (if and when available) capped at the cost of expansion. If at any time
NEPOOL proposes to charge a rate based on opportunity cost, it shall first file
with the Commission procedures for computing opportunity cost pricing for all
Transmission Customers. The Transmission Customer shall also be obligated to pay
any ancillary service charge and any applicable congestion or other uplift
charge required to be paid pursuant to Section 24 of this Tariff. The rate for
Firm Through or Out Service shall be as follows:

Per year      -   the T or O Rate
Per month     -   the T or O Rate divided by 12
Per week     -    the T or O Rate divided by 52
Per               day - the T or O Rate "per week" divided by 5; provided that
                  the rate for 5 to 7 consecutive days may not exceed the "per
                  week" rate.

The rate for Non-Firm Through or Out Service shall be as follows:

Per year      -    the T or O Rate
Per month     -    the T or O Rate divided by 12
Per week     -     the T or O Rate divided by 52
Per day     -      the T or O Rate "per week" divided by 7;
Per hour - the Non-Firm T or O Rate "per day" divided by 24.

The Pool PTF Rate shall be the Rate determined annually in accordance with
paragraph (2) of Schedule 8.

22  Payment for Internal Point-to-Point Service

Each Participant or Non-Participant which takes firm or non-firm Internal
Point-to-Point Service shall pay to NEPOOL a charge per Kilowatt of Reserved
Capacity based on an annual rate (the "IPTP Charge") which shall be the Internal
Point-to-Point Service Rate; provided that if either or both (i) a rate which is
derived from the annual incremental cost, not otherwise borne by the
Transmission Customer or a Generator Owner, of any new facilities or upgrades
that would not be required but for the need to provide the requested service, or
(ii) a rate which is equal to the Pool's opportunity cost (if and when
available) capped at the cost of expansion is greater than the Pool PTF Rate,
the IPTP Charge shall be the higher of such amounts; provided further that no
such charge shall be payable with respect to the use of Internal Point-to-Point
Service to effect a delivery to the NEPOOL power exchange in an Interchange
Transaction. If at any time NEPOOL proposes to charge a rate based on
opportunity cost, it shall first file with the Commission procedures for
computing opportunity cost pricing for all Transmission Customers. The
Transmission Customer shall also be obligated to pay any ancillary service
charges and any applicable congestion or other uplift charge required to be paid
pursuant to Sections 24, 25A and 25B of this Tariff. The charge for firm
Internal Point-to-Point Service shall be as follows:

Per year      -     the IPTP Charge
Per month     -     the IPTP Charge divided by 12
Per week     -     the IPTP Charge divided by 52
Per               day - the IPTP Charge "per week" divided by 5; provided that
                  the rate for 5 to 7 consecutive days may not exceed the "per
                  week" rate.

The rate for non-firm Internal Point-to-Point Service shall be as follows:

Per year      -     the IPTP Charge
Per month     -     the IPTP Charge divided by 12
Per week     -     the IPTP Charge divided by 52
Per day     -     the IPTP Charge "per week" divided by 7;
Per hour - the non-firm IPTP Charge "per day" divided by 24.

If several power marketers or other entities are involved in a series of sales
of the same energy and/or capacity, transmission service shall be required only
with respect to the delivery to the ultimate wholesale buyer, and if an Internal
Point-to-Point Service charge is payable with respect to the transaction, the
charge shall be paid only with respect to the delivery to, and absent other
arrangements the charge shall be paid by, the ultimate wholesale buyer.

23 Reservation of Capacity for Point-to-Point Transmission Service Compliance
with the applicable requirements of Part V of this Tariff is required for the
initiation of Through or Out Service or Internal Point-to- Point Service.


IV.  SERVICE DURING THE TRANSITION PERIOD; CONGESTION COSTS; EXCEPTED
TRANSACTIONS

The six-year Transition Period, and additional arrangements to be in effect
during the succeeding five-year period, will permit the phase-in on a negotiated
basis of the Tariff rates.

24   Transition Arrangements

The transition arrangements include (i) the treatment provided for certain
Excepted Transactions in Section 25, (ii) the provisions in Schedule 9 for the
phase-in of the rates for Regional Network Service, and (iii) the rules provided
in Sections 16.3 and 16.6 of the Agreement for the distribution and application
of revenues received by NEPOOL on behalf of the Participants from the payment of
the Tariff rates.

25   Congestion Costs and Congestion Revenue

(1) Until the earlier of the CMS/MSS Effective Date or the implementation
effective date of an order issued by the Commission directing a different
allocation of Congestion Costs, if limitations in available transmission
capacity over any interface within the NEPOOL Control Area in any hour require
that the System Operator dispatch resources out-of-merit, the System Operator
shall determine for the affected area or areas the aggregate of the Congestion
Costs for all such out-of-merit resources for the hour. The Congestion Costs for
each hour in any month shall be paid as a transmission charge and included in
the charge for Regional Network Service or Internal Point-to-Point Service or
Through or Out Service, whichever is applicable, by those Participants and
Non-Participants which are obligated to pay a Regional Network Service, Internal
Point-to-Point Service or Through or Out Service charge for the month, in
accordance with the following formula:

(EQUATION)

in which

CH =  the amount to be paid by a Participant or Non-Participant for the hour;

CC =  the Congestion Costs for the hour to be allocated and paid pursuant to
this Section 24(a);

HLi = the Network Load of the Participant or Non-Participant for the hour, if it
is obligated to pay a Regional Network Service charge for the month;

HL = the aggregate of the Network Loads for the hour of all Participants and
Non-Participants which are obligated to pay a Regional Network Service charge
for the month;

RCi = the Reserved Capacity, if any, for Internal Point-to-Point Service or
Through or Out Service of the Participant or Non-Participant for the hour; and

RC = the aggregate Reserved Capacity, if any, for Internal Point-to-Point
Service or Through or Out Service of all Participants and Non-Participants for
the hour.

This Section 24(a) shall terminate on the implementation effective date of an
order issued by the Commission directing a different allocation of Congestion
Costs.

As used in this Section 24(a), the "Congestion Cost" of an out-of-merit resource
for an hour means the product of (i) the difference between its Dispatch Price
and the Energy Clearing Price for the hour, times (ii) the number of megawatt
hours of out-of-merit generation produced by the resource for the hour. The
"Dispatch Price" of an out-of-merit resource for an hour is the price to provide
energy from the resource, as determined pursuant to market operation rules
approved by the NEPOOL Regional Market Operations Committee to incorporate the
Bid Price for such energy and any loss adjustments, if and as appropriate under
such market operation rules. The "Energy Clearing Price" for an hour is the
price determined for the hour in accordance with Section 14.8 of the Agreement.

26 (b) On and after the CMS/MSS Effective Date, when Congestion exists, the
Congestion Cost shall be reflected in Locational Prices calculated in accordance
with Section 14A.12 of the Agreement and Schedule 13 of the Tariff.

Congestion Cost shall be recovered from Non-Participant Transmission Customers
taking service under the Tariff in accordance with Schedule 13 of the Tariff.
Congestion Cost shall be recovered from Participants in accordance with Section
14A.17 of the Agreement.

Congestion Revenue shall be collected and maintained in a Congestion Revenue
Fund in accordance with Section E of Schedule 14 of the Tariff.

A system of Financial Congestion Rights shall be implemented and administered in
accordance with Schedule 14 of the Tariff.

A system of Auction Revenue Rights shall be implemented and administered in
accordance with Schedule 15 of the Tariff.

27   Excepted Transactions

Notwithstanding any other section of the Tariff but except as otherwise provided
in Section 25A or 25B of this Tariff, the power transfers and other uses of the
NEPOOL Transmission System effected under the transmission agreements in effect
on November 1, 1996 specified below ("Excepted Transactions") will continue to
be effected under such agreements for the respective periods specified below
rather than under this Tariff, but not thereafter, and such transfers and other
uses will continue to be effected after such period, if still occurring, under
this Tariff. Participants receiving service under the agreements listed in
Attachment G-1 shall not be required to take Local Network Service for such
transfers and other uses. The period for which each Excepted Transaction will
continue to be effected under such existing transmission agreements shall be:

(1) for the period to and including February 28, 2001, the following transfers
pursuant to Section 17 of the Agreement:

(a)  the transfer to a Participant's system within the NEPOOL Control Area of
its ownership interest in a Pool-Planned Unit which is off its system;

(b) the transfer to a Participant's system within the NEPOOL Control Area of its
Unit Contract Entitlement, under a contract entered into by it on or before
November 1, 1996, in a Pool-Planned Unit which is off its system; and

(c) the transfer to a Participant's system within the NEPOOL Control Area of its
Entitlement in a purchase (including a purchase under the HQ Phase II Firm
Energy Contract) from Hydro-Quebec under a contract entered into by it on or
before November 1, 1996, where the line over which the transfer is made into New
England is the HQ Interconnection;

(2) for the period to and including February 28, 2001, the transfer to a
Participant's system within the NEPOOL Control Area of its Unit Contract
Entitlement in the Vermont Yankee Nuclear Power Corporation unit or the Pilgrim
1 unit; provided the transfer is pursuant to a transmission agreement in effect
on November 1, 1996 and is to the entity which was receiving the service on
November 1, 1996; and

(3) for the period from the effective date of the Tariff until the termination
of the transmission agreement:

(a) transfers and other uses within the NEPOOL Control Area, as of November 1,
1996, of the NEPOOL Transmission System under the support or exchange agreements
specified in Attachment G;

(b) transfers and other uses within the NEPOOL Control Area, as of November 1,
1996, of the NEPOOL Transmission System under the comprehensive network service
agreements specified in Attachment G-1; and

(c) transfers and other uses within the NEPOOL Control Area, as of November 1,
1996, of the NEPOOL Transmission System under the other transmission agreements
or tariff service agreements specified in Attachment G.

The Management Committee is authorized to add additional agreements to
Attachment G if they have been inadvertently omitted. Except as otherwise
provided in Sections 25A or 25B below, the transfers or other uses under any of
the transmission agreements covering the transfers referred to in paragraphs
(1), (2) and (3) above shall be in accordance with the terms of the transmission
agreement as in effect on November 1, 1996, or a modification of the terms which
is expressly provided for in the agreement as in effect on November 1, 1996 and
is accomplished without amendment of the agreement or by an amendment entered
into after November 1, 1996 that does not extend the term of the agreement or
increase the amount of the service. Further, except as otherwise provided in
Sections 25A or 25B below, and notwithstanding the foregoing restriction on the
amendment after November 1, 1996 of transmission agreements with respect to
Excepted Transactions, the transmission arrangements for the Masspower and
Altresco facilities may continue as Excepted Transactions in accordance with
transmission agreement amendments or memoranda of understanding entered into as
of December, 1996 which do not extend the term of the agreements.

For the purpose of determining priorities under this Tariff, Excepted
Transactions shall have the same priority as Firm Point-To-Point Transmission
Service transactions for resources in existence on the effective date of this
Tariff which are effected as Regional Network Service or as Internal Point-
to-Point Service or as Through or Out Service.

When the transfers and other uses effected under the transmission agreements
that are Excepted Transactions cease to be Excepted Transactions before the end
of their term, except as therein provided in Sections 25A or 25B below the
transactions shall be effected under this Tariff and under any applicable Local
Network Service Tariff, to the extent appropriate, but the transactions shall
continue to have a priority not less than the priority that they would have had
if Regional Network Service had been used for the transactions from the
effective date of this Tariff. New transactions entered into after November 1,
1996 under umbrella tariff agreements then in effect will not be Excepted
Transactions.

Notwithstanding the foregoing or any other section of the Tariff, existing
agreements which provide for the support of the costs of transmission facilities
or for the interconnection of transmission facilities shall continue in effect
until the termination of the agreement to provide for such support or for the
rights and obligations of the parties with respect to the interconnection
arrangements. Attachment G-2 lists certain additional agreements covering
transactions, the status of which is described in the Attachment.

25A  Phase I Credit and Uplift Charge With Respect to Excepted Transactions

Notwithstanding the provisions of any other Section of this Tariff, the
following Participants will receive a total credit of $12,012,000 to settle
certain disputes regarding Excepted Transactions, allocated as set forth below
(defined for purposes of this Section 25A only as the Participant's "Phase I
Credit"):

Bangor Hydro-Electric Company     $     896,000

Massachusetts Municipal
Wholesale Electric Company
clients                           $     6,182,400

Braintree Electric Light
Department                        $     666,400

Reading Municipal Light
Department                        $     1,430,240

Taunton Municipal Lighting
Plant                             $     479,360

United Illuminating Company       $     280,000

Fitchburg Gas and Electric
Light Company                     $     117,600

Unitil Power Corporation          $     1,960,000

The Phase I Credit for each of the Participants identified above shall be
provided as reductions in each entity's NEPOOL bill equal to one-twelfth (1/12)
of the amount identified above commencing with and including the bill covering
the period June 1 - 30, 1999 and ending with the bill covering the period May 1
- - May 31, 2000.

The total $12,012,000 Phase I Credit shall be funded with twelve equal monthly
uplift charges (the "Phase I Uplift") which will be in effect for the twelve
month period beginning June 1, 1999 and continuing through May 31, 2000, and
which will be included in the bills corresponding to this time period. Each RNS
and Internal Point-to-Point Transmission Customer under the NEPOOL Tariff shall
pay the monthly Phase I Uplift charge determined as follows:

1) A Transmission Customer's monthly share of the Phase I Uplift charge shall be
determined in accordance with the following formula:

PIU     =     $998,387 x [(ULi + URCi + UAUi) / (UL + URC + UAU)]

Where:

PIU = The Phase I Uplift Charge for the Participant or Non-Participant per
month.

$998,387  =     The total monthly Phase I Uplift charge, exclusive of Taunton's
portion of the charge, calculated as follows:  ($12,012,000 / 12) - $2,613.

ULi     =     Monthly Uplift Network Load of a Participant or Non-Participant
for the month

UL     =     Aggregate of the Uplift Network Loads of all Participants or
Non-Participants for the month

URCi = The sum of a Participant's or Non-Participant's Maximum Reserved Capacity
for Internal Point-to-Point Service for each load served within a Local Network
or Network(s) during the month

URC     =     Aggregate of URCi for all Participants and Non-Participants

UAUi = The sum of a Participant's or Non-Participant's Maximum Unauthorized Use
associated with Internal Point-to-Point Service for each load served within a
Local Network or Network(s) during the month

UAU     =     Aggregate of UAUi for all Participants and Non-Participants

The monthly Uplift Network Load (ULi) for each Non-Participant shall be its
Network Load for the month.The monthly Uplift Network Load (ULi) for each
Participant shall be the "1998 12 CP Network Load" identified in connection with
the determination of the Pool PTF Rate to become effective June 1, 1999, on a
basis comparable to the "1997 12 CP Network Load" reflected in Attachment K of
this Tariff, except as follows:

1) The total Uplift Load (ULi + URCi + UAUi) for the Vermont Electric Power
Company shall be zero.

2) The total Uplift Load (ULi + URCi + UAUi) for Bangor Hydro-Electric Company
shall be 50 MW.

3) The monthly Uplift Network Load (ULi) for Commonwealth Electric Company and
Cambridge Electric Light Company shall be one half of the value reflected in the
"1998 12 CP Network Load" for such companies (excluding the load for Nantucket).

4) The monthly Uplift Network Load (ULi) for Montaup Electric Company and the
affiliated Eastern Utilities Associates Operating Companies shall be one half of
the value reflected in the "1998 12 CP Network Load" for "Eastern Utilities
Associates."

5) The Taunton Municipal Lighting Plant's monthly payment for the Phase I Uplift
shall be limited to $2,613.

25B Phase II Credit and Uplift Charge With Respect to Certain Excepted
Transactions Notwithstanding the provisions of any other Section of this Tariff,
the Participants identified in Section 25A of this Tariff receiving a Phase I
Credit as set forth in that Section, so long as they remain RNS Transmission
Customers under the Tariff, shall receive a credit (defined for purposes of this
Section 25B only as a "Phase II Credit") to their NEPOOL transmission bills
equal to the amounts they are assessed under the contracts and arrangements for
the month within the scope of Sections 25(1) and 25(2) of the NEPOOL Tariff
(specifically PPU, Yankee, Pilgrim and HQ II), for all charges assessed during
the period March 1, 1999 through and including February 28, 2001 (defined for
purposes of this Section 25B only as "Phase II").

The Phase II Credit for each of the Participants that are to receive the Phase
II Credit shall be provided as reductions in that Participant's NEPOOL bill
commencing with and including the bill covering the period beginning March 1,
1999 and terminating with the bill for the period through February 28, 2001.

The total Phase II Credit shall be funded with a monthly uplift charge (the
"Phase II Uplift") which will be in effect for the twenty-four-month period
beginning June 1, 1999 and continuing through May 31, 2001, and which will be
included in the bills corresponding to this time period. Each RNS and Internal
Point-to-Point Transmission Customer under the NEPOOL Tariff shall pay a share
of the monthly Phase II Uplift charge, determined as follows:

PIIUi  =     $Y x [(PIILi + URCi + UAUi) / (PIIL + URC + UAU)]

Where:

PIIUi  =     The Phase II Uplift charge for the Participant or Non-Participant
for the month

$Y = Sum of the EHV PTF, Vermont Yankee and Pilgrim transmission charges for the
month for Bangor Hydro-Electric Company, Massachusetts Municipal Wholesale
Electric Company, Braintree Electric Light Department, Reading Municipal Light
Department and Taunton Municipal Lighting Plant, the United Illuminating Company
and Unitil Power Corp.

PIILi     =     Phase II Uplift Network Load of a Participant or Non-Participant
for the month

UL     =     Aggregate of the Phase II Uplift Network Loads of all Participants
or Non-Participants for the month

URCi = The sum of a Participant's or Non-Participant's maximum Reserved Capacity
for Internal Point-to-Point Service for each load served within a Local Network
or Network(s) during the month

URC  =     Aggregate of URCi for all Participants and Non-Participants

UAUi = The sum of a Participant's or Non-Participant's Maximum Unauthorized Use
associated with Internal Point-to-Point Service for each load served within a
Local Network or Network(s) during the month

UAU     =     Aggregate of UAUi for all Participants and Non-Participants

The Phase II Uplift Network Load (PIIli) of a Transmission Customer in a month
shall be its Network Load in that month, except as follows:

1)     The Phase II Uplift Network Load (PIILi) for the Vermont Electric Power
Company shall be zero.

2)     The Phase II Uplift Network Load (PIILi) for Central Maine Power Company
shall be zero.

3) The Phase II Uplift Network Load (PIIli) for Bangor Hydro-Electric Company
shall be 50 MW.

4) The total Phase II Uplift Load (PIILi) and URCi) shall be one half of the sum
of the Network Load and Reserved Capacity for Internal Point-to-Point Service
for the following Transmission Customers:

Commonwealth Electric Company
Cambridge Electric Company
Canal Electric Company
Montaup Electric Company on its own behalf and on behalf of the operating
affiliates of Eastern Utilities Associates

All Internal Point-to-Point Service shall be deemed to be under the NEPOOL and
LNS Tariffs rather than under an Excepted Transaction.

V.     POINT-TO-POINT TRANSMISSION SERVICE

Preamble

Firm or Non-Firm Point-to-Point Transmission Service shall be reserved by all
Transmission Customers, whether Participants or Non-Participants, for all new
transfers to be effected as Internal Point-to-Point Service or as Through or Out
Service, pursuant to the applicable terms and conditions of Part III and this
Part V of the Tariff. Point-to-Point Transmission Service is the service
required for the receipt of capacity and/or energy at designated Point(s) of
Receipt and the transmission of such capacity and/or energy to designated
Point(s) of Delivery.

28   Scope of Application of Part V

Except for the deposit and creditworthiness requirement of Section 31.3, which
will apply only to Non-Participants, all of the requirements of this Part V
shall be fully applicable to both Participants and Non-Participants requesting
Internal Point-to-Point Service or Through or Out Service. Alternative deposit
and creditworthiness requirements are applicable to Participants under the
Financial Assurance Policy for NEPOOL Members which is set forth in Attachment L
hereto. Reservations under the Tariff shall not be required for the use of
Internal Point-to-Point Service for deliveries to the NEPOOL power exchange in
Interchange Transactions from a Point of Receipt within the NEPOOL Control Area,
but are required for the use of In Service for such deliveries from a Point of
Receipt at the NEPOOL Control Area boundary.

29   Nature of Firm Point-To-Point Transmission Service

29.1 Term: The minimum term of Firm Point-To-Point Transmission Service shall be
one day and the maximum term shall be that specified in the Service Agreement.

29.2 Reservation Priority: Long-Term Firm Point-To-Point Transmission Service
shall be available to Participants and Non-Participants on a first-come,
first-served basis, i.e., in the chronological sequence in which each
Transmission Customer's application for reserved service is received by the
System Operator pursuant to Section 31. Reservations for Short-Term Firm
Point-To-Point Transmission Service will be conditional based upon the length of
the requested transaction. If the NEPOOL Transmission System becomes
oversubscribed, requests for longer term service may preempt requests for
shorter term service up to the following deadlines: one day before the
commencement of daily service, one week before the commencement of weekly
service, and one month before the commencement of monthly service. Before the
conditional reservation deadline, if available transmission capability is
insufficient to satisfy all Applications, an Eligible Customer with a
reservation for shorter term service has the right of first refusal to match any
longer term reservation before losing its reservation priority. A longer term
competing request for Short-Term Firm Point-To-Point Transmission Service will
be granted if the Eligible Customer with the right of first refusal does not
agree to match the competing request within 24 hours (or earlier if necessary to
comply with the scheduling deadlines provided in Section 27.8) from being
notified by the System Operator of a longer-term competing request for
Short-Term Firm Point-To-Point Transmission Service. After the conditional
reservation deadline, service will commence pursuant to the terms of Part III of
this Tariff. Firm Point-To-Point Transmission Service will always have a
reservation priority over non-firm Point-To-Point Transmission Service under the
Tariff. All Long-Term Firm Point-To-Point Transmission Service will have
reservation priority equal to Native Load Customers, Network Customers and
customers for Excepted Transactions. Reservation priorities for existing firm
service customers, including customers receiving service with respect to
Excepted Transactions, are provided in Section 3.2.

29.3 Use of Firm Point-To-Point Transmission Service by the Participants That
Own PTF: A Transmission Provider that owns PTF will be subject to the rates,
terms and conditions of this Tariff when making Third-Party Sales to be
transmitted as Point-to-Point Transmission Service under (i) agreements executed
after November 1, 1996 or (ii) agreements executed on or before November 1, 1996
to the extent that the Commission requires them to be unbundled, by the date
specified by the Commission. A Transmission Provider that owns PTF will maintain
separate accounting, pursuant to Section 8, for any use of Firm Point-To-Point
Transmission Service to make Third-Party Sales to the extent not paid for under
this Tariff.

29.4 Service Agreements: A standard form Firm Point-To-Point Transmission
Service Agreement (Attachment A) will be offered to an Eligible Customer when it
submits a Completed Application for Long-Term or Short-Term Firm Point-To- Point
Transmission Service to be transmitted pursuant to this Tariff. Executed Service
Agreements that contain the information required under this Tariff will be filed
with the Commission in compliance with applicable Commission regulations.

29.5 Transmission Customer Obligations for Facility Additions or Redispatch
Costs: In cases where it is determined that the NEPOOL Transmission System is
not capable of providing new Firm Point-To-Point Transmission Service without
(1) degrading or impairing the reliability of service to Native Load Customers,
Network Customers, customers taking service for Excepted Transactions and other
Transmission Customers taking Firm Point-To-Point Transmission Service, or (2)
interfering with a Participant's ability to meet prior firm contractual
commitments to others, the Transmission Providers will be obligated to arrange
to expand or upgrade PTF for Long-Term Firm Service pursuant to the terms of
Section 33. The Transmission Customer must agree to compensate the Transmission
Providers or any other entity designated to effect construction through the
System Operator for any necessary transmission facility additions or upgrades
pursuant to the terms of Section 39. To the extent the System Operator can
relieve any system constraint more economically by redispatching the
Participants' resources, rather than through construction of additions or
upgrades, it shall do so, provided that the Eligible Customer agrees to
compensate the Participants pursuant to the terms of Section 39. Any redispatch,
addition or upgrade or Direct Assignment Facilities costs to be charged to the
Transmission Customer on an incremental basis under this Tariff will be
specified in the Service Agreement prior to initiating service.

29.6 Curtailment of Firm Transmission Service: In the event that a Curtailment
on the NEPOOL Transmission System, or a portion thereof, is required to maintain
reliable operation of the system, the Curtailment will be made on a
non-discriminatory basis to the transaction(s) that effectively relieve the
constraint. If multiple transactions require Curtailment, to the extent
practicable and consistent with Good Utility Practice, the System Operator will
curtail service to Network Customers and Transmission Customers taking Firm
Point- To-Point Transmission Service on a non-discriminatory basis. All
Curtailments will be made on a non-discriminatory basis; however, Non-Firm
Point-To-Point Transmission Service shall be subordinate to Firm Transmission
Service. When the System Operator determines that an electrical emergency exists
on the NEPOOL Transmission System and implements emergency procedures to effect
a Curtailment of Firm Transmission Service, the Transmission Customer shall make
the required reductions upon the System Operator's request. However, NEPOOL
reserves the right to effect a Curtailment, in whole or in part, of any Firm
Transmission Service provided under this Tariff when, in the System Operator's
sole discretion, an emergency or other unforeseen condition impairs or degrades
the reliability of the NEPOOL Transmission System. The System Operator will
notify all affected Transmission Customers in a timely manner of any scheduled
Curtailments. In the event the System Operator exercises its right to effect a
Curtailment, in whole or part, of Firm Point-to-Point Transmission Service, no
credit or other adjustment shall be provided as a result of the Curtailment with
respect to the charge payable by the Customer.

29.7   Classification of Firm Point-To-Point Transmission Service:

(a) A Transmission Customer taking Firm Point-To-Point Transmission Service may
(1) change its Points of Receipt and Delivery to obtain service on a non- firm
basis consistent with the terms of Section 36.1 or (2) request a modification of
the Points of Receipt or Delivery on a firm basis pursuant to the terms of
Section 36.2; provided that if any Transmission Provider or its designee
constructed new facilities or upgraded facilities to accommodate the original
firm service, such Transmission Provider or its designee shall continue to be
compensated for its facility costs by the Transmission Customer.

(b) A Transmission Customer may purchase transmission service to make sales from
multiple generating units or contracts that are on the NEPOOL Transmission
System. For such purchase of transmission service the Transmission Customer
shall specify a Location for each generating unit or contract.

(c) Deliveries will be provided from the Point(s) of Receipt to the Point(s) of
Delivery. Each Point of Receipt and Point of Delivery at which firm transmission
capacity is reserved for Long-Term Firm Point-to-Point Transmission Service by
the Transmission Customer shall be set forth in the Service Agreement for such
Service along with a corresponding capacity reservation. The greater of either
(1) the sum of the capacity reservations at the Point(s) of Receipt, or (2) the
sum of the capacity reservations at the Point(s) of Delivery shall be the
Transmission Customer's Reserved Capacity. The Transmission Customer will be
billed for its Reserved Capacity under the terms of Section 20 or Section 21,
whichever is applicable. The Transmission Customer's Use may not exceed its firm
capacity reserved at each Point of Receipt and each Point of Delivery except as
otherwise specified in Section 36. In the event that the Use by a Transmission
Customer (including Third-Party Sales by the Participants) exceeds that
Transmission Customer's Reserved Capacity at any Point of Receipt or Point of
Delivery in any hour, it shall pay 200% of the charge which is otherwise
applicable for each Kilowatt of the excess. In addition, the System Operator
will record all instances in which a Transmission Customer's Use exceeds that
Transmission Customer's firm Reserved Capacity, and if in any calendar year more
than 10 such instances occur with respect to any single Transmission Customer,
then the System Operator may require such Transmission Customer to apply for
additional Firm Point-to-Point Transmission Service under the Tariff in an
amount equal to the greatest amount of the excess of such Transmission
Customer's Use over its firm Reserved Capacity for the remainder of that
calendar year. Charges for such additional Firm Point-to-Point Transmission
Service will relate back to the first day of the month following the month in
which the System Operator notifies such Transmission Customer that it is subject
to the provisions of this paragraph.

29.8   Scheduling of Firm Point-To-Point Transmission Service:

(a) Until the CMS/MSS Effective Date, unless other schedules are permitted
pursuant to NEPOOL System Rules, schedules for the Transmission Customer's Firm
Point-To-Point Transmission Service (including schedules for resources to be
self scheduled) must be submitted to the System Operator no later than noon of
the day prior to commencement of such service. In the cases which are bid into
the power exchange, the Energy bid price must be submitted to the System
Operator by the noon deadline. Hour-to-hour schedules of any capacity and energy
that is to be delivered must be stated in increments of 1000 kW per hour.
Transmission Customers with multiple requests for Firm Point-To-Point
Transmission Service at a Point of Receipt, each of which request is under 1000
kW per hour, may consolidate their service requests at a common Point of Receipt
into units of 1000 kW per hour for scheduling and billing purposes. Scheduling
changes will be permitted up to thirty-five minutes before the start of the next
clock hour, provided that the Delivering Party and Receiving Party also agree to
the schedule modification. The System Operator will furnish to the Delivering
Party's system operator hour-to-hour schedules equal to those furnished by the
Receiving Party (unless reduced for losses) and will deliver the capacity and
energy provided by such schedules. Should the Transmission Customer, Delivering
Party or Receiving Party revise or terminate any schedule, such party shall
immediately notify the System Operator, and the System Operator will have the
right to adjust accordingly the schedule for capacity and energy to be received
and to be delivered.

(b) On and after the CMS/MSS Effective Date, unless other schedules are
permitted pursuant to the NEPOOL System Rules, Day-Ahead Market schedules for
the Transmission Customer's Firm Point-To-Point transmission service must be
submitted to the System Operator no later than noon of the day prior to the
Dispatch Day. The Supply Offers and Demand Bids must be submitted to the System
Operator by the noon deadline. The System Operator will furnish to the
Delivering Party's system operator hour-to-hour schedules equal to those
furnished by the Receiving Party and will deliver the capacity and Energy
provided by such schedules. Should the Transmission Customer, Delivering Party
or Receiving Party revise or terminate any schedule, such party shall
immediately notify the System Operator, and the System Operator will have the
right to adjust accordingly the schedule for capacity and Energy to be received
and to be delivered.

     On and after the CMS/MSS Effective Date, unless other schedules are
permitted pursuant to the NEPOOL System Rules, Real-Time Market schedules for
the Transmission Customer's Firm Point-To-Point transmission service must be
submitted to the System Operator in accordance with the NEPOOL System Rules. The
Supply Offers and Demand Bids must be submitted to the System Operator in
accordance with the NEPOOL System Rules. Scheduling changes will be permitted up
to thirty-five minutes before the start of the next clock hour, provided that
the Delivering Party and Receiving Party also agree to the schedule
modification. The System Operator will furnish to the Delivering Party's system
operator hour-to-hour schedules equal to those furnished by the Receiving Party
and will deliver the capacity and Energy provided by such schedules. Should the
Transmission Customer, Delivering Party or Receiving Party revise or terminate
any schedule, such party shall immediately notify the System Operator, and the
System Operator will have the right to adjust accordingly the schedule for
capacity and Energy to be received and to be delivered.

30   Nature of Non-Firm Point-To-Point Transmission Service

30.1 Term: Non-Firm Point-To-Point Transmission Service will be available for
periods ranging from one hour to one month. However, a Purchaser of Non-Firm
Point-To-Point Transmission Service will be entitled to reserve a sequential
term of service (such as a sequential monthly term without having to wait for
the initial term to expire before requesting another monthly term) so that the
total time period for which the reservation applies is greater than one month,
subject to the requirements of Section 32.3.


30.3 Reservation Priority: Non-Firm Point-To-Point Transmission Service shall be
available from transmission capability in excess of that needed for reliable
service to Native Load Customers, Network Customers, customers for Excepted
Transactions and other Transmission Customers taking Long-Term and Short-Term
Firm Point-To-Point Transmission Service. A higher priority will be assigned to
reservations with a longer duration of service. In the event the NEPOOL
Transmission System is constrained, competing requests of equal duration will be
prioritized based on the highest price offered by the Eligible Customer for the
Transmission Service, or in the event the price for all Eligible Customers is
the same, will be prioritized on a first-come, first-served basis i.e., in the
chronological sequence in which each Customer has reserved service. Eligible
Customers that have already reserved shorter term service have the right of
first refusal to match any longer term reservation before being preempted. A
longer term competing request for Non- Firm Point-To-Point Transmission Service
will be granted if the Eligible Customer with the right of first refusal does
not agree to match the competing request: (a) immediately for hourly Non-Firm
Point-To-Point Transmission Service after notification by the System Operator;
and (b) within 24 hours (or earlier if necessary to comply with the scheduling
deadlines provided in Section 28.6) for Non-Firm Point-To-Point Transmission
Service other than hourly transactions after notification by the System
Operator. Secondary transmission service for Network Customers pursuant to
Section 40.4 will have a higher priority than any Non-Firm Point-To-Point
Transmission Service. Non-Firm Point-To-Point Transmission Service over
secondary Point(s) of Receipt and Point(s) of Delivery will have the lowest
reservation priority under this Tariff.

30.4 Use of Non-Firm Point-To-Point Transmission Service by the Transmission
Provider: A Transmission Provider will be subject to the rates, terms and
conditions of this Tariff when making Third-Party Sales to be transmitted as
Non-Firm Point-to-Point Transmission Service under (i) agreements executed after
November 1, 1996 or (ii) agreements executed on or before November 1, 1996 to
the extent that the Commission requires them to be unbundled, by the date
specified by the Commission. A Transmission Provider will maintain separate
accounting, pursuant to Section 8, for any use of Non-Firm Point-To- Point
Transmission Service to make Third-Party Sales, to the extent not paid for under
this Tariff.

30.5 Service Agreements: The System Operator shall offer a standard form
Point-To-Point Transmission Service Agreement (Attachment A, modified to cover
non-firm service) to an Eligible Customer when the Eligible Customer first
submits a Completed Application for Non-Firm Point-To-Point Transmission Service
pursuant to the Tariff. Executed Service Agreements that contain the information
required under this Tariff shall be filed with the Commission in compliance with
applicable Commission regulations.

30.6 Classification of Non-Firm Point-To-Point Transmission Service: Non-Firm
Point-To-Point Transmission Service shall be offered under applicable terms and
conditions contained in Part III of this Tariff. The NEPOOL Participants
undertake no obligation under this Tariff to plan the NEPOOL Transmission System
in order to have sufficient capacity for Non-Firm Point-To-Point Transmission
Service. Parties requesting Non-Firm Point-To-Point Transmission Service for the
transmission of firm power do so with the full realization that such service is
subject to availability and to Curtailment or Interruption under the terms of
this Tariff. In the event that the Use by a Transmission Customer (including
Third-Party Sales by a Participant) exceeds that Transmission Customer's
non-firm Reserved Capacity at any Point of Receipt or Point of Delivery, it
shall pay 200% of the charge which is otherwise applicable for each Kilowatt of
the excess. In addition, the System Operator will record all instances in which
a Transmission Customer's Use exceeds that Transmission Customer's non-firm
Reserved Capacity, and if in any calendar year more than 10 such instances occur
with respect to any single Transmission Customer, then the System Operator may
require such Transmission Customer to apply for additional Non-Firm
Point-to-Point Transmission Service under the Tariff in an amount equal to the
greatest amount of the excess of such Transmission Customer's Use over its
non-firm Reserved Capacity for the remainder of that calendar year. Charges for
such additional Non-Firm Point-to-Point Transmission Service will relate back to
the first day of the month following the month in which the System Operator
notifies such Transmission Customer that it is subject to the provisions of this
paragraph.

(a) Non-Firm Point-To-Point Transmission Service shall include transmission of
energy on an hourly basis and transmission of scheduled short-term capacity and
energy on a daily, weekly or monthly basis, but not to exceed one month's
reservation for any one Application.

(b) Each Point of Receipt at which non-firm transmission capacity is reserved by
the Transmission Customer shall be set forth in the Application along with a
corresponding capacity reservation associated with each Point of Receipt.

30.7     Scheduling of Non-Firm Point-To-Point Transmission Service:

(a) Until the CMS/MSS Effective Date, unless other schedules are permitted
pursuant to NEPOOL System Rules, schedules for Non-Firm Point-To-Point
Transmission Service must be submitted to the Transmission Provider no later
than noon of the day prior to commencement of such service. Schedules submitted
after noon will be accommodated, if practicable. Hour-to-hour schedules of
energy that is to be delivered must be stated in increments of 1,000 kW per
hour. Transmission Customers within the NEPOOL Control Area with multiple
requests for Transmission Service at a Point of Receipt, each of which is under
1,000 kW per hour, may consolidate their schedules at a common Point of Receipt
into units of 1,000 kW per hour. Scheduling changes will be permitted up to
thirty-five minutes before the start of the next clock hour provided that the
Delivering Party and Receiving Party also agree to the schedule modification.
The System Operator will furnish to the Delivering Party's system operator,
hour-to-hour schedules equal to those furnished by the Receiving Party (unless
reduced for losses) and shall deliver the capacity and energy provided by such
schedules. Should the Transmission Customer, Delivering Party or Receiving Party
revise or terminate any schedule, such party shall immediately notify the System
Operator, and the System Operator shall have the right to adjust accordingly the
schedule for capacity and energy to be received and to be delivered.

(b) On and after the CMS/MSS Effective Date, unless other schedules are
permitted pursuant to the NEPOOL System Rules, Day-Ahead Market schedules for
Non-Firm Point-To-Point Transmission Service must be submitted to the
Transmission Provider no later than noon of the day prior to the Dispatch Day.
The Supply Offers and Demand Bids must be submitted to the System Operator by
the noon deadline. The System Operator will furnish to the Delivering Party's
system operator hour-to-hour schedules equal to those furnished by the Receiving
Party and shall deliver the capacity and Energy provided by such schedules.
Should the Transmission Customer, Delivering Party or Receiving Party revise or
terminate any schedule, such party shall immediately notify the System Operator,
and the System Operator shall have the right to adjust accordingly the schedule
for capacity and Energy to be received and to be delivered.

     On and after the CMS/MSS Effective Date, unless other schedules are
permitted pursuant to the NEPOOL System Rules, Real-Time Market schedules for
Non-Firm Point-To-Point Transmission Service must be submitted to the
Transmission Provider in accordance with the NEPOOL System Rules. The Supply
Offers and Demand Bids must be submitted to the System Operator in accordance
with the Market Rules. Scheduling changes will be permitted up to thirty-five
minutes before the start of the next clock hour provided that the Delivering
Party and Receiving Party also agree to the schedule modification. The System
Operator will furnish to the Delivering Party's system operator hour-to-hour
schedules equal to those furnished by the Receiving Party and shall deliver the
capacity and Energy provided by such schedules. Should the Transmission
Customer, Delivering Party or Receiving Party revise or terminate any schedule,
such party shall immediately notify the System Operator, and the System Operator
shall have the right to adjust accordingly the schedule for capacity and Energy
to be received and to be delivered.

30.8 Curtailment or Interruption of Service: The System Operator reserves the
right to effect a Curtailment, in whole or in part, of Non-Firm Point-To-Point
Transmission Service provided under this Tariff for reliability reasons when an
emergency or other unforeseen condition threatens to impair or degrade the
reliability of the NEPOOL Transmission System. The System Operator reserves the
right to effect an Interruption, in whole or in part, of Non-Firm Point-To-Point
Transmission Service provided under this Tariff for economic reasons in order to
accommodate (1) a request for Firm Transmission Service, (2) a request for
Non-Firm Point-To-Point Transmission Service of greater duration, or (3)
transmission service for Network Customers. The System Operator also will
discontinue or reduce service to the Transmission Customer to the extent that
deliveries for transmission are discontinued or reduced at the Point(s) of
Receipt. Where required, Curtailments or Interruptions will be made on a
non-discriminatory basis to the transaction(s) that effectively relieve the
constraint; however, Non-Firm Point-To-Point Transmission Service shall be
subordinate to Firm Transmission Service. If multiple transactions require
Curtailment or Interruption, to the extent practicable and consistent with Good
Utility Practice, Curtailments or Interruptions will be made to transactions of
the shortest term (e.g., hourly non-firm transactions will be Curtailed or
Interrupted before daily non-firm transactions and daily non-firm transactions
will be Curtailed or Interrupted before weekly non-firm transactions).
Transmission service for Network Customers will have a higher priority than any
Non-Firm Point-To-Point Transmission Service under this Tariff. Non-Firm
Point-To- Point Transmission Service furnished over secondary Point(s) of
Receipt and Point(s) of Delivery will have a lower priority than any other
Non-Firm Point-To-Point Transmission Service under this Tariff. The System
Operator will provide advance notice of Curtailment or Interruption where such
notice can be provided consistent with Good Utility Practice. In the event the
System Operator exercises its right to effect a Curtailment, in whole or part,
of Non-Firm Point-to-Point Transmission Service, no credit or other adjustment
shall be provided as a result of the Curtailment with respect to the charge
payable by the Customer. In the event the System Operator exercises its right to
effect an Interruption, in whole or part, of Non-Firm Point-to-Point
Transmission Service, the charge payable by the Customer shall be computed as if
the term of service actually rendered were the term of service reserved;
provided that an adjustment of the charge shall be made only when the
Interruption is initiated by the System Operator, not when the Customer fails to
deliver energy to NEPOOL.

31   Service Availability

31.1  General Conditions: Firm Point-To-Point Transmission Service over, on or
across the NEPOOL Transmission System is available to any Transmission Customer
that has met the applicable requirements of Section 31.

31.2 Determination of Available Transmission Capability: A description of
NEPOOL's specific methodology for assessing available transmission capability
posted on the NEPOOL OASIS(Section 5) is contained in Attachment C of this
Tariff. In the event sufficient transmission capability may not exist to
accommodate a service request, a System Impact Study will be performed.

31.3 Initiating Service in the Absence of an Executed Service Agreement: If the
System Operator and the Transmission Customer requesting Firm Point-To- Point
Transmission Service cannot agree on all the terms and conditions of the
applicable Service Agreement, the System Operator will file with the Commission,
within thirty days after the date the Transmission Customer provides written
notification directing the System Operator to file, an unexecuted Service
Agreement containing terms and conditions deemed appropriate by the System
Operator for such requested transmission service. The service will be commenced
subject to the Transmission Customer agreeing to (i) pay whatever rate the
Commission ultimately determines to be just and reasonable, and (ii) comply with
the terms and conditions of this Tariff including providing appropriate security
deposits in accordance with the terms of Section 31.3.

31.4 Obligation to Provide Transmission Service that Requires Expansion or
Modification of the Transmission System: If it is determined that the service
requested in a Completed Application for Long-Term Firm Point-To- Point
Transmission Service cannot be provided because of insufficient capability on
the NEPOOL Transmission System, one or more Transmission Providers or other
entities will be designated to use due diligence to expand or modify the NEPOOL
Transmission System to provide the requested Long-Term Firm Point-To-Point
Transmission Service, provided that the Transmission Customer agrees to
compensate the Transmission Providers or other entities that will be responsible
for the construction of any new facilities or upgrades for the costs of such new
facilities or upgrades pursuant to the terms of Section 39. The System Operator
and the designated Transmission Providers or other entities will conform to Good
Utility Practice in determining the need for new transmission facilities or
upgrades and in coordinating the design and construction of such facilities.
This obligation applies only to those facilities that the designated
Transmission Providers or other entities have the right to expand or modify.

31.5 Deferral of Service: Long-Term Firm Point-To-Point Transmission Service may
be deferred until the designated Transmission Providers or other entities
complete construction of new transmission facilities or upgrades needed to
provide such service whenever it is determined that providing the requested
service would, without such new facilities or upgrades, impair or degrade
reliability to any existing Firm Transmission Service.

31.6 Real Power Losses: Real power losses are associated with all transmission
service. The Transmission Provider is not obligated to provide real power
losses. Until the CMS/MSS Effective Date, to the extent PTF losses are not
specifically allocated through the market procedures provided for in Section 14
of the Agreement, point-to-point losses will be allocated on the basis of PTF
average losses as established by the System Operator. The System Operator shall
post on the OASIS the PTF average loss, which is initially set at 1.13% but
shall be adjusted by the System Operator from time to time. The applicable real
power loss factor shall be determined on the basis of PTF average losses.
Average PTF losses shall be determined initially on an estimated basis, pending
the accumulation of metered data needed to determine actual average PTF losses.

On and after the CMS/MSS Effective Date, the cost of PTF losses shall be
recovered through the Marginal Loss cost recovery mechanisms provided for in
Section 14A.16 of the Agreement and Schedule 13 of the Tariff.

31.7 Load Shedding: To the extent that a system contingency exists on the NEPOOL
Transmission System and the System Operator determines that it is necessary for
the Participants and the Transmission Customer to shed load, the Parties shall
shed load in accordance with the procedures under the Agreement and the rules
adopted thereunder, or in accordance with other mutually agreed-to provisions.

32     Transmission Customer Responsibilities

32.2     Conditions Required of Transmission Customers:  Firm Point-To-Point

Transmission Service will be provided only if the following conditions are
satisfied by the Transmission Customer:

a.     The Transmission Customer has pending a Completed Application for
service;

b.     In the case of a Non-Participant, the Transmission Customer meets the
creditworthiness criteria set forth in Section 11;

c. The Transmission Customer will have arrangements in place for any other
transmission service necessary to effect the delivery from the generating source
to the Point of Receipt prior to the time service under the Tariff commences;

d.     The Transmission Customer agrees to pay for any facilities or upgrades
constructed or any redispatch costs chargeable to such Transmission Customer
under this Tariff, whether or not the Transmission Customer takes service for
the full term of its reservation; and

e.    The Transmission Customer has executed a Service Agreement or has agreed
to receive service pursuant to Section 29.3.

32.3 Transmission Customer Responsibility for Third-Party Arrangements: Any
scheduling arrangements that may be required by other electric systems shall be
the responsibility of the Transmission Customer requesting service. (If Local
Network Service will be required, the System Operator shall notify the
Transmission Customer and the affected Participants.) The Transmission Customer
shall provide, unless waived by the System Operator, notification to the System
Operator identifying such other electric systems and authorizing them to
schedule the capacity and energy to be transmitted pursuant to this Tariff on
behalf of the Receiving Party at the Point of Delivery or the Delivering Party
at the Point of Receipt. The System Operator will undertake reasonable efforts
to assist the Transmission Customer in making such arrangements, including
without limitation, providing any information or data required by such other
electric system pursuant to Good Utility Practice.

33   Procedures for Arranging Firm Point-To-Point Transmission Service

33.1 Application: A request for Firm Point-To-Point Transmission Service for
periods of one year or longer must be made in an Application, delivered to ISO
New England Inc., One Sullivan Road, Holyoke, MA 01040-2841 or such other
address as may be specified from time to time. The request should be delivered
at least sixty days in advance of the calendar month in which service is
requested to commence. The System Operator will consider requests for such firm
service on shorter notice when practicable. Requests for firm service for
periods of less than one year will be subject to expedited procedures that will
be negotiated between the System Operator and the party requesting service
within the time constraints provided in Section 27.8. All Firm Point-To-Point
Transmission Service requests should be submitted by transmitting the Completed
Application to NEPOOL by mail or telefax. Each of these methods will provide a
time-stamped record for establishing the priority of the Application.

33.2   Completed Application: A Completed Application for Firm Point-To-Point
Transmission Service shall provide all of the information included at 18 C.F.R.
2.20 of the Commission's regulations, including but not limited to the
following:

(i)    The identity, address, telephone number and facsimile number of the
entity requesting service;

(ii)     A statement that the entity requesting service is, or will be upon
commencement of service, an Eligible Customer under this Tariff;

(iii)    The location of the Point(s) of Receipt and Point(s) of Delivery and
the identities of the Delivering Parties and the Receiving Parties;

(iv) The location of the generating facility(ies) supplying the capacity and
energy, and the location of the load ultimately served by the capacity and
energy transmitted. The System Operator will treat this information as
confidential in accordance with the NEPOOL information policy except to the
extent that disclosure of this information is required by this Tariff, by
regulatory or judicial order, or for reliability purposes pursuant to Good
Utility Practice. The System Operator will treat this information consistent
with the standards of conduct contained in 18 C.F.R. Part 37 of the Commission's
regulations;

(v)      A description of the supply characteristics of the capacity and energy
to be delivered;

(vi)     An estimate of the capacity and energy expected to be delivered to the
Receiving Party;

(vii)    The Service Commencement Date and the term of the requested
transmission service; and

(viii) The transmission capacity requested for each Point of Receipt and each
Point of Delivery on the NEPOOL Transmission System; customers may combine their
requests for service in order to satisfy the minimum transmission capacity
requirement.

The System Operator will treat this information consistent with the standards of
conduct contained in 18 C.F.R. Part 37 of the Commission's regulations.

33.3 Deposit: A Completed Application for Firm Point-To-Point Transmission
Service by a Non-Participant shall also include a deposit of either one month's
charge for Reserved Capacity or the full charge for Reserved Capacity for
service requests of less than one month. If the Application is rejected by the
System Operator because it does not meet the conditions for service as set forth
herein, or in the case of requests for service arising in connection with losing
bidders in a request for proposals (RFP), the deposit will be returned with
Interest, less any reasonable Administrative Costs incurred by the System
Operator or any affected Participants in connection with the review of the
Application. The deposit also will be returned with Interest less any reasonable
Administrative Costs incurred by the System Operator or any affected
Participants if the new facilities or upgrades needed to provide the service
cannot be completed. If an Application is withdrawn or the Eligible Customer
decides not to enter into a Service Agreement for the Service, the deposit will
be refunded in full, with Interest, less reasonable Administrative Costs
incurred by the System Operator or any affected Participants to the extent such
costs have not already been recovered from the Eligible Customer. The System
Operator will provide to the Eligible Customer a complete accounting of all
costs deducted from the refunded deposit, which the Eligible Customer may
contest if there is a dispute concerning the deducted costs. Deposits associated
with construction of new facilities or upgrades are subject to the provisions of
Section 33. If a Service Agreement for Firm Point-To-Point Transmission Service
is executed, the deposit, with interest, will be returned to the Transmission
Customer upon expiration or termination of the Service Agreement. Applicable
Interest will be calculated from the day the deposit is credited to the System
Operator's account.

33.4 Notice of Deficient Application: If an Application fails to meet the
requirements of this Tariff, the System Operator will notify the entity
requesting service within fifteen days of the System Operator's receipt of the
Application of the reasons for such failure. The System Operator will attempt to
remedy minor deficiencies in the Application through informal communications
with the Eligible Customer. If such efforts are unsuccessful, the System
Operator will return the Application, along with any deposit (less the
reasonable Administrative Costs incurred by the System Operator or any affected
Participants in connection with the Application), with Interest. Upon receipt of
a new or revised Application that fully complies with the requirements of this
Tariff, the Eligible Customer will be assigned a new priority based upon the
date of receipt by the System Operator of the new or revised Application.

33.5 Response to a Completed Application: Following receipt of a Completed
Application for Firm Point-To-Point Transmission Service, a determination of
available transmission capability will be made pursuant to Section 29.2. The
Eligible Customer will be notified as soon as practicable, but not later than
thirty days after the date of receipt of a Completed Application, if required,
that either (i) service will be provided without performing a System Impact
Study, or (ii) such a study is needed to evaluate the impact of the Application
pursuant to Section 33.1. Responses by the System Operator must be made as soon
as practicable to all Completed Applications and the timing of such responses
must be made on a non-discriminatory basis.


33.6 Execution of Service Agreement: Whenever the System Operator determines
that a System Impact Study is not required and that the requested service can be
provided, it will notify the Eligible Customer as soon as practicable but no
later than thirty days after receipt of the Completed Application, and will
tender a Service Agreement to the Eligible Customer. Failure of an Eligible
Customer to execute and return the Service Agreement or request the filing of an
unexecuted Service Agreement pursuant to Section 29.3, within fifteen days after
it is tendered by the System Operator shall be deemed a withdrawal and
termination of the Application and any deposit (less the reasonable
Administrative Costs incurred by the System Operator and any affected
Participants in connection with the Application) submitted will be refunded with
Interest. Nothing herein limits the right of an Eligible Customer to file
another Application after such withdrawal and termination. Where a System Impact
Study is required, the provisions of Section 33 will govern the execution of a
Service Agreement.

33.7 Extensions for Commencement of Service: The Transmission Customer can
obtain up to five one-year extensions for the commencement of service. The
Transmission Customer may postpone service by paying a non-refundable annual
reservation fee equal to one-month's charge for Firm Point-To-Point Transmission
Service for each year or fraction thereof. If during any extension for the
commencement of service an Eligible Customer submits a Completed Application for
Firm Point-To-Point Transmission Service, and such request can be satisfied only
by releasing all or part of the Transmission Customer's Reserved Capacity, the
original Reserved Capacity will be released unless the following condition is
satisfied: within thirty days, the original Transmission Customer agrees to pay
the applicable rate for Firm Point-To- Point Transmission Service for its
Reserved Capacity for the period that its reservation overlaps the period
covered by such Eligible Customer's Completed Application. In the event the
Transmission Customer elects to release the Reserved Capacity, the reservation
fees or portions thereof previously paid will be forfeited.

34     Procedures for Arranging Non-Firm Point-To-Point Transmission Service

34.1 Application: Eligible Customers seeking Non-Firm Point-To-Point
Transmission Service must submit a Completed Application to the System Operator.
Applications should be submitted by entering the information listed below on the
NEPOOL OASIS.

34.2     Completed Application: A Completed Application shall provide all of the
information included in 18 C.F.R. 2.20 including but not limited to the
following:

(i)      The identity, address, telephone number and facsimile number of the
entity requesting service;

(ii)     A statement that the entity requesting service is, or will be upon
commencement of service, an Eligible Customer under this Tariff;

(iii)     The Point(s) of Receipt and the Point(s) of Delivery;

(iv)     The maximum amount of capacity requested at each Point of Receipt and
Point of Delivery; and

(v)      The proposed dates and hours for initiating and terminating
transmission service hereunder.

In addition to the information specified above, when required to properly
evaluate system conditions, the System Operator also may ask the Transmission
Customer to provide the following:

(vi)     The electrical location of the initial source of the power to be
transmitted pursuant to the Transmission Customer's request for service; and

(vii)     The electrical location of the ultimate load.

The System Operator will treat this information in (vi) and (vii) as
confidential at the request of the Transmission Customer except to the extent
that disclosure of this information is required by this Tariff, by regulatory or
judicial order, or for reliability purposes pursuant to Good Utility Practice.
The System Operator shall treat this information consistent with the standards
of conduct contained in Part 37 of the Commission's regulations.

34.3 Reservation of Non-Firm Point-To-Point Transmission Service: Requests for
monthly service shall be submitted no earlier than sixty days before service is
to commence; requests for weekly service shall be submitted no earlier than
fourteen days before service is to commence; requests for daily service shall be
submitted no earlier than five days before service is to commence; and requests
for hourly service shall be submitted no earlier than 9:00 a.m. the second day
before service is to commence. Requests for service received later than noon of
the day prior to the day service is scheduled to commence will be accommodated
if practicable.

34.4 Determination of Available Transmission Capability: Following receipt of a
tendered schedule the System Operator will make a determination on a
non-discriminatory basis of available transmission capability pursuant to
Section 29.2. Such determination shall be made as soon as reasonably practicable
after receipt, but not later than the following time periods for the following
terms of service (i) thirty-five minutes for hourly service, (ii) thirty-five
minutes for daily service, (iii) four hours for weekly service, and (iv) two
days for monthly service.

35   Additional Study Procedures For Firm Point-To-Point Transmission Service
Requests

35.1 Notice of Need for System Impact Study: After receiving a request for Firm
Point-To-Point Transmission Service, the System Operator will review the effect
of the proposed service on the reliability requirements to meet existing and
pending obligations of the Participants and Non-Participants, and the
obligations of the particular Participants whose PTF facilities will be impacted
by the proposed service and determine on a non-discriminatory basis whether a
System Impact Study is needed. A description of the methodology for completing a
System Impact Study is provided in Attachment D. If the System Operator
determines that a System Impact Study is necessary to accommodate the requested
service, as soon as practicable thereafter the System Operator will so inform
the Eligible Customer and any affected Participants if the System Impact Study
is to be performed by the Participants. If the likely result of the study is
that a Direct Assignment Facility will be required, the study shall be performed
by the affected Participants, subject to review by the System Operator. In such
cases, the System Operator will within thirty days of receipt of a Completed
Application, tender a System Impact Study agreement in the form of Exhibit I to
this Tariff, or in any other form that is mutually agreed to, pursuant to which
the Eligible Customer shall agree to reimburse the System Operator and any
affected Participants for performing the required System Impact Study. For a
service request to remain a Completed Application, the Eligible Customer shall
execute the System Impact Study agreement and return it to the System Operator
within fifteen days. If the Eligible Customer elects not to execute a System
Impact Study agreement, its application shall be deemed withdrawn and its
deposit (less the reasonable Administrative Costs incurred by the System
Operator and any affected Participants in connection with the Application), will
be returned with Interest.

35.2     System Impact Study Agreement and Cost Reimbursement:

(i) The System Impact Study agreement shall clearly specify the System
Operator's estimate of the actual cost, and time for completion of the System
Impact Study. The charge shall not exceed the actual cost of the study. In
performing the System Impact Study, the System Operator and any affected
Participants will rely, to the extent reasonably practicable, on existing
transmission planning studies. The Eligible Customer shall not be assessed a
charge for such existing studies; however, the Eligible Customer shall be
responsible for charges associated with any modifications to existing planning
studies that are reasonably necessary to evaluate the impact of the Eligible
Customer's request for service on the NEPOOL Transmission System.

(ii) If in response to multiple Eligible Customers requesting service in
relation to the same competitive solicitation, a single System Impact Study is
sufficient for the System Operator to accommodate the requests for service, the
costs of that study will be equitably prorated among the Eligible Customers.

(iii) For System Impact Studies that the System Operator and any affected
Participants conduct on behalf of the Transmission Providers, the Participants
will record the cost of the System Impact Studies pursuant to Section 8.5.

35.3 System Impact Study Procedures: Upon receipt of an executed System Impact
Study agreement, the System Operator and any affected Participants will use due
diligence to complete the required System Impact Study within a sixty-day
period. The System Impact Study, if required, shall identify any system
constraints and redispatch options and the need for additional Direct Assignment
Facilities or facility additions or upgrades required to provide the requested
service. In the event that the required System Impact Study cannot be completed
within such time period, the System Operator will so notify the Eligible
Customer and provide an estimated completion date along with an explanation of
the reasons why additional time is required to complete the required study and
an estimate of any increase in cost which will result from the delay. A copy of
the completed System Impact Study and related work papers shall be made
available to the Eligible Customer. The System Operator will use the same due
diligence in completing the System Impact Study for an Eligible Customer that is
a Non-Participant as it uses when completing studies for the Participants. The
System Operator will notify the Eligible Customer immediately upon completion of
the System Impact Study if the NEPOOL Transmission System will be adequate to
accommodate all or part of a request for service or that no costs are likely to
be incurred for new transmission facilities or upgrades. Within fifteen days of
completion of the System Impact Study, the Eligible Customer must execute a
Service Agreement or request the filing of an unexecuted Service Agreement
pursuant to Section 29.3, or the Application shall be deemed terminated and
withdrawn.

35.4 Facilities Study Procedures: If a System Impact Study indicates that
additions or upgrades to the NEPOOL Transmission System are needed to supply the
Eligible Customer's service request, the System Operator, within thirty days of
the completion of the System Impact Study, will tender to the Eligible Customer
a Facilities Study agreement in the form of Attachment J to this Tariff, or in
any other form that is mutually agreed to, which is to be entered into by the
Eligible Customer and the System Operator and, if deemed necessary by the System
Operator, by one or more affected Transmission Provider(s) and pursuant to which
the Eligible Customer shall agree to reimburse the System Operator and any
affected Transmission Providers or other entity designated by the System
Operator for performing any required Facilities Study. For a service request to
remain a Completed Application, the Eligible Customer shall execute the
Facilities Study agreement and return it to the System Operator within fifteen
days. If the Eligible Customer elects not to execute the Facilities Study
agreement, its application shall be deemed withdrawn and its deposit, if any
(less the reasonable Administrative Costs incurred by the System Operator and
any affected Participants in connection with the Application), will be returned
with Interest. Upon receipt of an executed Facilities Study agreement, the
System Operator and any affected Transmission Provider(s) or other designated
entity will use due diligence to cause the required Facilities Study to be
completed within a sixty-day period. If a Facilities Study cannot be completed
in the allotted time period, the System Operator will notify the Transmission
Customer and provide an estimate of the time needed to reach a final
determination and any resulting increase in the cost, along with an explanation
of the reasons that additional time is required to complete the study. When
completed, the Facilities Study shall include a good faith estimate of (i) the
cost of Direct Assignment Facilities to be charged to the Transmission Customer,
or (ii) the Transmission Customer's appropriate share of the cost of any
required additions or upgrades, and (iii) the time required to complete such
construction and initiate the requested service. The Transmission Customer shall
provide a letter of credit or other reasonable form of security acceptable to
the Transmission Providers or other entities that will be responsible for the
construction of the new facilities or upgrades equivalent to the costs of the
new facilities or upgrades and consistent with relevant commercial practices, as
established by the Uniform Commercial Code. The Transmission Customer shall have
thirty days to execute a Service Agreement, if required, or request the filing
of an unexecuted Service Agreement with the Commission and provide the required
letter of credit or other form of security or the request will no longer be a
Completed Application and shall be deemed terminated and withdrawn.

     In addition to the foregoing, each Facilities Study shall contain a non-
binding estimate from the System Operator of the incremental FCRs and associated
ARRs, if any, resulting from the construction of the new facilities. After
completion of the transmission upgrade or expansion, the System Operator shall
determine the incremental FCRs and associated ARRs, if any, resulting from the
upgrade or expansion.

35.5 Facilities Study Modifications: Any change in design arising from inability
to site or construct proposed facilities will require development of a revised
good faith estimate. New good faith estimates also will be required in the event
of new statutory or regulatory requirements that are effective before the
completion of construction or other circumstances beyond the control of the
Transmission Providers or other entities that are responsible for the
construction of the new facilities or upgrades and that significantly affect the
final cost of the new facilities or upgrades to be charged to the Transmission
Customer pursuant to the provisions of this Tariff.

35.6 Due Diligence in Completing New Facilities: The System Operator will use
due diligence to designate Transmission Providers or other entities to add
necessary facilities or upgrade the NEPOOL Transmission System within a
reasonable time. A Transmission Provider or other entity will have no obligation
to upgrade its existing or planned transmission system in order to provide the
requested Firm Point-To-Point Transmission Service if doing so would impair
system reliability or otherwise impair or degrade existing firm service.

35.7 Partial Interim Service: If the System Operator determines that there will
not be adequate transmission capability to satisfy the full amount of a
Completed Application for Long-Term Firm Point-To-Point Transmission Service,
the portion of the requested Service that can be accommodated without addition
of any facilities or upgrades and through redispatch will be offered and
provided. However, there shall be no obligation to provide the incremental
amount of requested Long-Term Firm Point-To-Point Transmission Service that
requires the addition of facilities or upgrades to the NEPOOL Transmission
System until such facilities or upgrades have been placed in service.

35.8 Expedited Procedures for New Facilities: In lieu of the procedures set
forth above, the Eligible Customer shall have the option to expedite the process
by requesting the System Operator to tender at one time, together with the
results of required studies, an "Expedited Service Agreement" pursuant to which
the Eligible Customer would agree to pay for all costs incurred pursuant to the
terms of this Tariff. In order to exercise this option, the Eligible Customer
shall request in writing an Expedited Service Agreement covering all of the
above-specified items within thirty days of receiving the results of the System
Impact Study identifying the need for facility additions or upgrades and costs
to be incurred in providing the requested service. While the System Operator, on
behalf of the Transmission Providers or other entities that will be responsible
for constructing the new facilities or upgrades, agrees to provide the Eligible
Customer with its best estimate of the new facility costs and other charges that
may be incurred, such estimate shall not be binding and the Eligible Customer
shall agree in writing to pay for all costs incurred pursuant to the provisions
of this Tariff. The Eligible Customer shall execute and return such an Expedited
Service Agreement within fifteen days of its receipt or the Eligible Customer's
request for service will cease to be a Completed Application and will be deemed
terminated and withdrawn.

36   Procedures if New Transmission Facilities for Firm Point-To-Point
Transmission Service Cannot be Completed

36.1 Delays in Construction of New Facilities: If any event occurs that will
materially affect the time for completion of new facilities for Firm
Point-To-Point Service, or the ability to complete such facilities, the System
Operator will promptly notify the Transmission Customer. In such circumstances,
the System Operator will within thirty days of notifying the Transmission
Customer of such delays, convene a technical meeting with the Transmission
Customer and any affected Transmission Providers or other entities responsible
for construction to evaluate the alternatives available to the Transmission
Customer. The System Operator and the affected Transmission Providers or other
entities will make available to the Transmission Customer studies and work
papers related to the delay, including all information that is in the possession
of the System Operator or the Transmission Providers or other entities that are
responsible for the construction of the new facilities or upgrades that is
reasonably needed by the Transmission Customer to evaluate any alternatives.

36.2 Alternatives to the Original Facility Additions: When the review process of
Section 34.1 determines that one or more alternatives exist to the originally
planned construction project, the System Operator will present such alternatives
for consideration by the Transmission Customer. If, upon review of any
alternatives, the Transmission Customer desires to proceed with its Completed
Application subject to construction of the alternative facilities, it may
request the System Operator to submit a revised Service Agreement. If the
alternative approach solely involves Non-Firm Point-To-Point Transmission
Service, the System Operator will promptly tender a Service Agreement for
Non-Firm Point-To-Point Transmission Service providing for such service. In the
event the System Operator and the affected Participants or other entities
responsible for construction conclude that no reasonable alternative exists and
the Transmission Customer disagrees, the Transmission Customer may seek relief
under the dispute resolution procedures pursuant to Section 12 or it may refer
the dispute to the Commission for resolution.

36.3 Refund Obligation for Unfinished Facility Additions: If the System
Operator, the affected Transmission Providers or other entities responsible for
construction and the Transmission Customer mutually agree that no other
reasonable alternatives exist and the requested service cannot be provided out
of existing capability under the conditions of this Tariff, the obligation to
provide the requested Firm Point-To-Point Transmission Service shall terminate
and any deposit made by the Transmission Customer shall be returned, with
Interest. The Transmission Customer shall be responsible for all costs prudently
incurred by the System Operator and by the Transmission Providers or other
entities that have been responsible for the construction of the new facilities
or upgrades through the date that any required regulatory approval is denied or
construction is suspended and for cost of removal, if necessary, of facilities
constructed prior to suspension.

37     Provisions Relating to Transmission Construction and Services on the
Systems of Other Utilities

37.1 Responsibility for Third-Party System Additions: Neither the System
Operator nor any Participant which is not the Transmission Customer will be
responsible for making arrangements for any necessary engineering, permitting,
and construction of transmission or distribution facilities on the system(s) of
any other entity or for obtaining any regulatory approval for such facilities.
The System Operator will undertake reasonable efforts to assist the Transmission
Customer in obtaining such arrangements, including without limitation, providing
any information or data required by such other electric system pursuant to Good
Utility Practice.

37.2 Coordination of Third-Party System Additions: In circumstances where the
need for transmission facilities or upgrades is identified pursuant to the
provisions of this Tariff, and if such upgrades further require the addition of
transmission facilities on third-party systems, the System Operator and the
Transmission Providers or other entities that are responsible for the
construction of any new facilities or upgrades on the NEPOOL Transmission System
will have the right to coordinate construction on the NEPOOL Transmission System
with the construction required by the third parties. The System Operator and the
Transmission Providers or other entities that are responsible for the
construction of any new facilities or upgrades on the NEPOOL Transmission System
may, after consultation with the Transmission Customer and representatives of
such other systems, defer construction of new transmission facilities or
upgrades on the NEPOOL Transmission System if the new transmission facilities on
another system cannot be completed in a timely manner. The System Operator will
notify the Transmission Customer in writing of the basis for any decision to
defer construction and the specific problems that must be resolved before the
construction of new facilities will be initiated or resumed. Within sixty days
of receiving written notification by the System Operator of a decision to defer
construction pursuant to this section, the Transmission Customer may challenge
the decision in accordance with the dispute resolution procedures contained in
Section 12 or it may refer the dispute to the Commission for resolution.

38     Changes in Service Specifications

38.1 Modifications on a Non-Firm Basis: The Transmission Customer taking Firm
Point-To-Point Transmission Service may submit a request to the System Operator
for transmission service on a non-firm basis over Point(s) of Receipt and
Point(s) of Delivery other than those specified in the Service Agreement
("Secondary Receipt and Delivery Points"), in amounts not to exceed the
Transmission Customer's firm capacity reservation, without incurring an
additional Non-Firm Point-to-Point Transmission Service charge or executing a
new Service Agreement, subject to the following conditions:

(a) service provided over Secondary Receipt and Delivery Points will be non-firm
only, on an as-available basis, and will not displace any firm or non-firm
service reserved or scheduled by Participants or Non-Participants under this
Tariff or by the Participants on behalf of their Native Load Customers or
Excepted Transactions;

(b) the sum of all Firm Point-To-Point Transmission Service and Non-Firm
Point-To-Point Transmission Service provided to the Transmission Customer at any
time pursuant to this section shall not exceed the Reserved Capacity specified
in the relevant Service Agreement under which such services are provided;

(c) the Transmission Customer shall retain its right to schedule Firm
Point-To-Point Transmission Service at the Point(s) of Receipt and Point(s) of
Delivery specified in the relevant Service Agreement in the amount of the
Transmission Customer's original capacity reservation; and

(d) service over Secondary Receipt and Delivery Points on a non-firm basis shall
not require the filing of an Application for Non-Firm Point-to-Point
Transmission Service under the Tariff. However, all other requirements of this
Tariff (except as to transmission rates) shall apply to transmission service on
a non-firm basis over Secondary Receipt and Delivery Points.

38.2 Modification on a Firm Basis: Any request by a Transmission Customer to
modify Point(s) of Receipt and Point(s) of Delivery on a firm basis shall be
treated as a new request for service in accordance with Section 31, except that
such Transmission Customer shall not be obligated to pay any additional deposit
if the capacity reservation does not exceed the amount reserved in the existing
Service Agreement. While such new request is pending, the Transmission Customer
shall retain its priority for service at the firm Receipt Point(s) and Delivery
Point(s) specified in the Transmission Customer's Service Agreement.

39     Sale, Assignment or Transfer of Transmission Service

39.1 Procedures for Sale, Assignment or Transfer of Service: Subject to
Commission action on any necessary filings, a Transmission Customer may sell,
assign, or transfer all or a portion of its rights under its Service Agreement,
but only to another Eligible Customer (the "Assignee"). The Transmission
Customer that sells, assigns or transfers its rights under its Service Agreement
is hereafter referred to as the "Reseller." Compensation to the Reseller shall
not exceed the higher of (i) the original rate paid by the Reseller, (ii) the
maximum applicable rate on file under this Tariff at the time of the assignment,
or (iii) the Reseller's opportunity cost capped at the Participants' cost of
expansion. If the Assignee does not request any change in the Point(s) of
Receipt or the Point(s) of Delivery, or a change in any other term or condition
set forth in the original Service Agreement, the Assignee shall receive the same
services as did the Reseller and the priority of service for the Assignee shall
be the same as that of the Reseller. A Reseller shall notify the System Operator
as soon as possible after any sale, assignment or transfer of service occurs,
but in any event, notification must be provided prior to any provision of
service to the Assignee. The Assignee shall be subject to all terms and
conditions of this Tariff. If the Assignee requests a change in service, the
reservation priority of service will be determined by the System Operator
pursuant to Section 27.2.

     The sale, resale or assignment of FCRs is governed by Schedule 14 of the
Tariff, and this Section 37.1 is not applicable to such sales, resales and
assignments.

39.2 Limitations on Assignment or Transfer of Service: If the Assignee requests
a change in the Point(s) of Receipt or Point(s) of Delivery, or a change in any
other specifications set forth in the original Service Agreement, the System
Operator will consent to such change subject to the provisions of this Tariff,
provided that the change will not impair the operation and reliability of the
Participants' generation, transmission, or distribution systems. The Assignee
shall compensate the System Operator and any affected Participants for
performing any System Impact Study needed to evaluate the capability of the
NEPOOL Transmission System to accommodate the proposed change and any additional
costs resulting from such change. The Reseller shall remain liable for the
performance of all obligations under the Service Agreement, except as
specifically agreed to by the System Operator, the Reseller and the Assignee
through an amendment to the Service Agreement.

39.3 Information on Assignment or Transfer of Service: In accordance with
Section 5, Transmission Customers may use the NEPOOL OASIS to post information
regarding transmission capacity available for resale.

40     Metering and Power Factor Correction at Receipt and Delivery Points(s)

40.1 Transmission Customer Obligations: Unless the System Operator otherwise
agrees, the Transmission Customer shall be responsible for installing and
maintaining compatible metering and communications equipment to accurately
account for the capacity and energy being transmitted under this Tariff and to
communicate the information to the System Operator. Unless otherwise agreed,
such equipment shall remain the property of the Transmission Provider.

40.2 NEPOOL Access to Metering Data: The System Operator will have access to
such metering data as may reasonably be required to facilitate measurements and
billing under the Service Agreement.

40.3 Power Factor: Unless otherwise agreed, the Transmission Customer is
required to maintain a power factor within the same range as the Participants
maintain pursuant to Good Utility Practice and applicable NEPOOL requirements.
The power factor requirements are specified in the Service Agreement, where
applicable.

41     Compensation for New Facilities and Redispatch Costs

Whenever a System Impact Study performed in connection with the provision of
Firm Point-To-Point Transmission Service identifies the need for new facilities
or upgrades, the Transmission Customer shall be responsible for such costs to
the extent they are consistent with Commission policy. Whenever a System Impact
Study identifies capacity constraints that may be relieved more economically by
redispatching the Participants' resources than by building new facilities or
upgrading existing facilities to eliminate such constraints, the Transmission
Customer shall be responsible for the redispatch costs to the extent consistent
with applicable Commission policy.

VI.     REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION SERVICE)

The Participants will provide NEPOOL Regional Network Service (Network
Integration Transmission Service), as described in Part II of this Tariff to
Participants and Non-Participants pursuant to the applicable terms and
conditions contained in this Tariff. Part II of this Tariff specifies certain
terms and conditions which are generally applicable to the receipt of Regional
Network Service by both Participants and Non-Participants. This Part VI
specifies additional provisions with respect to the provision of Regional
Network Service.

42     Nature of Regional Network Service

42.1 Scope of Service: Regional Network Service (Network Integration
Transmission Service) is the transmission service described in Section 14 that
allows Network Customers to efficiently and economically utilize their resources
and Interchange Transactions to serve their Network Load located in the NEPOOL
Control Area and any additional load that may be designated pursuant to Section
43.3 of this Tariff. The Network Customer taking Regional Network Service must
obtain or provide Ancillary Services pursuant to Section 4.

42.2 Transmission Provider Responsibilities: The NEPOOL Participants will plan,
construct, operate and maintain the NEPOOL Transmission System in accordance
with Good Utility Practice in order to provide the Network Customer with
Regional Network Service over the NEPOOL Transmission System. Subject to Section
48, each Participant which is individually a Transmission Provider, on behalf of
its Native Load Customers, shall be required to designate resources and loads in
the same manner as any Network Customer under Part VI of this Tariff. This
information must be consistent with the information used by the Transmission
Provider to calculate available transmission capacity. The Participants shall
include the Network Customer's Network Load in NEPOOL Transmission System
planning and shall, consistent with Good Utility Practice, endeavor to construct
and place into service sufficient transmission capacity to deliver Network
Resources to serve the Network Customer's Network Load on a basis comparable to
the Participants' delivery of their own generating and purchased resources to
their Native Load Customers.

42.3 Network Integration Transmission Service: The Participants that are
individually Transmission Providers will provide firm transmission service over
the NEPOOL Transmission System to the Network Customer for the delivery of
energy and/or capacity from its resources to service its Network Loads on a
basis that is comparable to the Participants' use of the NEPOOL Transmission
System to reliably serve their Native Load Customers.

42.4 Secondary Service: The Network Customer may use the NEPOOL Transmission
System to deliver energy and/or capacity to its Network Loads from resources
that have not been designated as Network Resources. Such energy and capacity
shall be transmitted, on an as-available basis, at no additional charge, except
for any applicable charges for Congestion Cost and/or Marginal Loss cost
recovery, which are recovered from Non-Participants as part of Regional Network
Service and from Participants under the Agreement. Deliveries from resources
other than Network Resources will have a higher priority than any Non-Firm
Point-to-Point Transmission Service under this Tariff.

42.5 Real Power Losses: Real Power Losses are associated with all transmission
service. The Transmission Provider is not obligated to provide Real Power
Losses. To the extent PTF losses are not specifically allocated through the
market procedures provided for in Section 14 of the Agreement, total remaining
PTF losses, minus point-to-point losses, shall be allocated to all load on a
load ratio basis.

42.6 Restrictions on Use of Service: The Network Customer is entitled to use
Regional Network Service for any of the uses specified in Part II of this
Tariff.

43     Initiating Service

43.1 Condition Precedent for Receiving Service: Subject to the terms and
conditions of Parts II and VI of this Tariff, the Participants will provide
Regional Network Service to any Eligible Customer, provided that, except as
otherwise provided in Section 48, (i) the Eligible Customer completes an
Application for service as provided under Part VI of this Tariff, (ii) the
Eligible Customer and the System Operator complete the technical arrangements
set forth in Sections 41.3 and 41.4, (iii) the Eligible Customer executes a
Service Agreement in the form of Attachment B for service under Part VI of this
Tariff or requests in writing that the Transmission Provider file a proposed
unexecuted Service Agreement with the Commission, and (iv) the Eligible Customer
executes a Network Operating Agreement in the form of Exhibit H to this Tariff,
or in any other form that is mutually agreed to, with the Transmission Provider.

43.2 Application Procedures: Except as otherwise provided in Section 48, an
Eligible Customer requesting Network Integration Transmission Service under this
Tariff must submit an Application, with a deposit approximating the charge for
one month of service, to the System Operator as far as possible in advance of
the month in which service is to commence. Completed Applications for Network
Integration Transmission Service will be assigned a priority according to the
date and time the Application is received, with the earliest Application
receiving the highest priority. Applications should be submitted by entering the
information listed below on the NEPOOL OASIS to the extent feasible. A Completed
Application shall provide all of the information included in 18 CFR 2.20
including but not limited to the following:

(i)      The identity, address, telephone number and facsimile number of the
party requesting service;

(ii)     A statement that the party requesting service is, or will be upon
commencement of service, an Eligible Customer under this Tariff;

(iii) A description of the Network Load at each delivery point. This description
should separately identify and provide the Eligible Customer's best estimate of
the total loads to be served at each transmission voltage level, and the loads
to be served from each Transmission Provider substation at the same transmission
voltage level. The description should include a ten-year forecast of summer and
winter load resource requirements beginning with the first year after the
service is scheduled to commence;

(iv) The amount and location of any interruptible loads included in the Network
Load. This shall include the summer and winter capacity requirements for each
interruptible load (had such load not been interruptible), that portion of the
load subject to Interruption, the conditions under which an Interruption can be
implemented and any limitations on the amount and frequency of Interruptions. An
Eligible Customer should identify the amount of interruptible customer load (if
any) included in the ten-year load forecast provided in response to (iii) above;

(v) A description of Network Resources (current and ten-year projection), which
shall include, for each Network Resource, if not otherwise available to the
System Operator:

- -     Unit size and amount of capacity from that unit to be designated as
Network Resource

- -     VAR capability (both leading and lagging) of all generators

- -     Operating restrictions

- -     Any periods of restricted operations throughout the year

- -     Maintenance schedules

- -     Minimum loading level of unit

- -     Normal operating level of unit

- -     Any must-run unit designations required for system reliability or contract
      reasons

- -     Approximate variable dispatch price ($/MWH) for redispatch computations

- - Arrangements governing sale and delivery of power to third parties from
generating facilities located in the NEPOOL Control Area, where only a portion
of unit output is designated as a Network Resource

- - Description of external purchased power designated as a Network Resource
including source of supply, Control Area location, transmission arrangements and
delivery point(s) to the Transmission Provider's Transmission System;

(vi)     Description of Eligible Customer's transmission system:

- - Load flow and stability data, such as real and reactive parts of the load,
lines, transformers, reactive devices and load type, including normal and
emergency ratings of all transmission equipment in a load flow format compatible
with that used by the Participants

- -     Operating restrictions needed for reliability

- -     Operating guides employed by system operators

- - Contractual restrictions or committed uses of the Eligible Customer's
transmission system, other than the Eligible Customer's Network Loads and
Resources

- -     Location of Network Resources described in subsection (v) above

- -     ten-year projection of system expansions or upgrades

- -     Transmission System maps that include any proposed expansions or upgrades

- -     Thermal ratings of Eligible Customer's Control Area ties with other
Control Areas; and

(vii) Service Commencement Date and the term of the requested Network
Integration Transmission Service. The minimum term for Network Integration
Transmission Service is one year.

Unless the Eligible Customer and the System Operator agree to a different time
frame, the System Operator must acknowledge the request within ten days of
receipt. The acknowledgment must include a date by which a response, including a
Service Agreement, will be sent to the Eligible Customer. If an Application
fails to meet the requirements of this section, the System Operator shall notify
the Eligible Customer requesting service within fifteen days of receipt and
specify the reasons for such failure. Wherever possible, the System Operator
will attempt to remedy deficiencies in the Application through informal
communications with the Eligible Customer. If such efforts are unsuccessful, the
System Operator shall return the Application without prejudice to the Eligible
Customer, who may thereafter file a new or revised Application that fully
complies with the requirements of this section. The Eligible Customer will be
assigned a new priority consistent with the date of the new or revised
Application. The System Operator shall treat this information consistent with
the standards of conduct contained in Part 37 of the Commission's regulations.

43.3 Technical Arrangements to be Completed Prior to Commencement of Service:
Except as otherwise provided in Section 48, Regional Network Service shall not
commence until the Participants and the Network Customer, or a third party, have
completed installation of all equipment specified under a Network Operating
Agreement consistent with Good Utility Practice and any additional requirements
reasonably and consistently imposed to ensure the reliable operation of the
NEPOOL Transmission System. The Participants shall exercise reasonable efforts,
in coordination with the Network Customer, to complete such arrangements as soon
as practicable taking into consideration the Service Commencement Date.

43.4 Network Customer Facilities: The provision of Regional Network Service
shall be conditioned upon the Network Customer's constructing, maintaining and
operating the facilities on its side of each delivery point or interconnection
necessary to reliably deliver capacity and energy from the NEPOOL Transmission
System to the Network Customer. The Network Customer shall be solely responsible
for constructing or installing and operating and maintaining all facilities on
the Network Customer's side of each such delivery point or interconnection.

43.5     Filing of Service Agreement:  The System Operator will file Service
Agreements with the Commission in compliance with applicable Commission
regulations.

44     Network Resources

44.1 Designation of Network Resources: The designation of generation resources
as Network Resources shall be effected automatically in accordance with the
definition thereof for Participant Network Customers. A Network Customer shall
designate to the System Operator those Network Resources which are owned,
purchased or leased by it. The Network Resources so designated may not include
resources, or any portion thereof, that are committed for sale to non-designated
third party load or otherwise cannot be called upon to meet the Network
Customer's Network Load on a non-interruptible basis, or to the extent that the
resource is being delivered directly to a load being served with Internal
Point-to-Point Service. Any owned, purchased or leased resources that were
serving the Network Customer's loads under firm agreements entered into on or
before the Compliance Effective Date shall be deemed to continue to be so owned,
purchased or leased by it until the Network Customer informs the System Operator
of a change. Nothing in this Section is intended to relieve any customer of its
obligation to pay the charge for Internal Point-to-Point Service deliveries of
Network Resources to it.

44.2 Designation of New Network Resources: The Network Customer shall identify
the Network Resources which are owned, purchased or leased by it to the System
Operator with as much advance notice as practicable. A designation of a Network
Resource as owned, purchased or leased by the Customer must be made by a notice
to the System Operator.

44.3 Termination of Network Resources: The Network Customer may terminate the
designation of all or part of a Network Resource as owned, purchased or leased
by it at any time but should provide notification to the System Operator as soon
as reasonably practicable.

44.4 Network Customer Redispatch Obligation: As a condition to receiving Network
Integration Transmission Service, the Network Customer agrees to redispatch its
Network Resources as requested by the System Operator pursuant to Section 45.2.
To the extent practical, the redispatch of resources pursuant to this section
shall be on a least cost, non-discriminatory basis between all Network Customers
and the Participants.

44.5 Transmission Arrangements for Network Resources Not Physically
Interconnected With The NEPOOL Transmission System: The Network Customer shall
be responsible for any arrangements necessary to deliver capacity and energy
from a Network Resource not physically interconnected with the NEPOOL
Transmission System. The System Operator will undertake reasonable efforts to
assist the Network Customer in obtaining such arrangements, including without
limitation, providing any information or data required by such other entity
pursuant to Good Utility Practice.

44.6 Limitation on Designation of Resources: The Network Customer must
demonstrate that it owns, leases or has committed to purchase an Entitlement in
a generation resource pursuant to an executed contract in order to designate the
generating resource to serve its Network Load. Alternatively, the Network
Customer may establish that execution of a contract is contingent upon the
availability of transmission service under Part II of this Tariff.

44.7 Use of Interface Capacity by the Network Customer: There is no limitation
upon a Network Customer's use of the NEPOOL Transmission System at any
particular interface to integrate the Network Customer's resources (or
substitute purchases in Interchange Transactions) with its Network Loads.
However, a Network Customer's use of the NEPOOL total interface capacity with
other transmission systems to serve its Network Load may not exceed the Network
Customer's load.

45     Designation of Network Load

45.1 Network Load: Except as otherwise provided in Section 48, the Network
Customer must designate the individual Network Loads on whose behalf the
Participants will provide through NEPOOL Network Integration Transmission
Service. The Network Loads shall be specified in the Service Agreement.

45.2 New Network Loads Connected With the NEPOOL Transmission System: The
Network Customer shall provide the System Operator with as much advance notice
as reasonably practicable of the designation of new Network Load that will be
added to the NEPOOL Transmission System. A designation of new Network Load must
be made through a modification of service pursuant to a new Application. The
Participants will use due diligence to install or cause to be installed any
transmission facilities required to interconnect a new Network Load designated
by the Network Customer. The costs of new facilities required to interconnect a
new Network Load shall be determined in accordance with the procedures provided
in Section 44.4 and shall be charged to the Network Customer in accordance with
Commission policy and Schedule 11.

45.3 Network Load Not Physically Interconnected with the NEPOOL Transmission
System: This section applies to both initial designation pursuant to Section
43.1 and the subsequent addition of new Network Load not physically
interconnected with the NEPOOL Transmission System. To the extent that the
Network Customer desires to obtain transmission service for a load outside the
NEPOOL Control Area, the Network Customer shall have the option of (1) electing
to include the entire load as Network Load for all purposes under Part VI of
this Tariff and designating resources to serve such additional Network Load, or
(2) excluding that entire load from its Network Load. To the extent that the
Network Customer gives notice of its intent to add a new Network Load as part of
its Network Load pursuant to this section the request must be made through a
modification of service pursuant to a new Application, and shall be available
only so long as a scheduling and interconnection agreement acceptable to the
System Operator shall be required to be in effect with the Control Area in which
the load is located. Charges for such portion of the service shall be based on
the Through or Out Service rate applied to the amount reserved for the Network
Load which is not physically interconnected with the NEPOOL Transmission System.

45.4 New Interconnection Points: To the extent the Network Customer desires to
add a new Delivery Point or interconnection point between the NEPOOL
Transmission System and a Network Load, the Network Customer shall provide the
System Operator with as much advance notice as reasonably practicable.

45.5 Changes in Service Requests: Under no circumstances shall the Network
Customer's decision to cancel or delay a requested change in Network Integration
Transmission Service (the addition of a new Network Resource, if any, or
designation of a new Network Load) in any way relieve the Network Customer of
its obligation to pay the costs of transmission facilities constructed by the
Participants and charged to the Network Customer as reflected in the Service
Agreement or other appropriate agreement. However, the System Operator must
treat any requested change in Network Integration Transmission Service in a
non-discriminatory manner.

45.6 Annual Load and Resource Information Updates: The Network Customer shall
provide the System Operator with annual updates of Network Load and Network
Resource forecasts consistent with those included in its Application under Part
VI of this Tariff. The Network Customer also shall provide the System Operator
with timely written notice of material changes in any other information provided
in its Application relating to the Network Customer's Network Load, Network
Resources, its transmission system or other aspects of its facilities or
operations affecting the Participants' ability to provide reliable service.

46     Additional Study Procedures For Network Integration Transmission Service
Requests

46.1 Notice of Need for System Impact Study: After receiving a request for
service, the System Operator shall review the effect of the requested service on
the reliability requirements to meet existing and pending obligations of the
Participant(s) and on the obligations of the particular Participant(s) whose PTF
facilities will be impacted by the proposed service and shall determine on a
non-discriminatory basis whether a System Impact Study is needed. A description
of the methodology for completing a System Impact Study is provided in
Attachment D. If the System Operator determines that a System Impact Study is
necessary to accommodate the requested service, it shall as soon as practicable
inform the Eligible Customer and any affected Participant(s) if the System
Impact Study is to be performed by the Participant(s). If the likely result of
the study is that a Direct Assignment Facility will be required, the study shall
be performed by the affected Participant(s), subject to review by the System
Operator. In such cases, the System Operator shall within thirty days of receipt
of a Completed Application, tender a System Impact Study agreement in the form
of Attachment I to this Tariff, or in any other form that is mutually agreed to,
pursuant to which the Eligible Customer shall agree to reimburse the System
Operator and any affected Participant for performing the required System Impact
Study. For a service request to remain a Completed Application, the Eligible
Customer shall execute a System Impact Study agreement and return it to the
System Operator within fifteen days. If the Eligible Customer elects not to
execute a System Impact Study agreement, its Application shall be deemed
withdrawn and its deposit (less the reasonable Administrative Costs incurred by
the System Operator and any affected Participant(s)) shall be returned with
Interest.

46.2     System Impact Study Agreement and Cost Reimbursement:

(i) The System Impact Study agreement, whether in the form detailed in
Attachment I or in any other form that is mutually agreed to, will clearly
specify the System Operator's actual estimate of the actual cost, and time for
completion of the System Impact Study. The actual charge shall not exceed the
actual cost of the study. In performing the System Impact Study, the System
Operator and the affected Participants shall rely, to the extent reasonably
practicable, on existing transmission planning studies. The Eligible Customer
will not be assessed a charge for such existing studies; however, the Eligible
Customer will be responsible for charges associated with any modifications to
existing planning studies that are reasonably necessary to evaluate the impact
of the Eligible Customer's request for service on the NEPOOL Transmission
System.

(ii) If in response to multiple Eligible Customers requesting service in
relation to the same competitive solicitation, a single System Impact Study is
sufficient for the System Operator and the affected Participants to accommodate
the service requests, the costs of that study shall be prorated among the
Eligible Customers.

(iii) For System Impact Studies that the System Operator and any affected
Participants conduct on behalf of a Participant which is a Transmission
Provider, the Participant will record the cost of the System Impact Studies
pursuant to Section 8.5.

46.3 System Impact Study Procedures: Upon receipt of an executed System Impact
Study agreement, the System Operator and any affected Participants will use due
diligence to complete the required System Impact Study within a 60-day period.
The System Impact Study, if required, shall identify any system constraints,
redispatch options, or the need for additional Direct Assignment Facilities or
other facility additions or upgrades to provide the requested service. In the
event that the System Operator and any affected Participants are unable to
complete the required System Impact Study within such time period, the System
Operator shall so notify the Eligible Customer and provide an estimated
completion date along with an explanation of the reasons why additional time is
required to complete the required studies and an estimate of any increase in
cost which will result from the delay. A copy of the completed System Impact
Study and related work papers shall be made available to the Eligible Customer.
The System Operator will use the same due diligence in completing the System
Impact Study for an Eligible Customer as it uses when completing studies for the
Participants. The System Operator shall notify the Eligible Customer immediately
upon completion of the System Impact Study if the NEPOOL Transmission System
will be adequate to accommodate all or part of a request for service or that no
costs are likely to be incurred for new transmission facilities or upgrades. In
order for a request to remain a Completed Application, within fifteen days of
completion of the System Impact Study the Eligible Customer must execute a
Service Agreement or request the filing of an unexecuted Service Agreement, or
the Application shall be deemed terminated and withdrawn.

46.4 Facilities Study Procedures: If a System Impact Study indicates that
additions or upgrades to the NEPOOL Transmission System are needed to supply the
Eligible Customer's service request, the System Operator, within thirty days of
the completion of the System Impact Study, shall tender to the Eligible Customer
a Facilities Study agreement in the form of Attachment J to this Tariff, or in
any other form that is mutually agreed to, which is to be entered into by the
Eligible Customer and the System Operator and, if deemed necessary by the System
Operator, by one or more affected Transmission Provider(s) and pursuant to which
the Eligible Customer shall agree to reimburse the System Operator and any
affected Transmission Provider(s) for performing the required Facilities Study.
For a service request to remain a Completed Application, the Eligible Customer
shall execute the Facilities Study agreement and return it to the System
Operator within fifteen days. If the Eligible Customer elects not to execute a
Facilities Study agreement, its Application shall be deemed withdrawn and its
deposit, if any (less the reasonable Administrative Costs incurred by the System
Operator and any affected Transmission Provider(s)), shall be returned with
Interest. Upon receipt of an executed Facilities Study agreement, the System
Operator and any affected Transmission Provider(s), will use due diligence to
complete the required Facilities Study within a sixty-day period. If the System
Operator and any affected Transmission Provider(s) are unable to complete the
Facilities Study in the allotted time period, the System Operator shall notify
the Eligible Customer and provide an estimate of the time needed to reach a
final determination and any resulting increase in the cost, along with an
explanation of the reasons that additional time is required to complete the
study. When completed, the Facilities Study will include a good faith estimate
of (i) the cost of Direct Assignment Facilities to be charged to the Eligible
Customer, (ii) the Eligible Customer's appropriate share of the cost of any
required Network Upgrades, and (iii) the time required to complete such
construction and initiate the requested service. The Eligible Customer shall
provide a letter of credit or other reasonable form of security acceptable to
the affected Transmission Provider(s) or other entities that will be responsible
for the construction of the new facilities or upgrades equivalent to the costs
of new facilities or upgrades consistent with commercial practices as
established by the Uniform Commercial Code. The Eligible Customer shall have
thirty days to execute a Service Agreement or request the filing of an
unexecuted Service Agreement and provide the required letter of credit or other
form of security or the request no longer will be a Completed Application and
shall be deemed terminated and withdrawn.

     In addition to the foregoing, each Facilities Study shall contain a non-
binding estimate from the System Operator of the incremental FCRs and associated
ARRs, if any, resulting from the construction of the new facilities. After
completion of the transmission upgrade or expansion, the System Operator shall
determine the incremental FCRs and associated ARRs, if any, resulting from the
upgrade or expansion.

47     Load Shedding and Curtailments

47.1 Procedures: Prior to the Service Commencement Date, the System Operator and
the Network Customer shall establish Load Shedding and Curtailment procedures
pursuant to the Network Operating Agreement with the objective of responding to
contingencies on the NEPOOL Transmission System. The parties will implement such
programs during any period when the System Operator determines that a system
contingency exists and such procedures are necessary to alleviate such
contingency. The System Operator will notify all affected Network Customers in a
timely manner of any scheduled Curtailment.

47.2 Transmission Constraints: During any period when the System Operator
determines that a transmission constraint exists on the NEPOOL Transmission
System, and such constraint may impair the reliability of the NEPOOL
Transmission System, the System Operator will take whatever actions, consistent
with Good Utility Practice, that are reasonably necessary to maintain the
reliability of the system. To the extent the System Operator determines that the
reliability of the System can be maintained by redispatching resources, the
System Operator will initiate procedures pursuant to a Network Operating
Agreement to redispatch all the Network Customer's resources and the
Participants' own resources on a least-cost basis without regard to the
ownership of such resources. Any redispatch under this section may not unduly
discriminate between the Participants' use of the NEPOOL Transmission System on
behalf of their Native Load Customers and any Network Customer's use of the
Transmission System to serve its designated Network Load.

47.3     Cost Responsibility for Relieving Transmission Constraints:

(a) Until the earlier of the CMS/MSS Effective Date or the implementation
effective date of an order issued by the Commission directing a different
allocation of Congestion Costs, to the extent not otherwise covered under the
Network Operating Agreement, whenever the System Operator implements least- cost
redispatch procedures in response to a transmission constraint, the customers
taking Internal Point-to-Point Service and/or Through or Out Service and Network
Customers will each bear a proportionate share of the total redispatch cost.

(b) On and after the CMS/MSS Effective Date, to the extent not otherwise covered
under the Network Operating Agreement, whenever the System Operator implements
least-cost redispatch procedures in response to a transmission constraint, the
customers taking Internal Point-to-Point Service and/or Through or Out Service
and Network Customers will each bear a share of the total redispatch cost in
accordance with Section 14A.12 and 14A.17 of the Agreement and Schedule 13 of
the Tariff.

47.4 Curtailments of Scheduled Deliveries: If a transmission constraint on the
NEPOOL Transmission System cannot be relieved through the implementation of
least-cost redispatch procedures and the System Operator determines that it is
necessary to effect a Curtailment of scheduled deliveries, such schedule shall
be curtailed in accordance with the Network Operating Agreement.

47.5 Allocation of Curtailments: The System Operator shall on a non-
discriminatory basis, effect a Curtailment of the transaction(s) that
effectively relieve the constraint. However, to the extent practicable and
consistent with Good Utility Practice, any Curtailment will be shared by the
customers taking Internal Point-to-Point Service and/or Through or Out Service
and Network Customers on a non-discriminatory basis. The System Operator shall
not direct the Network Customer to effect a Curtailment of schedules to an
extent greater than the System Operator would effect a Curtailment of the
Participants' schedules under similar circumstances. Notwithstanding the
preceding provisions of this Section, Import Transactions shall be scheduled and
curtailed in accordance with Section 14.1.

47.6 Load Shedding: To the extent that a system contingency exists on the NEPOOL
Transmission System and the System Operator determines that it is necessary for
the customers taking Internal Point-to-Point Service and/or Through or Out
Service and Network Customers to shed load, the Parties shall shed load in
accordance with previously established procedures under the Network Operating
Agreement, or in accordance with other mutually agreed-to provisions.

47.7 System Reliability: Notwithstanding any other provisions of this Tariff,
the System Operator reserves the right, consistent with Good Utility Practice
and on a not unduly discriminatory basis, to effect a Curtailment of Network
Integration Transmission Service without liability on the part of the System
Operator or the Participants for the purpose of making necessary adjustments to,
changes in, or repairs on the Participants' lines, substations and facilities,
and in cases where the continuance of Network Integration Transmission Service
would endanger persons or property. In the event of any adverse condition(s) or
disturbance(s) on the NEPOOL Transmission System or on any other system(s)
directly or indirectly interconnected with the NEPOOL Transmission System, the
System Operator, consistent with Good Utility Practice, also may effect a
Curtailment of Network Integration Transmission Service in order to (i) limit
the extent or damage of the adverse condition(s) or disturbance(s), (ii) prevent
damage to generating or transmission facilities, or (iii) expedite restoration
of service. The System Operator will give the Network Customer as much advance
notice as is practicable in the event of such Curtailment. Any Curtailment of
Network Integration Transmission Service will be not unduly discriminatory
relative to the Participants' use of the Transmission System on behalf of their
Native Load Customers. The Network Operating Agreement shall specify the rate
treatment and all related terms and conditions applicable in the event that the
Network Customer fails to respond to established Load Shedding and Curtailment
procedures.

48     Rates and Charges

The Network Customer shall pay Transmission Providers for any Direct Assignment
Facilities and its share of the cost of any required Network Upgrades and
applicable study costs consistent with Commission policy, along with the payment
to the System Operator of the charges for Ancillary Services and the charge for
Regional Network Service provided under this Tariff.

48.1 Determination of Network Customer's Monthly Network Load: The Network
Customer's "Monthly Network Load" is its hourly load (including its designated
Network Load not physically interconnected with the Transmission Provider under
Section 43.3) coincident with the coincident aggregate load of the Participants
and other Network Customers served in each Local Network in the hour in which
the coincident load is at its maximum for the month ("Monthly Peak").

49     Operating Arrangements

49.1 Operation under The Network Operating Agreement: The Network Customer shall
plan, construct, operate and maintain its facilities in accordance with Good
Utility Practice and in conformance with the Network Operating Agreement which
shall be in the form of Exhibit H to this Tariff, or in any other form that is
mutually agreed to.

49.2 Network Operating Agreement: The terms and conditions under which the
Network Customer shall operate its facilities and the technical and operational
matters associated with the implementation of Part VI of the Tariff shall be
specified in the Network Operating Agreement. The Network Operating Agreement
shall provide for the Parties to (i) operate and maintain equipment necessary
for integrating the Network Customer within the NEPOOL Transmission System
(including, but not limited to, remote terminal units, metering, communications
equipment and relaying equipment), (ii) transfer data between the System
Operator and the Network Customer (including, but not limited to, heat rates and
operational characteristics of Network Resources, generation schedules for units
outside the NEPOOL Transmission System, interchange schedules, unit outputs for
redispatch required under Section 45, voltage schedules, loss factors and other
real time data), (iii) use software programs required for data links and
constraint dispatching, (iv) exchange data on forecasted loads and resources
necessary for long-term planning, and (v) address any other technical and
operational considerations required for implementation of Part VI of this
Tariff, including scheduling protocols. The Network Operating Agreement will
recognize that the Network Customer shall either (i) operate as a Control Area
under applicable guidelines of the North American Electric Reliability Council
(NERC) and the Northeast Power Coordinating Council (NPCC), (ii) satisfy its
Control Area requirements, including all necessary Ancillary Services, by
contracting with the System Operator and the Participants, or (iii) satisfy its
Control Area requirements, including all necessary Ancillary Services, by
contracting with another entity, consistent with Good Utility Practice, which
satisfies NERC and NPCC requirements. The System Operator shall not unreasonably
refuse to accept contractual arrangements with another entity for Ancillary
Services.

49.3 Network Operating Committee: A Network Operating Committee (Committee)
shall be established to coordinate operating criteria for the Parties'
respective responsibilities under the Network Operating Agreement, where the
Network Customer is not a Participant. Each Network Customer shall be entitled
to have at least one representative on the Committee. The Committee shall meet
from time to time as need requires, but no less than once each calendar year.

50     Scope of Application of Part VI to Participants

(a) All Participants which are receiving Regional Network Service on the
Compliance Effective Date shall be deemed to have requested to continue Regional
Network Service and to have identified as their Network Resources and Network
Load all of their resources and load as of the Compliance Effective Date, unless
they elect in accordance with Section 3.3 of this Tariff to receive Internal
Point-to-Point Service at one or more Point(s) of Delivery from one or more
Point(s) of Receipt.

(b) In view of the operational, informational and financial obligations imposed
on Participants by the Agreement, the NEPOOL Financial Assurance Policy (which
is set forth in Attachment L hereto) and NEPOOL rules, the following
requirements shall not be applicable to Participants:

(1)     the Application requirement specified in Sections 41.1(i) and 42 of this
Tariff;

(2)     the deposit requirement specified in Section 41.2 of this Tariff;

(3) the requirement that a Network Customer execute a Service Agreement, as
specified in Section 41.1 (iii) of this Tariff; provided that a Service
Agreement shall be required (i) for any Participant initially taking Regional
Network Service after the Compliance Effective Date, (ii) if a Participant
serves load not physically interconnected with the NEPOOL Transmission System
pursuant to Section 43.3 of this Tariff or (iii) if a new facility or upgrade is
to be constructed pursuant to Section 44.4 of this Tariff;

(4) the requirement that a Network Customer execute a Network Operating
Agreement, as specified in Section 41.1(iv) of this Tariff; provided that a
Network Operating Agreement shall be required if a Participant serves load not
physically interconnected with the NEPOOL Transmission System pursuant to
Section 43.3 of this Tariff; and

(5) the requirement that a Network Customer provide an annual update of Network
Load and Network Resource forecasts, as specified in Section 43.6 of the Tariff.

Notwithstanding the foregoing, if the System Operator determines at any time
that it requires information from a Participant which would be contained in an
Application submitted pursuant to Section 41.2 or an annual update of Network
Load and Network Resource forecasts provided pursuant to Section 43.6, it has
the right to require that the Customer provide the information.

VII.     TRANSMISSION PLANNING, ADDITIONS AND MODIFICATIONS

51     General

Additions to or modifications of the NEPOOL Transmission System may be required
or permitted under this Tariff, and be subject to related rights, obligations
and procedures, in any of the following circumstances:

(a) An addition or modification may be required under Part V or Part VI of the
Tariff in order to meet a new request for Point-to-Point Service or Regional
Network Service. Where such an addition or modification is to be effected, the
rights and obligations of the System Operator, the Transmission Providers and
Transmission Customers shall be determined in accordance with the applicable
provisions of Parts V and VI.

(b) An addition or modification may be required to permit the interconnection of
a new or modified generating unit or the interconnection of an Elective
Transmission Upgrade. Where such an addition or modification is to be effected,
the rights and obligations of the System Operator, the Transmission Owners, and
the Generator Owner or applicant for an Elective Transmission Upgrade, shall be
determined in accordance with Section 50 and Schedules 11 and 12.

(c) A Reliability Upgrade, an Economic Upgrade or a NEMA Upgrade may be required
or proposed pursuant to a NEPOOL Transmission Plan. Where a Reliability Upgrade,
an Economic Upgrade, or a NEMA Upgrade is to be effected, the rights and
obligations of the System Operator, the Transmission Owners and other
Participants shall be determined in accordance with Schedule 12.

(d) A Quick Fix Upgrade may be identified for implementation in 2000 or 2001.
Where a Quick Fix Upgrade is to be effected, the rights and obligations of the
System Operator, the Transmission Owners and other Participants shall be
determined in accordance with Section 52.

(e) Consistent with reliability and safety standards, Transmission Owners, the
operators of affected satellites in the NEPOOL Control Area and the System
Operator will coordinate scheduled generation and transmission facility outages
so as to minimize, to the extent practicable, Congestion and RMR-related costs.
The System Operator shall provide Transmission Owners and the operators of the
affected satellites with such information as is necessary to enable them to
perform this function. Any information provided to Transmission Owners and the
operators of the affected satellites pursuant to this provision will be subject
to all the applicable requirements of the Commission's Order 889.

These provisions for PTF additions and modifications are not intended to be
exclusive.

Nothing in this Tariff is intended to preclude any entity from identifying and
constructing Elective Transmission Upgrades on a merchant or other basis, so
long as it obtains all required legal rights and approvals and satisfies
applicable System Operator, NEPOOL, and Transmission Owner requirements relating
to such facilities.

An addition or modification which constitutes PTF under the Agreement and the
Tariff shall become part of the NEPOOL Transmission System and shall be fully
subject to this Tariff, whether or not all or any part of the costs of the
addition or modification are included in Pool-Supported PTF costs. The
priorities, if any, with respect to the use of the addition or modification as
among the owner and supporters of the addition or modification and other
Transmission Customers shall be determined under Parts I to VI, inclusive, of
this Tariff.

To the extent that a Generator Owner is responsible for the costs of a Generator
Interconnection Related Upgrade or Elective Transmission Upgrade, or an entity
other than a Generator Owner is responsible for costs of any other system
upgrade, the Generator Owner or entity which supports part or all of the costs
of the addition or modification shall be entitled to a share of any associated
ARRs equivalent to the share of the total costs of such upgrade which it
supports, as assigned and allocated in accordance with Schedules 14 and 15. Any
incremental FCRs resulting from Generator Interconnection Related Upgrades or
other upgrades shall be auctioned along with other FCRs in accordance with
Schedule 14.

Nothing in this Tariff is intended to waive the legal rights of any person or
the rights of the Transmission Owners under Section 17A of the Agreement.

If issues of cost allocation arise with respect to the recovery of any of the
costs provided for in this Part VII, or in Schedules 11 or 12, such issues shall
be subject to determination by the Commission in the appropriate proceeding.

52     Interconnection Procedures and Requirements

52.1 Interconnection of Generating Unit Under the Minimum Interconnection
Standard: Any Generator Owner that proposes after the Compliance Effective Date
(i) to place in service a new generating unit at a site which the Generator
Owner owns or controls, or which it has the right to acquire or control, and
that will interconnect to the NEPOOL Transmission System, or (ii) to materially
change and increase the capacity of an existing generating unit located in the
NEPOOL Control Area shall be obligated to:

(a) complete and submit to the System Operator a standard application, which is
available from the System Operator ("Interconnection Application"), along with
the administrative fee and description of its proposal and site information
required by the Interconnection Application, as well as any additional
information that may be reasonably required by the System Operator;

(b) within fifteen (15) days of its tender by the System Operator (which tender
shall occur no later than thirty (30) days following System Operator's receipt
of a complete Interconnection Application), enter into an agreement with the
System Operator and, if deemed necessary by the System Operator, one or more
affected Transmission Owners to provide for the conduct of a System Impact Study
to determine what additions or modifications to the NEPOOL Transmission System
and to the Non-PTF system are required in order to permit its generating unit to
interconnect in a manner that avoids any significant adverse effect on system
reliability, stability, and operability, including protecting against the
degradation of transfer capability for interfaces affected by the unit ("Minimum
Interconnection Standard"). If the Generator Owner does not enter into the
System Impact Study agreement within the above time period, its Interconnection
Application shall be deemed terminated and withdrawn. The System Impact Study
shall be conducted in accordance with the procedures, and subject to the
obligations, specified in Sections 33.2 and 33.3 and Attachment D of this Tariff
and using the form of agreement specified in Attachment I of this Tariff, except
that: (1) references therein to transmission service shall be deemed to refer to
interconnection; (2) references therein to Eligible Customer or Transmission
Customer shall be deemed to refer to the Generator Owner; (3) Attachment D shall
be applied so that the interconnection is studied on a Minimum Interconnection
Standard basis; and (4) any references to, or requirements for, a Service
Agreement in Section 33.3 shall be inapplicable;

(c) if a System Impact Study indicates that additions or modifications to the
NEPOOL Transmission System are required in order to permit the Generator Owner's
generating unit to be interconnected with the NEPOOL Transmission System on a
basis satisfying the Minimum Interconnection Standard, within fifteen (15) days
of its tender by the System Operator (which tender shall occur no later than
thirty (30) days following the completion of the System Impact Study), enter
into an agreement with the System Operator and, if deemed necessary by the
System Operator, one or more affected Transmission Owners to provide for the
conduct of a Facilities Study. The Facilities Study shall be conducted in
accordance with the procedures, and subject to the obligations, specified in
Sections 33.4 and 33.5 of this Tariff, and using the form of agreement specified
in Attachment J of this Tariff, except that: (1) references therein to
transmission service shall be deemed to refer to interconnection; (2) references
therein to Eligible Customer or Transmission Customer shall be deemed to refer
to the Generator Owner; and (3) any references to, or requirements for, a
Service Agreement in Section 33.4 shall be inapplicable. In lieu of a Facilities
Study, if transmission system additions or modifications are required, within
forty-five (45) days of submission of the final System Impact Study report to
the Generator Owner, the Generator Owner, the affected Transmission Owner(s)
and, when necessary, the System Operator may establish an agreement for
expedited interconnection. While the Transmission Owner(s) or other entities
that will be responsible for constructing the new facilities or modifications
pursuant to an expedited interconnection agreement will provide the Generator
Owner with its best estimate of the new facility costs and other charges that
may be incurred, such estimate shall not be binding and the Generator Owner
shall agree in writing to pay for all applicable costs ultimately incurred. If
the Generator Owner does not enter into the Facilities Study or expedited
interconnection agreement within the above time periods, its Interconnection
Application shall be deemed terminated and withdrawn;

(d) if the System Impact Study indicates that no additions or modifications are
required, work with the interconnecting Transmission Owner(s) to establish
appropriate interconnection agreements and provide the security, credit
assurances and/or deposits that the Transmission Owner determines is necessary
to ensure payment within ninety (90) days following issuance of a final System
Impact Study report. If the studies conducted pursuant to this Section indicate
that additions or modifications to PTF or Non-PTF are required: (i) the
Generator Owner and the interconnecting Transmission Owner(s) shall enter into
appropriate interconnection agreements, including security and deposit
provisions, or the Generator Owner may request, upon providing the security,
credit assurances, and/or deposits required by the Transmission Owner, the
filing with the Commission by the Transmission Owner of an unexecuted agreement;
and (ii) within ninety (90) days following issuance of the final Facilities
Study report, or within ninety (90) days following execution of an agreement for
expedited interconnection, the Generator Owner shall provide the security,
credit assurances, and/or deposits that the Transmission Owner determines is
necessary to ensure payment to the extent not already provided under (i) above;
and (iii) the Transmission Owner or its designee designated to perform the
construction of the additions or modifications shall, in accordance with the
terms of the arrangements described in this paragraph and subject to Sections
18.4 and 18.5 of the Agreement, use due diligence to design and effect the
proposed construction. If the Generator Owner fails to enter into an
interconnection agreement or to request the filing of an unexecuted agreement
within ninety (90) days following issuance of the final Facilities Study report,
or if it fails to provide the security, credit assurances and/or deposits
required by the Transmission Owner, its Interconnection Application shall be
deemed terminated and withdrawn. Sections 34.1, 34.2 (other than those sentences
referring to Service Agreements), 34.3 and 35 of the Tariff shall be applicable
to the facilities construction or modification, except that: (1) references
therein to transmission service shall be deemed to refer to interconnection; and
(2) references therein to Eligible Customer or Transmission Customer shall be
deemed to refer to the Generator Owner.

(e) satisfy any applicable requirements under the applicable tariff of the
relevant Transmission Owner on file with the Commission (except for those
relating to System Impact Studies and Facilities Studies, which will be
performed on a unified basis by the System Operator in accordance with this
Section) in the event that transmission service will be needed across Non-PTF of
the Transmission Owner; and

(f) submit its proposal for review in accordance with Section 18.4 of the
Agreement and related NEPOOL System Rules and thereafter take any action
required pursuant to Section 18.5 of the Agreement as a result of such Section
18.4 review.

Upon the satisfaction of the obligations described in (a), (b), (c), (d), (e),
and (f) above, and subject to all necessary legal rights and approvals being
obtained, the Generator Owner's unit shall have the right to be interconnected
with the NEPOOL Transmission System.

A Generator Owner proposing the interconnection of a new or materially changed
generating unit shall be responsible for the costs of any required Generator
Interconnection Related Upgrades which do not constitute costs of Pool-Supported
PTF in accordance with Schedule 11, and shall comply with the Transmission
Owner's requirements with respect to security, credit assurances and/or deposits
in accordance with Schedule 11.

With respect to upgrades required to meet the Minimum Interconnection Standard,
and consistent with reliability and safety standards, Transmission Owners, the
interconnecting Generator Owner and the System Operator shall jointly use their
best reasonable efforts to develop Congestion and RMR- related cost estimates
and construction schedules designed to minimize, to the extent practicable, the
financial impact of the upgrade-related transmission outages on all affected
parties. The development of the aforementioned construction schedule shall
include consultation with any affected existing Generator Owner. To the extent
it is possible to implement a procedure that facilitates the ability of
interconnecting Generator Owners and Transmission Owners to minimize, to the
extent reasonably practicable, the associated RMR and Congestion cost exposure
prior to implementation of CMS, the parties agree to continue the use of the
procedure after the implementation of CMS to the extent that such procedures are
consistent with CMS. There shall be no payment under this Tariff of lost
opportunity costs to Generator Owners for generating units that are dispatched
down or dispatched off. In connection with the consultation required by this
paragraph, the affected parties shall, as necessary, enter into non- disclosure
agreements protecting commercially sensitive information from unlimited
disclosure in order to facilitate the development of construction schedules
designed to minimize the financial impact on the affected parties.

For purposes of determining whether a generating unit is to be deemed a new
generating unit placed in service after the Compliance Effective Date so that it
is obligated to satisfy the requirements of this Section, any unit which, on
January 1, 1999, was in active or deactivated status, as classified in the April
1998 NEPOOL Capacity, Energy, Loads and Transmission Report and any other
generating unit in active status on that date which may receive deactivated
status after that date, subject to criteria developed by the appropriate NEPOOL
committee, may retain this status for a period not to exceed three (3) years
from the date the unit receives deactivated status and shall not be obligated to
comply with this Section if it is reactivated during such period, but if not
reactivated during such period shall be deemed retired at the end of such period
for purposes of this Section. Notwithstanding the foregoing, if a proposal is
submitted and approved under Section 18.4 of the Agreement during the three-year
period to 1) reactivate, 2) materially modify and reactivate or 3) replace the
deactivated unit, the unit may be reactivated without material modification
without compliance with this Section. Further, notwithstanding the foregoing,
any unit in deactivated status prior to January 1, 1999 shall be entitled to
retain such status through December 31, 2001 whether or not a submission is made
under Section 18.4 during such period.

52.2 Interconnection of Elective Transmission Upgrades: Any Participant or
Non-Participant may undertake the design, construction and interconnection of an
Elective Transmission Upgrade ("Elective Transmission Upgrade Applicant"). In
undertaking the design, construction and interconnection of an Elective
Transmission Upgrade, the Elective Transmission Upgrade Applicant shall
undertake, as a condition to its right to place the Elective Transmission
Upgrade in service, the following procedures and otherwise comply with the
relevant NEPOOL System Rules:

(a) complete and submit to the System Operator a standard application, which is
available from the System Operator, along with the administrative fee, that
describes the Elective Transmission Upgrade in sufficient detail to enable the
System Operator to identify the location of the upgrade, affected Transmission
Owners, and the purpose of the Elective Transmission Upgrade;

(b) if required by the System Operator, enter into a System Impact Study
Agreement with the System Operator and, if deemed necessary by the System
Operator, one or more affected Transmission Owners to determine the effects, if
any, of the upgrade on the NEPOOL Transmission System and Non-PTF. The System
Operator may permit the Elective Transmission Upgrade Applicant to undertake on
its own a System Impact Study in consultation with the System Operator and
affected Transmission Owner(s).

(c) upon receipt of the completed System Impact Study, notify the System
Operator whether it will seek approval of the Elective Transmission Upgrade
pursuant to Section 18.4 of the Agreement and, if so, submit its proposal for
review in accordance with Section 18.4 of the Agreement and relevant rules and
procedures of NEPOOL and the System Operator; and

(d) after obtaining approval for the Elective Transmission Upgrade, or after the
time periods set forth in Section 18.4 of the Agreement have passed without the
Elective Transmission Upgrade Transmission Applicant receiving notice in writing
that its proposed upgrade will have a significant adverse effect upon the
reliability or operating characteristics of its system or the system of one or
more Participants, the Elective Transmission Upgrade Applicant shall enter into
an interconnection agreement with the affected Transmission Owners. To the
extent necessary and appropriate, the Elective Transmission Upgrade Applicant
shall also enter into support agreements with the affected Transmission Owners.
The Elective Transmission Upgrade Applicant also may request, upon providing the
security, credit assurances, and/or deposits required by the affected
Transmission Owners, the filing with the Commission by the Transmission Owner of
unexecuted interconnection and support agreements. The Elective Transmission
Upgrade Applicant shall obtain all necessary legal rights and approvals for the
construction and maintenance of the upgrade and shall cooperate with
Transmission Owners in obtaining all necessary legal rights and approvals for
the construction and maintenance of additions or modifications, if any, required
in conjunction with the upgrade.

Upon satisfaction of the obligations described in (a), (b), (c), and (d) above,
subject to all necessary legal rights and approvals being obtained, and upon
satisfaction of any conditions placed on the Elective Transmission Upgrade
Applicant pursuant to Sections 18.4 and 18.5 of the Agreement, the Elective
Transmission Upgrade shall have the right to be interconnected with the NEPOOL
Transmission System.

The Participant or Non-Participant that constructs and/or maintains the Elective
Transmission Upgrade shall be responsible for 100% of all of the costs of said
upgrade and of any additions to or modifications of the NEPOOL Transmission
System and Non-PTF that are required to accommodate the Elective Transmission
Upgrade. A request for rate treatment of an Elective Transmission Upgrade, if
any, shall be determined by the Commission in the appropriate proceeding.

The completion of a System Impact Study for an Elective Transmission Upgrade and
the construction of an Elective Transmission Upgrade shall not delay the
completion of a System Impact Study or Facilities Study for a Generator Owner
applying to interconnect under the Minimum Interconnection Standard and shall
not delay the construction of upgrades for a generating unit interconnecting
under the Minimum Interconnection Standard.

53     Regional Transmission Planning and Expansion

53.1 General: Commencing with the NEPOOL Transmission Plan that will be
effective for the period 2001 and beyond, and subject to the final outcome of
rehearing requests and any appeals with respect to the Commission's June 28,
2000 CMS/MSS Order issued in Docket Nos. EL00-62-000 et al., and subject to any
changes resulting from compliance with the requirements of Commission Order No.
2000, the process defined in this Section 51, as amended from time to time,
shall be utilized for regional transmission planning. No provisions of this
Section 51 reflect or are intended to reflect agreement among the Participants
as to the ownership of any Upgrades to the NEPOOL Transmission System built
pursuant to an RFP under Section 51.6.

     The NEPOOL Transmission Plan and transmission enhancement and expansion
studies shall be completed with the involvement of the Transmission Expansion
Advisory Committee and the Transmission Planning Committee. These two committees
shall be established in accordance with the provisions of Section 51.2, and
shall be responsible for the functions identified in that Section.

53.2     Responsibilities of the Transmission Expansion Advisory Committee,
Transmission Planning Committee and System Operator:

(a) A Transmission Expansion Advisory Committee shall be established to perform
the functions set forth in subsection (b) below. This Committee shall not be
subject to the governance provisions of the Agreement nor shall it have any of
the authority conferred by those provisions. It shall have a Chair and
Secretary, who shall be appointed by the chief executive officer of the System
Operator after consultation with the Participant members of the Liaison
Committee established pursuant to Section 11C of the Agreement. Before
appointing an individual to the position of the Chair or Secretary, the System
Operator shall notify the Committee of the proposed assignment and, consistent
with its personnel practices, provide any other information about the individual
reasonably requested by the Committee. The chief executive officer of the System
Operator shall consider the input of the members of the Committee in selecting,
removing or replacing such officers. If members of the Committee representing
five or more entities conclude that the performance of the Chair or Secretary is
not satisfactory, they may identify their concerns to the System Operator. If
after 30 days their concerns have not been reasonably addressed, they may
request that the Participants Committee consider a resolution to remove the
officer. A vote of the Participants Committee to remove an officer of the
Transmission Expansion Advisory Committee shall be immediately effective and
binding on the System Operator and not subject to any appeal. If the
Participants Committee votes to remove an officer of the Transmission Expansion
Advisory Committee, the System Operator shall appoint a replacement officer in
accordance with this subsection.

(b) The Transmission Expansion Advisory Committee shall be responsible for
providing input to and feedback for both the development of the NEPOOL
Transmission Plan and the conduct of enhancement and expansion studies. Such
input and feedback may include comment on policy issues, objectives, study
scope, and solutions and alternatives for consideration in the development of
the NEPOOL Transmission Plan. Any entity may designate a member to the
Transmission Expansion Advisory Committee by providing written notice to the
Secretary of that Committee identifying the name of the entity represented by
the member and the member's name, address, telephone number, facsimile number
and electronic mail address. The entity may remove or replace such member at any
time by written notice to the Secretary of the Transmission Expansion Advisory
Committee.

(c) A Transmission Planning Committee shall be established to perform the
functions set forth in subsection (d) below. This Committee shall not be subject
to the governance provisions of the Agreement nor shall it have any of the
authority conferred by those provisions. It shall have a Chair and Secretary,
who shall be appointed by the chief executive officer of the System Operator
after consultation with the members of the Committee. The Chair shall be an
employee of the System Operator. Before an individual is appointed to the
position of the Chair or Secretary, the System Operator shall, consistent with
its personnel practices, provide any information about the individual reasonably
requested by members of the Transmission Planning Committee. The chief executive
officer of the System Operator shall consider the input of the members of this
Committee in selecting, removing or replacing such officers.

(d) The Transmission Planning Committee shall be responsible for providing the
data, information and analytical support necessary to perform studies as
required, and shall identify engineering and technical issues and engineering
and technical solutions and alternatives with respect to the work within the
scope of the NEPOOL Transmission Plan. The Transmission Planning Committee shall
be comprised of at least one representative from the System Operator and from
each of the Transmission Owners. The Transmission Owners' representatives must
be "transmission function employees" subject to the code of conduct requirements
of 18 C.F.R. 37.4, as such requirements may be amended or superseded from time
to time. The System Operator may, after notice to the Transmission Planning
Committee, invite representatives of other entities to attend a discussion by
the Transmission Planning Committee of an Upgrade proposed by such entities,
provided such representatives either are by confidentiality agreement or
otherwise, subject to the same limitations on the use and disclosure of
information as, "transmission function employees" subject to the standards of
conduct requirements of 18 C.F.R. 37.4, as such requirements may be amended or
superseded from time to time. The Transmission Planning Committee shall not be
subject to the requirements of Section 7.6 of the Agreement and, except as
provided above, attendance at any meeting shall be restricted solely to members
of that Committee.

(e) In addition to the responsibilities specifically assigned to the System
Operator in other Sections of this Section 51, those NEPOOL Transmission System
planning functions required by this Section 51 that are not functions of the
Transmission Expansion Advisory Committee, the Transmission Planning Committee
or another NEPOOL Committee or entity under other provisions of the Agreement or
this Tariff, shall be the sole responsibility of the System Operator; provided,
that the assignment of any technical, engineering or analytical planning
function to the Transmission Planning Committee is not intended to preclude the
performance of any technical, engineering or analytical planning function by the
System Operator. For Upgrades proposed to reduce Congestion Costs, the System
Operator also shall perform and publish analysis that identifies the costs and
benefits of the Upgrade and, to the extent feasible, the distribution of such
benefits in the region.

53.3     NEPOOL Transmission Plan: Principles, Scope, and Contents:

(a) The NEPOOL Transmission Plan shall conform to Good Utility Practice,
applicable reliability principles, guidelines, criteria, rules, procedures and
standards of NERC and NPCC and any of their successors, applicable publicly
available local reliability criteria, and the NEPOOL System Rules, as they may
be amended from time to time.

(b) The NEPOOL Transmission Plan shall consolidate regional transmission needs
into a single plan which is assessed on the basis of maintaining the NEPOOL
Control Area's reliability while accounting for economic and environmental
considerations. The NEPOOL Transmission Plan shall be based on the results of a
comprehensive transmission expansion and enhancement study conducted at least
once every three years in accordance with Section 51.5. The NEPOOL Transmission
Plan shall also account for at least the ensuing five year load and capacity
forecasts, proposed generation additions and retirements, proposed Merchant
Transmission Facility additions, and the requirements for system restoration
services (but will not include development of a system restoration plan). Based
on the foregoing requirements and considerations, the NEPOOL Transmission Plan
shall identify for at least each of the ensuing five years a list of proposed
enhancements and expansions to the NEPOOL Transmission System not otherwise
proposed as Merchant Transmission Facilities that are determined to be
appropriate at the time of the issuance of the Plan (collectively referred to as
"Upgrades"). That list of Upgrades is subject to adjustment in accordance with
subsection (c) of Section 51.4 and, accordingly, an Upgrade included in a Plan
may subsequently be removed from the Plan and not be constructed. The NEPOOL
Transmission Plan shall also identify any projected need for Transfer Capability
during or before the five-year period, based on information at that time, for
which Upgrades have not been identified.

(c) The NEPOOL Transmission Plan shall be designed (i) to avoid unnecessary
duplication of facilities; (ii) to avoid the imposition of unreasonable costs
upon any Transmission Owner, Transmission Customer or other user of a
transmission facility; (iii) to take into account the legal and contractual
rights and obligations of the Transmission Owners and the transmission-related
legal and contractual rights and obligations of any other entity; and (iv) to
provide for coordination with existing transmission systems and with appropriate
interregional and local expansion plans.

53.4     Procedures for Developing a NEPOOL Transmission Plan:

(a) An initial draft of a five-year NEPOOL Transmission Plan for the years
2001-2005 (the "2000 Plan") shall be assembled and provided to Participants as
soon as reasonably practicable. The 2000 Plan shall reflect the list of
additions and modifications to the NEPOOL Transmission System that have been
identified by the System Operator and by Transmission Owners for their
individual systems or that have been jointly planned by Transmission Owners by
December 31, 2000. The 2000 Plan shall reflect the results of
reliability-related studies including those already identified in Form 715
filings with the Commission as of March 31, 2000; provided that the 2000 Plan
may also reflect studies completed after March 31, 2000 and prior to December
31, 2000. The 2000 Plan shall be issued by December 31, 2000 and shall be deemed
to be the NEPOOL Transmission Plan referred to in Section (3) of Schedule 12.

(b) The starting point for the NEPOOL Transmission Plan for the years 2002-2006
(the "2001 Plan") and each subsequent NEPOOL Transmission Plan shall be the list
of Upgrades included in the prior Plan, as updated, that have not been completed
at that time. The 2001 Plan and each subsequent Plan shall include for each year
covered by that Plan on a coordinated regional basis a list of additional
Upgrades identified in enhancement and expansion studies performed pursuant to
Section 51.5. That list shall identify separately (i) Reliability Upgrades, (ii)
Economic Upgrades, (iii) Generator Interconnection Related Upgrades to be
effected pursuant to Section 50 to accommodate new generation interconnections
that have satisfied the requirements under Sections 18.4 and 18.5 of the
Agreement, and (iv) NEMA Upgrades as appropriate. The Plan shall also include a
description of the reasons for any new Upgrades proposed in the Plan, including
the information identified in subsection (g) below, or for any removal of
Upgrades from the Plan pursuant to subsection (c) below.

(c) An Upgrade may be added to the NEPOOL Transmission Plan at any time in a
given year, provided there has been consultation with and consideration of input
from the Transmission Expansion Advisory Committee and the Transmission Planning
Committee, within the scope of their respective functions as specified in
subsections (b) and (d) of Section 51.2. Similarly, provided there has been
consultation with and consideration of input from the Transmission Expansion
Advisory Committee and the Transmission Planning Committee, within the scope of
their functions as specified in subsections (b) and (d) of Section 51.2, the
NEPOOL Transmission Plan may be revised to remove a proposed Upgrade if the
market responds by proposing alternative generation projects, Merchant
Transmission Facilities in accordance with Section 51.8, or demand-side
projects, or other circumstances arise such that the need for the Upgrade no
longer exists; provided that the entity responsible for the construction of the
Upgrade is reimbursed for any costs prudently incurred or prudently committed to
be incurred in connection with the planning, preparation for construction,
and/or construction of the Upgrades proposed for removal from the Plan. All
Upgrades proposed to be added or removed during this planning process must meet
the requirements of subsection (a) of Section 51.3.

(d) The Transmission Owners, those entities requesting transmission service or
interconnection, and any other entities proposing to provide facilities to be
integrated into the NEPOOL Control Area or alternatives to such facilities shall
supply upon request and subject to applicable confidentiality requirements of
the NEPOOL Information Policy any information and data reasonably required to
prepare a NEPOOL Transmission Plan or to perform a transmission enhancement and
expansion study. Any confidential cost estimate for a proposed Upgrade to the
NEPOOL Transmission System that is or may be subject to subsection (a) of
Section 51.6 shall be considered by the System Operator to be competitively
sensitive, confidential information and shall be considered the estimator's
confidential information under the NEPOOL Information Policy, and shall not be
disclosed by the System Operator to other entities that may be eligible to
submit a proposal in accordance with Section 51.6, including, without
limitation, other Transmission Owners. Any other information or data provided
shall be subject to the rights and obligations of the NEPOOL Information Policy.

(e) The NEPOOL Transmission Plan shall be developed in coordination with the
transmission systems of the surrounding Control Areas and the regional
reliability councils, as appropriate.

(f) At the initiation of an effort to update a Plan or develop a new Plan, the
System Operator shall solicit input for the updated or new Plan from members of
the Transmission Expansion Advisory Committee and Transmission Planning
Committee. These Committees shall meet to perform their respective functions in
connection with the preparation of the NEPOOL Transmission Plan, as specified in
subsections (b) and (d) of Section 51.2. Thereafter, drafts of the NEPOOL
Transmission Plan shall be provided to the Transmission Expansion Advisory
Committee and input from that Committee shall be received and considered in
preparing and revising subsequent drafts. Before a final draft of any proposed
NEPOOL Transmission Plan is presented to the System Operator's Board of
Directors for approval, a subcommittee of that Board shall hold a public meeting
to receive input directly and to discuss any proposed revisions to the draft.

(g) For potential Upgrades proposed to be included in the NEPOOL Transmission
Plan, the System Operator (in connection with the preparation of the NEPOOL
Transmission Plan) shall identify, to the extent practicable, the anticipated
benefits of the proposed Upgrade. To the extent an Upgrade is proposed to reduce
Congestion Costs, the System Operator shall publish data and information, in a
manner that does not violate the Information Policy, that would reasonably
permit entities to calculate the costs and economic benefits of such an Upgrade
and, to the extent feasible, the distribution of such benefits within the
region. Such information shall be published so as to permit analysis for a
reasonably limited period of time (generally ten years or less), and shall
include the effects of (i) all projects for which applications have been
received for approval under Section 18.4 of the Restated NEPOOL Agreement,
including but not limited to proposed generation projects and Merchant
Transmission Facilities and (ii) demand-side projects planned within the NEPOOL
Control Area and identified to the System Operator.

(h) Any entity with a representative on the Transmission Expansion Advisory
Committee may request that specific proposals for alternative solutions or
facilities, including but not limited to generation projects, transmission
projects, and/or demand-side projects, be accounted for in the development of
the NEPOOL Transmission Plan. The recommended draft of a NEPOOL Transmission
Plan shall account for such proposals where appropriate provided that the
recommended Plan shall not include in the list of Upgrades any proposed resource
participating in competitive electricity markets or Merchant Transmission
Facilities. If a proposal is not accounted for in the draft Plan to be
recommended to the System Operator's Board of Directors, the recommendation to
the Board shall include a written explanation of why such proposal(s) were not
accounted for in the recommended Plan, which shall be made public.

(i) A draft of a recommended NEPOOL Transmission Plan shall be presented at
least annually to the System Operator's Board of Directors for approval. At
least every three years, a draft shall reflect the results of a new
comprehensive transmission planning and expansion study conducted pursuant to
Section 51.5. In other years, the draft may be only an update to a prior
approved Plan. The draft shall be presented to the System Operator's Board of
Directors no later than September 30 of each year and shall be acted on by the
Board within 60 days of receipt. The Board of Directors may approve the
recommended Plan as submitted, modify the Plan or remand all or any portion of
it back with guidance for development of a revised recommendation in accordance
with this Section 51.4. The Board of Directors may consider the Plan in
executive session, and shall consider in its deliberations the views of the
subcommittee of the Board reflecting the public meeting held pursuant to
subsection (f) of Section 51.4.

(j) The cost responsibility for each Upgrade that is listed in the NEPOOL
Transmission Plan shall be determined in accordance with this Tariff, including
Schedule 11 or 12 of this Tariff, as applicable.

53.5 Procedures for the Conduct of Enhancement and Expansion Studies: From time
to time in connection with the development of a NEPOOL Transmission Plan or any
updates thereto, transmission enhancement and expansion studies may be desired
or necessary. Such studies shall be conducted in accordance with the following
procedures:

(a) The System Operator shall initiate a comprehensive transmission enhancement
and expansion study at least once every three years. A more limited study shall
be conducted if (i) a need for additional transfer capability is identified by
the System Operator in its evaluation of requests for firm transmission service
with a term of one year or more or as a result of the System Operator's on-going
evaluation of the bulk power supply system's adequacy and performance; (ii) a
need for additional transfer capability is identified as a result of the NERC
and/or NPCC reliability assessment or more stringent publicly available local
reliability criteria, if any; or (iii) constraints or available transfer
capability limitations are identified as a result of generation additions or
retirements, evaluation of load forecasts or proposals for the addition of
transmission facilities in the NEPOOL Control Area. A transmission enhancement
and expansion study may also be initiated for any other circumstances which may
warrant such a study.

(b) Written notice of the initiation of a transmission enhancement and expansion
study shall be provided to all members of the Transmission Expansion Advisory
Committee and Transmission Planning Committee. That notice shall identify the
needs supporting the initiation of the study. Meetings of these two Committees
shall be convened thereafter to identify additional considerations relating to
such a transmission enhancement and expansion study that were not identified in
support of initiating the study, and to provide input on the study's scope,
assumptions and procedures, consistent with the respective responsibilities of
these Committees as set forth in Section 51.2.

(c) The results of the enhancement and expansion study, along with a discussion
of the study assumptions and input, shall be made public.

53.6     Request for Proposals ("RFP") Process For Upgrades:

(a) Except as otherwise provided in subsections (e) or (f) of this Section 51.6
below, the System Operator shall circulate a request for proposals ("RFP")
inviting any entity or entities to build an Upgrade included in the NEPOOL
Transmission Plan. The RFP shall be prepared by the System Operator which shall,
to the extent necessary, consult with the Transmission Owner(s) to obtain
necessary data, information and technical specifications that the System
Operator requires to prepare the RFP. The RFP shall include appropriate
requirements to safeguard the confidential nature of information provided by a
Transmission Owner in accordance with applicable commercial practices, the
requirements of the NEPOOL Information Policy and the requirements of any
applicable Commission order. Each such RFP shall require that respondents meet
specified technical and financial qualifications and submit proposals (i) that
conform with all the requirements of subsection (a) of Section 51.3 and
reasonable Transmission Owner requirements and specifications identified in the
RFP which are not inconsistent with Commission policy, (ii) that are consistent
with other applicable accepted engineering practices, governmental, technical,
and financial requirements, and (iii) that do not use a Transmission Owner's
facilities, rights-of-way or other property, provided that the affected
Transmission Owner may voluntarily agree, in its own discretion, to the use of
its property in connection with a proposal.

(b) The System Operator shall develop selection criteria in consultation with
the Transmission Expansion Advisory Committee and post the criteria on the
System Operator's website before it issues the RFP. The evaluation criteria may
consider any or all of the following non-exclusive factors: (i) the
qualifications of the entity that would be responsible for implementing the
proposal to build the proposed Upgrade; (ii) the estimated financial and
reliability impacts on Transmission Customers and load during and after
construction and installation of the proposed Upgrade if the proposal is
accepted and implemented; (iii) the timing for completion of the proposal; (iv)
the assurance that the entity responsible for implementing the proposal is able
to perform; and (v) the mobilization or demobilization of facilities affected by
the building of the proposed Upgrade during construction and installation.

(c) The issuance of an RFP for an Upgrade shall not preclude the modification of
a NEPOOL Transmission Plan in accordance with Section 51.4(c), including,
without limitation, a modification that eliminates such Upgrade from the
recommended plan.

(d) Any entity whose proposal is accepted by the System Operator in accordance
with subsection (b) shall be compensated in accordance with the terms of its
accepted proposal.

(e) An RFP shall not be required for an Upgrade under this Section 51.6 if the
Upgrade is initially included in the 2000 Plan or its estimated cost is less
than $10 million. In such circumstances, the Transmission Owner or Owners on
whose system(s) the proposed Upgrade in the Plan is located, or its/their
designee(s), shall be designated as the appropriate entity responsible for
completion of that Upgrade, in accordance with the requirements of Section 51.7.

(f) No proposed Merchant Transmission Facility and no Upgrade that uses the
facilities, rights-of-way or other property of a Transmission Owner, except as
the affected Transmission Owner may voluntarily agree, in its own discretion, to
such use, shall be the subject of the RFP process of this Section 51.6. No
provision of Section 51 affects any obligations to interconnect new customers to
the NEPOOL Transmission System imposed by other provisions of this Tariff or the
Federal Power Act.

53.7     Obligations of Transmission Owners to Build:

(a) If a Transmission Owner is responsible for completion of an Upgrade
identified in a NEPOOL Transmission Plan in accordance with subsection (e) of
Section 51.6, or the Upgrade is a Reliability Upgrade and construction is not
being accomplished in accordance with a proposal accepted by the System Operator
in accordance with subsection (b) of Section 51.6, or if the Transmission Owner
is otherwise required to complete an Upgrade in accordance with provisions of
Part III, V or VI of the Tariff or applicable regulations or statutes, the
Transmission Owner shall use its reasonable efforts to design, construct and
place the proposed Upgrade into service or enter into appropriate contracts to
fulfill such obligations, subject to a Transmission Owner's ability to: (i)
satisfy the requirements of applicable law, government regulations and
approvals, including, without limitation, requirements to obtain any necessary
state or local siting, construction and operating permits; (ii) obtain required
financing; (iii) acquire necessary rights-of-way; (iv) recover, pursuant to
appropriate financial arrangements and tariffs or contracts, all reasonably
incurred costs, plus a reasonable return on investment; and (v) comply with
Sections 18.4 and 18.5 of the Agreement.

(b) Any Transmission Owner may seek recovery for the costs of an Upgrade for
which it is responsible under this Section 51.7 on any basis it determines
appropriate, including on an incremental cost basis; provided that rates,
charges and terms and conditions for such recovery are accepted or approved by
the Commission. Nothing herein shall prohibit or otherwise restrict the ability
of affected entities to protest, challenge, comment upon or object to efforts by
any Transmission Owner to obtain regulatory approval of any proposed mechanism
for recovery by such Owner of the costs of such Upgrade.

53.8     Merchant Transmission Facilities; Compliance:

(a) Subject to compliance with the requirements of Section 18.4 and 18.5 of the
Agreement and any other applicable requirements with respect to the
interconnection of bulk power facilities with the NEPOOL Transmission System,
any entity shall have the right to propose and construct the addition of
transmission facilities outside the Plan, none of the costs of which shall be
Pool-Supported PTF or covered under Schedule 11 or 12 of this Tariff ("Merchant
Transmission Facilities"). Any such Merchant Transmission Facilities shall be
subject to the requirements of subsection (b) below. In performing studies in
connection with the NEPOOL Transmission Plan, the prospect that proposed
Merchant Transmission Facilities will be completed shall be accounted for on the
same basis as the prospect that proposed generating units will be completed.

(b) All Merchant Transmission Facilities shall comply with Sections 18.4 and
18.5 of the Agreement and shall be subject to: (i) agreements between the
proposed owner of such Merchant Transmission Facilities and the affected
Transmission Owners covering the interconnection of the Merchant Transmission
Facilities, said agreement not to be unreasonably withheld; (ii) agreements with
one or more Transmission Owners or the System Operator establishing
responsibility for the operation and maintenance of the Merchant Transmission
Facilities; (iii) agreements with any affected Transmission Owner or other
entity for access to and/or use of the property of such entity, as may be
necessary for the completion and operation of the Merchant Transmission
Facilities; (iv) if any such owner of the Merchant Transmission Facilities is
not a Participant, an agreement (A) to transfer to the System Operator
operational authority of any facilities rated 69 kV or above which constitute
part of the Merchant Transmission Facilities that are to be integrated with, or
that will affect, the NEPOOL Transmission System and (B) that comply with the
requirements of Sections 13, 21.3 and 21.7 of the Agreement, to the same extent
if such owner were a Participant; and (v) taking such other action as may be
required to make the facility available for use as part of the NEPOOL
Transmission System. A Transmission Owner shall have the right to require that
any agreement providing for the interconnection of any Merchant Transmission
Facilities with its own facilities includes requirements that the Merchant
Transmission Facilities' owner provide security, credit assurances and/or
deposits deemed necessary by the Transmission Owner, subject to Commission
acceptance or approval.

53.9     Alternative Remedies: Nothing herein shall limit in any way the right
of any entity to seek any available relief pursuant to the provisions of the
Federal Power Act.

1     "Quick Fix" Measures

Commencing as promptly as possible in 2000, and to the extent practicable,
Transmission Owners and the System Operator shall recommend cost effective
"quick fix" measures that they reasonably believe can be constructed/installed
in less than thirty (30) days and that reduce the likelihood of Congestion or
the running of generation resources out of merit order. These measures shall
include, but are not limited to, resagging transmission lines, relay changes or
additions, raising transmission structures, better coordination of maintenance
outages between the System Operator, Transmission Owners and the Satellites,
using temperature sensitive ratings, replacing limiting equipment such as
wavetraps and disconnect switches, transferring load, installing reactors and
capacitors, and sectionalizing lines. The Transmission Owners and the System
Operator shall recommend cost effective "quick fix" measures during 2000 and
2001. All expenses and capital investments incurred during 2000 and 2001 that
are related to these measures shall constitute Pool-Supported PTF costs and
shall be recovered through NEPOOL transmission charges, including the Post-1996
Pool PTF Rate. The System Operator and Transmission Owners will report to the
Participant Committee quarterly beginning in March 2000 as to which measures
have been completed or if any difficulties are occurring that prevent the
identification or implementation of such measures.




                                   SCHEDULE 1

                Scheduling, System Control and Dispatch Service

Scheduling, System Control and Dispatch Service is the service required to
schedule at the pool level the movement of power through, out of, within, or
into the NEPOOL Control Area. Local level service is provided under the Local
Network Service tariffs of the Participants which are the individual
Transmission Providers. For transmission service under this Tariff, this
Ancillary Service can be provided only by the System Operator and the
Transmission Customer must purchase this service from the System Operator.
Charges for Scheduling, System Control and Dispatch Service are to be based on
the expenses incurred by the System Operator, and by the individual Transmission
Providers in the operation of satellite dispatch centers or otherwise, to
provide these services. Effective as of January 1, 1999, or such other date as
the Commission may determine, the expenses incurred by the System Operator in
providing these services are to be recovered under its Tariff for Transmission
Dispatch and Power Administration Services, which has been filed in Docket No.
ER98-3554-000. A surcharge for the expenses incurred by Participants in the
provision of these services will be added to the Internal Point-to-Point Service
rate, to the Through or Out Service rate and to the Regional Network Service
rate.

The expenses incurred in providing Scheduling, System Control and Dispatch
Service for each Participant will be determined by an annual calculation based
on the previous calendar year's data as shown, in the case of Transmission
Providers which are subject to the Commission's jurisdiction, in the
Participants' FERC Form 1 report for that year, and shall be based on actual
data in lieu of allocated data if specifically identified in the Form 1 report.

This amended Schedule 1 shall be effective as of January 1, 1999, or such other
date as the Commission may determine. The surcharge shall be redetermined
annually as of June 1 in each year and shall be in effect for the succeeding
twelve months. The rate surcharge per kilowatt for each month is one-twelfth of
the amount derived by dividing the total annual Participant expenses for
providing the service by the sum of the average of the coincident Monthly Peaks
(as defined in Section 46.1) of all Local Networks for the prior calendar year.

Each Participant or Non-Participant which is obligated to pay the rate for
Regional Network Service for a month shall pay the surcharge on the basis of the
number of kilowatts of its Monthly Network Load (as defined in Section 46.1) for
the month. Each Participant or Non-Participant which is obligated to pay the
rate for Internal Point-to-Point Service or Through or Out Service for the
applicable period shall pay the surcharge on the basis of the highest amount of
its Reserved Capacity for each transaction scheduled as Internal Point-to-Point
Service and/or Through or Out Service for such period.

The revenues received under this Schedule 1 to cover the expenses incurred by
Participants for providing Scheduling, System Control and Dispatch Service shall
be allocated each month among the Participants whose satellite or other costs
are reflected in the computation of the surcharge for the service in proportion
to the costs for each which are reflected in the computation of the surcharge.

The details for implementation of Schedule 1 shall be established in accordance
with a rule approved by the Regional Transmission Operations Committee which
shall be filed with the Commission and considered a supplement to this Tariff.




                              SCHEDULE 2

               Reactive Supply and Voltage Control from
                     Generation Sources Service

In order to maintain transmission voltages on the NEPOOL Transmission System
within acceptable limits, generation facilities are operated to produce (or
absorb) reactive power. Thus, Reactive Supply and Voltage Control from
Generation Sources Service must be provided for each transaction on the NEPOOL
Transmission System. The amount of Reactive Supply and Voltage Control from
Generation Sources Service that must be supplied with respect to a Transmission
Customer's transaction will be determined based on the reactive power support
necessary to maintain transmission voltages within limits that are generally
accepted in the region and consistently adhered to by the Participants.

Reactive Supply and Voltage Control from Generation Sources Service is to be
provided through the Participants and the System Operator and the Transmission
Customer must purchase this service from the Participants through the System
Operator when the System Operator (or applicable satellite dispatching center)
determines, in the exercise of its discretion, that it is necessary to direct a
generating unit to alter its operations in an hour in order to provide such
service. The charge for each hour for such service, when required by the System
Operator (or satellite dispatching center) as set forth above, shall be paid by
each Participant or Non-Participant which receives either Regional Network
Service or Internal Point-to-Point Service or Through or Out Service and shall
be determined in accordance with the following formula:

The formula in Schedule 2 is amended to read as follows:

(EQUATION)

in which

CH      =     the amount to be paid by the Participant or Non-Participant for
the hour;

CC      =     the capacity costs for the hour, which shall be stated in an
informational filing with the Commission;

LOC     =     the lost opportunity costs for the hour to be paid to Participants
who provide VAR support;

PC = the portion of the amount paid to Participants for the hour for Energy
produced by a generating unit that is considered under the applicable
Implementation Rule to be paid for VAR support;

SCL = the cost of energy used in the hour by generating facilities, synchronous
condensers or static controlled VAR regulators in order to provide VAR support
to the transmission system;

HL1     =     the Network Load of the Participant or Non-Participant for the
hour;

HL     =     the aggregate of the Network Loads of all Participants and Non-
Participants for the hour;

RC1     =     the Reserved Capacity for Internal Point-to-Point Service and/or
Through or Out Service of the Participant or Non-Participant for the hour; and

RC = the aggregate Reserved Capacity for Internal Point-to-Point Service and/or
Through or Out Service of all Participants and Non-Participants for the hour.




                                   SCHEDULE 3

                  Regulation and Frequency Response Service
                         (Automatic Generation Control)

Regulation and Frequency Response Service (Automatic Generation Control or AGC)
is necessary to provide for continuous balancing of resources (generation and
interchange) with load, and for maintaining scheduled interconnection frequency
at sixty cycles per second (60 Hz). Regulation and Frequency Response Service
(Automatic Generation Control) is accomplished by dispatching on-line resources
whose output is raised or lowered (predominantly through the use of automatic
generating control equipment) as necessary to follow the moment-by-moment
changes in load. The obligation to maintain this balance between resources and
load lies with the System Operator and this service will be available to all
Participants and other entities that serve load within the NEPOOL Control Area
either under the Agreement for Participants or pursuant to Service Agreements
with Non- Participants entered into under the Tariff. The Transmission Customer
must either take this service from the System Operator pursuant to the Tariff or
under the Agreement or make alternative comparable arrangements to satisfy its
Regulation and Frequency Response Service (Automatic Generation Control)
obligation.

Until the CMS/MSS Effective Date, charges for this Service will be determined on
the basis of bids submitted by Participants in accordance with Section 14 of the
Agreement and applicable Market Rules. After the CMS/MSS Effective Date, charges
for this Service will be determined on the basis of Supply Offer Prices
submitted by Participants in accordance with Section 14A of the Agreement and
applicable Market Rules. In either case, the per unit charge for this service to
Non-Participants shall be the same as determined for Participants under Section
14.10 of the Agreement prior to the CMS/MSS Effective Date, and under Section
14A.8(c) of the Agreement and applicable Market Rules on and after the CMS/MSS
Effective Date.

The transmission service required with respect to Regulation and Frequency
Response Service (Automatic Generation Control) will be paid for as part of
Regional Network Service or Internal Point-to-Point Service by all Participants
and other entities serving load in the NEPOOL Control Area. The charge for
Regional Network Service is determined in accordance with Schedule 9 of the
Tariff. The charge for Internal Point-to-Point Service is determined in
accordance with Schedule 10 of the Tariff.

Sheet No. 204 is intentionally blank.




                              SCHEDULE 4

                            Energy Imbalance Service

Energy Imbalance Service is the service provided when a difference occurs
between the scheduled and the actual delivery of energy to a load located within
the NEPOOL Control Area during a single hour. The Transmission Customer may
either supply its load from its own resources or through bilateral arrangements
or obtain the service under the Agreement. This service will be available to all
Participants and other entities that serve load within the NEPOOL Control Area
either under the Agreement for Participants or pursuant to Service Agreements
with Non-Participants entered into under the Tariff. The prices for such service
will be determined in accordance with Section 14 of the Agreement and applicable
Market Rules until the CMS/MSS Effective Date, and will be the applicable
Locational Prices determined pursuant to Section 14A.12 of the Agreement and
applicable Market Rules on and after the CMS/MSS Effective Date.

The transmission service required with respect to Energy Imbalance Service under
the Agreement will be furnished as part of Regional Network Service or Internal
Point-to-Point Service to all Participants and other entities serving load in
the NEPOOL Control Area. The charges for Regional Network Service are determined
in accordance with Schedule 9 of the Tariff. The charges for Internal
Point-to-Point Service are determined in accordance with Schedule 10 of the
Tariff.




                                   SCHEDULE 5

         Operating Reserve - 10-Minute Spinning Reserve Service

10-Minute Spinning Reserve Service is a service needed to serve load immediately
in the event of a system contingency. This service will be available to all
Participants and other entities that serve load within the NEPOOL Control Area.
The Transmission Customer may either supply this service with its own resources
or through bilateral arrangements, or obtain the service either under the
Agreement for Participants or pursuant to Service Agreements with
Non-Participants entered into under the Tariff.

The total of each category of Operating Reserve requirements for the NEPOOL
Control Area in each hour is determined by the System Operator in accordance
with applicable NEPOOL System Rules. The currently applicable NEPOOL System
Rule, Operating Procedure No. 8, is on file with the Commission as a supplement
to the Tariff.

Under Section 14 of the Agreement, until the CMS/MSS Effective Date, the price
to be paid for Operating Reserve Service received in any hour will be the
Operating Reserve Clearing Price for the hour for that category of reserve
service, as determined on the basis of bids to provide the service plus any
applicable uplift charge.

On and after the CMS/MSS Effective Date, the price to be paid for Operating
Reserve Service shall be determined in accordance with Section 14A.8(b) of the
Agreement. In accordance with Section 14A.1(c) of the Agreement, Participants
and Non-Participant Transmission Customers shall be assigned Settlement
Obligations by the System Operator, which are used to allocate among the
Participants and Non-Participant Transmission Customers cost responsibility for
each category of Operating Reserve that is not self- supplied. The allocated
costs that must be paid for each category of Operating Reserve following the
CMS/MSS Effective Date are determined in accordance with Sections 14A.1(c) and
14A.8(c) of the Agreement.

The transmission service required with respect to Operating Reserve will be paid
for as part of Regional Network Service or Internal Point-to-Point Service by
all Participants and other entities serving load in the NEPOOL Control Area. The
charge for Regional Network Service is determined in accordance with Schedule 9
of the Tariff. The charge for Internal Point-to- Point Service is determined in
accordance with Schedule 10 of the Tariff.





                                   SCHEDULE 6

        Operating Reserve - 10-Minute Non-Spinning Reserve Service


10-Minute Non-Spinning Reserve Service is a service needed to serve load in the
event of a system contingency. This service will be available to all
Participants and other entities that serve load within the NEPOOL Control Area.
The Transmission Customer may either supply this service with its own resources
or through bilateral arrangements, or obtain the service either under the
Agreement for Participants or pursuant to Service Agreement with
Non-Participants entered into under the Tariff.

The total of each category of Operating Reserve requirements for the NEPOOL
Control Area in each hour is determined by the System Operator in accordance
with applicable NEPOOL System Rules. The currently applicable NEPOOL System
Rule, Operating Procedure No. 8, is on file with the Commission as a supplement
to the Tariff.

Under Section 14 of the Agreement, until the CMS/MSS Effective Date, the price
to be paid for Operating Reserve Service received in any hour will be the
Operating Reserve Clearing Price for the hour for that category of reserve
service, as determined on the basis of bids to provide the service plus any
applicable uplift charge.

On and after the CMS/MSS Effective Date, the price to be paid for Operating
Reserve Services shall be determined in accordance with Section 14A.8(b) of the
Agreement. In accordance with Section 14A.1(c) of the Agreement, Participants
and Non-Participant Transmission Customers shall be assigned Settlement
Obligations by the System Operator, which are used to allocate among the
Participants and Non-Participant Transmission Customers cost responsibility for
each category of Operating Reserve that is not self- supplied. The allocated
costs that must be paid for each category of Operating Reserve following the
CMS/MSS Effective Date are determined in accordance with Sections 14A.1(c) and
14A.8(c) of the Agreement.

The transmission service required with respect to Operating Reserve will be
furnished as part of Regional Network Service or Internal Point-to-Point Service
to all Participants and other entities serving load in the NEPOOL Control Area.
The charge for Regional Network Service is determined in accordance with
Schedule 9 of the Tariff. The charge for Internal Point-to- Point Service is
determined in accordance with Schedule 10 of the Tariff.



                                   SCHEDULE 7

               Operating Reserve - 30-Minute Reserve Service

30-Minute Reserve Service is a service needed to serve load in the event of a
system contingency. This service will be available to all Participants and other
entities that serve load within the NEPOOL Control Area. The Transmission
Customer may either supply this service with its own resources or through
bilateral arrangements, or obtain the service either under the Agreement for
Participants or pursuant to Service Agreements with Non- Participants entered
into under the Tariff.

The total of each category of Operating Reserve requirements for the NEPOOL
Control Area in each hour is determined by the System Operator in accordance
with applicable NEPOOL System Rules. The currently applicable NEPOOL System
Rule, Operating Procedure No. 8, is on file with the Commission as a supplement
to the Tariff.

Under Section 14 of the Agreement, until the CMS/MSS Effective Date, the price
to be paid for Operating Reserve Service received in any hour will be the
Operating Reserve Clearing Price for the hour for that category of reserve
service, as determined on the basis of bids to provide the service plus any
applicable uplift charge.

On and after the CMS/MSS Effective Date, the price to be paid for Operating
Reserve Service shall be determined in accordance with Section 14A.8(b) of the
Agreement. In accordance with Section 14A.1(c) of the Agreement, Participants
and Non-Participant Transmission Customers shall be assigned Settlement
Obligations by the System Operator, which are used to allocate among the
Participants and Non-Participant Transmission Customers cost responsibility for
each category of Operating Reserve that is not self- supplied. The allocated
costs that must be paid for each category of Operating Reserve following the
CMS/MSS Effective Date are determined in accordance with Sections 14A.1(c) and
14A.8(c) of the Agreement.

The transmission service required with respect to Operating Reserve will be
furnished as part of Regional Network Service or Internal Point-to-Point Service
to all Participants and other entities serving load in the NEPOOL Control Area.
The charge for Regional Network Service is determined in accordance with
Schedule 9 of the Tariff. The charge for Internal Point-to- Point Service is
determined in accordance with Schedule 10 of the Tariff.





                              SCHEDULE 8

                       Through or Out Service -
                         The Pool PTF Rate

(1) A Transmission Customer shall pay to NEPOOL for firm or non-firm Through or
Out Service reserved for it in accordance with Section 19 of the Tariff the
highest of (a) the Pool PTF Rate or (b)a rate which is derived from the annual
incremental cost, not otherwise borne by the Transmission Customer or a
Generator Owner, of any new facilities or upgrades that would not be required
but for the need to provide the requested service or (c) a rate which is equal
to NEPOOL's opportunity cost (if and when available) capped at the cost of
expansion, as determined for the period of service in accordance with Section 20
of this Tariff. If at any time NEPOOL proposes to charge a rate based on
opportunity cost, it shall first file with the Commission procedures for
computing opportunity cost pricing for all Transmission Customers. The
Transmission Customer shall also be obligated to pay any applicable ancillary
service charges and any congestion or other uplift charge required to be paid
pursuant to Section 24 of this Tariff.

(2) The Pool PTF Rate in effect at any time shall be determined annually on the
basis of the information for the most recent calendar year contained in Form 1
filings (or similar information on the books of Transmission Providers that are
not required to submit a Form 1 filing) and shall be changed annually effective
as of June 1 in each year. The Pool PTF rate shall be equal to (i) the sum for
all Participants of Annual Transmission Revenue Requirements determined in
accordance with Attachment F divided by (ii) the sum of the coincident Monthly
Peaks (as defined in Section 46.1) of all Local Networks, excluding from the
Monthly Peak for each Local Network as applicable the loads at each applicable
Point of Delivery of each Participant or Non-Participant which has elected to
take Internal Point-to-Point Service in lieu of Regional Network Service at one
or more Points of Delivery; plus the Long-Term Firm Reserved Capacity amount for
each such Participant or Non- Participant which has elected to take Firm
Internal Point-to-Point Service in lieu of Regional Network Service at one or
more Points of Delivery plus the Long-Term Reserved Capacity amount for each
Participant or Non-Participant for Firm Through or Out Service. Revenues
associated with Short-Term Point- to-Point reservations will be credited to the
sum of all Participants' Annual Transmission Revenue Requirements referred to in
(i) above.

(3) Discounts: Three principal requirements apply to discounts for Through or
Out Service as follows (1) any offer of a discount made by the Participants must
be announced to all Eligible Customers solely by posting on the OASIS, (2) any
customer-initiated requests for discounts (including requests for use by one's
wholesale merchant or an affiliate's use) must occur solely by posting on the
OASIS, and (3) once a discount is negotiated, details must be immediately posted
on the OASIS. For any discount agreed upon for service on a path, from Point(s)
of Receipt to Point(s) of Delivery, the Participants must offer the same
discounted transmission service rate for the same time period to all Eligible
Customers on all unconstrained transmission paths that go to the same Point(s)
of Delivery on the NEPOOL Transmission System.




                                   SCHEDULE 9

                            Regional Network Service

(1) A Transmission Customer which serves a Network Load in the NEPOOL Control
Area shall pay to NEPOOL each month for Regional Network Service the amount
determined in accordance with the following formula:

A =     1/12 (R . L)

in which

A =     the amount to be paid

R = the Participant RNS Rate per Kilowatt for the current Year for the
Participant which owns the Local Network from which the Customer's load is
served

L =     the Customer's Monthly Network Load for the month

It shall also be obligated to pay any ancillary charges and any applicable
congestion or other uplift charge required to be paid pursuant to Sections 24,
25A and 25B of this Tariff.

Each Participant RNS Rate is to be determined in accordance with the remaining
provisions of this Schedule 9. The Participants intend that the rate will be
determined by looking separately at the costs associated with facilities which
are in service at December 31, 1996, and the costs associated with new
facilities which are placed in service after December 31, 1996. Costs of new
facilities are to be shared regionally on a per Kilowatt basis in determining
the rates of each of the Participants with a Local Network, unless otherwise
allocated to a particular entity pursuant to this Tariff.

Costs of existing facilities are to be determined separately for each
Participant and reflected in the rate for service to Transmission Customers
serving load in the Participant's Local Network. This is initially subject to a
band width which limits the variation of the Participant per Kilowatt cost from
the average per Kilowatt cost for all Participants to not less than 70%, or more
than 130%, of the average cost.

(2) The Pool RNS Rate per Kilowatt is $1 in Year One, $4 in Year Two, $7 in Year
Three, $10 in Year Four and $13 in Years Five and Six and the period from the
end of Year Six to the next succeeding June 1, and is equal to the Pool PTF Rate
for each Year thereafter.

(3) The Participant RNS Rate for a Participant for a Year shall be a percentage
of the Pool RNS Rate for the year and shall be equal to the Pool RNS Rate after
the end of the transitional period described in paragraph (4) of this Schedule.
The percentage for each Participant for each Year shall equal the percentage
which the sum of (i) the Participant's pre-1997 Participant RNS Rate and (ii)
the post-1996 Pool PTF Rate represents of (iii) the Pool PTF Rate for the Year.

(4) The pre-1997 Participant RNS Rate for each Participant shall be determined
by comparing its individual pre-1997 PTF Rate, for the most recent calendar year
for which information is available from Form 1 filings or otherwise to the
pre-1997 Pool PTF Rate for the same calendar year. If the Participant's
individual pre-1997 PTF Rate for a Year is less than the pre- 1997 Pool PTF
Rate, its pre-1997 Participant RNS Rate for the Year shall be the rate
determined by reducing the pre-1997 Pool PTF Rate by the percentage which the
Participant's pre-1997 PTF Rate is less than the pre-1997 Pool PTF Rate;
provided that in no event shall its pre-1997 Participant RNS Rate be less than
70% of the pre-1997 Pool PTF Rate, until the end of Year Five, and thereafter
shall be no less than 50% of the pre-1997 Pool PTF Rate for Year Six through
Year Eleven, and shall be equal to the pre-1997 Pool PTF Rate for Year Twelve
and thereafter. If the Participant's individual pre-1997 PTF Rate is greater
than the pre-1997 Pool PTF Rate, its pre-1997 Participant RNS Rate shall be the
rate determined by increasing the pre-1997 Pool PTF Rate by the percentage which
its pre-1997 Participant PTF Rate is greater than the pre-1997 Pool PTF Rate;
provided that in no event shall its pre-1997 Participant RNS Rate be greater
than 130% of the pre-1997 Pool PTF Rate until the end of Year Six, and
thereafter shall be no greater than 127% of the pre- 1997 Pool PTF Rate for Year
Six, 123% of the pre-1997 Pool PTF Rate for Year Eight, 118% of the pre-1997
Pool PTF Rate for Year Nine, 112% of the pre-1997 Pool PTF Rate for Year Ten,
105% of the pre-1997 Pool PTF Rate for Year Eleven, and shall be equal to the
pre-1997 Pool PTF Rate for Year Twelve and thereafter. If for any Year the
revenues to be received from the payment by Participants or other Transmission
Customers of their respective applicable Participant RNS Rates will average more
or less than the Pool PTF Rate per Kilowatt for the Year, each Participant RNS
Rate will be increased or decreased, as appropriate, so that the revenues to be
received per Kilowatt per Year will equal the Pool PTF Rate per Kilowatt for the
Year.

(5) The individual pre-1997 PTF Rate of a Participant which owns a Local Network
for a year is the amount derived annually by dividing its Annual Transmission
Revenue Requirements for the most recent calendar year for which information is
available from Form 1 filings (or similar information on the books of
Transmission Providers that are not required to submit a Form 1 filing) with
respect to PTF placed in service before January 1, 1997, as determined in
accordance with Attachment F to this Tariff, by the average for the twelve
months of the calendar year on which the rate is based of the sum of the
coincident Monthly Peaks for the Local Network, as adjusted each month for
losses, excluding from the Monthly Peak the load at each applicable Point of
Delivery of each Participant or Non-Participant which has elected to take
Internal Point-to-Point Service in lieu of Regional Network Service at one or
more Points of Delivery; plus the Long-Term Firm Reserved Capacity amount for
each such Participant or Non-Participant which has elected to take Firm Internal
Point-to-Point Service in lieu of Regional Network Service at one or more Points
of Delivery.

(6)     The pre-1997 Pool PTF Rate shall be determined in accordance with the
following formula:

(EQUATION)

and the post-1996 Pool PTF Rate shall be determined in accordance with the
following formula:

(EQUATION)

     in which

R =     the pre-1997 Pool PTF Rate

          R' =      the post-1996 Pool PTF Rate

ATRR = the aggregate of the Annual Transmission Revenue Requirements of the
Participants with respect to PTF placed in service before January 1, 1997, as
determined in accordance with Attachment F to this Tariff.

ATRR' = the aggregate of the Annual Transmission Revenue Requirements of the
Participants with respect to PTF placed in service on or after January 1, 1997,
including upgrades, modifications or additions to PTF placed in service before
January 1, 1997, as determined in accordance with Attachment F to this Tariff.

ARNL = the average for the twelve months of the calendar year on which the rate
is based of the sum of the coincident Monthly Peaks for all Local Networks, as
adjusted each month for NEPOOL losses, excluding from the Monthly Peak for each
Local Network as applicable the load at each applicable Point of Delivery of
each Participant or Non-Participant which has elected to take Internal
Point-to-Point Service in lieu of Regional Network Service at one or more Points
of Delivery; plus the Long-Term Firm Reserved Capacity amount for each such
Participant or Non-Participant which has elected to take Firm Internal
Point-to-Point Service in lieu of Regional Network Service at one or more Points
of Delivery plus the Long-Term Reserved Capacity amount for each Participant or
Non-Participant for Firm Through or Out Service.

(7) As used in this Schedule, "Monthly Peak" and "Monthly Network Load" each has
the meaning specified in Section 46.1 of this Tariff.

(8) With the exception of any provision of this Schedule relating to the
determination or application of the post-1996 Pool PTF Rate and technical
changes to the last sentence of paragraph (4) of this Schedule 9 to allocate
costs as necessary to keep Participants within the band widths identified in
that paragraph, the provisions of this Schedule 9 shall not be amended for
service rendered under the NEPOOL Tariff through December 31, 2003, except by
agreement in writing of the parties executing the Settlement Agreement in FERC
Docket Nos. OA97-237-000 et al. and compliance with the applicable requirements
of the Restated NEPOOL Agreement.



                            SCHEDULE 10

                   Internal Point-to-Point Service

(1) A Transmission Customer shall pay to NEPOOL for firm or non-firm Internal
Point-to-Point Service reserved for it in accordance with Section 19 of the
Tariff a charge per Kilowatt, as determined for the period of the service in
accordance with Section 21 of this Tariff, equal to the Internal Point-to-Point
Service Rate; provided if either or both (i) a rate which is derived from the
annual incremental cost not otherwise borne by the Transmission Customer or a
Generator Owner, of any new facilities or upgrades that would not be required
but for the need to provide the requested service or (ii) a rate which is equal
to NEPOOL's opportunity cost (if and when available) capped at the cost of
expansion, is greater than the Pool PTF Rate the charge shall be the higher of
such amounts; provided further that no such charge shall be payable with respect
to the use of Internal Point-to-Point Service to effect a delivery to the NEPOOL
power exchange in an Interchange Transaction. If at any time NEPOOL proposes to
charge a rate based on opportunity cost, it shall first file with the Commission
procedures for computing opportunity cost pricing for all Transmission
Customers. The Customer shall also be obligated to pay any applicable ancillary
service charge and any applicable congestion or other uplift charge required to
be paid pursuant to Sections 24, 25A and 25B of this Tariff.

(2) Discounts: Three principal requirements apply to discounts for Internal
Point-to-Point Service as follows (1) any offer of a discount made by the
Participants must be announced to all Eligible Customers solely by posting on
the OASIS, (2) any customer-initiated requests for discounts (including requests
for use by one's wholesale merchant or an affiliate's use) must occur solely by
posting on the OASIS, and (3) once a discount is negotiated, details must be
immediately posted on the OASIS. For any discount agreed upon for service on a
path, from Point(s) of Receipt to Point(s) of Delivery, the Participants must
offer the same discounted transmission service rate for the same time period to
all Eligible Customers on all unconstrained transmission paths that go to the
same Point(s) of Delivery on the NEPOOL Transmission System.





                            SCHEDULE 11

            Generator Interconnection Related Upgrade Costs

(1) Classification of Generating Projects. The treatment for purposes of this
Tariff of the Generator Interconnection Related Upgrade costs with respect to
the facilities needed for the interconnection of a particular new or modified
generating unit project in accordance with Section 50 of the Tariff depends on
whether the project is a Category A Project, a Category B Project or a Category
C Project, as follows:

(a) A Category A Project is one whose Generator Owner committed to pay for
upgrade costs prior to October 29, 1998 and has filed a petition with the
Commission requesting that the costs associated with the interconnection of its
generation project be determined in accordance with Schedule 11 of the Tariff,
as filed with the Thirty-Sixth Agreement Amending the Restated NEPOOL Agreement.
Subject to the outcome of proceedings pending before the Commission in Docket
No. ER98-3853, including all appeals, and consistent with the Commission's June
28, 2000 order in Docket Nos. EL00-62-000, et al., and further Commission orders
with respect thereto, the following projects have been identified as potentially
being Category A Projects:

EMI Dighton
EMI Tiverton
EMI Rumford
Polsky AEC
Millennium Power Partners, L.P.
PDC Berkshire
Duke, Bridgeport Energy
Duke, Maine Independence


(b) A Category B Project is any one, other than a Category A Project, on which
the Generator Owner had expended at least $5,000,000, including amounts due
under irrevocable commitments, as of June 22, 1999 with respect to the project.
The Category B Projects are:

Sithe, Mystic Station Expansion Sithe Edgar Station Expansion, Fore River Sithe,
West Medway PG&E, Generating Lake Road Generating PDC, Milford Power PDC,
Meriden Power Reliant Energy, Hope Rhode Island IDC FPL, Bellingham
Constellation, Merrimack (Nickel Hill) Energy Project SEI, Canal Re-powering
ANP, Bellingham ANP, Blackstone Cabot, Island End Calpine, Westbrook Power HQ,
Bucksport AES, Londonderry ConEd, Newington

(c)     A Category C Project is any project which is not a Category A Project or
a Category B Project.

(2) Direct Interconnection Transmission Costs. Direct Interconnection
Transmission Costs shall mean the cost of facilities constructed for sole use of
the Generator Owner that are not PTF. One hundred percent of Direct
Interconnection Transmission Costs shall be the responsibility of the Generator
Owner whether the Generator Owner's project is a Category A Project, a Category
B Project or a Category C Project.

(3)     Treatment of Category A Project Transmission Costs. The allocation of
costs of Generator Interconnection Related Upgrades for Category A Projects
will be determined as follows:

(a) One-half of the Shared Amount (as defined below) of the capital cost of the
PTF upgrade shall constitute Pool-Supported PTF and be included in Annual
Transmission Revenue Requirements under Attachment F. The Generator Owner shall
be obligated to pay, in addition to the Direct Interconnection Transmission
Costs, the other half of the Shared Amount of the capital cost of the PTF
upgrade and all of the capital costs in excess of the Shared Amount, and any
applicable tax gross-up amounts, and such amounts to be paid by the Generator
Owner shall not be included in Annual Transmission Revenue Requirements under
Attachment F. Following completion of the construction or modification of the
Generator Interconnection Related Upgrade, the Generator Owner shall be
obligated to pay its pro rata share of all of the annual costs (including cost
of capital, federal and state income taxes, O&M and A&G expenses, annual
property taxes and other related costs) which are allocable to such upgrade,
pursuant to the interconnection agreement with the individual Transmission Owner
or its designee which is responsible for the construction or modification, which
agreement may be filed with the Commission by the Transmission Owner unsigned
either on its own or at the request of the Generator Owner.

(b) In determining the cost responsibilities related to a Generator
Interconnection Related Upgrade to PTF, the Participants Committee may determine
that all or a portion of the proposed facilities exceed regional system,
regulatory or other public requirements. In such a case, the Participants
Committee shall determine the amount of the excess costs of the Generator
Interconnection Related Upgrade which shall be borne by the entity which is
responsible for requiring such excess costs, and the excess costs shall not be
included in the calculation of the Shared Amount.

(c) The Shared Amount of the capital cost of the Generator Interconnection
Related Upgrade of PTF shall be initially determined as of the time that the
System Impact Study agreement is executed by all parties and the Generator Owner
has paid the cost of the study (such initial determination to be based on the
estimated cost of the Generator Interconnection Related Upgrade, subject to
later adjustment as set forth below) subject to truing up the KW element of the
following formula upon completion of the Generator Interconnection Upgrade, and
shall be the lesser of (1) the full actual capital cost of the Generator
Interconnection Related Upgrade of PTF (excluding any costs which are determined
to be excess costs in accordance with paragraph (b) above) or (2) the amount
determined in accordance with the following formula:

(EQUATION)

               in which:

P     is the maximum amount to be shared;

KW in the case of a generating unit, is the actual demonstrated net capability
of the new generating unit or increase in the capacity of an existing generating
unit corrected to 50*F in kilowatts. If winter operating conditions are shown in
the System Impact Study and/or application under Section 18.4 of the Agreement
to require additional transmission reinforcements beyond those reinforcements
required for summer operating conditions, the net capability of the unit will be
corrected to an ambient air temperature of 0*F;

R is the Pool PTF Rate in effect on the Compliance Effective Date, which is
$15.57 per kilowatt year, adjusted to reflect compliance with the April 5, 1999
Settlement Agreement, approved by the Commission by order dated July 30, 1999 in
Docket Nos. OA97-237-000, et al.; and

C is the weighted average carrying charge factor of all of the Transmission
Providers which own PTF, determined, as of the Compliance Effective Date, in
accordance with Attachment F to the Tariff, which is 15.87 percent, adjusted to
reflect compliance with the April 5, 1999 Settlement Agreement, approved by the
Commission by order dated July 30, 1999 in Docket Nos. OA97-237-000, et al.

(d) All payments required hereunder shall be determined initially on an
estimated basis, and then adjusted after the appropriate portion of the
construction or modification costs has been reflected in Tariff rates in the
first adjustment of Tariff rates after the upgrade has been placed in commercial
operation.

(e) The provisions in this Section (3) with respect to allocation of costs for
Generator Interconnection Related Upgrades of PTF for Category A projects are
subject to further clarifications and/or modifications to reflect the outcome of
proceedings in Commission Docket Nos. ER98-3853 (including any court appeals)
and EL00-62-000, et al., and further Commission orders with respect thereto.

(4) Treatment of Category B Project Transmission Costs. If, and to the extent
capital costs for, a Generator Interconnection Related Upgrade are required to
be incurred in order to satisfy the Minimum Interconnection Standard in
connection with a Category B Project, and would not have been required but for
the interconnection of the generator, one-half of such capital cost of the
Generator Interconnection Related Upgrade, other than Direct Interconnection
Transmission Costs and any excess costs as described below, up to a maximum of
two million dollars ($2,000,000) (or one-half of $4,000,000), shall constitute
Pool-Supported PTF costs and shall be included in Annual Transmission Revenue
Requirements under Attachment F of the Tariff. The Generator Owner shall be
obligated to pay the remaining costs of the Generation Interconnection Related
Upgrade required to be incurred to meet the Minimum Interconnection Standard for
the Category B Project that would not be needed but for the interconnection of
that Generator (including all Direct Interconnection Transmission Costs, any
excess costs as described below, and any applicable tax gross-up amounts) and to
pay the entire costs of any Elective Transmission Upgrade requested by such
Generator Owner (including all Direct Interconnection Transmission Costs, any
excess costs as described below, and any applicable tax gross-up amounts); and
such amounts to be paid by the Generator Owner shall not be included in Annual
Transmission Revenue Requirements under Attachment F. Following completion of
the construction or modification of the Generator Interconnection Related
Upgrade, the Generator Owner shall be obligated to pay its pro rata share of all
of the annual costs (including cost of capital, federal and state income taxes,
O&M and A&G expenses, annual property taxes and other related costs) which are
allocable to such upgrade, pursuant to the interconnection agreement with the
individual Transmission Owner or its designee which is responsible for the
construction or modification, which agreement may be filed with the Commission
by the Transmission Owner unsigned either on its own or at the request of the
Generator Owner.

      In determining the cost responsibilities related to a Generator
Interconnection Related Upgrade for a particular Category B Project, the
Participants Committee may determine that all or a portion of the proposed
facilities exceed regional system, regulatory or other public requirements. In
such a case, the Participants Committee shall determine the amount of the excess
costs of the Generator Interconnection Related Upgrade which shall be borne by
the entity which is responsible for requiring such excess costs, and the excess
costs shall not be included in the calculation of the amount of the capital
costs to be shared as discussed above. All payments required hereunder shall be
determined initially on an estimated basis, and then adjusted after the
appropriate portion of the construction or modification costs has been reflected
in Tariff rates in the first adjustment of Tariff rates after the upgrade has
been placed in commercial operation.

(5) Treatment of Category C Project Transmission Costs. If a Generator
Interconnection Related Upgrade is required in order to satisfy the Minimum
Interconnection Standard in connection with a Category C Project, the Generator
Owner shall be obligated to pay all of the cost of such upgrade, including all
Direct Interconnection Transmission Costs and any applicable tax gross-up
amounts, to the extent such costs would not have been incurred but for the
interconnection. Following completion of the construction or modification, the
Generator Owner shall be obligated to pay all of the annual costs (including
federal and state income taxes, O&M and A&G expenses, annual property taxes and
other related costs) which are allocable to the Generator Interconnection
Related Upgrade, pursuant to the interconnection agreement (or support
agreement) with the individual Transmission Owner or its designee which is
responsible for the construction or modification, which agreement may be filed
with the Commission by the Transmission Owner either signed by both parties or
unsigned at the request of the Generator Owner.

(6) Treatment of Elective Transmission Upgrades for Generating Units. If a
Generator Owner has requested an Elective Transmission Upgrade pursuant to
Section 50.2 of this Tariff in connection with a new or materially changed
generation unit, the Generator Owner shall be subject to the cost, credit
assurance and contract obligations set forth in Section 50.2 and Schedule 12 for
Elective Transmission Upgrades.

(7) Contract and Credit Requirements. If a Generator Interconnection Related
Upgrade is required, the Generator Owner requesting such upgrade, at the request
of the Transmission Owner or its designee responsible for effecting the
construction or modification, shall be obligated to pay to the Transmission
Owner or its designee responsible for effecting the Generator Interconnection
Related Upgrade an amount equal to its share of the estimated cost of the
construction at one time or in monthly or other periodic installments,
including, without limitation, all costs associated with acquiring land, rights
of way easements, purchasing equipment and materials, installing, constructing,
interconnecting, and testing the facilities; O&M and engineering costs; all
related overheads; and any and all associated taxes and government fees. In
addition to, or in lieu of said payment, the affected Transmission Owner or its
designee may require the Generator Owner to provide, as security for its
obligation to pay any unfunded balance of the construction costs, a letter of
credit or other reasonable form of security acceptable to the Transmission Owner
or its designee that will be responsible for the construction equivalent to the
cost of the upgrade including taxes and consistent with relevant commercial
practices, as established by the Uniform Commercial Code. As soon as reasonably
practical, but in any event within 180 days after completion of the construction
or modifications, or as otherwise mutually agreed, the Transmission Owner or its
designee responsible for the construction or modification will determine the
difference, if any, between the estimated cost already paid by the Generator
Owner to the Transmission Owner or its designee responsible for the construction
or modification and its share of the actual cost of the construction or
modification, and will either receive from the Generator Owner, with Interest
(if the sum paid is insufficient) or pay to the Generator Owner, with Interest
(if the sum paid is surplus) the difference; provided that if, at the time such
determination is made, items of construction that remain to be completed and/or
some construction costs have not been invoiced and paid, the Transmission Owner
or its designee responsible for the construction or modification shall continue
to be entitled to recover from the Generator Owner the Generator Owner's share
of the costs of such remaining items and may retain a reserve to cover such
items. Furthermore, the Transmission Owner shall release any letter of credit or
other security instrument received by the Transmission Owner, up to the amount
allowed to be recovered through the Transmission Owner's Annual Transmission
Revenue Requirement for Category A and B Projects, no later than sixty (60) days
after the later of the reflection of such costs in the Pool rates and the
commercial operation of the generation addition or modification. To the extent
Generator Interconnection Related Upgrades, or any portion thereof, are
completed in a calendar year, Transmission Owners will use their best efforts to
reflect such facilities in their Annual Transmission Revenue Requirements
calculated on the basis of that year. That portion of the construction or
modification costs or deposit paid by the Generator Owner may, by mutual
agreement of the Transmission Owner and the Generator Owner, either be retained
by the Transmission Owner, or be refunded to the Generator Owner upon the
Generator Owner executing a contract with the Transmission Owner obligating the
Generator Owner to pay the Transmission Owner the ongoing transmission revenue
requirement associated with its share of the Generator Interconnection Related
Upgrade, including but not limited to cost of capital, federal and state income
taxes, O&M and A&G costs, annual property taxes and all other related costs, and
providing the Transmission Owner with an irrevocable letter of credit or other
form of security acceptable to the Transmission Owner. In the event the
Generator Owner's portion of the construction or modification costs is retained
by the Transmission Owner or its designee in accordance with the preceding
sentence, the Generator Owner will be obligated (i) to pay the federal and state
income taxes required to be paid by the Transmission Owner with respect to the
retained amount, and (ii) to pay annually its percentage of the O&M and A&G
costs, annual property taxes and all other related costs, except for those costs
required to be paid under (i) or any costs that are retained by the Transmission
Owner in accordance with the interconnection agreement. If the Generator Owner
for whatever reason goes out of business, or otherwise abandons its generation
project and the Generator Interconnection Related Upgrade has already been
partially or completely constructed, the Generator Owner shall be responsible
for all of the unrecovered ongoing costs of the upgrade that would not have been
incurred but for the proposed generation project. Nothing contained herein shall
prevent the Transmission Owner or its designee responsible for the construction
or modification and the Generator Owner from negotiating other methods for
providing financial security associated with the cost of an upgrade deemed
acceptable to the Transmission Owner or other entity. Subject to the foregoing,
the interconnection and support agreements for a Generation Interconnection
Related Upgrade may specify the basis for continued support of such upgrade in
the event of a termination of NEPOOL, the cancellation of the project due to a
failure to obtain regulatory approvals or permits or required rights of way or
other property, or action to terminate the project before its completion for
whatever reason and any other matters.

Interest payable hereunder shall be calculated in accordance with Section 8.3 of
the Tariff.




                                   SCHEDULE 12

                 Reliability Upgrade, Economic Upgrade
                and Elective Transmission Upgrade Costs

(1) Allocation and Recovery of Costs for Reliability Upgrades and Economic
Upgrades Associated with the NEPOOL Transmission Plan. All costs of Merchant
Transmission Facilities shall be recovered in accordance with the recovery
mechanism for those facilities that is filed with and accepted by the
Commission. All costs associated with Upgrades for the interconnection of
Merchant Transmission Facilities shall be treated in the same fashion and
subject to the same rights and obligations as Generator Interconnection Related
Upgrade Costs for Category C Projects under Schedule 11 of this Tariff,
including the provisions of Sections (5), (6) and (7) of that Schedule. To the
extent not otherwise covered above or by Part III or Schedule 11 of the Tariff
or Sections (2) or (3) of this Schedule 12 below, the costs of a Reliability
Upgrade and Economic Upgrade shall be allocated as follows:

(a) If entities have agreed to bear some or all of the cost responsibility for
an Upgrade, the Upgrade costs shall be allocated to such entities in accordance
with that agreement.

(b) To the extent there are Reliability Upgrade or Economic Upgrade costs that
are not allocated in accordance with other arrangements as identified in the
introductory language of this Section (1) or subparagraph (a) above, such costs
shall be allocated utilizing an appropriate cost causation and cost benefit
methodology to be specified in NEPOOL System Rules, which are to be a supplement
to the Tariff and are filed with, and accepted by, the Commission. Any
allocation to a specific entity or entities or a Reliability Region or Region(s)
pursuant to such Rules over which there is a dispute shall be filed with the
Commission and shall become effective on the date specified by the Commission.

(c) To the extent there still remain Reliability Upgrade or Economic Upgrade
costs that are not allocated in accordance with other arrangements as identified
in the introductory language of this Section (1) or subparagraphs (a) or (b)
above, or the cost allocation determined in accordance with subparagraph (b) has
not yet become effective, such costs shall be treated as Pool-Supported PTF
costs recoverable under Attachment F to this Tariff.

(2) Elective Transmission Upgrade Costs. The capital and annual costs of
Elective Transmission Upgrades and of any additions to or modifications of the
NEPOOL Transmission System that are required to accommodate the Elective
Transmission Upgrades shall not constitute Pool-Supported PTF costs and shall
not be included in Annual Transmission Revenue Requirements under Attachment F,
except to the extent approved pursuant to the Agreement. Until further review by
the NEPOOL Reliability Committee and amendment of this Tariff, contract and
credit requirements for an Elective Transmission Upgrade shall be governed by
the provisions of Section 50.2 of this Tariff.

(3) Northeast Massachusetts Upgrade Costs. In recognition of the unique
Congestion situation in the Northeast Massachusetts Reliability Region, as
identified in Attachment B to the Agreement, up to thirty-five million dollars
($35,000,000) of the capital costs of Northeast Massachusetts Upgrades shall
constitute Pool-Supported PTF costs and shall be included in Annual Transmission
Revenue Requirements under Attachment F.

A "Northeast Massachusetts Upgrade" is an addition to or modification of the
NEPOOL Transmission System into or within the Northeast Massachusetts
Reliability Region that is not, as of December 31, 1999, the subject of a System
Impact Study or application filed pursuant to Section 18.4 of the Restated
NEPOOL Agreement; that is not related to generation interconnections; and that
will be completed and placed in service by June 30, 2004. Such upgrades include,
but are not limited to, new transmission facilities and related equipment and/or
modifications to existing transmission facilities and related equipment. Any
Northeast Massachusetts Upgrade will be identified within a reasonable period of
time and included in the NEPOOL Transmission Plan to be completed on or about
September 1, 2000. A Northeast Massachusetts Upgrade also must satisfy one of
the following three criteria:

(a) The addition or modification qualifies as an Economic Upgrade. If an
addition or modification meets these requirements, the full estimated capital
cost of the upgrade shall be taken into account for purposes of the $35,000,000
aggregate limit specified above.

(b) The addition or modification qualifies as a Reliability Upgrade meet a
future reliability need within the five years covered by the NEPOOL Transmission
Plan, and the net present value of the expected benefit advancing the
construction of the addition or modification exceeds the incremental cost of
advancing the in-service date of the addition or modification. The incremental
cost of the advancement shall qualify as a cost of Pool-Supported PTF pursuant
to this Section and only the incremental cost shall be taken into account for
purposes of the $35,000,000 aggregate limit specified above. The remaining cost
of the addition or modification shall qualify as the Pool-Supported PTF cost of
a Reliability Upgrade.

(c) The addition or modification is in construction as of January 1, 2000 or
planned for construction in 2000 and would qualify as an Economic Upgrade except
for the fact that it has not yet been included in a NEPOOL Transmission Plan. If
an addition or modification meets this requirement, the full estimated capital
cost of the addition or modification shall be taken into account for purposes of
the $35,000,000 aggregate limit specified above.

The aggregate capital costs of the Northeast Massachusetts Upgrades which
qualify as Pool-Supported PTF costs shall not exceed $35,000,000. If there are
multiple proposed additions or modifications which satisfy the criteria
specified in paragraphs (a), (b), or (c) above, and the aggregate cost of such
proposed additions or modifications to be taken into account for purposes of the
$35,000,000 limit specified above exceeds $35,000,000, the proposed additions or
modifications meeting the criteria specified in paragraph (a) or (b) above with
the highest benefit/cost ratios shall be given priority. For this purpose, the
benefit/cost ratio of an addition or modification is the net present value of
the benefit of the addition or modification divided by the net present value of
the cost of the addition or modification.

In considering whether to undertake a proposed addition or modification which
might otherwise qualify under this Subsection (3), the Transmission Owners and
the System Operator shall not limit their consideration of alternative means of
Congestion relief to transmission additions or modifications.




                              SCHEDULE 13

          Locational Prices; Congestion Cost; Congestion Revenue;
                Marginal Loss Cost; Marginal Loss Revenue

A. Calculation of Locational Prices: When Congestion exists on the NEPOOL
Transmission System, Congestion Cost and Marginal Loss cost shall be recovered,
pursuant to Section B below, from Non-Participant Transmission Customers taking
service under the Tariff. Congestion Cost and Marginal Loss Cost are derived
from the Congestion Components and Marginal Loss Components of Locational Prices
calculated as described below.

(1) Nodal Prices for Nodes and External Nodes. The System Operator shall
calculate the Nodal Price at each Node for each hour of the Dispatch Day for the
Day-Ahead Market using the Day-Ahead unit commitment model, and for the
Real-Time Market using the Real-Time scheduling software. In calculating Nodal
Prices the System Operator shall use the Demand Bids and Supply Offers submitted
pursuant to Sections 14A.3, 14A.4 and 14A.6 of the Agreement. The Real-Time
Nodal Price at each Node for each hour shall be the time interval
weighted-average of the Clearing Prices calculated at that Node for each time
interval within that hour, except as noted in Section A(4) below with respect to
the prices used for Real-Time settlements at External Nodes.

The System Operator shall calculate Nodal Prices for an hour for the Day-Ahead
Market or the Real-Time Market at a given Node i using the following formula, or
a formula similar in substance and effect:

(EQUATION)

where:

(EQUATION)      the Nodal Price at Node i in $/megawatthour;

(EQUATION)      the marginal cost in $/megawatthour, based on Demand Bids and
Supply Offers, to serve additional load at the Reference Node;

(EQUATION)      the Marginal Loss Component of the Nodal Price at Node i in
$/megawatthour; and

(EQUATION) the Congestion Component of the Nodal Price at Node i in
$/megawatthour.

     The Marginal Loss Component of the Nodal Price at any Node i on the NEPOOL
Transmission System is calculated using the equation

(EQUATION)

     in which WFi, the Withdrawal Factor at Node i relative to the system
Reference Node, is calculated using the following equation:

where:

(EQUATION)

L =      NEPOOL Transmission System losses;

Pi =      the net amount of Energy injected into the NEPOOL Transmission System
at Node i; and

(EQUATION) = the ratio of: (1) the amount by which NEPOOL Transmission System
losses occurring in the Day-Ahead Schedule or Real-Time dispatch would have
increased, as calculated by the System Operator's Day-Ahead or Real-Time
computer algorithm, if a very small additional amount of Energy had been
injected at Node i (in addition to the injections and withdrawals already
scheduled to occur on the NEPOOL Transmission System in the Day-Ahead schedule
or occurring on the NEPOOL Transmission System in the Real-Time dispatch), to
(2) the size of the additional injection of Energy at Node i.

     The Congestion Component of the Nodal Price at Node i is calculated using
the equation:

(EQUATION)

where:

K =     the set of thermal or interface constraints;

GFik = the Shift Factor for the generator at Node i on constraint k in the pre-
or post-contingency case that limits flows across that constraint; and

(EQUATION) the reduction in system cost that results from an incremental
relaxation of constraint k, expressed in $/megawatthour.

     Substituting the equations for calculating the Marginal Loss Component and
the Congestion Component of the Nodal Price for the terms and into the equation
for calculating the Nodal Price for a given Node i yields:

(2) Zonal Prices. For Congestion pricing purposes, Load Zones based on
Reliability Regions have been established and Zonal Prices shall be calculated
by the System Operator for each Load Zone. Each Load Zone shall be coterminous
with a Reliability Region, except that a Participant which owns and operates
distribution lines and other facilities used for the distribution of Energy to
retail customers in a single state in New England and which is subject to
regulation by the public utility regulatory authority in that state (a
"Distribution Company") which (i) serves retail customers in more than one
Reliability Region in a single state and (ii) is subject to a state-imposed
obligation to provide its retail customers with a power supply at fixed prices
for a certain time period ("Standard Offer Obligation"), may elect, by notice to
the System Operator and the Secretary of the Participants Committee, within the
time prescribed by the Market Rules, to have its entire service territory
treated as a single Load Zone (a "Distribution Company Load Zone") until its
Standard Offer Obligation ends. In addition, Vermont shall be a single Load Zone
for those Distribution Companies in Vermont that maintain their single
Participant status for settlement purposes with other Distribution Companies in
Vermont pursuant to Section 4 of the Agreement even if Vermont spans more than
one Reliability Region. The election by one or more Distribution Companies in
Vermont not to be treated as a single Participant with other Vermont
Participants shall not affect the Load Zone for the remaining Distribution
Companies in Vermont maintaining the single Participant election.

     After consulting with the Participants, the System Operator may reconfigure
Reliability Regions and add or subtract Reliability Regions as necessary over
time to reflect changes to the grid, patterns of usage and intrazonal
Congestion. The System Operator shall file any such changes with the Commission.

     The System Operator shall calculate a Zonal Price for each Reliability
Region for both the Day-Ahead and Real-Time Markets for each hour using a
load-weighted average of the Nodal Prices for the Nodes within that Reliability
Region. The load weights used in calculating the Day-Ahead Zonal Prices for the
Reliability Region shall be determined in accordance with applicable Market
Rules and shall be based on the Demand Bids for the Nodes that make up that
Reliability Region. The System Operator shall determine, in accordance with
applicable Market Rules, the load weights used in Real-Time based on calculated
load distribution. The System Operator shall calculate Zonal Prices for
Reliability Regions using the following formula, or a formula similar in
substance and effect, where the Zonal Price for a Reliability Region j can be
written as:

(EQUATION)

where:

(EQUATION)  =      Zonal Price for Reliability Region j in $/megawatthour;

(EQUATION)  is the Marginal Loss Component of the Zonal Price for
Reliability Region j in $/megawatthour;

(EQUATION)  is the Congestion Component of the Zonal Price for Reliability
Region j in $/megawatthour;

Nj =      the set of Nodes that make up the Reliability Region j; and

Wij = the load-weighting factor for Node i used to calculate the Zonal Price for
Reliability Region j, determined such that the weighting factors for any given
Reliability Region sum to one.

     For a Distribution Company Load Zone, the Zonal Price shall be determined
by the weighted average of the Zonal Prices for the Reliability Regions making
up the Load Zone, with the weights equal to that Distribution Company's share of
the load in each of those Reliability Regions. The load weights used in
calculating the Day-Ahead Zonal Prices for the Distribution Company Load Zones
shall be determined in accordance with applicable Market Rules and shall be
based on the Demand Bids for the Nodes that make up the Distribution Company
Load Zones. The System Operator shall determine, in accordance with applicable
Market Rules, the load weights used in Real-Time based on the calculated
Real-Time load distribution. The System Operator shall calculate Zonal Prices
for each hour of the Dispatch Day for Distribution Company Load Zones using the
following formula: Zonal Price equals the Distribution Company's load in each
Reliability Region making up the Distribution Company Load Zone times the Zonal
Price for each such Reliability Region summed for all such Reliability Regions
making up the Distribution Company Load Zone, divided by the sum of the
Distribution Company's load in each Reliability Region making up the
Distribution Company Load Zone. The Congestion and Marginal Loss Components of
the Zonal Price for each Distribution Company Load Zone shall be calculated as
the weighted average of the Congestion and Marginal Loss Components,
respectively, of the Zonal Prices in the Reliability Regions making up that Load
Zone, using the same weights that are used to calculate the Zonal Price for that
Distribution Company Load Zone.

(3) Hub Prices. On behalf of the Participants, the System Operator shall
maintain and facilitate the use of a Hub or Hubs for the Energy market,
comprised of a set of Nodes within NEPOOL, which Nodes shall be identified by
the System Operator on its Internet website. The System Operator has used the
following criteria to establish an initial Hub and shall use the same criteria
to establish any additional Hubs:

(i)     each Hub shall contain a sufficient number of Nodes to try to ensure
that a Hub Price can be calculated for that Hub at all times;

(ii) each Hub shall contain a sufficient number of Nodes to ensure that the
unavailability of, or an adjacent line outage to, any one Node or set of Nodes
would have only a minor impact on the Hub Price;

(iii)   each Hub shall consist of Nodes with a relatively high rate of service
availability;

(iv)    each Hub shall consist of Nodes among which transmission service is
relatively unconstrained; and

(v) no Hub shall consist of a set of Nodes for which directly connected load
and/or generation at that set of Nodes is dominated by any one entity or its
affiliates.

The System Operator shall calculate hourly Hub Prices for both the Day-Ahead and
Real-Time Markets using a fixed-weighted average of the Nodal Prices that
comprise the Hub. The System Operator shall calculate Hub Prices using the
following formula, or a formula similar in substance and effect, where the Hub
Price for a Hub j can be written as:

(EQUATION)

where:

(EQUATION)  =      Hub Price for Hub j in $/megawatthour;

(EQUATION)     is as defined in Section A(1);

(EQUATION)  is the Marginal Loss Component of the Hub Price for Hub j in
$/megawatthour;

(EQUATION)  is the Congestion Component of the Hub Price for Hub j in
$/megawatthour;

Hj =      the set of  Nodes in Hub j; and

WijH = the load weighting factor for Node i used to calculate the Hub Price for
Hub j, determined such that the weighting factors for any given Hub sum to one.

Participants may acquire FCRs to and from the Hub in accordance with Schedule 14
of the Tariff.

(4) Nodal Prices for External Nodes. The System Operator shall calculate Nodal
Prices for External Nodes. The External Nodes shall be identified in applicable
Market Rules. External Nodes shall be used for pricing Energy that is received
from or delivered to neighboring Control Areas. The Nodal Prices for External
Nodes shall be calculated in the same way as Nodal Prices for Nodes, with the
exception of the calculation of the Marginal Loss Component of the price.

The Marginal Loss Component of Nodal Prices for External Nodes shall be
calculated so as to ensure that it does not include the effect of withdrawals at
a Node or External Nodes on the cost of losses incurred outside the NEPOOL
Control Area. In order to accomplish this, a hypothetical transaction will be
modeled, in which an increment of load at each External Node is served by an
increment of generation at the Reference Node. The amount of Energy that would
flow out of the NEPOOL Transmission System over each interconnection point
between the NEPOOL Transmission System and an adjoining Control Area or the
Non-PTF transmission system will be calculated next. Finally, the Marginal Loss
Component of the Nodal Price at each External Node will be calculated as the
weighted average of the Marginal Loss Components at each of the interconnection
points between the NEPOOL Transmission System and an adjoining Control Area or
the Non-PTF transmission system. The weight assigned to each interconnection
will be equal to the proportion of the total amount of Energy delivered off of
the NEPOOL Transmission System in association with this hypothetical transaction
that flows over that interconnection. As a result, the Marginal Loss Component
of the price at each External Node will only include the effects on Marginal
Losses on the NEPOOL Transmission System.

The Shift Factors for each External Node determine the proportion of the Energy
in such a transaction that would flow over each interconnection point between
the NEPOOL Transmission System and external Control Areas or the Non- PTF
transmission system and, therefore, the Marginal Loss Component of the Nodal
Price at an External Node i shall be calculated using the following equation, or
a formula similar in substance and effect:

(EQUATION)

where:

(EQUATION)  =      the Marginal Loss Component of the Nodal Price at an External
Node i in $/megawatthour;

I =     the set of interconnection points between the NEPOOL Transmission System
and adjacent Control Areas or the Non-PTF transmission system;

GFin =     Shift Factor at External Node i for the interconnection line that
passes through Node n; and

(WFn - 1) = the Marginal Loss Component of the Nodal Price at Node n in
$/megawatthour, where WFn is the withdrawal factor at Node n and (EQUATION)
  is as defined in Section A(1).

The price used for Real-Time settlements at External Nodes will be the Real-
Time price as determined based on the Real-Time dispatch except in the
circumstance in which imports or exports were constrained in the hour ahead
scheduling process either by constraints that are not monitored in Real-Time or
by closed interface constraints that are not affected by internal dispatchable
generators. In this special circumstance, the price used for Real-Time
settlements of imports from External Nodes will be the lower of the Real-Time
price at the External Node or the hour ahead price at the External Node.
Similarly, in this situation, the price used for Real-Time settlements of
exports to External Nodes will be the higher of the Real-Time price at the
External Node or the hour ahead price at the External Node.

B.     Congestion Cost:

(1) Congestion Cost. Congestion Cost shall be recovered under this Section B
from each Non-Participant Transmission Customer taking service under the Tariff
when the Congestion Component of the Locational Price at the Point of Delivery's
Location exceeds the Congestion Component of the Locational Price at the Point
of Receipt's Location for the transaction. In accordance with NEPOOL System
Rules, each Transmission Customer may elect to specify a maximum Congestion Cost
that it is willing to pay to have its transaction scheduled or to keep its
transaction from being wholly or partially curtailed.

The System Operator shall calculate Congestion Cost to be recovered from such
customers for each hour of the Dispatch Day in which Congestion exists in the
Day-Ahead and the Real-Time Markets. Such Congestion Cost recovered with respect
to Day-Ahead transmission service scheduling shall equal (1) the amount (in
$/megawatthour) by which the Congestion Component of the Day-Ahead Locational
Price at the Point of Delivery's Location exceeds the Congestion Component of
the Day-Ahead Locational Price at the Point of Receipt's Location; multiplied by
(2) the quantity of Energy scheduled by the Transmission Customer for that hour.
Such Congestion Cost recovered with respect to Real-Time transmission service
scheduling shall equal (1) the amount (in $/megawatthour) by which the
Congestion Component of the Real-Time Locational Price at the Point of
Delivery's Location exceeds the Congestion Component of the Real-Time Locational
Price at the Point of Receipt's Location; multiplied by (2) the quantity of
Energy scheduled by the Transmission Customer for that hour, minus the quantity
of Energy that Transmission Customer scheduled for that hour in its Day-Ahead
transmission service scheduling.

(2) Congestion Cost Relief. Each Non-Participant Transmission Customer taking
Through or Out or Point-to-Point Service shall be paid or be credited for
Congestion relief when the Congestion Component of the Locational Price at the
Point of Receipt's Location exceeds the Congestion Component of the Locational
Price at the Point of Delivery's Location for the transaction.

The System Operator shall calculate and allocate such payments or credits to
such customers for each hour of the Dispatch Day in which Congestion exists in
the Day-Ahead and the Real-Time Markets. Such payments or credits made with
respect to the Day-Ahead transmission service scheduling shall equal (i) the
amount (in $/megawatthour) by which the Congestion Component of the Day- Ahead
Locational Price at the Point of Receipt's Location exceeds the Congestion
Component of the Day-Ahead Locational Price at the Point of Delivery's Location;
multiplied by (ii) the quantity of Energy scheduled by the Transmission Customer
for that hour. Such payments or credits made with respect to the Real-Time
Market shall equal (i) the amount (in $/megawatthour) by which the Congestion
Component of the Real-Time Locational Price at the Point of Receipt's Location
exceeds the Congestion Component of the Real-Time Locational Price at the Point
of Delivery's Location; multiplied by (ii) the quantity of Energy scheduled by
the Transmission Customer for that hour, minus the quantity of Energy that
Transmission Customer scheduled for that hour in its Day-Ahead transmission
service scheduling.

C.      Congestion Revenue: For each hour the System Operator shall calculate
and collect Congestion Revenue and maintain a Congestion Revenue Fund in
accordance with Section E of Schedule 14.

D.      Marginal Loss Cost and Marginal Loss Revenue:

(1) Marginal Loss Cost. Marginal Loss cost shall be recovered under this Section
D from each Non-Participant Transmission Customer taking service under the
Tariff when the Marginal Loss Component of the Locational Price at the Point of
Delivery's Location exceeds the Marginal Loss Component of the Locational Price
at the Point of Receipt's Location for the transaction.

The System Operator shall calculate Marginal Loss cost to be recovered from such
customers for each hour of the Dispatch Day. Such costs shall equal the amount
(in $/megawatthour) of the Marginal Loss Component of the Real-Time Locational
Price at the Point of Delivery's Location minus the Marginal Loss Component of
the Real-Time Locational Price at the Point of Receipt's Location, multiplied by
the amount of Energy scheduled for the transaction in that hour.

Each Non-Participant Transmission shall be paid or credited when the Marginal
Loss Component of the Real-Time Locational Price at the Point of Receipt's

Location exceeds the Marginal Loss Component of the Real-Time Locational Price
at the Point of Delivery's Location for the transaction. Such Marginal Loss
payment or credit shall equal the amount (in $/megawatthour) of the Marginal
Loss Component of the Real-Time Locational Price at the Point of Receipt's
Location minus the Marginal Loss Component of the Real-Time Locational Price at
the Point of Delivery's Location, multiplied by the amount of Energy scheduled
for the transaction in that hour.

(2) Marginal Loss Revenue. To the extent that there is any Marginal Loss Revenue
in any settlement period, such revenue shall be collected in a Marginal Loss
Revenue Fund and allocated in accordance with the Market Rules to load serving
entities paying for Energy during such settlement period.

E.      Additional Rules and Procedures: Consistent with this Schedule 13, the
implementation of its provisions shall further be detailed, defined and carried
out pursuant to the Agreement and Market Rules.




                                   SCHEDULE 14

                 Financial Congestion Rights ("FCRs")

The System Operator shall implement and administer a system of Financial
Congestion Rights ("FCRs") as provided for below.

A. FCR Holder Status and Transfer of FCRs: FCRs shall be awarded to winning
bidders in the mandatory FCR Auctions pursuant to Section F below and may be
acquired in the subsequent bilateral market from FCR Holders. An entity that
acquires an FCR through the FCR Auction shall automatically be recognized by the
System Operator as the registered FCR Holder of that FCR, subject to having
already met the eligibility criteria for bidding in the FCR Auction. The
registered FCR Holder shall be entitled to receive or be obligated to make FCR
Payments arising from such FCR in accordance with Section C.

An entity that acquires an FCR through the FCR Auction or through a subsequent
bilateral transaction may elect to hold it, sell it in the FCR Auction or sell
it bilaterally. The registered FCR Holder of an FCR sold in a bilateral
transaction will continue to be the FCR Holder for that FCR unless it submits a
confirmation of the sale to the System Operator in accordance with the Market
Rules. The System Operator upon receipt of such a confirmation will transfer
record ownership on its register. The purchaser of an FCR in a bilateral
transaction that is not recorded on the System Operator's register receives only
a contractual right against the seller of the FCR and has no rights or
obligations in settlement or in the Energy market. An entity who subsequently
acquires an FCR from an FCR Holder through a bilateral transaction must meet
applicable criteria established by the Participants Committee, including
creditworthiness criteria, to be the FCR Holder of that FCR and secure the
associated rights and obligations. The System Operator shall settle FCRs only
with the registered FCR Holders. At any given time, each FCR shall have only one
registered FCR Holder.

B. FCR Designation and Simultaneous Feasibility: FCRs shall be unidirectional,
financial transmission rights based on the transfer capability of the NEPOOL
Transmission System, denominated in Megawatts, designated to and from specified
Locations and/or Reliability Regions, and lasting for a certain term. To the
extent feasible, FCRs valid for on-peak and/or off-peak periods shall be
available in the FCR Auctions and shall be accommodated in the FCR settlement
process by the System Operator.

Each FCR shall be designated to and from specified Locations and/or Reliability
Regions for the purpose of determining FCR Payments. Each FCR shall also have a
specified origin and destination Node that shall be used to determine to which
new Load Zone and/or Reliability Region an existing FCR would be assigned if and
when a Load Zone and/or Reliability Region were reconfigured.

The System Operator shall determine, initially and periodically thereafter in
conjunction with the FCR Auctions, the FCRs that can be made available based on
a simultaneous feasibility test. The purpose of the test shall be to determine
whether the NEPOOL Transmission System, under security constrained conditions,
could accommodate all the potential transactions represented by a defined set of
FCRs.

The System Operator shall maintain a record of the FCRs, containing such
information as is necessary to administer the system of FCRs including, but not
limited to, each FCR's designated origin and destination Nodes and settlement
Locations and/or Reliability Regions, Megawatt amount, registered Holder, and
the period during which the FCR is valid. FCR Holders shall provide the System
Operator with such information regarding the FCRs as is reasonably requested by
the System Operator for the administration of the system of FCRs.

An FCR Holder may, to the extent permitted by the Market Rules, subdivide FCRs
into individually transferable components representing the intermediate points
of injection and withdrawal contained within the FCR's path, such that an FCR
from point A to point C, for example, may be subdivided prior to transfer based
on the intermediate point B, resulting in two individually transferable FCRs,
one from point A to point B, and one from point B to point C. Likewise, the
Holder of an FCR that is valid for more than one hour may, to the extent
permitted by the Market Rules, subdivide that FCR into individually transferable
components representing subsets of those hours. For example, an FCR valid during
January and February may be subdivided into an FCR valid during January and an
FCR valid during February, each of which would be individually transferable.

FCRs awarded in the FCR Auction or acquired through subsequent bilateral
transactions may be reconfigured, but only through the System Operator. The
System Operator shall facilitate the transfer and reconfiguration of FCRs,
ensure their simultaneous feasibility, and register the FCR Holders of the
reconfigured FCRs.

In effecting the award or transfer of any FCR that can be subdivided into any of
the following general and specific components, the System Operator shall
subdivide the FCR into its general and specific components and record the FCR as
having such components. The general components are Load Zone and/or Reliability
Region to Load Zone and/or Reliability Region, Hub to Load Zone and/or
Reliability Region, Load Zone and/or Reliability Region to Hub. The specific
components are Node or External Node to Load Zone and/or Reliability Region in
which the Node or External Node is located, Load Zone and/or Reliability Region
to Node or External Node contained in the Load Zone and/or Reliability Region,
and Node or External Node to Node or External Node contained in the same Load
Zone and/or Reliability Region.

Each FCR shall be designated to and from specified Locations and/or Reliability
Regions for the purpose of determining FCR Payments. Each FCR shall also have a
specified origin and destination Node that shall be used to determine to which
new Load Zone and/or Reliability Region an existing FCR would be assigned if and
when a Load Zone and/or Reliability Region were reconfigured.

The System Operator shall determine, initially and periodically thereafter in
conjunction with the FCR Auctions, the FCRs that can be made available based on
a simultaneous feasibility test. The purpose of the test shall be to determine
whether the NEPOOL Transmission System, under security constrained conditions,
could accommodate all the potential transactions represented by a defined set of
FCRs.

The System Operator shall maintain a record of the FCRs, containing such
information as is necessary to administer the system of FCRs including, but not
limited to, each FCR's designated origin and destination Nodes and settlement
Locations and/or Reliability Regions, Megawatt amount, registered Holder, and
the period during which the FCR is valid. FCR Holders shall provide the System
Operator with such information regarding the FCRs as is reasonably requested by
the System Operator for the administration of the system of FCRs.

An FCR Holder may, to the extent permitted by the Market Rules, subdivide FCRs
into individually transferable components representing the intermediate points
of injection and withdrawal contained within the FCR's path, such that an FCR
from point A to point C, for example, may be subdivided prior to transfer based
on the intermediate point B, resulting in two individually transferable FCRs,
one from point A to point B, and one from point B to point C. Likewise, the
Holder of an FCR that is valid for more than one hour may, to the extent
permitted by the Market Rules, subdivide that FCR into individually transferable
components representing subsets of those hours. For example, an FCR valid during
January and February may be subdivided into an FCR valid during January and an
FCR valid during February, each of which would be individually transferable.

FCRs awarded in the FCR Auction or acquired through subsequent bilateral
transactions may be reconfigured, but only through the System Operator. The
System Operator shall facilitate the transfer and reconfiguration of FCRs,
ensure their simultaneous feasibility, and register the FCR Holders of the
reconfigured FCRs.

In effecting the award or transfer of any FCR that can be subdivided into any of
the following general and specific components, the System Operator shall
subdivide the FCR into its general and specific components and record the FCR as
having such components. The general components are Load Zone and/or Reliability
Region to Load Zone and/or Reliability Region, Hub to Load Zone and/or
Reliability Region, Load Zone and/or Reliability Region to Hub. The specific
components are Node or External Node to Load Zone and/or Reliability Region in
which the Node or External Node is located, Load Zone and/or Reliability Region
to Node or External Node contained in the Load Zone and/or Reliability Region,
and Node or External Node to Node or External Node contained in the same Load
Zone and/or Reliability Region.

C. FCR Payments: Except as provided in Section E below, each FCR Holder shall be
entitled to receive for each hour of the Dispatch Day for which that FCR is
valid an FCR Payment for an FCR when the Congestion Component of the Locational
Price at the FCR's specified destination Location and/or Reliability Region
exceeds the Congestion Component of the Locational Price at the FCR's specified
origin Location and/or Reliability Region. Such FCR Payment shall equal the
amount (in $/megawatthour) by which the Congestion Component of the Locational
Price at the FCR's specified destination Location and/or Reliability Region
exceeds the Congestion Component of the Locational Price at the FCR's specified
origin Location and/or Reliability Region, multiplied by the Megawatt
designation of the FCR for that hour. The FCR Holder shall be entitled to
receive such FCR Payments independent of the FCR Holder's actual use of the
NEPOOL Transmission System.

In the event that in any hour of the Dispatch Day in which an FCR is valid the
Congestion Component of the Locational Price at an FCR's specified origin
Location and/or Reliability Region exceeds the Congestion Component of the
Locational Price at the FCR's specified destination Location and/or Reliability
Region, the FCR Holder of that FCR shall be obligated to make an FCR Payment.
Such FCR Payment shall equal the amount (in $/megawatthour) by which the
Congestion Component of the Locational Price at the FCR's specified origin
Location exceeds the Locational Price at the FCR's specified destination
Location, multiplied by the Megawatt designation of the FCR, for that hour. The
FCR Holder shall be obligated to make such FCR Payments independent of the FCR
Holder's actual use of the NEPOOL Transmission System.

D. FCR Settlements: FCRs may be acquired from: Node to Node, Node to External
Node, Node to Hub, Node to Load Zone, Node to Reliability Region; External Node
to Node, External Node to External Node, External Node to Hub, External Node to
Load Zone, External Node to Reliability Region; Hub to Node, Hub to External
Node, Hub to Hub (if multiple Hubs are established), Hub to Load Zone, Hub to
Reliability Region; Load Zone to Hub, Load Zone to Node, Load Zone to External
Node, Load Zone to Load Zone, Load Zone to Reliability Region; Reliability
Region to Node, Reliability Region to External Node, Reliability Region to Hub,
Reliability Region to Load Zone, and Reliability Region to Reliability Region.
Each FCR shall be settled based on its designated settlement Locations and/or
Reliability Regions.

FCRs shall be settled for the Day-Ahead Market not the Real-Time Market. FCRs
shall be settled based on the difference between the Congestion Components of
the relevant Locational Prices at the origin and destination Locations and/or
Reliability Regions.

E. Congestion Revenue Shortfalls or Surpluses: There may be instances (resulting
from physical conditions on the NEPOOL Transmission System or other reasons) in
which the total Congestion Revenue collected by the System Operator will be less
or more than the sum of all Target FCR Payments, creating Congestion Revenue
Shortfalls or Surpluses. A cash reserve in the Congestion Revenue Fund shall be
established and maintained by the System Operator so as to minimize the impact
on FCR Holders of Congestion Revenue Shortfalls. During each month, a Congestion
Revenue Surplus would increase the cash reserve, and a Congestion Revenue
Shortfall would decrease the cash reserve.

The System Operator shall calculate the Congestion Revenue collected and the
total Target FCR Payments on an hourly basis. The System Operator shall
determine total Target FCR Payments by summing the Target FCR Payments in a
given hour over all FCRs. The actual Congestion Revenue collections in each hour
shall be calculated through the following steps:

(1)     multiplying the withdrawals at each Location and/or Reliability Regions
by the Congestion Component of the Locational Price applying to that withdrawal;

(2)     summing the calculation in Step 1 over all withdrawals;

(3)     multiplying the injections at each Node by the Congestion Component of
the Nodal Price applying to that injection;

(4)     summing the calculation in Step 3 over all injections; and

(5)     subtracting the total calculated in Step 4 from the total calculated in
Step 2.

If the actual Congestion Revenue collected in each hour, summed over all hours
in a billing month, exceeds the total Target FCR Payments for each hour, summed
over all hours in that billing month, then the difference will constitute a
Congestion Revenue Surplus for that billing month. All Congestion Revenue
Surpluses will be added to the Congestion Revenue Fund, and all FCR Payments
made from the Congestion Revenue Fund to FCR Holders for that billing month
shall be equal to the Target FCR Payments to those FCR Holders.

If the actual Congestion Revenue collected in each hour, summed over all hours
in a billing month, is less than the total Target FCR Payments for each hour,
summed over all hours in that billing month, then the difference will constitute
a Congestion Revenue Shortfall for that billing month. If there is a Congestion
Revenue Shortfall for that billing month, but that Congestion Revenue Shortfall
is not greater than the balance of the Congestion Revenue Fund cash reserve
entering the month, then the Congestion Revenue Shortfall shall be deducted from
the Congestion Revenue Fund, and all FCR Payments made from the Congestion
Revenue Fund to FCR Holders for that billing month shall be equal to the Target
FCR Payments to those FCR Holders.

If the Congestion Revenue Shortfall for a month is greater than the balance of
the Congestion Revenue Fund cash reserve entering the month, then that balance
as of the conclusion of that month shall be set to zero, and the funds in the
Congestion Revenue Fund will be used to make FCR Payments to FCR Holders.
However, these funds, in combination with the Congestion Revenue collected in
that billing month, will not be sufficient to permit the FCR Payment to each FCR
Holder to be equal to the Target FCR Payment to that FCR Holder for every hour
in that billing month. Consequently, each FCR Payment made by the Congestion
Revenue Fund to an FCR Holder for an hour in that month shall be set equal to
the Target FCR Payment that would have been payable to that FCR Holder for that
hour multiplied by a proportionality factor. This proportionality factor (which
shall be the same for all hours and all FCRs) shall be the number that makes the
sum of all FCR Payments made by the Congestion Revenue Fund for that billing
month equal to the sum of: (1) the balance of the Congestion Revenue Fund at the
beginning of that billing month; (2) the Congestion Revenue collected for that
billing month; (3) the FCR Payments made by FCR Holders to the Congestion
Revenue Fund for that billing month; and (4) the amount paid, if any and to the
extent provided for in the Market Rules, by generators interconnecting with the
NEPOOL Transmission System for redispatch caused by interconnecting such
generators.

When an FCR Holder is obligated to make an FCR Payment in accordance with
Section C above, the FCR Holder shall be obligated to make a payment to the
Congestion Revenue Fund equal to the Target FCR Payment. This obligation shall
not be affected by the existence of a Congestion Revenue Shortfall or Surplus.

At the end of each calendar year, the balance of the Congestion Revenue fund
will first be used to pay the holder of any FCR who received less than the
Target FCR Payment with respect to that FCR in a month during the calendar year.
To the extent that the balance is not sufficient to pay all such Target FCR
Payment shortfalls, the shortfalls will be multiplied by a proportionality
factor that makes the sum of all shortfalls equal to the balance in the
Congestion Revenue fund. To the extent that the balance exceeds the amount
required to pay all shortfalls, any remaining balance, with the exception of any
amount that is retained in the Congestion Revenue Fund pursuant to the Market
Rules, shall be allocated to those entities who paid for Congestion Cost either
under the Agreement or the Tariff. Such allocation shall be in accordance with
the Market Rules.

F. FCR Auctions: Prior to the implementation of CMS, and on an annual and
monthly basis following the CMS/MSS Effective Date, the System Operator shall
perform a simultaneous feasibility test using appropriate power flow models of
security-constrained dispatch to determine the feasible set of simultaneous FCRs
that can be offered in the annual and monthly FCR Auctions. Such test shall take
into account already awarded FCRs (following the first FCR Auction), and outages
of both individual generation units and transmission facilities. Such tests
shall be based on reasonable assumptions about the configuration and
availability of transmission capability during the period covered by the FCR
Auction. The System Operator shall perform the simultaneous feasibility test
with the purpose of ensuring that there will be adequate Congestion Revenue
under expected conditions to fund FCR Payments made to the purchasers of FCRs
sold in the FCR Auction.

FCRs shall be reconfigured and awarded in the FCR Auction to maximize the
valuation of the awarded FCRs (based on buyers' bids) net of the value of the
offered FCRs (based on sellers' reservation prices in the case of previously
awarded FCRs offered for sale, or based on a zero price in the case of FCRs
supporting payments to ARR Holders), subject to the constraint that the awarded
FCRs must be simultaneously feasible in a security constrained dispatch in
conjunction with all FCRs already awarded in the FCR Auction or acquired through
subsequent bilateral transactions and held by FCR Holders and not offered into
the auction.

Based on the outcome of the System Operator's simultaneous feasibility tests,
FCRs shall be made available to Eligible FCR Bidders through periodic FCR
Auctions conducted by the System Operator or another authorized agent of the
NEPOOL Participants. An "Eligible FCR Bidder" is an entity that has satisfied
the reasonable creditworthiness criteria set by the Participants Committee, and
shall not include the Auctioneer, its affiliates, and their officers, directors,
employees, consultants and other representatives.

FCR Auctions shall initially be held on both a biannual and a monthly basis. In
the initial biannual FCR Auction, the maximum term of the awarded FCRs shall be
six months. Ten percent of the transfer capacity of the NEPOOL Transmission
System will be made available to support the sale in this initial auction of
FCRs with a term of six months. During the second biannual FCR Auction,
twenty-five percent of the transfer capacity of the NEPOOL Transmission System
will be made available to support FCRs with a term of six months. During this
initial twelve-month period, following each biannual FCR Auction, the remaining
transfer capability of the NEPOOL Transmission System will be made available to
support the sale of FCRs with a term of one month in the monthly FCR Auctions.

Following the initial auctions, FCR Auctions shall be held on both an annual and
a monthly basis. Fifty percent of the feasible FCRs that can be made available
with a term of one (1) year to five (5) years (in one-year increments for the
five calendar years immediately subsequent to the FCR Auction) shall be made
available in the annual FCR Auction conducted in accordance with the Market
Rules.

Each Eligible FCR Bidder may submit bids in the annual FCR Auction for FCRs for
a single year or for multiple years in the five-year period covered by the
auction. Each Eligible FCR Bidder in the annual FCR Auction shall specify the
year or years for which it wishes to purchase a specified FCR.

After the annual FCR Auction has been conducted, the remaining feasible FCRs,
each having a term of one month, shall be made available in monthly FCR Auctions
conducted in accordance with the Market Rules.

After each auction of monthly FCRs is complete, a residual FCR sale mechanism
shall be established pursuant to the Market Rules, in which any FCR that is
simultaneously feasible in conjunction with all outstanding FCRs may be
purchased on a daily, peak and off-peak basis for any day of the next month.

Each offer to sell a previously awarded FCR shall identify the FCR by Megawatt
quantity and the FCR's origin and destination Locations and/or Reliability
Regions and other pertinent information as required by the Market Rules. An
offer to sell a specified Megawatt quantity of FCRs shall be deemed an offer to
sell a quantity of FCRs equal to or less than the specified quantity. An offer
to sell may not specify a minimum quantity being offered. Each offer to sell a
previously awarded FCR may specify a reservation price, below which the offeror
will not sell the FCR.

Each bid to buy an FCR shall specify the Megawatt quantity, price per Megawatt,
and specific origin and destination Locations and/or Reliability Regions of the
FCR and other pertinent information as required by the Market Rules. A bid to
purchase a specified Megawatt quantity of FCRs shall be deemed a bid to purchase
a quantity of FCRs equal to or less than the specified quantity. A bid to
purchase may not specify a minimum quantity that the bidder wishes to purchase.
A bid to purchase may specify any origin and destination Locations and/or
Reliability Regions for which the System Operator calculates Locational Prices.

Offers and bids in the FCR Auction may specify on-peak and off-peak time periods
of the Dispatch Day for which an FCR will be valid.

The System Operator shall model all existing FCRs not offered into the FCR
Auction in the simultaneous feasibility test as fixed injections and withdrawals
on the NEPOOL Transmission System for their remaining term, thereby in effect
reserving the transfer capability required to honor the existing FCR. FCRs to
and from a Hub shall be treated in the simultaneous feasibility test as
injections and withdrawals at each Node comprising that Hub, with the amount
injected or withdrawn at each such Node corresponding to the weight assigned by
the System Operator to that Node when calculating the Hub Price at that Hub in
the Day-Ahead Market. FCRs to and from Load Zones and/or Reliability Regions
shall be treated in the simultaneous feasibility test as injections and
withdrawals at each Node in that Load Zone and/or Reliability Regions, with the
amount injected or withdrawn at each such Node corresponding to the weights
assigned by the System Operator to that Node when calculating the Zonal Price
for that Load Zone and/or Reliability Regions in the Day-Ahead Market. The
System Operator's simultaneous feasibility test shall also test for revenue
adequacy under future Load Zone and/or Reliability Regions definitions through a
second test in which FCRs with a term of one year or more to and from Load Zones
and/or Reliability Regions would be treated as injections and withdrawals at the
designated origin and destination Locations and/or Reliability Regions for each
FCR.

Each winning bidder for an FCR in an FCR Auction shall pay the market- clearing
price as determined by the FCR Auction, for the awarded FCR when that price is
positive. If the market-clearing price for the awarded FCR is negative, the
winning bidder for that FCR shall receive a payment equal to the absolute value
of the market-clearing price for that FCR. Each seller of an FCR in the FCR
Auction shall be paid the market-clearing price, as determined by the FCR
Auction, for the FCR sold when that price is positive. If the market-clearing
price for the FCR sold is negative, the seller of that FCR shall make a payment
equal to the absolute value of the market-clearing price for that FCR. As soon
as feasible and in accordance with the Market Rules, the System Operator shall
post on its Internet website the market- clearing price of each FCR sold in the
FCR Auction.

Revenues from the FCR Auctions shall be collected by the System Operator or
another authorized agent of the NEPOOL Participants and held in the Auction
Revenue Fund. FCR Auction Revenue shall be allocated to FCR Holders who sell
their FCRs in the FCR Auction and to Auction Revenue Rights Holders as described
in Schedule 15 and Section 49.

G. FCRs as Options: To the extent feasible, as determined by the Participants
Committee and the System Operator, FCRs in the form of financial options shall
be available through the FCR Auctions. The rules governing such option type
FCRs, if such FCRs have been determined feasible, shall be stated in the Tariff
and detailed in the NEPOOL System Rules.

H.     Additional Rules and Procedures:       Consistent with this Schedule 14,
the implementation of its provisions shall further be detailed, defined and
carried out pursuant to the Market Rules.




                            SCHEDULE 15

                        Auction Revenue Rights

Auction Revenue Rights ("ARRs") are rights to receive FCR Auction Revenues from
the sale of FCRs other than FCRs sold by FCR Holders. ARRs shall be determined
and allocated to Congestion Paying Entities, Transmission Customers and NEMA
LSEs (including any of the foregoing that are parties to Excepted Transactions
that are included in the list of transactions in Attachments G and G-2 of the
Tariff), using a four-stage process as described below (the "ARR Allocation").

A.     First Stage of ARR Allocation

(1) Excepted Transactions. In the first stage of each ARR Allocation, each
entity serving load to which Energy is delivered pursuant to an Excepted
Transaction included in the list of transactions in Attachments G and G-2 of the
Tariff, and which is the party responsible for paying Congestion Cost associated
with Energy purchased under the Excepted Transaction shall have the option to be
allocated ARRs from the generator to the location of the load. Alternatively,
each seller delivering Energy pursuant to an Excepted Transaction to an entity
serving load and which seller is the party responsible for paying Congestion
Cost associated with Energy purchased under the Excepted Transaction shall have
the option to be allocated ARRs from the generation source to the load.

In order to be eligible to receive ARRs in association with an Excepted
Transaction, each entity to which Energy is delivered pursuant to an Excepted
Transaction or which delivers Energy pursuant to an Excepted Transaction must
request that it be allocated ARRs pursuant to this section prior to the second
stage of the ARR Allocation. The first-stage ARR Allocation to an entity serving
load to which Energy is delivered pursuant to an Excepted Transaction who makes
such a request shall be equal to the number of Megawatts of Energy to be
delivered to that customer under the Excepted Transaction. The origin Node or
External Node for those ARRs shall match the generation source for any such
Excepted Transaction and the destination Locations and/or Reliability Regions
for those ARRs shall match the location of the load served by those Excepted
Transactions. The first-stage ARR Allocation to an entity selling Energy to an
entity serving load to which Energy is delivered pursuant to an Excepted
Transaction who makes such a request shall be equal to the number of Megawatts
of Energy to be delivered by that selling entity under the Excepted Transaction.
The origin Node or External Node for those ARRs shall match the generation
source for any such Excepted Transaction and the destination Locations and/or
Reliability Regions for those ARRs shall match the Locations and/or Reliability
Regions of the load served by those Excepted Transactions.

Each entity shall be entitled to make requests for ARRs under the terms of this
section until the Excepted Transaction has terminated, or ten years from the
CMS/MSS Effective Date, whichever is earlier.

(2) Transmission Customers and Congestion Paying Entities. ARRs shall be
allocated to each Congestion Paying Entity and Transmission Customer from each
NEPOOL generator and tie line source in proportion to the capacity of the
generator and tie line source and in proportion to the Monthly Peak Load served
by that Congestion Paying Entity or Transmission Customer, provided, however,
that the allocation of first-stage ARRs to Transmission Customers under this
Section A(2) shall be in proportion to: (i) the Transmission Customer's Monthly
Peak Load not served by a Congestion Paying Entity, less (ii) any portion of the
Transmission Customer's or Congestion Paying Entity's load for which ARRs have
been allocated pursuant to the Excepted Transaction election described above.
The determination of the first-stage ARR Allocation to Transmission Customers
and Congestion Paying Entities shall be performed using the following formula:

Nijkt = Git * (Ljkt/Lt),

where:

Nijkt = the amount of ARRs from Node or External Node i to Reliability Region j
awarded to Transmission Customer or Congestion Paying Entity k for month t;

Git =     the total rated capacity for month t of generators or the capacity
during month t-1 of tie line capacity located at node i;

Ljkt= the Monthly Peak Load of Transmission Customer or Congestion Paying Entity
k calculated on the basis of its Monthly Peak Load during the same month t of
the prior year in Reliability Region j, less any portion of that Monthly Peak
Load (up to a maximum of the total Monthly Peak Load) for which ARRs have been
allocated in association with Excepted Transactions as described above; and

Lt = total Monthly Peak Load during month t of the prior year.

The total quantity of ARRs assigned pursuant to this Section A(2) to
Transmission Customer or Congestion Paying Entity k in month t shall be:

(EQUATION)

B. Second Stage of ARR Allocation: The amount of ARRs allocated to each entity
in the first stage of each ARR Allocation may be modified in the second stage of
that ARR Allocation. The second stage of each ARR Allocation shall determine the
final allocation of ARRs to all ARR Holders for that FCR Auction, except for
NEMA LSEs. Allocations of ARRs to NEMA LSEs may be modified in the third and
fourth stages of the ARR Allocation for each FCR Auction.

The second stage of each ARR Allocation shall be performed using the following
procedure, which will be adjusted on an annual and monthly basis to account for
changes in available transmission capacity, load ratio shares, transfer of load
obligations and the termination or expiration of Excepted Transactions. The
System Operator shall make such adjustments in accordance with the allocation
methodology described below, the Agreement, and NEPOOL System Rules.

Step 1: Begin with the combination of all ARRs included in the first-stage ARR
Allocation described in Section A above. This set of ARRs almost certainly will
not be simultaneously feasible.

Step 2:      Hold the FCR Auction as described in Section F of Schedule 14.

Step 3: Through the following steps, eliminate ARRs having a negative value in
the FCR Auction and then reduce the set of remaining ARRs defined in Step 1
proportionately on a per Megawatt of constraint impact basis as necessary to
arrive at a set of ARRs that is simultaneously feasible in a contingency
constrained dispatch.

3(a):     Identify all ARRs determined in Step 1 that receive a positive value
(in $/Megawatt) in the FCR Auction.

3(b):     Test whether the ARRs identified in Step 3(a) are simultaneously
feasible.

3(c):     If the ARRs identified in Step 3(a) are simultaneously feasible, go to
Step 4.

3(d): If the ARRs identified in Step 3(a) are not simultaneously feasible,
calculate the pre- and post-contingency power flows associated with dispatching
the system to honor the ARRs defined in Step 3(a).

3(e): Identify the constraint whose relief would require the largest
proportionate reduction in all of the ARRs defined in Step 3(a) that increase
flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all ARRs defined in Step 3(a) that increase flows over
this constraint until the constraint is relieved.

3(f): Test whether the ARRs identified in Step 3(e) are simultaneously feasible.
If the set of ARRs defined in Step 3(e) is simultaneously feasible, proceed to
Step 4.

3(g): Otherwise, calculate the pre- and post-contingency power flows associated
with dispatching the system to honor the ARRs defined in Step 3(e).

3(h): Identify the constraint whose relief would require the largest
proportionate reduction in all of the ARRs defined in Step 3(e) that increase
flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all ARRs defined in Step 3(e) that increase flows over
this constraint until the constraint is relieved.

3(i)     Repeat Steps 3(f) through 3(h) as necessary until a simultaneously
feasible set of ARRs is obtained.

3(j) If as a result of the application of Steps 3(e) through 3(i) any of the
constraints over which ARRs were reduced in Steps 3(e) through 3(i) is no longer
binding, ARRs defined in Step 3(a) that have been reduced in Steps 3(e) through
3(i) and do not exacerbate any binding transmission constraint would be
proportionately scaled up until a transmission constraint becomes binding.

The allocation process ends here if NEMA is not significantly constrained and
the ARRs allocated at the conclusion of Step 3(j) constitute the final
allocation of ARRs.

Step 4. The ARR Allocation determined in the preceding steps shall be divided
into two sets: ARRs allocated to entities that are not NEMA LSEs, and ARRs
allocated to NEMA LSEs.

NEMA LSEs are Transmission Customers and Congestion Paying Entities that serve
load within NEMA.

C. Third Stage of ARR Allocation. The ARRs allocated to NEMA LSEs, as determined
in the first two stages of each ARR Allocation, may be modified further in the
third and fourth stages of the ARR Allocation. The third and fourth stages of
any ARR Allocation shall not change the amount or origin Nodes or External Nodes
or destination Locations and/or Reliability Regions of any ARRs allocated to
entities that are not NEMA LSEs as of the conclusion of the second stage of that
ARR Allocation.

For the purposes of this stage, a set of "Stage 3 ARRs" shall be defined as
follows: Certain NEMA LSEs which have long-term purchase contracts in effect as
of November 1, 1999 for generation resources with delivery points in NEMA,
excluding long-term purchase contracts covered by Excepted Transactions, ("NEMA
Contracts") shall be allocated Stage 3 ARRs. The NEMA Contracts for these NEMA
LSEs' respective generation resources and entitlements, which entitle them to
Stage 3 ARRs subject to verification that the NEMA Contracts meet the criteria
specified in the preceding sentence, are listed in Attachment 1 to this Schedule
15. Each NEMA LSE listed in Attachment 1 shall provide by October 1, 2000 to the
System Operator and shall make available upon request to each NEMA LSE, copies
of its NEMA Contract(s) in the form that such contracts existed as of November
1, 1999, together with copies of any subsequent modifications or amendments, any
notices of termination, and any notices or elections shortening the term or
reducing the amount of power to be purchased under its NEMA Contract(s). For as
long as a NEMA LSE listed in Attachment 1 has a right to request Stage 3 ARRs,
it shall have an ongoing obligation to provide, in a timely manner, each NEMA
LSE and the System Operator with copies of any further modifications or
amendments, any notices of termination, and any notices or elections shortening
the term or reducing the amount of power to be purchased under its NEMA
Contract. The amount of Stage 3 ARRs that will be allocated to each NEMA LSE
shall be equal to the sum of the Megawatts of entitlement specified in each NEMA
LSE's NEMA Contract(s) calculated based on the winter capability period (the
period from the beginning of October through the end of May) capacity during
months of the winter capability period and the summer capability period (the
period from the beginning of June through the end of September) capacity during
the months of the summer capability period subject to the limitation that the
Stage 3 ARRs allocated to each NEMA LSE shall not exceed that NEMA LSE's Monthly
Peak Load during that month of the prior year, as defined in the NEPOOL Tariff.
The origin Node or External Node for the Stage 3 ARRs allocated to NEMA LSEs
shall match the Node or External Node where Energy was purchased in association
with the NEMA Contracts listed in Attachment 1, and the destination Location for
the Stage 3 ARRs allocated to NEMA LSEs shall match the Location of the load
served by that NEMA LSE in association with that contract.

The NEMA LSEs identified in Attachment 1 to this Schedule 15 shall be entitled
to make requests for Stage 3 ARRs under the terms of this section until the
earlier of the expiration of the term of each of its NEMA Contract(s) in effect
as of November 1, 1999, but excluding any optional extensions which had not been
exercised as of November 1, 1999, or until NEMA is no longer significantly
constrained. To the extent that such a NEMA LSE transfers to other another
entity the responsibility under the Agreement or the Tariff for paying for the
Congestion Cost and RMR Charge, resulting from the NEMA LSE's NEMA Contract, the
entity assuming such responsibility shall receive the entitlement to the NEMA
LSE's Stage 3 ARRs in lieu of the NEMA LSE receiving that entitlement.

The third stage of each ARR Allocation shall be performed using the following
procedure, which will be adjusted on an annual and monthly basis to account for
changes in available transmission capacity, load ratio shares, transfer of load
obligations, reductions in or resale of purchase amounts under NEMA Contracts,
and the termination of the NEMA Contract(s) or expiration of the term of the
NEMA Contract(s) in effect as of November 1, 1999, but excluding any optional
extensions which had not been exercised as of November 1, 1999. The System
Operator shall make such adjustments in accordance with the allocation
methodology described below, the Agreement, and the NEPOOL System Rules:

Step 1:       Begin with the set of all Stage 3 ARRs.

Step 2: Through the following steps, eliminate Stage 3 ARRs having a negative
value in the FCR Auction and then reduce the set of remaining Stage 3 ARRs
proportionately on a per Megawatt of constraint impact basis as necessary to
arrive at a set of ARRs that is simultaneously feasible in a contingency
constrained dispatch.

2(a): Identify all ARRs determined in Step 1 that receive a positive value (in
$/Megawatt) in the FCR Auction. Then add the set of all non-NEMA ARRs as
determined in Step 4 of Stage 2 to the remaining Stage 3 ARRs.

2(b):     Test whether the ARRs identified in Step 2(a) are simultaneously
feasible.

2(c):     If the ARRs identified in Step 2(a) are simultaneously feasible, go to
Step 3.

2(d): If the ARRs identified in Step 2(a) are not simultaneously feasible,
calculate the pre- and post-contingency power flows associated with dispatching
the system to honor the ARRs defined in Step 2(a).

2(e): Identify the constraint whose relief would require the largest
proportionate reduction in all of the Stage 3 ARRs defined in Step 2(a) that
increase flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all Stage 3 ARRs defined in Step 2(a) that increase
flows over this constraint until the constraint is relieved.

2(f): Test whether the ARRs identified in Step 2(e) are simultaneously feasible.
If the set of ARRs defined in Step 2(e) is simultaneously feasible, proceed to
Step 3.

2(g): Otherwise, calculate the pre- and post-contingency power flows associated
with dispatching the system to honor the ARRs defined in Step 2(e).

2(h): Identify the constraint whose relief would require the largest
proportionate reduction in all of the Stage 3 ARRs defined in Step 2(e) that
increase flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all Stage 3 ARRs defined in Step 2(e) that increase
flows over this constraint until the constraint is relieved.

2(i)     Repeat Steps 2(f) through 2(h) as necessary until a simultaneously
feasible set of ARRs is obtained.

2(j) If as a result of the application of Steps 2(e) through 2(i) any of the
constraints over which ARRs were reduced in Steps 2(e) through 2(i) is no longer
binding, ARRs defined in Step 2(a) that have been reduced in Steps 2(e) through
2(i) and do not exacerbate any binding transmission constraint would be
proportionately scaled up until a transmission constraint becomes binding.

Step 3.     Remove the non-NEMA ARRs.  The remaining ARRs will be the ARRs for
the NEMA Contracts.

D. Fourth Stage of ARR Allocation. The fourth stage of the ARR Allocation shall
determine the final allocation of ARRs for a given FCR Auction. The fourth stage
shall only affect the allocation of ARRs to NEMA LSEs. For the purposes of this
step, a set of "Stage 4 ARRs" shall be defined. Each NEMA LSE shall be allocated
Stage 4 ARRs, using the following formula:

Nikt = Aikt * Xkt

where:

Nikt = the amount of Stage 4 ARRs from Node or External Node i to the Locations
within NEMA allocated to NEMA LSE k for month t;

Aikt = the amount of ARRs from Node i to NEMA that had been allocated to NEMA
LSE k for month t as of the conclusion of the second stage of the ARR
Allocation; and

Xkt = the ratio of (the Monthly Peak Load of NEMA LSE k calculated on the basis
of its Monthly Peak Load during the same month t of the prior year less the
allocation of ARRs for NEMA Contracts to NEMA LSE k for month t) to the Monthly
Peak Load of NEMA LSE k in month t of the prior year.

The fourth stage of each ARR Allocation shall be performed using the following
procedure, which will be adjusted on an annual and monthly basis to account for
changes in available transmission capacity, load ratio shares, transfer of load
obligations, reductions in purchase amounts under NEMA Contracts, and the
termination of the NEMA Contract(s) or expiration of the term of the NEMA
Contract(s) in effect as of November 1, 1999, but excluding any optional
extensions which had not been exercised as of November 1, 1999. The System
Operator shall make such adjustments in accordance with the allocation
methodology described below, the Agreement, and NEPOOL System Rules:
Step 1:     Begin with the set of all Stage 4 ARRs.

Step 2: Through the following steps, eliminate negatively-valued Stage 4 ARRs
and then reduce the set of remaining Stage 4 ARRs proportionately on a per
Megawatt of constraint impact basis as necessary to arrive at a set of ARRs that
is simultaneously feasible in a contingency constrained dispatch.

2(a): Identify all ARRs determined in Step 1 that receive a positive value (in
$/Megawatt) in the FCR Auction. Then add the set of all non-NEMA ARRs and all
ARRs for NEMA Contracts to the remaining Stage 4 ARRs.

2(b):     Test whether the ARRs identified in Step 2(a) are simultaneously
feasible.

2(c):     If the ARRs identified in Step 2(a) are simultaneously feasible, go to
Step 3.

2(d): If the ARRs identified in Step 2(a) are not simultaneously feasible,
calculate the pre- and post-contingency power flows associated with dispatching
the system to honor the ARRs defined in Step 2(a).

2(e): Identify the constraint whose relief would require the largest
proportionate reduction in all of the Stage 4 ARRs defined in Step 2(a) that
increase flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all Stage 4 ARRs defined in Step 2(a) that increase
flows over this constraint until the constraint is relieved.

2(f):     Test whether the ARRs identified in Step 2(e) are simultaneously
feasible. If the set of ARRs defined in Step 2(e) is simultaneously feasible,
proceed to Step 3.

2(g):     Otherwise, calculate the pre- and post-contingency power flows
associated with dispatching the system to honor the ARRs defined in Step
2(e).

2(h): Identify the constraint whose relief would require the largest
proportionate reduction in all of the Stage 4 ARRs defined in Step 2(e) that
increase flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all Stage 4 ARRs defined in Step 2(e) that increase
flows over this constraint until the constraint is relieved.

2(i)     Repeat Steps 2(f) through 2(h) as necessary until a simultaneously
feasible set of ARRs is obtained.

2(j) If as a result of the application of Steps 2(e) through 2(i) any of the
constraints over which ARRs were reduced in Steps 2(e) through 2(i) is no longer
binding, ARRs defined in Step 2(a) that have been reduced in Steps 2(e) through
2(i) and do not exacerbate any binding transmission constraint would be
proportionately scaled up until a transmission constraint becomes binding.

Step 3. The remaining ARRs constitute the final allocation of ARRs. Holders of
ARRs in this allocation shall be deemed ARR Holders.

E. Payments to ARR Holders. Each ARR Holder shall be entitled to receive a share
of the Auction Revenues from each annual or monthly FCR Auction reflecting the
value in that auction of FCRs, other than those sold by FCR Holders,
corresponding to its ARRs, whether or not such specific FCRs are actually sold.
This share shall equal the amount of ARRs (quantified in Megawatts) received in
the final allocation of ARRs with specified origin Nodes or External Nodes and
destination Locations and/or Reliability Regions that it holds which cover the
period for which FCRs were sold in that auction, multiplied by the value
determined in that FCR Auction for FCRs with the same origin Nodes or External
Nodes and destination Locations and/or Reliability Regions as the ARRs. The
determination of the FCRs awarded in each FCR Auction shall be subject to a
simultaneous feasibility test in accordance with Schedule 14. The amount of
feasible FCRs available in the FCR Auction (and the corresponding Auction
Revenues and payments to ARR Holders) will vary depending on transmission system
conditions.

F. Annual and Monthly ARR Adjustments. ARR Holders who receive a share of the
Auction Revenues from FCRs sold in the annual FCR Auction and whose load serving
responsibility (as reflected in the NEPOOL market settlement system) decreases
in subsequent months in the same year shall retain the annual ARR payments, but
shall be allocated a smaller share of ARRs, in proportion to their decrease in
load ratio share, to the monthly Auction Revenues.

G. Incremental ARRs. An entity who pays for new transmission upgrades which
increase transfer capability on the NEPOOL Transmission System, making it
possible for the System Operator to award additional FCRs in the FCR Auction,
shall be awarded ARRs. The amount of ARRs awarded to such an entity, and the
origin and destination Locations and/or Hubs for those ARRs, shall be consistent
with the FCRs that were made possible by the transmission upgrade, as determined
by the System Operator and the FCRs awarded in the auction. The award shall be
in direct proportion to the percentage of the costs of the upgrade paid by such
entity, and shall continue for so long as the entity supports the costs of the
upgrade. ARRs awarded to an entity who pays for transmission upgrades will not
be subject to reduction in Stages 2, 3 and 4 of the ARR Allocation process
described above. To the extent that transmission upgrades resulting in new
transfer capability are paid for through the Pool RNS Rate, any Auction Revenue
Rights associated with the sale of FCRs made possible by such upgrades, other
than FCRs sold by FCR Holders, shall be allocated to Transmission Customers and
Congestion Paying Entities on a Monthly Peak Load basis.

H.     Additional Rules and Procedures. Consistent with this Schedule 15, the
implementation of its provisions shall further be detailed, defined and carried
out pursuant to Market Rules.



                       ATTACHMENT 1 TO SCHEDULE 15


                                     TABLE 1

                                 NEMA CONTRACTS

NEMA Load-Serving Entity                   NEMA Contract Entitlements(FN1)

Danvers                                    1.  Millstone 3 (.263%)
                                           2.  Seabrook (1.12%)
                                           3.  Stony Brook Combined Cycle
                                               (8.457%)
                                           4.  Stony Brook 2A (11.555%)
                                           5.  Stony Brook 2B (11.555%)
                                           6.  Vermont Yankee (1.08 MW)
                                           7.  Hydro Quebec (2.93 MW
                                              (winter))
                                           8.  NYPA (2.44 MW)

Georgetown                                 1.  Millstone 3 (.021%)
                                           2.  Seabrook (.096%)
                                           3.  Stony Brook Combined Cycle
                                               (.736%)










- ------
(FN1) NEMA Contract entitlements are stated by percentage in case of unit
entitlements held on percentage basis, and by megawatts (MW) where contract
states entitlement in MW.



                                           4.  Stony Brook 2A (1.014%)
                                           5.  Stony Brook 2B (1.014%)
                                           6.  Vermont Yankee (.144 MW)
                                           7.  System Power (Select Energy)
                                              (2.0 MW)
                                           8.  Hydro Quebec (.280 MW
                                              (winter))
                                           9.  NYPA (.620 MW)

Ipswich                                    1.  Millstone 3 (.061%)
                                           2.  Seabrook (.107%)
                                           3.  Stony Brook Combined Cycle
                                             (.293%)
                                           4.  Vermont Yankee (.522 MW)
                                           5.  NYPA (1.35 MW)

Marblehead                                 1.  Millstone 3 (.154%)
                                           2.  Seabrook (.135%)
                                           3.  Stony Brook Combined Cycle
                                               (2.64%)
                                           4.  Stony Brook 2A (1.598%)
                                           5.  Stony Brook 2B (1.598%)
                                           6.  Wyman 4 (.279%)
                                           7.  Vermont Yankee (.655 MW)
                                           8.  Hydro Quebec (1.040 MW
                                              (winter))
                                           9.  NYPA (2.140 MW)

Middleton                                  1.  Millstone 3 (.044%)
                                           2.  Seabrook (.328%)
                                           3.  Stony Brook Combined Cycle
                                              (.878%)
                                           4.  Stony Brook 2A (1.892%)
                                           5.  Stony Brook 2B (1.892%)
                                           6.  Wyman 4 (.101%)
                                           7.  Vermont Yankee (.213%)
                                           8.  System Power (NU) (10.5 MW)
                                           9.  Hydro Quebec (.580 MW
                                              (winter))
                                           10. NYPA (.6 MW)

Peabody                                    1.  Millstone 3 (.297%)
                                           2.  Seabrook (1.13%)
                                           3.  Stony Brook Combined Cycle
                                                (13.052%)
                                           4.  Vermont Yankee (1.693 MW)
                                           5.  Hydro Quebec (3.480 MW
                                              (winter))
                                           6.  NYPA (4.860 MW)

Reading                                    1.  Millstone 3 (.404%)
                                           2.  Seabrook (.635%)
                                           3.  Stony Brook Combined Cycle
                                              (14.453%)
                                           4.  Stony Brook 2A (19.516%)
                                           5.  Stony Brook 2B (19.516%)
                                           6.   System Power (NU) 15 MW
                                               (out of a total of 30 -
                                               remaining 15 MW are
                                               Excepted Transactions)
                                           7.  Hydro Quebec (5.710 MW
                                              (winter))

Wakefield                                  1.  Millstone 3 (.206%)
                                           2.  Seabrook (.387%)
                                           3.  Stony Brook (3.993%)
                                           4.  Stony Brook 2A (6.379%)
                                           5.  Stony Brook 2B (6.379%)
                                           6.  Wyman 4 (.440%)
                                           7.  Vermont Yankee (.885 MW)
                                           8.  Hydro Quebec (1.520 MW
                                               (winter))
                                           9.  NYPA (2.230 MW)

Concord                                    1.  Hydro Quebec (.890 MW
                                              (winter))

Groveland                                  1.  System Power (NU) (6.1 MW)
                                           2.  NYPA (.510 MW)

Merrimac                                   1.  System Power (NU) (4.9 MW)
                                           2.  NYPA (.520 MW)

Rowley                                     1.  System Power (NU) (6.7 MW)
                                           2.  Hydro Quebec (.2 MW (winter))
                                           3.  NYPA (.510)




                                   SCHEDULE 16

         System Restoration and Planning Service from Generators


System Restoration and Planning Service is necessary to ensure the continued
reliable operation of the New England Transmission System. System Restoration
and Planning Service enables the System Operator to designate specific
generators interconnected to the transmission or distribution system at
strategic locations capable of supplying load to re-energize the transmission
system following a system-wide blackout. These designated generators are able to
start without an outside electrical supply and are otherwise known as "Black
Start Capable." The planning and maintenance of adequate capability for
restoration of the NEPOOL Control Area following a blackout represents a benefit
to all entities using the power system. Therefore, this service must be taken
from the System Operator. In contrast to the System Restoration and Planning
Service described herein, the actual supply of power that would allow a power
producer to restart its own generating units may itself be self-supplied or
purchased from another power producer independent of the NEPOOL Control Area
arrangements formulated by the System Operator. The Black Start Capability
intrinsic of System Restoration and Planning Service is to be provided by
designated Participants through the System Operator.

I.  Rate Formulas

A Transmission Customer Purchasing either Regional Network Service under
Schedule 9 of this Agreement or Internal Point to Point Service under Schedule
10 of this Agreement, or a Transmission Customer making Unauthorized Use shall
be required to pay NEPOOL for its share of Black Start Restoration and Planning
Service ("Black Start Responsibility") as determined in accordance with the
following formulas:

MRSR =       (EQUATION)

     Where:

MRSR =     The Transmission Customers' Monthly Restoration Service Rate.

NL = The aggregate of the individual sums of each Participant's or Non-
Participant's Network Load for the billing month.

IPP = The aggregate of the individual sums of each Participant's or Non-
Participant's maximum Reserved Capacity for Internal Point-to-Point Service for
each load served within a Local Network or Network(s) during the billing month.

UAU = The aggregate of the individual sums of each Participant's or Non-
Participant's Maximum Unauthorized Use associated with Internal Point-to- Point
Service for each load served within a Local Network or Network(s) during the
month.

C = The annual cost of Service as determined from Supplement 1.

Each individual Participant's or Non-Participant's charge in any billing month
would be calculated by the following formula:

     MC =     (MRSR)(NLi + IPPi + UAUi)

     Where

MC =     The Monthly Charge.

NLi = The sum of a Participant's or Non-Participant's Network Load for the
billing month.

IPPi = The sum of a Participant's or Non-Participant's maximum Reserved Capacity
for Internal Point-to-Point Service for each load served within a Local Network
or Network(s) during the billing month.

UAUi = The sum of a Participant's or Non-Participant's Maximum Unauthorized Use
associated with Internal Point-to-Point Service for each load served within a
Local Network or Network(s) during the month.

A separate charge for this service based upon the above rates will be added to
the Transmission Customer's monthly bill. The above rates are based upon
generator expense as determined by Supplement 1.

II.

III.     Compensation to Generators

A.     Eligibility.  In order to be designated as a "Black Start Generator"
providing System Restoration Service and to be eligible for compensation
under this Schedule 16 of the NEPOOL Open Access Transmission Tariff, a
generator must meet the following criteria:

1. The unit is "Black Start Capable" in that it has the ability of being started
without energy from other NEPOOL generating units in such a way that it meets
all of the requirements stated in Operating Procedure 11 (Black Start Capability
Eligibility & Testing Requirements); and

2. The unit owner, NEPOOL, and the System Operator agree that the unit should be
designated Black Start Capable and accordingly is listed as a Black Start unit
in Operating Procedure 11.

Each generator which is eligible for and seeks compensation under the NEPOOL
Open Access Transmission Tariff for providing System Restoration Service shall
execute an agreement with NEPOOL.

III.     Effective Date.  This Schedule 16 shall be effective as of September 1,
1998.



                                  Supplement 1
                                 To Schedule 16

         System Restoration and Planning Service Revenue Requirement

The annual Revenue Requirement for System Restoration and Planning Service will
be the sum of the annual revenue requirements for each generator which is
designated in NEPOOL Operating Procedure 11 as providing Black Start Service and
which has provided to the System Operator, along with work papers and supporting
documents, a calculation of its annual Revenue Requirement, determined in
accordance with this Supplement 1.

Each Black Start Generator's Revenue Requirement will reflect the generator's
costs for its Black Start equipment as listed in Exhibit 1. Each Generator's
Revenue Requirement will be an annual calculation based on the previous calendar
year's data and supplied to the ISO in time for a June 1 informational filing.
The calculation is set forth below:

The Generator's Revenue Requirement shall equal the sum of generator's (A)
Return and Associated Income Taxes, (B) Black Start Plant Depreciation Expense,
(C) Black Start Related Amortization of Loss on Reacquired Debt, (D) Black Start
Related Amortization of Investment Tax Credits, (E) Black Start Related
Municipal Tax Expense, (F) Black Start Operation and Maintenance Expense, and
(G) Black Start Related Administrative and General Expense.

A.     Return and Associated Income Taxes shall equal the product of the Black
Start Plant Investment Base and the Cost of Capital Rate.

1. The Black Start Plant Investment Base will consist of (a) Black Start Plant
in FERC 345 or equivalent accounts, plus (b) Related General Plant in FERC 244
or equivalent accounts, less (c) Related Depreciation Reserve, less (d) Related
Accumulated Deferred Taxes, plus (e) Related Loss on Reacquired Debt, plus (f)
other regulatory assets, plus (g) Prepayments, plus (h) Materials and Supplies,
plus (i) Related Cash Working Capital.

a. Black Start Plant will equal the calculated average balance of generator's
investment in the Exhibit 1 facilities based upon GAAP records and engineering
studies and evaluations categorized similar in principal to FERC 345 or
equivalent accounts.

b. Black Start Related General Plant shall equal generator's calculated average
balance of investment in general plant based upon GAAP records and engineering
studies and evaluations categorized similar in principal to FERC 244 or
equivalent accounts multiplied by the ratio of Black Start related wages and
salaries utilizing a standard labor rate to the generator's total wages and
salaries of the black start facilities, and excluding administrative and general
wages and salaries ("Black Start Allocation Factor").

c. Black Start Related Depreciation Reserve shall equal the average balance of
total Black Start depreciation reserve for the Black Start Plant plus the
average balance of Black Start Related General Plant depreciation reserve. The
Black Start Plant depreciation reserve shall be the average balance of the total
Black Start Plant depreciation recovered by the generator for providing system
restoration services. Black Start Related General Plant depreciation reserve
shall equal the product of the Black Start General Plant reserve and the Black
Start Allocation Factor.

d. Black Start Related Accumulated Deferred Taxes shall equal generator's
average balance of total accumulated deferred income taxes, multiplied by the
ratio of total investment in Black Start Plant plus Black Start Related General
Plant to total plant in service excluding general plant ("Plant Allocation
Factor").

e. Black Start Related Loss on Reacquired Debt shall equal generator's average
balance of total loss on reacquired debt multiplied by the Plant Allocation
Factor described in Section (A) (1) (d).

f. Other Regulatory Assets shall equal generator's average balance of FAS 106
multiplied by the Black Start Allocation Factor described in Section (A) (1) (b)
above and the balance of FAS 109, net of FAS 109 liability multiplied by the
Plant Allocation Factor described in Section (A) (1) (d) above.

g. Black Start Prepayments shall equal generator's average balance of
prepayments multiplied by the Black Start Allocation Factor described in Section
(A) (1) (b) above.

h. Black Start Materials and Supplies shall equal generator's average balance of
plant materials and supplies multiplied by the Plant Allocation Factor described
in Section (A) (1) (d) above or the actual materials and supplies utilized in
the operation and maintenance of Black Start equipment.

i. Black Start Related Cash Working Capital shall be a 12.5% allowance (45 days
/ 360 days) of Black Start operation and maintenance expense and related
administrative and general expense.

2.     The Cost of Capital Rate shall equal (a) the Weighted Cost of Capital,
plus (b) Federal Income Taxes, plus (c) State Income Taxes.

a. The Weighted Cost of Capital will be the weighted average cost of debt and
common equity, using a proxy capital structure based upon a 50% debt and 50%
equity split.

i) The Return on Equity Component shall be the average of the NEPOOL
Transmission Providers' return on equity pursuant to the NEPOOL Tariff.

ii)    The Cost of Debt component shall equal the current interest rate of a
30-year U.S. Treasury Bond.

b.     Federal Income Taxes shall equal

(EQUATION)

where FT is the federal income tax rate (35%) and A is the Return on Equity
Component, as determined in Section (A) (2) (a) (i).

c.     State Income Taxes shall equal

(A + Federal Income Tax)(ST)
        1 - ST

Where ST is the state income tax rate for the applicable state and A is the
Return on Equity Component, as determined in Section (A) (2) (a) (i), and
Federal Income Tax is the rate determined in Section (A) (2) (b) above.

B. Black Start Depreciation Expense shall equal the sum of depreciation expense
for Black Start Plant plus an allocation of general plant depreciation expense
calculated by multiplying general plant depreciation expense by the Black Start
Allocation Factor, described in Section (A) (1) (b) above.


C. Black Start Related Amortization of Loss on Reacquired Debt shall equal
generator's amortization of loss on reacquired debt multiplied by the Plant
Allocation Factor described in Section (A) (1) (d) above.


D. Black Start Related Amortization of Investment Tax Credits shall equal
generator's amortization of investment tax credits multiplied by the Plant
Allocation Factor described in Section (A) (1) (d) above.

E. Black Start Related Municipal Tax Expense shall equal generator's total
municipal tax expense multiplied by the Plant Allocation Factor described in
Section (A) (1) (d) above.

F.     Black Start Operation and Maintenance Expense shall equal all expenses
charged directly to Black Start equipment.

G. Black Start Related Administrative and General Expenses shall equal
generator's administrative and general expenses, plus payroll taxes, multiplied
by the Black Start Allocation Factor described in Section (A) (1) (b) above.





                            Exhibit 1 to Supplement 1

        Additional Black Start Cost of Service Methodology Details


The objective of this methodology is to apply cost of service principles to
determine the amount of compensation providers of black start service receive.
Black Start Generators are only compensated for the incremental costs that are
incurred in making and maintaining a unit black start capable and do not include
any other costs. Generators shall not recover those black start costs for which
they are otherwise compensated through other rate schedules or divestiture
contracts.

O&M includes equipment wear and tear, training, black start labor costs
associated with testing, and periodic maintenance. It is assumed that there are
25 worker-hours per black start unit per year of training. Wear and tear
associated with testing black start units will be prorated based on number of
hours between maintenance activities. For example, if a maintenance activity
occurs every 1,000 hours, and black start testing lasts 1 hour per year, than
0.1% of the costs associated with that maintenance activity will be recovered
through black start charges.

Fuel costs are those actual, average in tank fuel costs including emission
allowances/credits used in testing Black Start Generators and their actual use
in system restoration. Fuel costs include fuel consumed due to minimum run
requirements.

Cash and Working Capital include spare parts associated with the equipment that
makes a generating unit black start capable.

The list of equipment below is equipment commonly associated with making
generating units Black Start Capable. The exact equipment varies depending on
the specific generator. In addition, some generating units are made Black Start
Capable by having a stand alone generating unit that is not connected to the
bulk power system (and therefore cannot participate in any of the NEPOOL
markets). This stand-alone generating unit provides the means by which the black
start generating unit is Black Start Capable.



      (FN1) The following equipment is assumed to be depreciated over the
following number of years (unless a different depreciation is required by FERC):


Air compressors          10 years
Air tanks               30 years
Batteries/Chargers          10 years
DC motors               25 years
DC Controllers          25 years
DC/AC Inverters          10 years








- ----
(FN 1) These depreciation times are intended to be consistent with FERC policy
and need to be verified as such. If they are not consistent, they will be made
so.





                             Supplement 2
                            To Schedule 16

Black Start System Restoration and Planning Service Terms and Conditions

1.     Definition of System Restoration and Planning Service. A unit is defined
to provide "System Restoration and Planning Service" if both of the following
conditions are met:

A. The unit is "Black Start Capable" in that it has the ability of being started
without energy from other NEPOOL generating units in such a way that it meets
all of the requirements stated in Operating Procedure 11 (Black Start Capability
Eligibility & Testing Requirements); and

B.     The unit owner, NEPOOL, and the System Operator agree that the unit
should be designated Black Start Capable.

2.     Generator Owner's commitment to provide System Restoration and Planning
Service:

A. Generators need to commit initially for at least three years to provide
System Restoration and Planning Service from the date of the last
black-start/system restoration study. The most recent study was conducted in
October 1998.

B.     All succeeding commitments must be at least for three years.

C.     Generators may, and are encouraged to, commit to provide System
Restoration and Planning Service for periods greater than three years with
System Operator and NEPOOL concurrence.

D. Generators need to give at least one-year notice that they will no longer be
able to provide System Restoration and Planning Service. This one-year notice
cannot truncate the generator's commitment to provide System Restoration and
Planning Service except as noted in item 2(E) or 2(F) below.

E. If due to an event of Force Majeure a Generator Owner cannot provide System
Restoration and Planning Service, the above notification requirements stated in
items 2(A) and 2(B) are not binding.

F. If an owner of a generation unit that is designated Black Start Capable
decides to retire that unit, then the three year requirement to provide System
Restoration and Planning Service from that unit is not binding. The one-year
notice, however, is binding.

3.     Performance obligations of generators that are providing System
Restoration and Planning Service:

A. Generators that are providing System Restoration and Planning Service will be
tested in accordance with Operating Procedure 11 or its successor, which may be
revised from time to time.

B. Units that are providing System Restoration and Planning Service must start-
up within the prescribed time stipulated in Operating Procedure 11 (Black Start
Capability Eligibility & Testing Requirements). Not all unmanned units that are
providing System Restoration and Planning Service will be asked to start-up at
the same time.

C. If a unit fails a System Restoration and Planning Service test, the owner
must incur the necessary costs to make that unit capable of passing the test
within a reasonable amount of time. Until the unit passes another System
Restoration and Planning Service test, it would not be compensated for providing
System Restoration and Planning Service. All costs associated with System
Restoration and Planning Service unit re-tests are at the owner's expense.

4.     Obligations by System Operator and NEPOOL to generators that are
providing System Restoration and Planning Service:

A. Generators that commit to provide System Restoration and Planning Service
will not have their Black Start Capable designation terminated within the time
period of their commitment.

B. The System Operator and NEPOOL must provide at least one-year notice to the
owner or owners of generation units that are providing System Restoration and
Planning Service prior to terminating that unit's designation as Black Start
Capable.

C. There are no additional restrictions on generation maintenance of designated
Black Start Capable units beyond what exists for non-Black Start units except
that designated Black Start generation units cannot take seasonal outages.

If a Generator Owner makes System Operator and NEPOOL approved capital
investments necessary to System Restoration and Planning Service, then that
owner will recover all of the associated costs of that investment, including on
and of capital, unless the owner voluntary removes that unit from providing
System Restoration and Planning Service prior to the recovery of its investment
costs in accordance with the cost-of-service methodology approved for the
recovery of System Restoration and Planning Service costs. If a Generator Owner
voluntary removes a unit from providing System Restoration and Planning Service
prior to the recovery of all of its investment costs, then that owner only
receives that portion of its investment cost that was recovered during the
period that its unit was providing System Restoration and Planning Service.

The System Operator or its designated agent shall have the right to
independently audit the accounts and records of each generator receiving
payments under this rate schedule. The generator shall make its accounts and
records available at its offices at a mutually agreeable time for this audit.
Such audit shall extend only to those areas relating specifically to this rate
schedule. Any errors identified as a result of such audit shall be corrected
with interest in accordance with FERC policy with refunds and surcharges, as
appropriate, for any amounts previously over- or under-charged due to such
errors.




                            ATTACHMENT A

                   Form of Service Agreement for
                     Through or Out Service or
                  Internal Point-To-Point Service


1.0 This Service Agreement, dated as of , is entered into, by and between the
NEPOOL Participants acting through (the "System Operator") and ("Transmission
Customer").

2.0 The Transmission Customer has been determined by the System Operator to have
a Completed Application for Firm [Non-Firm] Transmission Service under this
Tariff.

3.0 If required, the Transmission Customer has provided to the System Operator
an Application deposit in accordance with the provisions of this Tariff.

4.0 Service under this Service Agreement shall commence on the later of (1) the
requested service commencement date, or (2) the date on which construction or
any Direct Assignment Facilities and/or facility additions or upgrades are
completed, or (3) such other date as it is permitted to become effective by the
Commission. Service under this Service Agreement shall terminate on such date as
is mutually agreed upon by the parties.

     [The Service Agreement may be a blanket agreement for non-firm service.]

5.0 The Participants agree to provide, and the Transmission Customer agrees to
take and pay for, Transmission Service in accordance with the provisions of the
Tariff and this Service Agreement.

6.0 Any notice or request made to or by either party regarding this Service
Agreement shall be made to the representative of the other party as indicated
below.

NEPOOL Participants:

New England Power Pool
One Sullivan Road
Holyoke, MA 01040-2841

Transmission Customer:

7.0     The Tariff is incorporated in this Service Agreement and made a part
hereof.

IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be
executed by their respective authorized officials.

NEPOOL Participants:

By [System Operator]

By:

Name
Title
Date




Transmission Customer:

By:
Name
Title
Date




                      Specifications For Through or Out Service
                       or Internal Point-to-Point Service


1.0  Term of Transaction:
     Start Date:
     Termination Date:

2.0 Description of capacity and energy to be transmitted by Participants
including the electric Control Area in which the transaction originates.


3.0     Point(s) of Receipt:
        Delivering party:

4.0     Point(s) of Delivery:
        Receiving party:

5.0     Maximum amount of capacity and energy to be transmitted (Reserved
Capacity):

6.0     Designation of party(ies) or other entity(ies) subject to reciprocal
service obligation:

7.0     Name(s) of any intervening systems providing transmission
service:


8.0 Service under this Service Agreement may be subject to some combination of
the charges detailed below. (The appropriate charges for individual transactions
will be determined in accordance with the terms and conditions of this Tariff.)

8.1     Transmission Charge:


8.2     System Impact Study and/or Facilities Study Charge(s):



8.3     direct assignment expansion charge [Need to define or reference upgrade
costs]:








                             ATTACHMENT B

                          Form Of Service Agreement For
                            Regional Network Service


1.0     This Service Agreement, dated as of             , is entered into, by
and between the NEPOOL Participants acting through
                  (the "System Operator"), and
("Transmission Customer").

2.0 The Transmission Customer has been determined by the System Operator to be a
Transmission Customer under the Tariff and has requested Regional Network
Service under the Tariff.

3.0 Regional Network Service (including, if requested, Network Integration
Transmission Service) under this Agreement shall be provided by the NEPOOL
Participants upon request by an authorized representative of the Transmission
Customer.

4.0 The Transmission Customer agrees to supply information the System Operator
deems reasonably necessary in accordance with Good Utility Practice in order for
it to provide the requested service.

5.0 The Participants agree to provide and the Transmission Customer agrees to
take and pay for Regional Network Service in accordance with the provisions of
the Tariff and this Service Agreement.

6.0 Any notice or request made to or by either party regarding this Service
Agreement shall be made to the representative of the other party as indicated
below.

NEPOOL Participants:
New England Power Pool
One Sullivan Road
Holyoke, MA 01040-2841

Transmission Customer:



7.0     The Tariff is incorporated herein and made a part hereof.

IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be
executed by their respective authorized officials.


Transmission Customer:

By:


Name
Title
Date



NEPOOL Participants:

By: [System Operator]
By:


Name
Title
Date





                                  ATTACHMENT C


         Methodology To Assess Available Transmission Capability

Available Transmission Capability (ATC) will be assessed based on industry-
accepted standards; currently, ATC will be established by reducing the
determined Total Transfer Capability (TTC) by the Transmission Reliability
Margin (TRM) and by transmission commitments.

Total Transfer Capability (TTC) is the determined amount of electric power that
can be reliably transferred over the network consistent with the following:


     Good utility practice

     NERC standards, guides, and procedures;

     NPCC criteria and guidelines;

     New England criteria, rules, procedures, and reliability standards;
     Applicable guides, standards, and criteria of the affected Transmission
     Owner(s), whether Participant or Non-Participant; Other applicable
     guidelines and standards which may need to be established from time to
     time.

As such, TTC will be determined at a level which maintains all of the following:


     All equipment within its applicable capabilities;

     Voltages and reactive reserves within acceptable levels;

     Stability maintained with adequate levels of damping;

     Frequency (Hz) within acceptable levels.

TTC will be evaluated using appropriate and suitable tools, data, and
information, considering the physical impacts of electric power transfers on the
interconnected transmission network. It will reflect anticipated system
conditions and equipment status to the degree practicable.

The Transmission Reliability Margin (TRM) will be established at a level which
incorporates the uncertainties and continued variability of system conditions
and the practical limitations of system control.

Transmission commitments include existing and pending requests for transmission
service and obligations of other existing contracts under which transmission
service is provided.






                             ATTACHMENT D


         Methodology for Completing a System Impact Study

The system impact study will be performed to evaluate the impact of the
requested service on the reliability and operating characteristics of the bulk
power system, consistent with:


     Good utility practice

     NERC standards, guides, and procedures;

     NPCC criteria and guidelines;

     New England criteria, rules, procedures, and reliability standards;

     Applicable guides, standards, and criteria of the impacted Transmission
     Owner(s), whether Participant or Non-Participant; Other applicable
     guidelines and standards which may need to be established from time to
     time.

As such, the study will examine the impact on the New England regional bulk
power system and its component systems and neighboring and external systems.
Consistent with the aforementioned, the ability to operate the system subject to
the following will be considered:


     All equipment within its applicable capabilities;

     Voltages and reactive reserves within acceptable levels;

     Stability maintained with adequate levels of damping;

     Frequency (Hz) within acceptable levels.

The study will consider the reliability requirements to meet existing and
pending obligations of the Participants and the obligations of the impacted
Transmission Owner(s).

The study will be performed using appropriate and suitable analysis tools and
modeling data consistent with the nature and duration of the requested service.
It is expected that the Eligible Customer will provide the information as
prescribed in Exhibit 1 of Attachment I, and such other information as may be
reasonably required and associated with the requested service and necessary for
its study. It is also recognized that it may be determined that additional or
specialized analysis tools or computer software are necessary for the study. The
responsibility for the provision of these items will be subject to the System
Impact Study Agreement.

The study will identify if the requested service or a portion of it can be
provided without adverse impact on the reliability and operating characteristics
of the system. The study will also identify if it appears that modification of
the system is necessary to provide the service.







                             ATTACHMENT E

                            Local Networks

The Local Networks, as of the effective date of this Tariff, are those of the
following:

1.     Bangor Hydro-Electric Company
2.     Boston Edison Company
3.     Central Maine Power Company
4.     the Commonwealth Energy System companies
5.     the Eastern Utility Associates companies
6.     the New England Electric System companies
7.     the Northeast Utilities companies
8.     The United Illuminating Company
9.     Vermont Electric Power Company and the entities which are grouped with it
        as a single Participant.





                          ATTACHMENT F

          Annual Transmission Revenue Requirements

The Transmission Revenue Requirements for each Participant will reflect the
Participant's costs with respect to Pool-Supported PTF. The Transmission Revenue
Requirements will be an annual calculation based on the previous year's calendar
data as shown, in the case of Transmission Providers which are subject to the
Commission's jurisdiction, in the Participants' FERC Form 1 report for that
year, and shall be based on actual data in lieu of allocated data if
specifically identified in the Form 1 report in accordance with the following
formula:

I. The Transmission Revenue Requirement shall equal the sum of the Transmission
Provider's (A) Return and Associated Income Taxes, (B) Transmission Depreciation
Expense, (C) Transmission Related Amortization of Loss on Reacquired Debt, (D)
Transmission Related Amortization of Investment Tax Credits, (E) Transmission
Related Municipal Tax Expense, (F) Transmission Related Payroll Tax Expense, (G)
Transmission Operation and Maintenance Expense, (H) Transmission Related
Administrative and General Expense, (I)

     Transmission Related Integrated Facilities Charges, minus (J) Transmission
Support Revenue, plus (K) Transmission Support Expense, plus (L) Transmission
Related Expense from Generators, plus (M) Transmission Related Taxes and Fees
Charge, minus (N) Revenue for Short-Term Transmission Service under the NEPOOL
Tariff and (O) Transmission Rents Received from Electric Property.

The details for implementation of Attachment F, as well as the definitions of
the terms used in the Attachment F formula, shall be established in accordance
with the applicable rule set forth in the Settlement Agreement entered into in
FERC Dockets OA97-237-000, et al. Any changes to that rule must be approved by
the Regional Transmission Operations Committee. The rule and any changes thereto
shall be filed with the Commission and considered a supplement to this Tariff.



ATTACHMENT G: List of Excepted Transaction Agreements

                         (Table)

Attachment G is a listing of transmission agreements pertaining to certain
point-to-point wheeling transactions across or out of a Local Network. In
accordance with Sections 25, 25A and 25B of the Tariff, these agreements will
continue to be in effect at the rates and terms thereunder rather than under the
Tariff.


Notes to Attachments G, G-1 and G-2

1. NEP's long-term Point-to-Point transmission services will be grandfathered at
a fixed rate of $17.00/kW-yr. Distribution, transformation, and metering
surcharges when applicable, will be subject to NEP's applicable point-to-point
tariffs.

2. See FERC Contract for specific details of agreement. In general, 100MW's
until transmission upgrades are complete. This item is still under review and is
subject to further review dependent upon outcome of Congestion Pricing.

3.     Excepted status applies to transmission by CMP. Transmission by others
(MEPCO, NBP, MPS) remains under the rates, terms and conditions of applicable
agreements.

4.     This Transmission Service Agreement is governed in part by a memorandum
of understanding, filed 6/13/97 in Docket nos. EC90-10-007, ER93-294-000,
ER95-1686-000, ER96-496-000, OA97-237-000, and ER97-1079-000.




               ADDENDUM TO ATTACHMENTS G, G-1 AND G-2


Pursuant to the terms of a settlement agreement (the "Settlement Agreement")
reached in FERC Dockets OA97-237-000, et al., the parties to the Excepted
Transaction Agreements specifically identified below have reached the following
agreements with respect to those Excepted Transaction Agreements. In addition to
the items specifically identified below, other Excepted Transaction Agreements
listed in Attachment G, G-1 and G-2 to this Tariff may also be affected more
generally by the terms of that Settlement Agreement.

NEPOOL Tariff Attachment G, Item 1

If the Settlement Agreement is approved in its entirety and takes effect as to
all signatories, Unitil and CMP agree as follows: This Transmission Service
Agreement between Unitil and CMP (the "Unitil/CMP Agreement") will continue in
effect without modification until that date on which the revenues received by
CMP, pursuant to the terms and conditions of the Unitil/CMP Agreement, as
calculated prospectively from March 1, 1999, equals Three Hundred Thousand
Dollars ($300,000.00). Such date is anticipated to be December 13, 1999. On that
date, the said Unitil/CMP Agreement will terminate, and any rights and
obligations enjoyed by CMP and Unitil under the terms of the Unitil/CMP
Agreement will cease. Any issues involving the revenues received prior to March
1, 1999 by CMP from Unitil pursuant to the Unitil/CMP Agreement have been
resolved in accordance with the terms of the Settlement Agreement, Section G.
Unitil and CMP each agree to waive any claims against the other arising prior to
March 1, 1999, whether identified previously or not, that are based on or in any
way relate to the terms and conditions of the Unitil/CMP Agreement.

NEPOOL Tariff Attachment G, Item 4

Phase I payments will be made according to the Settlement Agreement, Section G.
This Excepted Transaction will be terminated effective March 1, 1999.

NEPOOL Tariff Attachment G, Items 7 and 8

From March 1, 1999 forward the service under the Excepted Transaction will be
terminated and will be subject to NEPOOL Tariff and, if applicable, the NEP LNS
Tariff.

NEPOOL Tariff Attachment G, Item 10

Phase I payments will be made according to the Settlement Agreement, Section G.
This Excepted Transaction will be terminated effective March 1, 1999.

NEPOOL Tariff Attachment G, Item 11

Phase I payments will be made according to the Settlement Agreement, Section G.
This Excepted Transaction will be terminated effective March 1, 1999.

NEPOOL Tariff Attachment G, Item 12

Phase I payments will be made according to the Settlement Agreement, Section G.
This Excepted Transaction will be terminated effective March 1, 1999.

NEPOOL Tariff Attachment G, Item 13

Phase I payments will be made according to the Settlement Agreement, Section G.
This Excepted Transaction will be terminated effective March 1, 1999. As a
clarification, Maine Yankee has been retired and swapped for Vermont Yankee.
Therefore, retroactively, the refunds apply to both Maine and Vermont Yankee and
prospectively the transmission of Vermont Yankee is terminated.

NEPOOL Tariff Attachment G, Item 15

This contract has been terminated and Holyoke is receiving service under NU's
Open Access Tariff.

NEPOOL Tariff Attachment G, Items 17, 19 and 46

These arrangements will continue for the life of the Unit Contract at a rate of
$6.50 per kw-year.

NEPOOL Tariff Attachment G, Item 18

NU, UI and Unitil agree that Item 19, which is a contract for corridor
transmission service between NU and UI (the "NU-UI Agreement") that was entered
into as a settlement of prior disputes, will remain in effect in accordance with
its terms. The parties further agree that the Purchased Power Agreement between
UI and Unitil for power from Bridgeport Harbor Station Unit No. 3 (the
"UI-UNITIL Agreement") shall remain in effect subject to the terms of that
agreement for its full term at the rate stated therein. NU shall pay Unitil an
amount equal to one-third of the transmission charges Unitil pays to reimburse
UI for the costs UI incurs for the transmission of Unitil's power in connection
with the UI-UNITIL agreement for the period between March 1, 1999 and October
31, 2003. From November 1, 2003 to October 31, 2005, NU shall pay Unitil an
amount equal to 100% of the transmission charges Unitil pays UI to reimburse UI
for the costs UI incurs for the transmission of Unitil's power in connection
with the UI-UNITIL Agreement. NU, UI and Unitil agree that the foregoing
arrangements satisfy any claims of double charges under the NU-UI Agreement and
the UI-UNITIL Agreement.

NEPOOL Tariff Attachment G, Item 20

This contract will remain in force according to its terms at a rate of $6.50 per
kw-year.

NEPOOL Tariff Attachment G, Item 21 and 23

The transmission contract between NUSCO and MASSPOWER will remain in effect for
its full term. The MASSPOWER transmission contract (and the contract between
NUSCO and Pittsfield) will remain under the NU System Companies' Tariff No. 9,
subject to the settlement among MASSPOWER, Pittsfield and the NU System
Companies that is currently pending the Commission in Dockets ER93- 545-000 and
ER93-219-000. The parties in those dockets who are also signatories to this
Settlement Agreement will withdraw their opposition to the settlement pending in
those dockets.

NEPOOL Tariff, Attachment G, Items 24 and 25

The parties to these Excepted Transactions, which are contracts for transmission
service by NU over the New York tie, have agreed that these contracts for
transmission service will remain in effect for their full term at a rate of
$6.50 per kw-year.

NEPOOL Tariff Attachment G, Item 32

NU and Reading have agreed that the transmission rate applicable to this
Attachment G contract will be one-half of the current transmission charge paid
by Reading under such contract from March 1, 1999 through the remainder of its
term. This Attachment G contract will remain in effect in accordance with its
current terms. Reading will continue to be billed and pay for service in
accordance with the pre-existing negotiated rates in this Attachment G contract
and such bills will include a line item reflecting the cost of transmission
based on the NU Tariff 9 rate in effect for the applicable billing period.
Monthly adjustments in the transmission portion of the bill will be made
separately by NU's transmission group to account for the difference between the
Tariff 9 rate used for billing purposes and the settlement rate of one-half the
current transmission charge paid by Reading under this contract such that
Reading will pay a net transmission charge of one-half the current transmission
charge paid by Reading under this contract.

NEPOOL Tariff Attachment G, Items 33, 34, 35, 39, 40, 41, 42, 43 and 45

NU and the MMWEC parties have agreed that the transmission rate applicable to
these Attachment G contracts will be $6.50/kw-year from March 1, 1999 through
the remainder of their terms. These Attachment G contracts will remain in effect
in accordance with their current terms. The customers will continue to be billed
and pay for service in accordance with the pre-existing negotiated rates in
those contracts and such bills will include a line item reflecting the cost of
transmission based on the NU Tariff 9 rate in effect for the applicable billing
period. Monthly adjustments in the transmission portion of the bill will be made
separately by NU's transmission group to account for the difference between the
Tariff 9 rate used for billing purposes and the settlement rate of $6.50/kw-year
such that the MMWEC parties will pay a net transmission charge of $6.50/kw-year.

NEPOOL Tariff Attachment G, Item 38

     This contract ended by its terms in 1998.

NEPOOL Tariff Attachment G, Items 55 and 56

Montaup, as Transmission Provider, and MASSPOWER and Pittsfield, as Transmission
Customers, and all other Parties agree that these Excepted Transactions shall
not be affected by this Settlement Agreement and shall remain in full force and
effect in accordance with their terms.

NEPOOL Tariff Attachment G, Items 57, 58, 60 and 61

Non-firm wheeling of Cleary 9 power by Montaup to North Attleboro, Hudson Light
& Power and Hingham will continue at 50% of the current contract transmission
rate until February 28, 2001, after which date it will terminate. Non-firm
wheeling of Cleary 9 power by Montaup to Braintree terminated as of February 28,
1999.

NEPOOL Tariff Attachment G, Item 59

Firm wheeling of NYPA power by Montaup for Braintree and Reading will continue
at 50% of the current contract transmission rate until the expiration of the
existing contract. Firm wheeling by Montaup for Hingham, Hull, Wellesley,
Belmont and Concord under the same transaction will continue at 50% of the
current transmission rate until February 28, 2001 after which date it terminates
subject to extension upon agreement of the parties.

NEPOOL Tariff Attachment G, Item 63

Firm wheeling of NYPA power by Montaup for Pascoag Fire District will continue
at 50% of the current transmission rate until February 28, 2001 after which date
it terminates, subject to extension upon agreement of the parties.

NEPOOL Tariff Attachment G, Item 68

From March 1, 1999 to the expiration of the contract, BECO will not bill
Braintree, Reading, Hingham and Hull, and BECO will bill Concord, Wellesley and
Belmont at 50% of the contract rate.

NEPOOL Tariff Attachment G, Item 69

CVPS and Unitil are currently engaged in an arbitration with respect to this
Excepted Transaction. This Settlement Agreement has no impact on arbitration
findings for payments due prior to March 1, 1997. For purposes of this
Settlement Agreement, CVPS and Unitil agree as follows: If Unitil prevails at
the arbitration, Unitil will owe nothing to CVPS. If CVPS prevails, then Unitil
will pay 75% of the amount of the award related to the period March 1, 1997
through February 28, 1999, plus 100% of any interest. The transmission component
of this contract shall be null and void going forward from February 28, 1999.
Unitil shall continue to take and pay for capacity and energy for the term of
the contract, consistent with the existing terms of the agreement. Neither CVPS
nor Unitil shall communicate any aspect of this Settlement Agreement, or side
agreement between them, to the arbitrator prior to the rendering of his
decision.

NEPOOL Tariff Attachment G-1, Items 1 and 2

NEP and NU will terminate items 1 and 2 in Attachment G-1 to the NEPOOL Tariff
and both services will transfer to the respective LNS Tariffs as of April 1,
1999.

NEPOOL Tariff Attachment G-1, Item 10

     This contract has been terminated.




                                  ATTACHMENT H

                                     Form of
                           Network Operating Agreement

1.0     Preamble

This Network Operating Agreement is entered into by and between the NEPOOL
Participants (the "Transmission Provider") acting through (the "System
Operator") and (the "Transmission Customer") as an implementing agreement for
the NEPOOL Open Access Transmission Tariff and is subject to and in accordance
with the NEPOOL Open Access Transmission Tariff. All definitions and other terms
and conditions of the NEPOOL Open Access Transmission Tariff are incorporated
herein by reference. The Transmission Provider may designate a satellite
dispatch center and/or one or more Participants to act for it under this
Agreement.

2.0     General Terms and Conditions

The Transmission Provider agrees to provide transmission service to the
Transmission Customer's equipment or facilities, etc., subject to the
Transmission Customer operating its facilities in accordance with applicable
NEPOOL and NPCC criteria, rules, standards, procedures, or guidelines as they
may be adopted and/or amended from time to time. In addition to the provisions
defined in those documents, service to the Transmission Customer's equipment or
facilities, etc. is provided subject to the following specified terms and
conditions.

2.1     Electrical Supply:  The electrical supply to the Point(s) of Delivery
shall be in the form of three-phase sixty-hertz alternating current at a
voltage class determined by mutual agreement of the parties.

2.2 Coordination of Operations: The Transmission Provider shall consult the
Transmission Customer and/or its Designated Agent regarding timing of scheduled
maintenance of the Transmission System and the Transmission Provider shall
schedule any shutdown or withdrawal of facilities to coincide with the
Transmission Customer's equipment or facilities, etc. scheduled outages of the
Transmission Customer's resources, to the extent practicable. In the event the
Transmission Provider is unable to schedule the shutdown of its facilities to
coincide with Transmission Customer's schedule, the Transmission Provider shall
notify the Transmission Customer and/or its Designated Agent, in advance if
feasible, of reasons for the shutdown, the time scheduled for it to take place,
and its expected duration. The Transmission Provider shall use due diligence to
resume delivery of electric power as quickly as possible.

2.3 Reporting Obligations: The Transmission Customer shall be responsible for
all information required by NPCC or NEPOOL. The Transmission Customer shall
respond promptly and completely to the Transmission Provider's reasonable
requests for information, including but not limited to, data necessary for
operations, maintenance, regulatory requirements and analysis. In particular,
that information may include:

For Network Loads:

- -     10-year coincident, seasonal (summer, winter) Annual Peak Load forecast,
aggregated by geographic distribution area

- -     Load Power Factor performance by geographic distribution area

- -     Underfrequency load shedding capability aggregated by geographic
distribution area

- -     Block load shedding capability aggregated by geographic distribution area

- -     Disturbance/interruption reports

- -     Protection system setting conformance

- -     Protection system testing and maintenance conformance

- -     Planned changes to protection systems

- -     Metering testing and maintenance conformance

- -     Planned changes in transformation capability

- -     Conformance to harmonic and voltage fluctuation limits

- -     Dead station tripping conformance

- -     Voltage reduction capability conformance

For Network Resources and interconnected generators:

- -     10-year forecast of generation capacity retirements and additions, if
applicable

- -     Generator reactive capability verification

- -     Generator underfrequency relaying conformance

- -     Protection system testing and maintenance conformance

- -     Planned changes to protection system

- -     Planned changes to generation parameters

- -     Metering testing and maintenance conformance

Failure by the Transmission Customer to do so may constitute default.
Delinquency in responding by the Transmission Customer will result in a fine as
described in 5.0 below.

The Transmission Customer shall supply accurate and reliable information to the
system operators regarding metered values for MW, MVAR, volt, amp, frequency,
breaker status indication, and all other information deemed necessary by the
Transmission Provider for reliable operation. Information shall be gathered for
electronic communication using one or more of the following: supervisory control
and data acquisition (SCADA), remote terminal unit (RTU) equipment, and remote
access pulse recorders (RAPR). All equipment used for metering, SCADA, RTU,
RAPR, and communications must be approved by the Transmission Provider.

2.4 Operational Obligations: The Transmission Customer shall request permission
from the system operators prior to opening and/or closing circuit breakers per
applicable switching and operating procedures. The Transmission Customer shall
carry out all switching orders from the Transmission Provider, the System
Operator or the Transmission Provider's designee in a timely manner.

The Transmission Customer shall balance the load at the Point(s) of Delivery
such that the difference in the individual phase currents are acceptable to the
Transmission Provider.

The Transmission Customer's equipment shall conform with harmonic distortion and
voltage fluctuation standards of the Transmission Provider.

The Transmission Customer's equipment must comply with all environmental
requirements to the extent they impact the operation of the Transmission
Provider's system.

The Transmission Customer shall operate all of its equipment and facilities
connected to the Transmission Provider's system in a safe and efficient manner
and in accordance with manufacturers' recommendations, Good Utility Practice,
applicable regulations, and requirements of the Transmission Provider, the
System Operator, and NPCC.

2.5 Notice of Transmission Service Interruptions: If at any time, in the
reasonable exercise of the system operator's judgement, operation of the
Transmission Customer's equipment adversely affects the quality of service or
interferes with the safe and reliable operation of the system, the Transmission
Provider may discontinue transmission service until the condition has been
corrected. Unless the system operators perceive that an emergency exists or the
risk of one is imminent, the system operators shall give the Transmission
Customer and/or its Designated Agent reasonable notice of its intention to
discontinue transmission service and, where practical, allow suitable time for
the Transmission Customer to remove the interfering condition. The Transmission
Provider's judgement with regard to the discontinuance of service under this
paragraph shall be made in accordance with Good Utility Practice. In the case of
such discontinuance, the Transmission Provider shall immediately confer with the
Transmission Customer regarding the conditions causing such discontinuance and
its recommendation concerning timely correction thereof. Failure by a Customer
to shed load would be subject to an additional charge of 10/kWh for every kWh
the Customer failed to shed.

2.6 Access and Control: Properly accredited representatives of the Transmission
Provider shall at all reasonable times have access to the Transmission
Customer's facilities to make reasonable inspections and obtain information
required in connection with this Tariff. Such representatives shall make
themselves known to the Transmission Customer's personnel, state the object of
their visit, and conduct themselves in a manner that will not interfere with the
construction or operation of the Transmission Customer's facilities. The
Transmission Provider or its designee will have control such that it may open or
close the circuit breaker or disconnect and place safety grounds at the Point(s)
of Delivery, or at the station, if the Point(s) of Delivery is remote from the
station.

2.7 Point(s) of Delivery: Network Integration Transmission Service will be
delivered by the Transmission Provider at the Point(s) of Delivery as specified
in the customer's Service Agreement, and as amended from time to time. Each
Point of Delivery shall have a unique identifier, meter location, meter number,
metered voltage, terms on meter compensation and, the actual, or if not
currently in service, the projected in-service year.

2.8 Maintenance of Equipment: The Transmission Customer shall maintain all of
its equipment and facilities connected to the Transmission Provider's system in
a safe and efficient manner and in accordance with manufacturers'
recommendations, Good Utility Practice, applicable regulations, and requirements
of NEPOOL, and NPCC.

     The Transmission Provider may request that the Transmission Customer test,
calibrate, verify or validate the data link, metering, data acquisition,
transmission, protective, or other equipment or software consistent with the
Transmission Customer's routine obligation to maintain its equipment and
facilities or for the purposes of trouble shooting problems on the network
facilities. The Transmission Customer will be responsible for the cost to test,
calibrate, verify or validate the equipment or software.

     The Transmission Provider shall have the right to inspect the tests,
calibrations, verifications and validations of the data link, metering, data
acquisition, transmission, protective, or other equipment or other software
connected to the Transmission Provider's system.

     The Transmission Customer, at the Transmission Provider's request, shall
supply the Transmission Provider with a copy of the installation, test, and
calibration records of the data link, metering, data acquisition, transmission,
protective or other equipment or software connected to the Transmission
Provider's system.

     The Transmission Provider shall have the right, at the Transmission
Customer's expense, to monitor the factory acceptance test, the field acceptance
test, and the installation of any metering, data acquisition, transmission,
protective or other equipment or software connected to the Transmission
Provider's system.

2.9     Emergency System Operations: The Transmission Customer's equipment and
facilities, etc. shall be subject to all applicable emergency operation
standards required of and by the Transmission Provider to operate in an
interconnected transmission network.

     The Transmission Provider reserves the right to have the system operators
take whatever actions or inactions they deem necessary during emergency
operating conditions to: (i) preserve the integrity of the Transmission System,
(ii) limit or prevent damage, (iii) expedite restoration of service, or (iv)
preserve public safety.

2.10 Cost Responsibility: The Transmission Customer shall be responsible for all
costs incurred by the Transmission Provider relative to the Transmission
Customer's facilities. Some costs may be allocated to several Transmission
Customers. If the method for allocating costs is not clearly defined, then the
method for allocation will be at the Transmission Provider's discretion.

3.0     Service For a Network Resource

The following Terms and Conditions are specific to Service for a generator
Network Resource.

3.1 Voltage or Reactive Control Requirements: Unless directed otherwise, the
Transmission Customer will operate its existing interconnected generation
facility(ies) with an automatic voltage regulator(s). The voltage regulator will
control voltage at the Point(s) of Receipt consistent with the range of voltage
scheduled by the System Operator.

     At the discretion of the Transmission Provider, the Transmission Customer
may be directed to deactivate the automatic voltage regulator and to supply
reactive power per a schedule provided by the Transmission Provider.

     If the Transmission Customer has not installed capacity sufficient to
operate its generation facility consistent with recommendations of the
Transmission Provider resulting from the System Impact and Facilities Studies or
fails to operate at such capacity, the Transmission Provider may install, at the
Transmission Customer's expense, reactive compensation equipment necessary to
ensure the proper voltage or reactive supply at the Point(s) of Receipt.

3.2 Station Service: When the Transmission Customer's generation facility is
producing electricity, the Customer must supply its own station service power.
If and when the Transmission Customer's generation facility is not producing
electricity, the Customer must obtain station service capacity and energy from
another supplier or another of its resources.

3.3     Protection Requirements: Protection requirements are defined in NEPOOL
and NPCC documents as may be adopted or amended from time to time.

3.4     Operational Obligations:  The Transmission Provider may require the
generator to be equipped for Automatic Generation Control (AGC).  The
Transmission Customer will be responsible for all costs associated with
installing and maintaining an AGC system on the generator(s).

     The Transmission Provider retains the right to require reduced generation
at times when system conditions present transmission restrictions or otherwise
adversely affect the Transmission Provider's other customers. The Transmission
Provider will use due diligence to resolve the problems to allow the generator
to return to the operating level prior to the Transmission Provider's notice to
reduce generation.

     All operations (including start-up, shutdown and determination of hourly
generation) will be coordinated by the Transmission Provider.

3.5 Coordination of Operations: The Transmission Customer shall furnish the
Transmission Provider with generator annual maintenance schedules, advise the
Transmission Provider if its Network Resource is capable of participation in
system restoration and/or if it has black start capability.

     The Transmission Provider reserves the right to specify turbine and/or
generator control (e.g., droop) settings as determined by the System Impact or
Facilities Study or subsequent studies. The Transmission Customer agrees to
comply with such specifications by the Transmission Provider at the Transmission
Customer's expense.

     If the generator is not dispatchable by the Transmission Provider, the
Transmission Customer shall notify the Transmission Provider at least 48 hours
in advance of its intent to take its resource temporarily off-line and its
intent to resume generation. In circumstances such as forced outages, the
Transmission Customer shall notify the Transmission Provider as promptly as
possible of the Network Resource's temporary interruption of generation and/or
transmission.

4.0     Service for Delivery to Load

The following Terms and Conditions are specific to Service for Delivery to Load.

4.1 Power Factor Requirement: The Transmission Customer agrees to maintain an
overall Load Power Factor and reactive power supply within predefined sub-areas
as measured at the Point(s) of Delivery within ranges specified by the
Transmission Provider or NEPOOL criteria, rules and standards which identify the
power factor levels that must be maintained throughout the applicable sub-area
for each anticipated level of total NEPOOL load. The Transmission Customer
agrees to maintain Load Power Factor and reactive power requirements within the
range specified by the Transmission Provider for the sub-area based on total
NEPOOL load during that hour. NEPOOL may revise the power factor limits required
from time to time. If the Transmission Customer lacks the capability to maintain
the Load Power Factor within the ranges specified, the Transmission Provider
may:

a)     install, at the Transmission Customer's expense, reactive compensation
equipment necessary to ensure proper load power factor at the Point(s) of
Delivery;

b)     charge the Transmission Customer per the Tariff.

4.2 Protection Requirements: The Transmission Customer's relay and protection
systems must comply with all applicable NEPOOL and NPCC criteria, rules,
procedures, guidelines, standards or requirements as may be adopted or amended
from time to time.

4.3 Operational Obligations: The Transmission Customer shall be responsible for
operating and maintaining security of its electric system in a manner that
avoids adverse impact to the Transmission Provider's or others' interconnected
systems and complies with all applicable NEPOOL, and NPCC operating criteria,
rules, procedures, guidelines and interconnection standards as may be amended or
adopted from time to time. These actions include, but are not limited to:

- -     Voltage Reduction Load Shedding
- -     Underfrequency Load Shedding
- -     Block Load Shedding
- -     Dead Station Tripping
- -     Transferring Load Between Point(s) of Delivery
- -     Implementing Voluntary Load Reductions Including Interruptible Customers
- -     Starting Stand-by Generation
- -     Permitting Transmission Provider Controlled Service Restoration Following
         Supply Delivery Contingencies on Transmission Provider Facilities

5.0     Default

If the Transmission Customer's equipment fails to perform consistent with the
Terms and Conditions of this agreement, then the Transmission Customer will be
deemed to be in default and service may be suspended immediately and subject to
a termination through a FERC filing. If the Transmission Customer fails to
provide the information required in Section 2.3 in a timely manner, the
Transmission Provider shall be permitted to assess a penalty of $100 per day
until such information is provided in its entirety to the Transmission Provider.

The Parties whose authorizing signatures appear below warrant that they will
abide by the foregoing terms and conditions.


NEPOOL Participants
By (System Operator)

(Transmission Customers)


By:

By:

Title:

Title:

Date:
Date:





                                  ATTACHMENT I

                                Form of
                     System Impact Study Agreement

This Agreement dated , is entered into by (the "Transmission Customer") and the
NEPOOL Participants (the "Transmission Provider") acting through (the "System
Operator"), for the purpose of setting forth the terms, conditions and costs for
conducting a System Impact Study relative to ,in accordance with the NEPOOL Open
Access Transmission Tariff ("Tariff"). All definitions and other terms and
conditions of that Tariff are incorporated herein by reference. The Transmission
Provider may designate one or more Participants or the System Operator to act
for it under this Agreement.

1. The Transmission Customer agrees to provide, in a timely and complete manner,
the information and technical data specified in Exhibit 1 to this Agreement and
reasonably necessary for the Transmission Provider to conduct the System Impact
study. The Transmission Customer understands that it must provide all such
information and data prior to the Transmission Provider's commencement of the
Study. Such information and technical data is specified in Exhibit 1 to this
Agreement.

2. All work pertaining to the System Impact Study that is the subject of this
Agreement will be approved and coordinated only through designated and
authorized representatives of the Transmission Provider and the Transmission
Customer. Each party shall inform the other in writing of its designated and
authorized representative.

3. The Transmission Provider will advise the Transmission Customer of any
additional information as it may in its sole reasonable discretion deem
necessary to complete the study. Any such additional information shall be
obtained only if required by Good Utility Practice and shall be subject to the
Transmission Customer's consent to proceed, such consent not to be unreasonably
withheld.

4. The Transmission Provider contemplates that it will require to complete the
System Impact Study. Upon completion of the Study by the Transmission Provider,
the Transmission Provider will provide a report to the Transmission Customer
based on the information provided and developed as a result of this effort. If,
upon review of the Study results, the Transmission Customer decides to pursue ,
the Transmission Provider will, at the Transmission Customer's direction, tender
a Facilities Study Agreement within thirty (30) days. The System Impact and
Facilities Studies, together with any additional studies contemplated in
Paragraph 3, shall form the basis for the Transmission Customer's proposed use
of the Transmission Provider's transmission system and shall be furthermore
utilized in obtaining necessary third-party approvals of any interconnection
facilities and requested transmission services. The Transmission Customer
understands and acknowledges that any use of study results by the Transmission
Customer or its agents, whether in preliminary or final form, prior to NEPOOL
l8.4 approval, is completely at the Transmission Customer's risk and that the
Transmission Provider will not guarantee or warrant the completeness, validity
or utility of study results prior to NEPOOL 18.4 approval.

5. The estimated costs contained within this Agreement are the Transmission
Provider's good faith estimate of its costs to perform the System Impact Study
contemplated by this Agreement. The Transmission Provider's estimates do not
include any estimates for wheeling charges that may be associated with the
transmission of facility output to third parties or with rates for station
service. The actual costs charged to the Transmission Customer by the
Transmission Provider may change as set forth in this Agreement. Prepayment will
be required for all study, analysis, and review work performed by the
Transmission Provider or its Designated Agent, all of which will be billed by
the Transmission provider to the Transmission Customer in accordance with
Paragraph 6 of this Agreement.

6. The payment required is $ from the Transmission Customer to the Transmission
Provider for the primary system analysis, coordination, and monitoring of the
System Impact Study. The Transmission Provider will, in writing, advise the
Transmission Customer in advance of any cost increases for work to be performed
if total amount increases by 10% or more. Any such changes to the Transmission
Provider's costs for the study work shall be subject to the Transmission
Customer's consent, such consent not to be unreasonably withheld. The
Transmission Customer shall, within thirty (30) days of the Transmission
Provider's notice of increase, either authorize such increases and make payment
in the amount set forth in such notice, or the Transmission Provider will
suspend the System Impact Study and this Agreement will terminate if so
permitted by the Federal Energy Regulatory Commission. In the event this
Agreement is terminated for any reason, the Transmission Provider shall refund
to the Transmission Customer the portion of the above credit or any subsequent
payment to the Transmission Provider by the Transmission Customer that the
Transmission provider did not expend in performing its obligations under this
Agreement. Any additional billings under this Agreement shall be subject to an
interest charge computed in accordance with the provisions of the Tariff.
Payments for work performed shall not be subject to refunding except in
accordance with Paragraph 7 below.

7. If the actual costs for the work exceed prepaid estimated costs, the
Transmission Customer shall make payment to the Transmission Provider for such
actual costs within thirty (30) days of the date of the Transmission Provider's
invoice for such costs. If the actual costs for the work are less than those
prepaid, the Transmission Provider will credit such difference toward
Transmission Provider costs unbilled, or in the event there will be no
additional billed expenses, the amount of the overpayment will be returned to
the Transmission Customer with interest computed as stated in Paragraph 6 of
this Agreement, from the date of reconciliation.

8. Nothing in this Agreement shall be interpreted to give the Transmission
Customer immediate rights to wheel over or interconnect with the Transmission
Provider's transmission or distribution system. Such rights shall be provided
for under separate agreement and in accordance with the Transmission Provider's
open access tariff.

9. Within one (1) year following the Transmission Provider's issuance of a final
bill under this Agreement, the Transmission Customer shall have the right to
audit the Transmission Provider's accounts and records at the offices where such
accounts and records are maintained, during normal business hours; provided that
appropriate notice shall have been given prior to any audit and provided that
the audit shall be limited to those portions of such accounts and records that
relate to service under this Agreement. The Transmission Provider reserves the
right to assess a reasonable fee to compensate for the use of its personnel time
in assisting any inspection or audit of its books, records or accounts by the
Transmission Customer or its Designated Agent.

10. Each party agrees to indemnify and hold the other party and its Related
Persons of each of them (collectively "Affiliates") harmless from and against
any and all damages, costs (including attorney's fees), fines, penalties and
liabilities, in tort, contract, or otherwise (collectively "Liabilities")
resulting from claims of third parties arising, or claimed to have arisen as a
result of any acts or omissions of either party under this Agreement. Each party
hereby waives recourse against the other party and its Related Persons for, and
releases the other party and its Related Persons from, any and all Liabilities
for or arising from damage to its property due to a performance under this
Agreement by such other party except in cases of negligence or intentional
wrongdoing by either party.

11. If either party materially breaches any of its covenants hereunder, the
other party may terminate this Agreement by filing a notice of intent to
terminate with the Federal Energy Regulatory Commission and serving notice of
same on the other party to this Agreement. This remedy is in addition to any
other remedies available to the injured party.

12.    This Agreement shall be construed and governed in accordance with the
laws of the State of Connecticut and with Part II of the Federal Power Act, 16
U.S.C. 824d et seq., and with Part 35 of Title 18 of the Code of Federal
Regulations, 18 C.F.R. 35 et seq.

13.    All amendments to this Agreement shall be in written form executed by
both parties.

14.     The terms and conditions of this Agreement shall be binding on the
successors and assigns of either party.

15. This Agreement will remain in effect for a period of up to two years from
its effective date as permitted by the Federal Energy Regulatory Commission, and
is subject to extension by mutual agreement. Either party may terminate this
Agreement by thirty (30) days' notice except as is otherwise provided herein. If
this Agreement expires by its own terms, it shall be the Transmission Provider's
responsibility to make such filing. Transmission Customer:

Name:

Title:

Date:


NEPOOL Participants

By (System Operator)

Name:

Title:

Date:





                                    EXHIBIT 1
          Information to be Provided to the Transmission Provider
            by the Transmission Customer for System Impact Study


1.0     Facilities Identification

1.1     Requested capability in MW and MVA; summer and winter

1.2     Site location and plot plan with clear geographical references

1.3     Preliminary one-line diagram showing major equipment and extent of
Transmission Customer ownership

1.4     Auxiliary power system requirements

1.5     Back-up facilities such as standby generation or alternate supply
sources

2.0     Major Equipment

2.1 Power transformer(s): rated voltage, MVA and BIL of each winding, LTC and or
NLTC taps and range, Z1 (positive sequence) and Zo (zero sequence) impedances,
and winding connections. Provide normal, long-time emergency and short-time
emergency thermal ratings.

2.2 Generator(s): rated MVA, speed and maximum and minimum MW output, reactive
capability curves, open circuit saturation curve, power factor (V) curve,
response (ramp) rates, H (inertia), D (speed damping), short circuit ratio, X1
(leakage), X2:(negative sequence), and Xo (zero sequence) reactances and other
data:


                                          Direct          Quadrature
                                           Axis               Axis

Saturated synchronous reactance             Xdv               Xqv
unsaturated synchronous reactance           Xdi               Xqt
saturated transient reactance               X'dv              X'qv
unsaturated transient reactance             X'di              X'qi
saturated subtransient reactance            X"dv              X"qv
unsaturated subtransient reactance          X"di              X"qi
transient open-circuit time constant        T'do              T'qo
transient short-circuit time constant       T"d               T"q
subtransient open-circuit time constant     T"do              T"qo
subtransient short-circuit time constant    T"d               T"q

2.3     Excitation system, power system stabilizer and governor: manufacturer's
data in sufficient detail to allow modeling in transient stability simulations.

2.4     Prime mover: manufacturer's data in sufficient detail to allow modeling
in transient stability simulations, if determined necessary.

2.5     Busses:  rated voltage and ampacity (normal, long-time emergency and
short-time emergency thermal ratings), conductor type and configuration.

2.6 Transmission lines: overhead line or underground cable rated voltage and
ampacity (normal, long-time emergency and short-time emergency thermal ratings),
Z1 (positive sequence) and Zo (zero sequence) impedances, conductor type,
configuration, length and termination points.

2.7 Motors greater than 150 kW 3-phase or 50 kW single-phase: type (induction or
synchronous), rated hp, speed, voltage and current, efficiency and power factor
at 1/2, 3/4 and full load, stator resistance and reactance, rotor resistance and
reactance, magnetizing reactance.

2.8     Circuit breakers and switches:  rated voltage, interrupting time and
continuous, interrupting and momentary currents.   Provide normal, long-time
emergency and short-time emergency thermal ratings.

2.9 Protective relays and systems: ANSI function number, quantity manufacturer's
catalog number, range, descriptive bulletin, tripping diagram and three-line
diagram showing AC connections to all relaying and metering.

2.10     CT's and VT's: location, quantity, rated voltage, current and ratio.

2.11    Surge protective devices: location, quantity, rated voltage and energy
capability.

3.0     Other

3.1 Additional data reasonably necessary to perform the System Impact Study will
be provided by the Transmission Customer as requested by the Transmission
Provider.

3.2 The Transmission Provider reserves the right to require that the
Transmission Customer accept the use in the study of specific equipment settings
or characteristics necessary to meet NEPOOL and NPCC criteria and standards.





                                  ATTACHMENT J

                                Form of
                           Facilities Study Agreement

This agreement dated , is entered into by (the Transmission Customer) and the
NEPOOL Participants (the "Transmission Operator") acting through the ("System
Provider"), for the purpose of setting forth the terms, conditions and costs for
conducting a Facilities Study relative to , in accordance with the NEPOOL Open
Access Transmission Tariff ("Tariff"). All definitions and other terms and
conditions of that Tariff are incorporated herein by reference. The Transmission
Provider may designate one or more Participants or the System Operator to act
for it under this Agreement. The Facilities Study will determine the detailed
engineering, design and cost of the facilities necessary to satisfy the
Transmission Customer's request for service over the NEPOOL Transmission System.

1.     The Transmission customer agrees to provide, in a timely complete manner,
the information and technical data specified in Exhibit 1 to this Agreement and

     reasonably necessary for the Transmission Provider to conduct the
Facilities Study. Where such information and technical data was provided for the
System Impact Study, it should be reviewed and updated with current information,
as required.

2. All work pertaining to the Facilities Study that is the subject of this
Agreement will be approved and coordinated only through designated and
authorized representatives of the Transmission Provider and the Transmission
Customer. Each party shall inform the other in writing of its designated and
authorized representative.

3. The Transmission Provider will advise the Transmission Customer of additional
information as may be reasonably deemed necessary to complete the study by the
Transmission Provider. Any such additional information shall be obtained only if
required by Good Utility Practice and shall be subject to the Transmission
Customer's consent to proceed, such consent not to be unreasonably withheld.

4. The Transmission Provider contemplates that it will require ____ days to
complete the Facilities Study. Upon completion of the study by the Transmission
Provider, the Transmission Provider will provide a report to the Transmission
Customer based on the information provided and developed as a result of this
effort. If, upon review of the study results, the Transmission Customer decides
to pursue its transmission service request, the Transmission Customer must sign
a supplemental Service Agreement with the Transmission Provider under the
Tariff. The System Impact and Facilities Studies, together with any additional
studies contemplated in Paragraph 3, shall form the basis for the Transmission
Customer's proposed use of the Transmission Provider's Transmission System and
shall be furthermore utilized in obtaining necessary third-party approvals of
any facilities and requested transmission services. The Transmission Customer
understands and acknowledges that any use of the study results by the
Transmission Customer or its agents whether in preliminary or final form, prior
to approval under Section 18.4 of the Restated NEPOOL Agreement, is completely
at the Transmission Customer's risk and that the Transmission Provider will not
guarantee or warrant the completeness, validity or utility of the study results
prior to NEPOOL 18.4 approval.

5. The estimated costs contained within this Agreement are the Transmission
Provider's good faith estimate of its costs to perform the Facilities Study
contemplated by this Agreement. The Transmission Provider's estimates do not
include any estimates for wheeling charges that may be associated with the
transmission of facility output to third parties or with rates for station
service. The actual costs charged to the Transmission Customer by the
Transmission Provider may change as set forth in this Agreement. Prepayment will
be required for all study, analysis, and review work performed by the
Transmission Provider's or its Designated Agent's personnel, all of which will
be billed by the Transmission Provider to the Transmission Customer in
accordance with Paragraph 6 of this Agreement.

6. The payment required is $ from the Transmission Customer to the Transmission
Provider for the primary system analysis, coordination, and monitoring of the
Facilities Study to be performed by the Transmission Provider for the
Transmission Customer's requested service. The Transmission Provider will, in
writing, advise the Transmission Customer in advance of any cost increases for
work to be performed if the total amount increases by 10% or more. Any such
changes to the Transmission Provider's costs for the study work to be performed
shall be subject to the Transmission Customer's consent, such consent not to be
unreasonably withheld. The Transmission Customer shall, within thirty (30) days
of the Transmission Provider's notice of increase, either authorize such
increases and make payment in the amount set forth in such notice, or the
Transmission Provider will suspend the study and this Agreement will terminate
if so permitted by the Federal Energy Regulatory Commission.

     In the event this Agreement is terminated for any reason, the Transmission
Provider shall refund to the Transmission Customer the portion of the above
credit or any subsequent payment to the Transmission Provider by the
Transmission Customer that the Transmission Provider did not expend in
performing its obligations under this Agreement. Any additional billings under
this Agreement shall be subject to an interest charge computed in accordance
with the provisions of the Tariff. Payments for work performed shall not be
subject to refunding except in accordance with Paragraph 7 below.

7. If the actual costs for the work exceed prepaid estimated costs, the
Transmission Customer shall make payment to the Transmission Provider for such
actual costs within thirty (30) days of the date of the Transmission Provider's
invoice for such costs. If the actual costs for the work are less than that
prepaid, the Transmission Provider will credit such difference toward
Transmission Provider's costs unbilled, or in the event there will be no
additional billed expenses, the amount of the overpayment will be returned to
the Transmission Customer with interest computed in accordance with the
provisions of the Tariff.

8. Nothing in this Agreement shall be interpreted to give the Transmission
Customer immediate rights to interconnect to or wheel over the NEPOOL
Transmission System. Such rights shall be provided for under separate agreement.

9. Within one (1) year following the Transmission Provider's issuance of a final
bill under this Agreement, the Transmission Customer shall have the right to
audit the Transmission Provider's accounts and records at the offices where such
accounts and records are maintained during normal business hours; provided that
appropriate notice shall have been given prior to any audit and provided that
the audit shall be limited to those portions of such accounts and records that
relate to service under this Agreement. The Transmission Provider reserves the
right to assess a reasonable fee to compensate for the use of its personnel time
in assisting any inspection or audit of its books, records or accounts by the
Transmission Customer or its Designated Agent.

10. Each party agrees to indemnify and hold the other party and its Related
Persons harmless from and against any and all damages, costs (including
attorney's fees), fines, penalties and liabilities, in tort, contract, or
otherwise (collectively "Liabilities") resulting from claims of third parties
arising, or claimed to have arisen as a result of any acts or

     omissions of either party under this Agreement. Each party hereby waives
recourse against the other party and its Related Persons for, and releases the
other party and its Related Persons from, any and all Liabilities for or arising
from damage to its property due to performance under this Agreement by such
other party except in cases of negligence or intentional wrongdoing by either
party.

11. If any party materially breaches any of its covenants hereunder, the other
party may terminate this Agreement by filing a notice of intent to terminate
with the Federal Energy Regulatory Commission and serving notice of same on the
other party to this Agreement. This remedy is in addition to any other remedies
available for the injured party.

12. This agreement shall be construed and governed in accordance with the laws
of the State of Connecticut and with Part II of the Federal Power Act, 16 U.S.C.
Sections 824d et seq., and with Part 35 of Title 18 of the Code of Federal
Regulations, 18 C.F.R. Sections 35 et seq.

13.     All amendments to this Agreement shall be in written form executed by
both parties.

14.     The terms and conditions of this Agreement shall be binding on the
successors and assigns of either party.

15. This Agreement will remain in effect for a period of two years from its
effective date as permitted by the Federal Energy Regulatory Commission, and is
subject to extension by mutual agreement.

     Either party may terminate this Agreement by thirty (30) days' notice
except as is otherwise provided herein. If this Agreement expires by its own
terms, it shall be the Transmission Provider's responsibility to make such
filing.

Transmission Customer:


Name:

Title:

Date:



NEPOOL Participants

By (System Operator)

Name:

Title:

Date:






                                  ATTACHMENT K

                        1997 Twelve CP Network Load Data

                         NEPOOL 1997 12 CP Network Load

                         NEPOOL 1997 12CP Network Loads


NEPOOL

Local Networks - 1997                            1997 12CP
                                             Network Load (MW)

Boston Edison Co.                             3,023.024
Bangor Hydro Electric                           255.589
Commonwealth Energy Systems                     601.023
Central Maine Power                           1,464.781
Eastern Utilities Associates                    885.357
New England Electric System                   3,957.775
Northeast Utilities                           6,332.724
United Illuminating                             677.367
Vermont Electric Light Co.                      796.881
     TOTAL                                   17,994.521



Boston Edison Company

Network Load Customer                         1997 12CP
                                               Network
                                              Load (MW)

Boston Edison Co.**                           2,383.727
Braintree                                        58.395
Cambridge***                                    216.966
Concord (PASNY)                                   1.690
Hingham                                          25.083
Hull                                              6.139
MBTA                                              7.283
Norwood (NYPA)                                    2.635
Norwood (NEP Tariff 1)                           48.448
Quincy/Weymouth (Retail Wheeling-MECO)            0.000
Quincy/Weymouth (NEP Tariff 1)                  185.693
Reading                                          82.333
Wellseley (PASNY)                                 2.335
Belmont (PASNY)                                   2.297
          Total                               3,023.024




                Bangor Hydro Electric Company


Network Load Customer                        1997 12CP
                                              Network
                                              Load (NW)

Bangor Hydro Electric                         255.589
     Total                                    255.589




               Commonwealth Electric Company


Network Load Customer                       1997 12CP
                                             Network
                                            Loan (MW)

Commonwealth Electric Company               585.283
Nantucket (NEP Tariff 1)                     15.740
Nantucket (Retail Wheeling)                   0.000
     Total                                  601.023



                     Central Maine Power


Network Load Customer                      1997 12CP
                                            Network
                                           Loan (MW)

Central Maine Power                       1,407.939
Fox Island                                    1.491
Kennebunk                                    15.024
Madison                                      40.327
     Total                                1,464.781




                    Eastern Utilities Associates


Network Load Customer                     1997 12CP
                                           Network
                                          Loan (MW)

Eastern Utilities Associates**            756.175
Middleborough                              22.967
Pascoag, RI                                 1.592
Taunton                                    90.940
Tiverton (Retail Wheeling - NECO)           0.000
Tiverton (NEP Tariff 1)                    13.683
     Total                                885.357




                        New England Power


Network Load Customer                     1997 12CP
                                           Network
                                          Loan (MW)

New England Power**                       3,287.945
Granite State Electric (Retail Wheeling)      2.307
Massachusetts Electric (Retail Wheeling)     43.397
Narragansett Electric (Retail Wheeling)       2.750
Ashburnham                                    4.540
Boylston                                      3.930
Central Vermont Public Service                8.234
Danvers                                      52.435
Fitchburg Gas & Electric                     72.331
French King                                  11.341
Georgetown                                    6.805
Green Mountain Power (Except Stamford)       59.480
Groton, MA                                    8.281
Groveland (NYPA Load)                         0.510
Holden                                       15.199
Hudson                                       47.500
Ispwich                                      14.670
Littleton, MA                                26.751
Mansfield                                    31.725
MBTA                                          5.851
Marblehead                                   17.121
Massachusetts Governors Land Bank             2.127
Merrimac (NYPA)                               0.525
Middleton                                    14.928
N. Attleboro                                 36.158
Paxton                                        3.069


Network Load Customer                      1997 12CP
                                            Network
                                           Loan (MW)

Peabody                                     73.540
Princeton                                    2.388
Rowley                                       5.305
Shrewsbury                                  43.113
Sterling                                     6.673
Templeton                                    8.902
Wakefield                                   28.317
W. Boylston                                  9.627
     Total                               3,957.775



                 Northeast Utilities


Network Load Customer                          1997 12CP
                                                Network
                                               Loan (MW)

Northeast Utilities**                         5,377.920
Bolt Hill                                        34.630
Chicopee                                         64.539
Conn. Municipal Electric Energy Co-op           268.199
Holyoke Gas & Electric                           48.541
SBNG (Retail Wheeling - MECO)***                  0.000
SBNG (NEP Tariff 1)***                           84.184
S. Hadley                                        21.182
The Six United Illuminating Substations         218.535
UNITIL                                          164.297
Westfield                                        50.697
     Total                                    6,332.724




                   United Illuminating Company


Network Load Customer                          1997 12CP
                                                Network
                                               Loan (MW)

United Illuminating                             677.367
     Total                                      677.367




                    Vermont Electric Power Co.



Network Load Customer                           1997 12CP
                                                 Network
                                                Loan (MW)

Vermont Electric Light Co.                       796.881
     Total                                       796.881



Total of all Transmission Providers 12CP = 17,994.521





                                  ATTACHMENT L

               Financial Assurance Policy for NEPOOL Members


This Financial Assurance Policy for NEPOOL Members ("Policy") shall become
effective January 1, 1999 (the "Policy Effective Date"). (FN1)


The purpose of this Policy is (i) to establish a financial assurance policy for
NEPOOL members ("Participants") that includes commercially reasonable credit
review procedures to assess the financial ability of an applicant for membership
in NEPOOL ("Applicant") or of a Participant to pay for service transactions
under the Restated NEPOOL Agreement and the NEPOOL Open Access Transmission
Tariff (the "Tariff") and to pay its share of NEPOOL expenses, including amounts
owed to the ISO under its tariff, (ii) to set forth requirements for alternative
forms of security that will be deemed acceptable to NEPOOL and consistent with
commercial practices established by the Uniform Commercial Code that protects
the Participants against the risk of non- payment by other, defaulting
Participants, (iii) to set forth the conditions under which NEPOOL will conduct
business so as to avoid the possibility of failure of payment for services
rendered under the Tariff or the Restated NEPOOL Agreement, and (iv) to collect
amounts past due, collect amounts payable upon billing adjustments, make up
shortfalls in payments, and terminate membership of defaulting Participants.

In accordance with Sections 3.5 and 7.5 of the Restated NEPOOL Agreement, NEPOOL
requires the following procedures and requirements to apply to all Applicants
and Participants. Generally, any Applicant or Participant that does not have an
investment grade rating by either Standard & Poor's, Moody's, Duff & Phelps, or
Fitch (or in the case of Applicants or Participants that are not rated
themselves, any Applicant or Participant that does not have outstanding debt
with such a rating) will be required to provide financial assurances, as
described in detail below.








- ---------
(FN1) Capitalized terms used but not defined in this Policy are intended to have
the meanings given to such terms in Section 1 of the Restated NEPOOL Agreement
or Section 1 of the Restated NEPOOL Open Access Transmission Tariff (the
"Tariff"), as amended.










GENERAL REQUIREMENTS

Each Applicant or Participant must comply with the following general
requirements. In the case of a group of members that are treated as a single
Participant pursuant to Section 4.1 of the Restated NEPOOL Agreement, the group
members shall be deemed to have elected to be jointly and severally liable for
all debts to NEPOOL of any of the group members unless (i) charges of an
individual member can be tracked and allocated to the member incurring such
charges by the System Operator (FN1) utilizing all information available to the
System Operator determined by it to be reliable, including information from
Participants or from a single Participant's representative, (ii) an alternate
form of financial assurance is provided as set forth below, (iii) the group
members agree to allocate amongst themselves responsibility for payment of group
member charges on a percentage basis in a manner acceptable to NEPOOL, with
additional financial assurance to be provided by those members, if any, that do
not satisfy the minimum corporate debt rating, or (iv) the group members when
evaluated as a whole (at their expense by one of the above rating agencies)
satisfy the minimum corporate debt rating requirement set forth above and, in
addition, provide a corporate guaranty from a parent or other responsible
affiliate, which parent or affiliate satisfies the minimum corporate debt
rating. For the fourth type of consolidated Participant, NEPOOL will conduct a
financial assurances review based on the credit rating of only the rated members
of the group.

For the purposes of these financial assurance provisions, the term "Participant"
shall, in the case of a group of members that are treated as a single
Participant pursuant to Section 4.1 of the Restated NEPOOL Agreement, be deemed
to refer to the group of members as a whole unless the group members have
affirmatively indicated to NEPOOL, and NEPOOL has agreed, that they are to be
treated pursuant to options (i) or (iii) above, in which case the term
"Participant" shall be deemed to refer to each individual group member and not
to the aggregate of such group; and the terms "charges" and fees" shall,
likewise, be deemed to refer to the charges and fees allocable to the individual
group member as opposed to the aggregate of such group.








- --------
(FN1) The System Operator will act as NEPOOL's agent in managing and enforcing
this Policy with the exception of termination of membership issues, which are
specifically reserved to the NEPOOL Participants and will be addressed by the
NEPOOL Executive Committee Membership Subcommittee, subject to appeal to the
Management Committee. Accordingly, all financial information required pursuant
to this Policy is to be provided to the System Operator, which will keep all
such information confidential in accordance with the provisions of Section 2 of
NEPOOL Criteria, Rules and Standards No. 45.

Proof of Financial Viability

Each Applicant must with its application submit proof of financial viability, as
described below, satisfying NEPOOL requirements to demonstrate the Applicant's
ability to meet its obligations, or must provide prior to its membership
becoming effective financial assurance in the form of a cash deposit, letter of
credit or performance bond as set forth below. An Applicant that chooses to
provide a cash deposit, letter of credit or performance bond will not be
required to provide financial information to NEPOOL.

Generally, each Applicant must submit a current rating agency report, which
report must indicate an investment grade rating by either Standard & Poor's,
Moody's, Duff & Phelps, or Fitch for the Applicant or, if the Applicant itself
is not rated, for the Applicant's outstanding rated debt, in order for the
Applicant to be considered as a candidate for NEPOOL membership without
furnishing additional financial assurances as described below.

Current Participants must also provide a current rating agency report by the
Policy Effective Date, as well as any of the financial statements and
information set forth below if and as requested by NEPOOL within ten (10) days
of such request. Those Participants that do not satisfy the rating requirement
as set forth above must provide instead on the Policy Effective Date one form of
the financial assurances set forth below. A Participant's failure to meet these
requirements may result in termination proceedings by NEPOOL.

Financial Statements

Each Applicant must submit, if and as requested by NEPOOL and within ten (10)
days of such request, audited financial statements for at least the immediately
preceding three years, or the period of its existence, if shorter, including,
but not limited to, the following information:

               Balance Sheets
               Income Statements
               Statements of Cash Flows
               Notes to Financial Statements

Additionally, the following information for at least the immediately preceding
three years, if available, must be submitted if and as requested by NEPOOL and
within ten (10) days of such request:

               Annual and Quarterly Reports
               10-K, 10-Q and 8-K Reports

Where the above financial statements are available on the Internet, the
Applicant may provide instead a letter to NEPOOL stating where such statements
may be located and retrieved by NEPOOL.

Each Applicant may also be required to provide at least one bank reference and
three (3) Utility credit references. In those cases where an Applicant does not
have three (3) Utility credit references, three (3) trade payable vendor
references may be substituted.

Each Applicant may also be required to include information as to any known or
anticipated material lawsuits, as well as any prior bankruptcy declarations by
the Applicant, or by its predecessor(s), if any.

In the case of certain Applicants, some of the above financial submittals may
not be applicable, and alternate requirements may be specified by NEPOOL.

Ongoing Financial Review

Each Participant that has not provided a cash deposit, letter of credit,
performance bond, or corporate guaranty must submit its current rating agency
report promptly upon the request of NEPOOL, and 8-K Reports promptly upon their
issuance.

In addition, each Participant is responsible for informing NEPOOL in writing
within ten (10) business days of any material change in its financial status. A
material change in financial status includes, but is not limited to, the
following: a downgrade to a below investment grade rating of senior long term
debt by a major rating agency, being placed on credit watch with negative
implication by a major rating agency if senior long term debt does not have an
investment grade rating, a bankruptcy filing, insolvency, a report of a
significant quarterly loss or decline of earnings, the resignation of key
officer(s), and/or the filing of a material lawsuit that could materially
adversely impact current or future financial results. A Participant's failure to
provide this information may result in termination proceedings by NEPOOL.

If there is a material adverse change in the financial condition of the
Participant, NEPOOL may require the Participant to provide one of the forms of
other financial assurances set forth below. If the Participant fails to do so,
NEPOOL may initiate termination proceedings in accordance with the procedure set
forth in Section 21.2(d) of the Restated NEPOOL Agreement.

OTHER FINANCIAL ASSURANCES

Applicants or Participants that do not satisfy the rating requirement or
NEPOOL's credit review process must submit instead one of the following
additional financial assurances, depending on the type of transactions they
anticipate engaging in as Participants. Each financial assurance for monthly
charges, unless replaced in accordance with the terms hereof or no longer
required pursuant to the terms hereof, shall remain in effect for one hundred
twenty days after termination of the Participant's membership, provided, however
that financial assurances required by this Financial Assurance Policy related to
potential billing adjustments chargeable to a terminated Participant shall
remain in effect until such billing adjustment request is finally resolved in
accordance with the provisions of the NEPOOL Billing Policy.

In general, Participants must provide additional financial assurance in the
following amounts, based on their average or expected monthly charges for
interchange and transmission service under the Tariff (which would include
charges for Regional Network Service or Through or Out Service) and the Restated
NEPOOL Agreement (which would include energy and other services received through
NEPOOL) and NEPOOL expenses for services, including amounts owed to ISO New
England Inc. under its tariff (collectively the "NEPOOL Charges"):

Monthly NEPOOL Charges                   Financial Assurance Requirement

$0 - $15,000                               0 months' NEPOOL Charges
$15,001 - $30,000                          1 month's NEPOOL Charges
$30,001 - $50,000                          2 months' NEPOOL Charges
$50,001 or more                            3 1/2 months' NEPOOL Charges

The three and one-half months is based on the time required for a FERC filing
made by NEPOOL to suspend service to be effective.

Therefore, a Participant with $32,000 in monthly NEPOOL Charges that does not
satisfy the rating requirement or NEPOOL credit review process must provide
additional financial assurances in the amount of $64,000 to NEPOOL.

In the case of new Participants, the additional financial assurance requirement
will be based on estimated monthly NEPOOL Charges, which estimate NEPOOL has the
right to adjust in light of subsequent experience as to actual monthly NEPOOL
Charges.

Furthermore and without limiting the generality of the foregoing, if a
Participant that has received from one or more other Participants or Non-
Participant Transmission Customers an amount the payment of which is the subject
of a dispute, an amount equal to 100% of such amount in dispute shall be
included in determining that Participant's overall financial assurance
requirement. Any additional financial assurance provided under this paragraph
shall not be terminated or returned prior to the resolution of the dispute
requiring such additional financial assurance, even if the Participant providing
such additional financial assurance is terminated or withdraws from NEPOOL and
otherwise satisfies all of its obligations to NEPOOL. As used herein, the term
"Financial Assurance Requirement" shall include 100% of such amount in dispute,
in addition to the other amounts included in such Financial Assurance
Requirement for the relevant Participant.

In addition, and without limiting the foregoing, any Participant that does not
satisfy the rating requirement or NEPOOL's credit review process and that has
monthly NEPOOL Charges (determined as set forth above) in excess of $15,000
shall not at any time have net NEPOOL Charges (regardless of whether such
charges have actually become due and owing or not) in excess of the amount of
the additional financial assurance provided by such Participant. Any Participant
that does not satisfy the rating requirement or NEPOOL's credit review process
but is exempt from providing additional financial assurance by virtue of having
monthly NEPOOL charges of $15,000 or less shall not at any time have net NEPOOL
Charges (regardless of whether such charges have actually become due and owing
or not) in excess of $15,000 unless such Participant provides the additional
financial assurance described herein in an amount not less than such net NEPOOL
Charges. If a Participant that does not satisfy the rating requirement or
NEPOOL's credit review process exceeds the limits for net NEPOOL Charges set
forth for it in this paragraph, NEPOOL may initiate termination proceedings. A
Participant that does not satisfy the rating requirement or NEPOOL's credit
review process and knows or reasonably should know that it has exceeded the
limits for net NEPOOL Charges set forth for it in this paragraph shall notify
the ISO immediately that it has exceeded such limits.

Cash Deposit

A cash deposit for the full value of the Financial Assurance Requirement, as
determined by NEPOOL, provides an acceptable form of financial assurance to
NEPOOL.

If the amount of the deposit is below the required level, the Participant shall
immediately replenish or increase the deposit to the required level; otherwise,
NEPOOL may initiate termination proceedings. In the event that actual NEPOOL
Charges exceed those anticipated, the anticipated charges will be increased
accordingly and the Participant must augment its cash deposit to reach the
required level.

The cash deposit will be invested by NEPOOL in investments as may be designated
by the Participant in direct obligations of the United States or its agencies
and interest earned will be paid to the Participant. NEPOOL may sell or
otherwise liquidate such investments at its discretion to meet the Participant's
obligations to NEPOOL.

The requirement to continue the deposit may be reviewed by NEPOOL after one
year. Consideration will be given to replacing the cash deposit with a corporate
guaranty if certain conditions are met, as discussed below in the Corporate
Guaranty section.

Letter of Credit

An irrevocable standby letter of credit for the full value of the Financial
Assurance Requirement, as determined by NEPOOL, provides an acceptable form of
financial assurance to NEPOOL. The letter of credit will renew automatically
unless the issuing bank provides notice to NEPOOL at least ninety (90) days
prior to the letter of credit's expiration of the bank's decision not to renew
the letter of credit.

If the letter of credit amount is below the required level, the Participant
shall immediately replenish or increase the letter of credit amount; otherwise,
NEPOOL may initiate termination proceedings. If actual NEPOOL Charges exceed
those anticipated, the Participant must obtain a substitute letter of credit
that equals the actual NEPOOL Charges.

The form, substance, and provider of the letter of credit must all be acceptable
to NEPOOL. The letter of credit should clearly state the full names of the
"Issuer," "Account Party" and "Beneficiary" (NEPOOL), the dollar amount
available for drawings, and should include a statement required on the drawing
certificate and other terms and conditions that should apply. It should also
specify that funds will be disbursed, in accordance with the instructions,
within one (1) business day after due presentation of the drawing certificate.
The bank issuing the letter of credit must have a minimum corporate debt rating
of an "A-" by Standard & Poor's, or "A3" by Moody's, or "A-" by Duff & Phelps,
or "A-" by Fitch, or an equivalent short term debt rating by one of these
agencies.

Please refer to Attachment 1, which provides an example of a generally
acceptable sample "clean" letter of credit. All costs associated with obtaining
financial security and meeting the Policy provisions are the responsibility of
the Applicant or Participant.

The requirement to continue to provide a letter of credit may be reviewed by
NEPOOL after one year. Consideration will be given to replacing the letter of
credit with a corporate guaranty if certain conditions are met, as discussed
below in the Corporate Guaranty section.

Performance Bond

A performance bond complying with the requirements set forth herein provides an
acceptable form of financial assurance to NEPOOL. The penal sum of such
performance bond shall be in an amount equal to the full value of the Financial
Assurance Requirement, as determined by NEPOOL, and shall automatically be
adjusted to reflect any adjustment in such Financial Assurance Requirement. The
bond shall permit suit thereunder until two years after the date that all of the
Applicant's or Participant's obligations to NEPOOL expire.

If the amount of the penal sum of the performance bond available to NEPOOL is
below the required level, the Participant shall immediately replenish or
increase the amount of the penal sum; otherwise, NEPOOL may initiate termination
proceedings. If actual NEPOOL Charges exceed those anticipated, the Participant
must either cause the penal sum of such performance bond to be increased
accordingly or must obtain a substitute performance bond in the appropriate
amount.

The form, substance and provider of the performance bond must be acceptable to
NEPOOL. The performance bond should clearly state the full names of the
"Principal," the "Surety" and the "Obligee" (NEPOOL) and the penal sum and
should include a clear statement that the surety will promptly and faithfully
perform the Participant's obligations to NEPOOL if the Participant fails to do
so. The insurance company issuing the performance bond must be rated "A" or
better by A.M. Best & Co.

Please refer to Attachment 2, which provides an example of a generally
acceptable sample performance bond. All costs associated with obtaining
financial security and meeting the Policy provisions, including without
limitation the cost of the premiums for such performance bond, are the
responsibility of the Applicant or Participant.

The requirement to continue to provide a performance bond may be reviewed by
NEPOOL after one year. Consideration will given to replacing the performance
bond with a corporate guaranty if certain conditions are met, as discussed below
in the Corporate Guaranty section.

Weekly Payments

A Participant that does not satisfy the rating requirement may request that, in
lieu of providing one of the additional financial assurances set forth above, a
weekly billing schedule be implemented for it. NEPOOL may, in its discretion,
agree to such a request; provided, however, that any weekly billing arrangement
will terminate no more than six months after the date on which such arrangement
begins unless the Participant requests an extension of such arrangement and
demonstrates to NEPOOL's satisfaction in its sole discretion that the
termination of such arrangement and compliance with the other provisions of this
Policy (including providing another form of financial assurance, if required)
will impose a substantial hardship on the Participant. Such demonstration of a
substantial hardship shall be made every six months after the initial
demonstration, and a Participant's weekly billing arrangement will be terminated
if it fails to demonstrate to NEPOOL's satisfaction in its sole discretion at
any such six month interval that compliance with the other provisions of this
Policy will impose a substantial hardship on it.

If NEPOOL agrees to implement a weekly billing schedule for a Participant, the
Participant shall be billed weekly in arrears on an estimated basis for all
amounts owed to NEPOOL and the System Operator for the week, with an adjustment
for each month as part of the regular NEPOOL monthly billing to reflect any
under or over collection for the month. The Participant shall be obligated to
pay each such weekly bill within five business days after it is received. The
Participant shall pay with respect to each weekly bill an administrative fee,
determined by the System Operator, to reimburse the System Operator for the
costs it incurs as a result of that Participant's weekly billing arrangement.

If a weekly billing schedule is implemented for a Participant in lieu of
requiring the Participant to provide an additional financial assurance, the
Participant may be required to provide an additional financial assurance at any
time if the Participant fails to pay when due any weekly bill. In addition, upon
the termination of a Participant's weekly billing arrangement, the Participant
shall either satisfy the rating requirement set forth herein or provide one of
the other forms of financial assurance set forth herein.

Use of Transaction Setoffs

Under certain conditions, NEPOOL may be obligated to make payments to a
Participant. In this event, the amount of the cash deposit, letter of credit or
performance bond required for financial assurance for the contemplated
transactions may be reduced ("setoff") by an amount equal to NEPOOL's unpaid
balance or expected billing under the other transactions. The terms and the
amount of the setoff must be approved by NEPOOL.

Corporate Guaranty

An irrevocable corporate guaranty obtained from a Participant's affiliated
company ("Guarantor") for the full value of the Financial Assurance Requirement,
as determined by NEPOOL, may provide an acceptable form of financial assurance
to NEPOOL.

If actual NEPOOL Charges exceed those anticipated, the Participant must provide
a substitute corporate guaranty that equals the actual NEPOOL Charges.

A Participant for which a letter of credit, performance bond or cash deposit was
initially required may have the opportunity to substitute a corporate guaranty
if the following conditions are met:

1.     NEPOOL determines that the Participant has satisfactorily met its payment
obligations in NEPOOL for at least one-year, which one-year period may in whole
or in part pre-date the Policy Effective Date;

2.     NEPOOL determines that the financial condition of the Guarantor meets the
requirements of this Policy; and 3.

3.     The form and substance of the corporate guaranty are acceptable to
NEPOOL.

Upon NEPOOL's written authorization, the Participant may substitute a corporate
guaranty that is issued by the Guarantor for a cash deposit, bank letter of
credit or performance bond when it has satisfied the conditions stipulated
above. The corporate guaranty is considered to be a lesser form of financial
assurance than a cash deposit, letter of credit or performance bond, and
therefore is allowed as an acceptable form of financial assurance only to those
Participants that have satisfied their payment obligations to NEPOOL in a timely
manner for at least one year.

The corporate guaranty may only be used if the Participant is affiliated with a
Guarantor that has greater financial assets, a strong balance sheet and income
statements, and at minimum an investment grade rating by either Standard &
Poor's, Moody's, Duff & Phelps, or Fitch.

The corporate guaranty should clearly state the identities of the "Guarantor,"
"Beneficiary" and "Obligor," and the relationship between the Guarantor and the
Participant Obligor. The corporate guaranty must be duly authorized by the
Guarantor, must be signed by an officer of the Guarantor, and must be furnished
with either an opinion satisfactory to NEPOOL of the Guarantor's counsel with
respect to the enforceability of the guaranty or accompanied by a certificate of
corporate guarantee that includes a seal of the corporation with the signature
of the corporate secretary. Additionally, adequate documentation regarding the
signature authority of the person signing the corporate guaranty must be
provided with the corporate guaranty.

A corporate guaranty must also obligate the Guarantor to submit a current rating
agency report promptly upon the request of NEPOOL, to submit 8-K Reports
promptly upon their issuance, to submit financial reports if and as requested by
NEPOOL within ten (10) days of such request, and to inform NEPOOL in writing
within ten (10) business days of any material change in its financial status. A
material change in financial status includes, but is not limited to, the
following: a downgrade to a below investment grade rating of senior long term
debt by a major rating agency, being placed on credit watch with negative
implication by a major rating agency if senior long term debt does not have an
investment grade rating, a bankruptcy filing, insolvency, a report of a
significant quarterly loss or decline of earnings, the resignation of key
officer(s), and/or the filing of a material lawsuit that could materially
adversely impact current or future financial results. A Guarantor's failure to
provide this information may result in proceedings by NEPOOL to terminate the
Participant Obligor. If there is a material adverse change in the financial
condition of the Guarantor, NEPOOL may require the Participant Obligor to
provide another form of financial assurance, either a cash deposit or a letter
of credit or a performance bond.

Non-payment of Amounts Due

If a Participant does not pay amounts billed when due and as a result a letter
of credit or cash deposit is drawn down or a performance bond is paid on, then
the Participant must immediately replenish the letter of credit or cash deposit
to the required amount or cause the penal sum of the performance bond to be
increased to equal the required amount plus all amounts paid thereunder. If a
Participant fails to do so, NEPOOL may initiate termination proceedings against
the Participant in accordance with the procedure set forth in Section 21.2(d) of
the Restated NEPOOL Agreement.

In order to encourage prompt payment by Participants of amounts owed to NEPOOL
and the ISO, if a Participant is delinquent two or more times within any period
of twelve months in paying on time its NEPOOL Charges, the Participant shall
pay, in addition to interest on each late payment, a late payment charge for its
second failure to pay on time, and for each subsequent failure to pay on time,
within the same twelve-month period, in an amount equal to the greater of (i)
two percent (2%) of the total amount of such late payment or (ii) $250.00.

In the case of a former Participant that applies again for membership in NEPOOL,
a determination of delinquency shall be based on the Participant's history of
payment of its NEPOOL Charges in its last twelve (12) months of membership.

Financial Assurance upon Termination of Membership

Upon termination of membership in NEPOOL, a Participant must provide financial
assurance in the amount of all potential billing adjustments chargeable to such
Participant for all unresolved billing disputes in existence on the date of
termination of such Participant's membership. Such financial assurance must be
in the form of a cash deposit, a letter of credit, an affiliate guaranty, or a
performance bond meeting the requirements of this policy. The amount of such
financial assurance shall be reduced to the extent any billing dispute is
resolved and the former Participant pays the billing adjustments or no billing
adjustment is chargeable to the former Participant.

Notification of Default

In the event that a Participant fails to comply with this Financial Assurance
Policy (including, without limitation, a failure by such Participant (i) to
provide NEPOOL with the required information, (ii) to maintain its additional
financial assurance at the required level, (iii) to notify NEPOOL of a material
adverse change in the financial condition of such Participant or its Guarantor,
or (iv) to notify NEPOOL of such Participant's net Monthly Charges exceeding the
limits set forth above) (a "Financial Assurance Default") and such failure
continues for at least ten days, NEPOOL may (but shall not be required to)
notify such Participant in writing, electronically and by first class mail sent
in each case to such Participant's member or alternate on the NEPOOL
Participants Committee or billing contact (it being understood that NEPOOL will
use reasonable efforts to contact all three), of such Financial Assurance
Default. Either simultaneously with the giving of the notice described in the
preceding sentence or within the ten days thereafter (unless the Financial
Assurance Default is cured during such period), NEPOOL shall notify each other
member and alternate on the NEPOOL Participants Committee and each Participant's
billing contact of the identity of the Participant receiving such notice,
whether such notice relates to a Financial Assurance Default, and the actions
NEPOOL plans to take and/or has taken in response to such Financial Assurance
Default.

No remedy for a Financial Assurance Default is or shall be deemed to be
exclusive of any other available remedy or remedies. Each such remedy shall be
distinct, separate and cumulative, shall not be deemed inconsistent with or in
exclusion of any other available remedy, and shall be in addition to and
separate and distinct from every other remedy.





                                  ATTACHMENT 1
                             SAMPLE LETTER OF CREDIT
                                                            [DATE PROVIDED]

                   IRREVOCABLE STANDBY LETTER OF CREDIT NO.

[EXPIRATION DATE] AT OUR COUNTERS [unless an evergreen l/c is obtained]

WE DO HEREBY ISSUE AN IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT BY
ORDER OF AND FOR THE ACCOUNT OF ON BEHALF OF [PARTICIPANT] ("ACCOUNT PARTY") IN
FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") IN AN AMOUNT
NOT EXCEEDING US$ .00 (UNITED STATES DOLLARS
          AND 00/100) AGAINST PRESENTATION TO US OF A DRAWING CERTIFICATE SIGNED
BY A PURPORTED OFFICER OR AUTHORIZED AGENT OF NEPOOL AND DATED THE DATE OF
PRESENTATION CONTAINING THE FOLLOWING STATEMENT:

"THE UNDERSIGNED HEREBY CERTIFIES TO [BANK] ("BANK"), WITH REFERENCE TO
IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT NO. ISSUED BY [BANK] IN
FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") THAT
[PARTICIPANT] HAS FAILED TO PAY NEPOOL IN ACCORDANCE WITH THE TERMS AND
PROVISIONS OF THE RESTATED NEPOOL AGREEMENT BETWEEN [PARTICIPANT] AND THE OTHER
NEPOOL MEMBERS , AND THUS NEPOOL IS DRAWING UPON THE LETTER OF CREDIT IN AN
AMOUNT EQUAL TO $ ."

IF PRESENTATION OF ANY DRAWING CERTIFICATE IS MADE ON A BUSINESS DAY AND SUCH
PRESENTATION IS MADE AT OUR COUNTERS ON OR BEFORE 10:00 A.M. TIME, WE SHALL
SATISFY SUCH DRAWING REQUEST ON THE SAME BUSINESS DAY. IF THE DRAWING
CERTIFICATE IS RECEIVED AT OUR COUNTERS AFTER 10:00 A.M. TIME, WE WILL SATISFY
SUCH DRAWING REQUEST ON THE NEXT BUSINESS DAY, FOR THE PURPOSES OF THIS SECTION,
A BUSINESS DAY MEANS A DAY, OTHER THAN A SATURDAY OR SUNDAY, ON WHICH COMMERCIAL
BANKS ARE NOT AUTHORIZED OR REQUIRED TO BE CLOSED IN NEW YORK, NEW YORK.

DISBURSEMENTS SHALL BE IN ACCORDANCE WITH THE INSTRUCTIONS OF NEPOOL.

THE FOLLOWING TERMS AND CONDITIONS APPLY:

THIS LETTER OF CREDIT SHALL EXPIRE AT THE CLOSE OF BUSINESS [DATE].  WE WILL
PROVIDE NOTICE TO NEPOOL AT LEAST 90 DAYS PRIOR TO SUCH DATE IF THIS LETTER
OF CREDIT WILL NOT BE RENEWED AS OF SUCH DATE [or: THIS LETTER OF CREDIT
SHALL EXPIRE ONLY UPON THE FOLLOWING CONDITIONS: (1) WHEN FULL PAYMENT HAS
BEEN RECEIVED BY NEPOOL FROM [PARTICIPANT] AND (2) NEPOOL HAS PROVIDED A
WRITTEN RELEASE TO THIS BANK .]

THE AMOUNT WHICH MAY BE DRAWN BY YOU UNDER THIS LETTER OF CREDIT SHALL BE
AUTOMATICALLY REDUCED BY THE AMOUNT OF ANY UNREIMBURSED DRAWINGS HEREUNDER AT
OUR COUNTERS. ANY NUMBER OF PARTIAL DRAWINGS ARE PERMITTED FROM TIME TO TIME
HEREUNDER.

ALL COMMISSIONS AND CHARGES WILL BE BORNE BY THE ACCOUNT PARTY.

THIS LETTER OF CREDIT IS NOT TRANSFERABLE OR ASSIGNABLE.

THIS LETTER OF CREDIT DOES NOT INCORPORATE AND SHALL NOT BE DEEMED MODIFIED,
AMENDED OR AMPLIFIED BY REFERENCE TO ANY DOCUMENT, INSTRUMENT OR AGREEMENT (A)
THAT IS REFERRED TO HEREIN (EXCEPT FOR THE UCP, AS DEFINED BELOW) OR (B) IN
WHICH THIS LETTER OF CREDIT IS REFERRED TO OR TO WHICH THIS LETTER OF CREDIT
RELATES.

THIS LETTER OF CREDIT SHALL BE GOVERNED BY THE UNIFORM CUSTOMS AND PRACTICE FOR
DOCUMENTARY CREDITS, 1993 REVISION, INTERNATIONAL CHAMBER OF COMMERCE
PUBLICATION NO. 500 (THE "UCP"), EXCEPT TO THE EXTENT THAT TERMS HEREOF ARE
INCONSISTENT WITH THE PROVISIONS OF THE UCP, INCLUDING BUT NOT LIMITED TO
ARTICLES 13(b) AND 17 OF THE UCP, IN WHICH CASE THE TERMS OF THE LETTER OF
CREDIT SHALL GOVERN.

THIS LETTER OF CREDIT MAY NOT BE AMENDED, CHANGED OR MODIFIED WITHOUT THE
EXPRESS WRITTEN CONSENT OF NEPOOL AND US.

WE HEREBY ENGAGE WITH YOU THAT DOCUMENTS DRAWN UNDER AND IN COMPLIANCE WITH THE
TERMS OF THIS LETTER OF CREDIT SHALL BE DULY HONORED UPON PRESENTATION AS
SPECIFIED.

PRESENTATION OF ANY DRAWING CERTIFICATE UNDER THIS STANDBY LETTER OF CREDIT MAY
BE SENT TO US BY COURIER, CERTIFIED MAIL, REGISTERED MAIL, TELEGRAM, TELEX TO
THE ADDRESS SET FORTH BELOW, OR SUCH OTHER ADDRESS AS MAY HEREAFTER BE FURNISHED
BY US. OTHER NOTICES CONCERNING THIS STANDBY LETTER OF CREDIT MAY BE SENT BY
FACSIMILE OR SIMILAR COMMUNICATIONS FACILITY TO THE RESPECTIVE ADDRESSES SET
FORTH BELOW. ALL SUCH NOTICES AND COMMUNICATIONS SHALL BE EFFECTIVE WHEN
ACTUALLY RECEIVED BY THE INTENDED RECIPIENT PARTY.

IF TO THE BENEFICIARY OF THIS LETTER OF CREDIT:


IF TO THE ACCOUNT PARTY:


IF TO US:



[signature]

[signature]






                                  ATTACHMENT 2

                             SAMPLE PERFORMANCE BOND

                               [Insurance Company]



Bond No.

KNOW ALL MEN BY THESE PRESENTS, That the undersigned [participant], of
[participant's address] hereinafter referred to as the Principal, and [insurance
company], a corporation organized and existing under the laws of the State of
[insurance company's state of incorporation], as Surety, are held and firmly
bound unto the Participants in the New England Power Pool as obligees,
hereinafter referred to collectively as the Obligee, in the sum of
                , lawful money of the United States of America (which sum shall
automatically be adjusted to reflect any adjustment in the Financial Assurance
Requirement applicable to the Principal under the New England Power Pool's
Financial Assurance Policy for NEPOOL Members, as in effect from time to time)
for the payment of which sum, well and truly to be made, we bind ourselves, our
executors, administrators, successors, and assigns, jointly and severally,
firmly by these presents.

WHEREAS, the Principal has entered into agreements for the purchase and sale of
electric services and the payment of amounts owed to ISO New England Inc. and
its share of the expenses of the New England Power Pool under the Restated
NEPOOL Agreement, the Restated NEPOOL Open Access Transmission Tariff and the
ISO New England Inc. Tariff for Transmission Dispatch and Power Administration
Services, each as amended from time to time (collectively referred to as the
"Agreements"), and in strict accordance with their respective terms.

NOW, THEREFORE, the condition of this obligation is such, that if the Principal
shall promptly and faithfully make the payments required by, and comply with
terms of, the Agreements which have been or may hereafter be in force and shall
save and keep harmless the Obligee from all loss or damage which it may sustain
or for which it may become liable on account of the issuance of said Agreements
to the Principal, then this obligation shall be void; otherwise, it shall remain
in full force and effect.

Upon notice from ISO New England Inc. of nonpayment by the Principal, Surety
will pay to ISO New England Inc., as agent for the Obligee, the amounts owed
by the Principal under the Agreements.

The Surety hereby waives notice of any alteration or extension of time made by
the Obligee.

Any suit on this bond must be instituted before the expiration of two (2) years
from the date on which the Principal's obligations under the Agreements expires.

SIGNED, SEALED AND DATED this        day of                               ,
19   .




[Seal]
[Participant]

Principal
By:





[Seal]
[Insurance Company]

Surety
By:





                                  ATTACHMENT 3
                               CORPORATE GUARANTY

     For and in consideration of the credit advance or sale of products on open
account by the New England Power Pool Participants from time to time
("Participants") to [Participant] ("Company"), the undersigned guarantor,
("Guarantor"), the [subsidiary/affiliate] of Company, hereby unconditionally and
irrevocably guarantees the prompt and complete payment of all amounts that
Company now or hereafter owes to Participants under the Restated NEPOOL
Agreement and Restated NEPOOL Open Access Transmission Tariff, [and performance
by Company of any other agreements, whether now existing or hereafter arising,
between Company and Participants], as amended from time to time (collectively
referred to as the "Agreements"), in strict accordance with their respective
terms.

1. If Company does not perform its obligations in strict accordance with the
Agreements, Guarantor shall immediately pay all amounts now or hereafter due
thereunder (including, without limitation, all principal, interest, and fees)
and otherwise proceed to complete the same and satisfy all of Company's
obligations under the Agreements. This Guaranty may be satisfied by Guarantor
paying and/or performing (as appropriate) Company's obligations or by Guarantor
causing Company's obligations to be paid or performed; provided, however, that
Guarantor shall at all times remain fully responsible and liable for its
obligations hereunder notwithstanding any such payment or performance (or
failure thereof) by any third party. Participants will undertake commercially
reasonable efforts to notify Guarantor of a failure by Company to make a payment
or perform its obligations under the Agreements; provided, however, that failure
by Participants to so notify Guarantor shall not defeat, limit or otherwise
affect the rights and obligations of Participants, Company or Guarantor. Subject
to the terms and conditions set forth herein, Guarantor's obligations hereunder
shall not exceed the complete payment of all amounts that Company now or
hereafter owes to Participants under the Restated NEPOOL Agreement and NEPOOL
Open Access Transmission Tariff and performance by Company of the Agreements in
strict accordance with their respective terms.

2. This Guaranty is an absolute, unconditional and continuing guaranty of the
full and punctual payment and performance by Company of each of its obligations
under the Agreements, and not of collectibility only, and is in no way
conditioned upon any requirement that Participants first attempt to collect
payment from Company or any other guarantor or surety or resort to any security
or other means of obtaining payment of all or any part of Company's obligations
or upon any other contingency. This is a continuing guaranty and shall be
binding upon Guarantor until the full, final and irrevocable payment and
performance of all of Company's obligations under the Agreements, regardless of
(i) how long after the date hereof any part of the obligations under the
Agreements is incurred by Company and (ii) the amount of the obligations under
the Agreements at any time outstanding. This Guaranty may be enforced by
Participants from time to time and as often as occasion for such enforcement may
arise.

3. The obligations hereunder are independent of the obligations of Company, and
a separate action or actions may be brought and prosecuted against Guarantor
whether action is brought against Company or whether Company be joined in any
such action or actions. Guarantor's liability under this Guaranty is not
conditioned or contingent upon genuineness, validity, regularity or
enforceability of the Agreements.

4. Guarantor authorizes Participants, without notice or demand and without
affecting its liability hereunder, from time to time to (a) renew, extend, or
otherwise change the terms of the Agreements or any part thereof, (b) take and
hold security for the payment of the Agreements, and exchange, enforce, waive
and release any such security; and (c) apply such security and direct the order
or manner of sale thereof as Participants in their sole discretion may
determine. The obligations and liabilities of Guarantor hereunder shall be
absolute and unconditional, shall not be subject to any counterclaim, set- off,
deduction or defense based upon any claim Guarantor may have against Company,
any other guarantor, or any other person or entity, and shall remain in full
force and effect until all of the obligations hereunder and under the Agreements
have been fully satisfied, without regard to, or release or discharge by, any
event, circumstance or condition (whether or not Guarantor shall have knowledge
or notice thereof) which but for the provisions of this Section might constitute
a legal or equitable defense or discharge of a guarantor or surety or which
might in any way limit recourse against Guarantor, including without limitation:
(a) any amendment or modification of, or supplement to, the terms of the
Agreements; (b) any waiver, consent or indulgence by Participants, or any
exercise or non-exercise by Participants of any right, power or remedy, under or
in respect of this Guaranty or the Agreements (whether or not Guarantor or
Company has or have notice or knowledge of any such action or inaction); (c) the
invalidity or unenforceability, in whole or in part, of the Agreements, or the
termination (except pursuant to its terms or by written agreement between
Participants and Company), cancellation or frustration of any thereof, or any
limitation or cessation of Company's liability under any thereof (other than any
limitation or cessation expressly provided for therein), including without
limitation any invalidity, unenforceability or impaired liability resulting from
Company's lack of capacity, power and/or authority to enter into the Agreements
and/or to incur any or all of the obligations thereunder, or from the execution
and delivery of any Agreement by any person acting for Company without or in
excess of authority (except to the extent the same would limit or cease
Company's liability under the Agreements); (d) any actual, purported or
attempted sale, assignment or other transfer by Participants of any Agreement or
of any of its rights, interests or obligations thereunder; (e) the taking or
holding by Participants of a security interest, lien or other encumbrance in or
on any property as security for any or all of the obligations of Company under
the Agreements or any exchange, release, non- perfection, loss or alteration of,
or any other dealing with, any such security; (f) the addition of any party as a
guarantor or surety of all or any part of the obligations of Company under the
Agreements; (g) any merger, amalgamation or consolidation of Company into or
with any other entity, or any sale, lease, transfer or other disposition of any
or all of Company's assets or any sale, transfer or other disposition of any or
all of the shares of capital stock or other securities of Company to any other
person or entity; (h) any change in the financial condition of Company or (as
applicable) of any subsidiary, affiliate, partner or controlling shareholder
thereof, or Company's entry into an assignment for the benefit of creditors, an
arrangement or any other agreement or procedure for the restructuring of its
liabilities, or Company's insolvency, bankruptcy, reorganization, dissolution,
liquidation or any similar action by or occurrence with respect to Company.

5. Guarantor unconditionally waives, to the fullest extent permitted by law: (a)
notice of any of the matters referred to in Section 4 hereof; (b) any right to
the enforcement, assertion or exercise by Participants of any of their rights,
powers or remedies under, against or with respect to (i) any of the Agreements,
(ii) any other guarantor or surety, or (iii) any security for all or any part of
the obligations of Company under the Agreements or obligations of Guarantor
hereunder; (c) any requirement of diligence and any defense based on a claim of
laches; (d) all defenses which may now or hereafter exist by virtue of any
statute of limitations, or of any stay, valuation, exemption, moratorium or
similar law, except the sole defense of full and indefeasible payment; (e) any
requirement that Guarantor be joined as a party in any action or proceeding
against Company to enforce any of the provisions of the Agreements; (f) any
requirement that Participants mitigate or attempt to mitigate damages resulting
from a default by Guarantor hereunder or from a default by Company under any of
the Agreements; (g) acceptance of this Guaranty by Participants; and (h) all
presentments, protests, notices of dishonor, demands for performance and any and
all other demands upon and notices to Company, and any and all other formalities
of any kind, the omission of or delay in performance of which might but for the
provisions of this Section constitute legal or equitable grounds for relieving
or discharging Guarantor in whole or in part from its irrevocable, absolute and
continuing obligations hereunder, it being the intention of Guarantor that its
obligations hereunder shall not be discharged except by payment and performance
and then only to the extent thereof.

6. Guarantor waives any right to require Participants to (a) proceed against
Company; (b) proceed against or exhaust any security held from Company; or (c)
pursue any other remedy in Participants' power whatsoever. So long as any
obligations remain outstanding under this Guaranty or the Agreements, Guarantor
shall not exercise any rights against Company arising as a result of payment by
Guarantor hereunder, by way of subrogation or otherwise, and will not prove any
claim in competition with Participants or their affiliates in respect of any
payment under the Agreements in bankruptcy or insolvency proceedings of any
nature; Guarantor will not claim any set-off or counterclaim against Company in
respect of any liability of Guarantor to Company and Guarantor waives any
benefit of any right to participate in any collateral which may be held by
Participants or any of their affiliates. Guarantor shall have no right of
subrogation or reimbursement, contribution or other rights against Company.

7. If after receipt of any payment of, or the proceeds of any collateral for,
all or any part of the obligations of Company under the Agreements, Participants
are compelled to surrender or voluntarily surrender such payment or proceeds to
any person because such payment or application of proceeds is or may be avoided,
invalidated, recaptured, or set aside as a preference, fraudulent conveyance,
impermissible setoff or for any other reason, whether or not such surrender is
the result of (i) any judgment, decree or order of any court or administrative
body having jurisdiction over Participants, or (ii) any settlement or compromise
by Participants of any claim as to any of the foregoing with any person
(including Company), then the obligations of Company under the Agreements, or
part thereof affected, shall be reinstated and continue and this Guaranty shall
be reinstated and continue in full force as to such obligations or part thereof
as if such payment or proceeds had not been received, notwithstanding any
previous cancellation of any instrument evidencing any such obligation or any
previous instrument delivered to evidence the satisfaction thereof. The
provisions of this Section shall survive the termination of this Guaranty and
any satisfaction and discharge of Company by virtue of any payment, court order
or any federal or state law until the full, final and irrevocable satisfaction
of all of Company's obligations under the Agreements.

8. Any indebtedness of Company now or hereafter held by Guarantor is hereby
subordinated to any indebtedness of Company to Participants; and such
indebtedness of Company to Guarantor shall be collected, enforced and received
by Guarantor as trustee for Participants and be paid over to Participants on
account of the indebtedness of Company due and owing at any time to Participants
but without reducing or affecting in any manner the liability of Guarantor under
the other provisions of this Guaranty.

9. Guarantor represents and warrants to Participants, as an inducement to
Participants to make the credit advances or sales of products on open account to
Company, that:

a. the execution, delivery and performance by Guarantor of this Guaranty (i) are
within Guarantor's powers and have been duly authorized by all necessary action;
(ii) do not contravene Guarantor's charter documents or any law or any material
contractual restrictions binding on or affecting Guarantor or by which
Guarantor's property may be affected; and (iii) do not require any authorization
or approval or other action by, or any notice to or filing with, any public
authority or any other person except such as have been obtained or made;

b. this Guaranty constitutes the legal, valid and binding obligation of
Guarantor, enforceable in accordance with its terms, except as the
enforceability thereof may be subject to or limited by bankruptcy, insolvency,
reorganization, arrangement, moratorium or other similar laws relating to or
affecting the rights of creditors generally and by general principles of equity;
and

c. there is no action, suit or proceeding affecting Guarantor pending or
threatened before any court, arbitrator, or public authority that may materially
adversely affect Guarantor's ability to perform its obligations under this
Guaranty, except as set forth in writing to the Participants and ISO New England
Inc. prior to Participants' written authorization of this Guaranty.

10. Guarantor shall submit to Participants (i) a current credit rating agency
report regarding Guarantor promptly upon the request of Participants, (ii) a
copy of any Report on Form 8-K promptly after the filing by Guarantor of such
report with the Securities and Exchange Commission, and (iii) a balance sheet,
statement of income and such other financial statements of Guarantor as
Participants shall reasonably request within ten (10) days after such statements
are requested by Participants. Guarantor shall notify Participants in writing
within ten (10) days after a material change in the financial status of
Guarantor. For purposes of this section, a material change in financial status
includes, but is not limited to, the following: (a) a downgrade to a below
investment grade rating in the rating of Guarantor's senior long-term debt by a
major rating agency; (b) the placement of Guarantor on credit watch with
negative implication by a major credit rating agency if Guarantor's senior
long-term debt does not have an investment grade rating; (c) Guarantor's
bankruptcy or insolvency; (d) a report by Guarantor of a significant quarterly
loss or decline in earnings; (e) the resignation of a key officer of Guarantor;
and (e) the filing of a lawsuit that could materially adversely impact
Guarantor's current or future financial results. Guarantor acknowledges that
failure by it to provide the information required hereunder may result in
Participants bringing proceedings to terminate Company from the New England
Power Pool.

11. Guarantor agrees to pay on demand all reasonable attorneys' fees and all
other costs and expenses which may be incurred by Participants in the
enforcement of this Guaranty. No terms or provisions of this Guaranty may be
changed, waived, revoked or amended without Participants' prior written consent.
Should any provision of this Guaranty be determined by a court of competent
jurisdiction to be unenforceable, all of the other provisions shall remain
effective. This Guaranty embodies the entire agreement among the parties hereto
with respect to the matters set forth herein, and supersedes all prior
agreements among the parties with respect to the matters set forth herein. No
course of prior dealing among the parties, no usage of trade, and no parol or
extrinsic evidence of any nature shall be used to supplement, modify or vary any
of the terms hereof. There are no conditions to the full effectiveness of this
Guaranty. Participants may assign this Guaranty without in any way affecting
Guarantor's liability under it, except that Guarantor shall be provided
reasonable notice of any such assignment. This Guaranty shall inure to the
benefit of Participants and their successors and assigns. This Guaranty is in
addition to the guaranties of any other guarantors and any and all other
guaranties of Company's indebtedness or liabilities to Participants.

12. This Guaranty shall be governed by the laws of the State of Connecticut,
without regard to conflicts of laws principles. Guarantor hereby irrevocably
submits to the jurisdiction of any Connecticut State or United States Federal
court sitting in Connecticut over any action or proceeding arising out of or
relating to this Guaranty or any of the Agreements, and Guarantor hereby
irrevocably agrees that all claims in respect of such action or proceeding may
be heard and determined in such Connecticut State or Federal court. Guarantor
irrevocably consents to the service of any and all process in any such action or
proceeding by the mailing of copies of such process to Guarantor at its address
set forth below its signature. Guarantor agrees that a final judgment in any
such action or proceeding shall be conclusive and may be enforced in other
jurisdictions by suit on the judgment or in any other manner provided by law.
Guarantor further waives any objection to venue in such State and any objection
to an action or proceeding in such State on the basis of forum non conveniens.
Guarantor further agrees that any action or proceeding brought against
Participants shall be brought only in Connecticut State or United States Federal
courts sitting in Connecticut. Nothing herein shall affect the right of
Participants to bring any action or proceeding against the Guarantor or its
property in the courts of any other jurisdictions.

13. GUARANTOR ACKNOWLEDGES THAT IT HAS BEEN ADVISED BY COUNSEL OF ITS CHOICE
WITH RESPECT TO THIS GUARANTY AND THAT IT MAKES THE FOLLOWING WAIVERS KNOWINGLY
AND VOLUNTARILY:

a. IRREVOCABLY WAIVES TRIAL BY JURY IN ANY COURT AND IN ANY SUIT, ACTION OR
PROCEEDING OR ANY MATTER ARISING IN CONNECTION WITH OR IN ANY WAY RELATED TO THE
TRANSACTIONS CONTEMPLATED BY THIS GUARANTY, THE AGREEMENTS OR ANY DOCUMENTS
RELATED THERETO (INCLUDING CONTRACT CLAIMS, TORT CLAIMS, BREACH OF DUTY CLAIMS,
AND ALL OTHER COMMON LAW OR STATUTORY CLAIMS) AND THE ENFORCEMENT OF ANY OF
PARTICIPANTS' RIGHTS AND REMEDIES; AND

b. GUARANTOR EXPRESSLY ACKNOWLEDGES THAT THE OBLIGATIONS GUARANTEED HEREBY ARE
PART OF A COMMERCIAL TRANSACTION AS SUCH TERM IS USED AND DEFINED IN CHAPTER
903a OF THE CONNECTICUT GENERAL STATUTES AND VOLUNTARILY AND KNOWINGLY WAIVES
ANY AND ALL RIGHTS WHICH ARE OR MAY BE CONFERRED UPON IT UNDER CHAPTER 903a OF
SAID STATUTES (OR ANY OTHER STATUTE AFFECTING PREJUDGMENT REMEDIES) TO ANY
NOTICE OR HEARING OR PRIOR COURT ORDER OR THE POSTING OF ANY BOND PRIOR TO ANY
PREJUDGMENT REMEDY WHICH PARTICIPANTS MAY USE.

14. Any demand, notice, request, instruction or other communication to be given
hereunder by any party to another party shall be in writing and delivered
personally, by nationally recognized overnight courier, by certified mail,
postage prepaid and return receipt requested, by telegram, or by telecopier, as
follows:

     If to Guarantor, at:




     If to Participants, at:

Communications given by personal delivery or mail shall be effective upon actual
receipt. Communications given by telegram or telecopier shall be effective upon
actual receipt during the recipient's normal business hours, or at the beginning
of the next business day after receipt if not received during the recipient's
normal business hours. All communications by telegram or telecopier shall be
confirmed promptly in writing by certified mail or personal delivery. Any party
may change any address to which communications are to be given by giving notice
as provided above of such change of address.

IN WITNESS WHEREOF, the undersigned Guarantor has executed this Guaranty as of
this day of [month], 199_.

[GUARANTOR]
By:

Title:
     Corporate Officer

Address:






                          ATTACHMENT M
      Financial Assurance Policy for NEPOOL Non-Participant
                      Transmission Customers

This Financial Assurance Policy for Transmission Customers (FN1) that are
Non-Participants ("Policy") shall become effective on January 1, 1999 (the
"Policy Effective Date").

The purpose of this Policy is (i) to establish a financial assurance policy for
Non-Participant Transmission Customers pursuant to Section 11 of the Restated
NEPOOL Open Access Transmission Tariff (the "Tariff") that includes commercially
reasonable credit review procedures to assess the financial ability of each
Non-Participant applicant for service ("Applicant") under the Tariff to pay for
service transactions under the Tariff and under the ISO New England Inc. Tariff
for Transmission Dispatch and Power Administration Services (the "ISO Tariff"),
(ii) to set forth requirements for alternative forms of security that will be
deemed acceptable to NEPOOL and consistent with commercial practices established
by the Uniform Commercial Code that protects the Participants against the risk
of non-payment by Non-Participant Transmission Customers, (iii) to set forth the
conditions under which NEPOOL will conduct business so as to avoid the
possibility of failure of payment for services rendered to Non-Participant
Transmission Customers under the Tariff and the ISO Tariff, and (iv) to collect
amounts past due, make up shortfalls in payments, and terminate service to
defaulting Non-Participant Transmission Customers.


- -------
(FN1)

Capitalized terms used but not defined in this Policy are intended to have the
meanings given to such terms in Section 1 of the Restated NEPOOL Agreement or
Section 1 of the Restated NEPOOL Open Access Transmission Tariff (the "Tariff"),
as amended.


In accordance with Section 11 of the Tariff, NEPOOL requires the following
procedures and requirements to apply to all Applicants and Non-Participant
Transmission Customers. Generally, any Applicant or Non-Participant Transmission
Customer that does not have an investment grade rating by either Standard &
Poor's, Moody's, Duff & Phelps, or Fitch (or in the case of Applicants and
Non-Participant Transmission Customers that are not rated themselves, any
Applicant or Non-Participant Transmission Customer that does not have
outstanding debt with such a rating) will be required to provide financial
assurances, as described in detail below. (FN2)






- ------
(FN2)


The System Operator will act as NEPOOL's agent in managing and enforcing this
Policy with the exception of termination of membership issues, which are
specifically reserved to the NEPOOL Participants and will be addressed by the
NEPOOL Executive Committee Membership Subcommittee, subject to appeal to the
Management Committee. Accordingly, all financial information required pursuant
to this Policy is to be provided to the System Operator, which will keep all
such information confidential in accordance with the provisions of Section 2 of
NEPOOL Criteria, Rules and Standards No. 45.





                              GENERAL REQUIREMENTS

Each Applicant or Non-Participant Transmission Customer must comply with the
following general requirements.

Proof of Financial Viability

Each Applicant must with its application for service submit proof of financial
viability, as described below, satisfying NEPOOL requirements to demonstrate the
Applicant's ability to meet its obligations, or must provide, prior to NEPOOL's
filing of a Service Agreement for the Applicant and provision of service to the
Applicant under the Tariff, financial assurance in the form of a cash deposit,
letter of credit or performance bond as set forth below. An Applicant that
chooses to provide a cash deposit, letter of credit or performance bond will not
be required to provide financial information to NEPOOL.

Generally, each Applicant must submit a current rating agency report, which
report must indicate an investment grade rating by either Standard & Poor's,
Moody's, Duff & Phelps, or Fitch for the Applicant or, if the Applicant itself
is not rated, for the Applicant's outstanding rated debt, in order for NEPOOL to
file a Service Agreement for the Applicant and provide service to the Applicant
under the Tariff without the Applicant being required to furnish additional
financial assurances as described below.

Current Non-Participant Transmission Customers that have not already provided to
NEPOOL financial assurances consistent with the requirements of this Policy must
also provide a current rating agency report by the Policy Effective Date, as
well as any of the financial statements and information set forth below if and
as requested by NEPOOL within ten (10) days of such request. Those
Non-Participant Transmission Customers that do not satisfy the rating
requirement as set forth above must provide instead on the Policy Effective Date
one form of the financial assurances set forth below. A Non- Participant
Transmission Customer's failure to meet these requirements may result in
termination of service by NEPOOL in accordance with the procedure set forth for
payment defaults in Section 8.4 of the Tariff.

Financial Statements

Each Applicant must submit, if and as requested by NEPOOL and within ten (10)
days of such request, audited financial statements for at least the immediately
preceding three years, or the period of its existence, if shorter, including,
but not limited to, the following information:

          Balance Sheets
          Income Statements
          Statements of Cash Flows
          Notes to Financial Statements

Additionally, the following information for at least the immediately preceding
three years, if available, must be submitted if and as requested by NEPOOL and
within ten (10) days of such request:

          Annual and Quarterly Reports
          10-K, 10-Q and 8-K Reports

Where the above financial statements are available on the Internet, the
Applicant may provide instead a letter to NEPOOL stating where such statements
may be located and retrieved by NEPOOL.

Each Applicant may also be required to provide at least one bank reference and
three (3) utility credit references. In those cases where an Applicant does not
have three (3) utility credit references, three (3) trade payable vendor
references may be substituted.

Each Applicant may also be required to include information as to any known or
anticipated material lawsuits, as well as any prior bankruptcy declarations by
the Applicant, or by its predecessor(s), if any.

In the case of certain Applicants, some of the above financial submittals may
not be applicable, and alternate requirements may be specified by NEPOOL.

Ongoing Financial Review

Each Non-Participant Transmission Customer that has not provided a cash deposit,
letter of credit, performance bond, or corporate guaranty must submit its
current rating agency report promptly upon the request of NEPOOL, and 8-K
Reports promptly upon their issuance.

In addition, each Non-Participant Transmission Customer that has not provided a
cash deposit, letter of credit, performance bond or corporate guaranty is
responsible for informing NEPOOL in writing within ten (10) business days of any
material change in its financial status. A material change in financial status
includes, but is not limited to, the following: a downgrade to a below
investment grade rating of senior long term debt by a major rating agency, being
placed on credit watch with negative implication by a major rating agency if
senior long term debt does not have an investment grade rating, a bankruptcy
filing, insolvency, a report of a significant quarterly loss or decline of
earnings, the resignation of key officer(s), and/or the filing of a material
lawsuit that could materially adversely impact current or future financial
results. A Non-Participant Transmission Customer's failure to provide this
information as required may result in termination of service by NEPOOL in
accordance with the procedure set forth in Section 8.4 of the Tariff.

If there is a material adverse change in the financial condition of the Non-
Participant Transmission Customer that has not provided a cash deposit, letter
of credit, performance bond or corporate guaranty, NEPOOL may require such
Non-Participant Transmission Customer to provide one of the forms of other
financial assurances set forth below. If the Non-Participant Transmission
Customer fails to do so, NEPOOL may terminate service in accordance with the
procedure set forth for payment defaults in Section 8.4 of the Tariff.

OTHER FINANCIAL ASSURANCES

Applicants or Non-Participant Transmission Customers that do not satisfy the
rating requirement or NEPOOL's credit review process must submit instead one of
the following additional financial assurances, depending on the specific aspects
of the transactions they anticipate engaging in as Non-Participant Transmission
Customers.

In general, Non-Participant Transmission Customers must provide additional
financial assurance in the following amounts, based on their average or expected
monthly charges for service under the Tariff, including amounts owed to ISO New
England Inc. under the ISO Tariff (collectively the "NEPOOL Charges"):

Monthly NEPOOL Charges                Financial Assurance Requirement

$0 - $15,000                           0 months' NEPOOL Charges
$15,001 - $30,000                      1 month's NEPOOL Charges
$30,001 - $50,000                      2 months' NEPOOL Charges
$50,001 or more                        31/2 months' NEPOOL Charges

The three and one-half months is based on the time required for a FERC filing
made by NEPOOL to suspend service to be effective.

Therefore, a Non-Participant Transmission Customer with $32,000 in monthly
NEPOOL Charges that does not satisfy the rating requirement or NEPOOL credit
review process must provide additional financial assurances in the amount of
$64,000 to NEPOOL.

In the case of new Non-Participant Transmission Customers, the Financial
Assurance Requirement will be based on estimated monthly NEPOOL Charges, which
estimate NEPOOL has the right to adjust in light of subsequent experience as to
actual monthly NEPOOL Charges. In no event will the Financial Assurance
Requirement exceed the anticipated charge for the service requested by the
Non-Participant Transmission Customer.

Cash Deposit

A cash deposit for the full value of the Financial Assurance Requirement based
on actual or anticipated NEPOOL Charges, as determined by NEPOOL, provides an
acceptable form of financial assurance to NEPOOL. A cash deposit greater than or
equal to one month's NEPOOL Charges of a Non-Participant Transmission Customer
shall also serve as that Non-Participant Transmission Customer's deposit under
Sections 31.3 and 41.2 of the Tariff.

If it is necessary to use all or a portion of the deposit to pay the Non-
Participant Transmission Customer's obligation, the deposit must be promptly
replenished to the required level; otherwise, termination of service proceedings
may be initiated. In the event that actual NEPOOL Charges exceed those
anticipated, the anticipated charges will be increased accordingly and the
Non-Participant Transmission Customer must augment its cash deposit to reach the
required level.

The cash deposit will be invested by NEPOOL in investments as may be designated
by the Non-Participant Transmission Customer in direct obligations of the United
States or its agencies and interest earned will be paid to the Non-Participant
Transmission Customer. NEPOOL may sell or otherwise liquidate such investments
at its discretion to meet the Non-Participant Transmission Customer's
obligations to NEPOOL.

The requirement to continue the deposit may be reviewed by NEPOOL after one
year. Consideration will be given to replacing the cash deposit with a corporate
guaranty if certain conditions are met, as discussed below in the Corporate
Guaranty section.

Letter of Credit

An irrevocable standby letter of credit for the full value of the Financial
Assurance Requirement based on actual or anticipated NEPOOL Charges, as
determined by NEPOOL, provides an acceptable form of financial assurance to
NEPOOL. The letter of credit will renew automatically unless the issuing bank
provides notice to NEPOOL at least ninety (90) days prior to the letter of
credit's expiration of the bank's decision not to renew the letter of credit.

If the letter of credit amount falls below the required level because of a
drawing, it must be replenished immediately; otherwise, termination of service
proceedings may be initiated by NEPOOL. If actual NEPOOL Charges exceed those
anticipated, the Non-Participant Transmission Customer must obtain a substitute
letter of credit that equals the actual NEPOOL Charges.

The form, substance, and provider of the letter of credit must all be acceptable
to NEPOOL. The letter of credit should clearly state the full names of the
"Issuer," "Account Party" and "Beneficiary" (NEPOOL), the dollar amount
available for drawings, and should include a statement required on the drawing
certificate and other terms and conditions that should apply. It should also
specify that funds will be disbursed, in accordance with the instructions,
within one (1) business day after due presentation of the drawing certificate.
The bank issuing the letter of credit must have a minimum corporate debt rating
of an "A-" by Standard & Poor's, or "A3" by Moody's, or "A-" by Duff & Phelps,
or "A-" by Fitch, or an equivalent short term debt rating by one of these
agencies.

Please refer to Attachment 1, which provides an example of a generally
acceptable sample "clean" letter of credit. All costs associated with obtaining
financial security and meeting the Policy provisions are the responsibility of
the Applicant or Non-Participant Transmission Customer.

The requirement to continue to provide a letter of credit may be reviewed by
NEPOOL after one year. Consideration will be given to replacing the letter of
credit with a corporate guaranty if certain conditions are met, as discussed
below in the Corporate Guaranty section.

Performance Bond

A performance bond complying with the requirements set forth herein provides an
acceptable form of financial assurance to NEPOOL. The penal sum of such
performance bond shall be in an amount equal to the full value of the Financial
Assurance Requirement based on actual or anticipated NEPOOL Charges, as
determined by NEPOOL, and shall automatically be adjusted to reflect any
adjustment in such Financial Assurance Requirement. The bond shall permit suit
thereunder until two years after the last date that service is provided to the
Non-Participant Transmission Customer under the Tariff.

If the amount of penal sum of the performance bond available to NEPOOL falls
below the required level because of a payment thereon, it must be increased to
the required level immediately; otherwise, termination of service proceedings
may be initiated by NEPOOL. If actual NEPOOL Charges exceed those anticipated,
the Non-Participant Transmission Customer must either cause the penal sum of
such performance bond to be increased accordingly or must obtain a substitute
performance bond in the appropriate amount.

The form, substance and provider of the performance bond must be acceptable to
NEPOOL. The performance bond should clearly state the full names of the
"Principal," the "Surety" and the "Obligee" (NEPOOL) and the penal sum and
should include a clear statement that the surety will promptly and faithfully
perform the Non-Participant Transmission Customer's obligations to NEPOOL if the
Non-Participant Transmission Customer fails to do so. The insurance company
issuing the performance bond must be rated "A" or better by A.M. Best & Co.

Please refer to Attachment 2, which provides an example of a generally
acceptable sample performance bond. All costs associated with obtaining
financial security and meeting the Policy provisions, including without
limitation the cost of the premiums for such performance bond, are the
responsibility of the Applicant or Non-Participant Transmission Customer.

The requirement to continue to provide a performance bond may be reviewed by
NEPOOL after one year. Consideration will given to replacing the performance
bond with a corporate guaranty if certain conditions are met, as discussed below
in the Corporate Guaranty section.

Weekly Payments

A Non-Participant Transmission Customer that does not satisfy the rating
requirement may request that, in lieu of providing one of the additional
financial assurances set forth above, a weekly billing schedule be implemented
for it. NEPOOL may, in its discretion, agree to such a request; provided,
however, that any weekly billing arrangement will terminate no more than six
months after the date on which such arrangement begins unless the
Non-Participant Transmission Customer requests an extension of such arrangement
and demonstrates to NEPOOL's satisfaction in its sole discretion that the
termination of such arrangement and compliance with the other provisions of this
Policy (including providing another form of financial assurance, if required)
will impose a substantial hardship on the Non- Participant Transmission
Customer. Such demonstration of a substantial hardship shall be made every six
months after the initial demonstration, and a Non-Participant Transmission
Customer's weekly billing arrangement will be terminated if it fails to
demonstrate to NEPOOL's satisfaction in its sole discretion at any such six
month interval that compliance with the other provisions of this Policy will
impose a substantial hardship on it.

If NEPOOL agrees to implement a weekly billing schedule for a Non-Participant
Transmission Customer, the Non-Participant Transmission Customer shall be billed
weekly in arrears on an estimated basis for all amounts owed to NEPOOL and the
System Operator for the week, with an adjustment for each month as part of the
regular NEPOOL monthly billing to reflect any under or over collection for the
month. The Non-Participant Transmission Customer shall be obligated to pay each
such weekly bill within five business days after it is received. The
Non-Participant Transmission Customer shall pay with respect to each weekly bill
an administrative fee, determined by the System Operator, to reimburse the
System Operator for the costs it incurs as a result of that Non-Participant
Transmission Customer's weekly billing arrangement.

If a weekly billing schedule is implemented for a Non-Participant Transmission
Customer in lieu of requiring the Non-Participant Transmission Customer to
provide an additional financial assurance, the Non-Participant Transmission
Customer may be required to provide an additional financial assurance at any
time if the Non-Participant Transmission Customer fails to pay when due any
weekly bill or, in its sole discretion, termination of service proceedings may
be initiated by NEPOOL. In addition, upon the termination of a Non-Participant
Transmission Customer's weekly billing arrangement, the Non-Participant
Transmission Customer shall either satisfy the rating requirement set forth
herein or provide one of the other forms of financial assurance set forth
herein.

Use of Transaction Setoffs

Under certain conditions, NEPOOL may be involved in other transactions with a
Non-Participant Transmission Customer in which NEPOOL is the buyer. In this
event, the amount of the prepayment, cash deposit, performance bond or letter of
credit required hereunder may be reduced ("setoff") by an amount equal to
NEPOOL's unpaid balance or expected billing under the other transaction. The
terms and the amount of the setoff must be approved by the System Operator. The
System Operator is responsible for monitoring the status of the setoff and
ensuring that an adequate financial assurance balance is maintained at all times
until the transaction is settled.

Corporate Guaranty

An irrevocable corporate guaranty obtained from a Non-Participant Transmission
Customer's affiliated company ("Guarantor") for the full value of the Financial
Assurance Requirement based on actual or anticipated NEPOOL Charges, as
determined by NEPOOL, may provide an acceptable form of financial assurance to
NEPOOL.

If actual NEPOOL Charges exceed those anticipated, the Non-Participant
Transmission Customer must provide a substitute corporate guaranty that equals
the actual NEPOOL Charges.

A Non-Participant Transmission Customer for which a letter of credit,
performance bond or cash deposit was initially required may have the opportunity
to substitute a corporate guaranty if the following conditions are met:

1.     NEPOOL determines that the Non-Participant Transmission Customer has
satisfactorily met its payment obligations in NEPOOL for at least one year,
which one-year period may in whole or in part pre-date the Policy Effective
Date;

2.     NEPOOL determines that the financial condition of the Guarantor meets the
requirements of this Policy; and

3.     The form and substance of the corporate guaranty are acceptable to
NEPOOL.

Upon NEPOOL's written authorization, the Non-Participant Transmission Customer
may substitute a corporate guaranty that is issued by the Guarantor for a cash
deposit, bank letter of credit or performance bond when it has satisfied the
conditions stipulated above. The corporate guaranty is considered to be a lesser
form of financial assurance than a cash deposit, letter of credit or performance
bond, and therefore is allowed as an acceptable form of financial assurance only
to those Non-Participant Transmission Customers that have satisfied their
payment obligations to NEPOOL in a timely manner for at least one year.

The corporate guaranty may only be used if the Non-Participant Transmission
Customer is affiliated with a Guarantor that has greater financial assets, a
strong balance sheet and income statements, and at minimum an investment grade
rating by either Standard & Poor's, Moody's, Duff & Phelps, or Fitch.

The corporate guaranty should clearly state the identities of the "Guarantor,"
"Beneficiary" and "Obligor," and the relationship between the Guarantor and the
Non-Participant Transmission Customer Obligor. The corporate guaranty must be
duly authorized by the Guarantor, must be signed by an officer of the Guarantor,
and must be furnished with either an opinion satisfactory to NEPOOL of the
Guarantor's counsel with respect to the enforceability of the guaranty or
accompanied by a certificate of corporate guarantee that includes a seal of the
corporation with the signature of the corporate secretary. Additionally,
adequate documentation regarding the signature authority of the person signing
the corporate guaranty must be provided with the corporate guaranty.

A corporate guaranty must also obligate the Guarantor to submit a current rating
agency report promptly upon the request of NEPOOL, to submit 8-K Reports
promptly upon their issuance, to submit financial reports if and as requested by
NEPOOL within ten (10) days of such request, and to inform NEPOOL in writing
within ten (10) business days of any material change in its financial status. A
material change in financial status includes, but is not limited to, the
following: a downgrade to a below investment grade rating of senior long term
debt by a major rating agency, being placed on credit watch with negative
implication by a major rating agency if senior long term debt does not have an
investment grade rating, a bankruptcy filing, insolvency, a report of a
significant quarterly loss or decline of earnings, the resignation of key
officer(s), and/or the filing of a material lawsuit that could materially
adversely impact current or future financial results. A Guarantor's failure to
provide this information may result in proceedings by NEPOOL to terminate
service to the Non-Participant Transmission Customer Obligor. If there is a
material adverse change in the financial condition of the Guarantor, NEPOOL may
require the Non-Participant Transmission Customer Obligor to provide another
form of financial assurance, either a cash deposit or a letter of credit or a
performance bond.

Non-payment of Amounts Due

If a Non-Participant Transmission Customer does not pay amounts billed when due
and as a result a letter of credit or cash deposit is drawn down or a
performance bond is paid on, then the Non-Participant Transmission Customer must
immediately replenish the letter of credit or cash deposit to the required
amount or cause the penal sum of the performance bond to be increased to equal
the required amount plus all amounts paid thereunder. If a Non-Participant
Transmission Customer fails to do so, NEPOOL may initiate termination of service
proceedings against the

Non-Participant Transmission Customer in accordance with the procedure for
payment defaults set forth in Section 8.4 of the Tariff.

In order to encourage prompt payment of NEPOOL Charges by Non-Participant
Transmission Customers, if a Non-Participant Transmission Customer is delinquent
in paying on time its NEPOOL Charges, the Non-Participant Transmission Customer
shall pay interest on any unpaid amount as provided in Section 8.3 of the
Tariff.



                                  ATTACHMENT 1
                             SAMPLE LETTER OF CREDIT

                                                        [DATE PROVIDED]

                 IRREVOCABLE STANDBY LETTER OF CREDIT NO.


[EXPIRATION DATE] AT OUR COUNTERS [unless an evergreen l/c is obtained]

WE DO HEREBY ISSUE AN IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT BY
ORDER OF AND FOR THE ACCOUNT OF ON BEHALF OF [NON- PARTICIPANT TRANSMISSION
CUSTOMER] ("ACCOUNT PARTY") IN FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND
POWER POOL ("NEPOOL") IN AN AMOUNT NOT EXCEEDING US$ .00 (UNITED STATES DOLLARS
AND 00/100) AGAINST PRESENTATION TO US OF A DRAWING CERTIFICATE SIGNED BY A
PURPORTED OFFICER OR AUTHORIZED AGENT OF NEPOOL AND DATED THE DATE OF
PRESENTATION CONTAINING THE FOLLOWING STATEMENT:

"THE UNDERSIGNED HEREBY CERTIFIES TO [BANK] ("BANK"), WITH REFERENCE TO
IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT NO. ISSUED BY [BANK] IN
FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") THAT
[NON-PARTICIPANT TRANSMISSION CUSTOMER] HAS FAILED TO PAY AMOUNTS DUE UNDER THE
RESTATED NEPOOL OPEN ACCESS TRANSMISSION TARIFF OR THE ISO NEW ENGLAND INC.
TARIFF FOR TRANSMISSION DISPATCH AND POWER ADMINISTRATION SERVICES, AND THUS
NEPOOL IS DRAWING UPON THE LETTER OF CREDIT IN AN AMOUNT EQUAL TO $ ."

IF PRESENTATION OF ANY DRAWING CERTIFICATE IS MADE ON A BUSINESS DAY AND SUCH
PRESENTATION IS MADE AT OUR COUNTERS ON OR BEFORE 10:00 A.M. TIME, WE SHALL
SATISFY SUCH DRAWING REQUEST ON THE SAME BUSINESS DAY. IF THE DRAWING
CERTIFICATE IS RECEIVED AT OUR COUNTERS AFTER 10:00 A.M. TIME, WE WILL SATISFY
SUCH DRAWING REQUEST ON THE NEXT BUSINESS DAY, FOR THE PURPOSES OF THIS SECTION,
A BUSINESS DAY MEANS A DAY, OTHER THAN A SATURDAY OR SUNDAY, ON WHICH COMMERCIAL
BANKS ARE NOT AUTHORIZED OR REQUIRED TO BE CLOSED IN NEW YORK, NEW YORK.

DISBURSEMENTS SHALL BE IN ACCORDANCE WITH THE INSTRUCTIONS OF NEPOOL.

THE FOLLOWING TERMS AND CONDITIONS APPLY:

THIS LETTER OF CREDIT SHALL EXPIRE AT THE CLOSE OF BUSINESS [DATE]. WE WILL
PROVIDE NOTICE TO NEPOOL AT LEAST 90 DAYS PRIOR TO SUCH DATE IF THIS LETTER OF
CREDIT WILL NOT BE RENEWED AS OF SUCH DATE [or: THIS LETTER OF CREDIT SHALL
EXPIRE ONLY UPON THE FOLLOWING CONDITIONS: (1) WHEN FULL PAYMENT HAS BEEN
RECEIVED BY NEPOOL FROM [NON-PARTICIPANT TRANSMISSION CUSTOMER] AND (2) NEPOOL
HAS PROVIDED A WRITTEN RELEASE TO THIS BANK .]

THE AMOUNT WHICH MAY BE DRAWN BY YOU UNDER THIS LETTER OF CREDIT SHALL BE
AUTOMATICALLY REDUCED BY THE AMOUNT OF ANY UNREIMBURSED DRAWINGS HEREUNDER AT
OUR COUNTERS. ANY NUMBER OF PARTIAL DRAWINGS ARE PERMITTED FROM TIME TO TIME
HEREUNDER.

ALL COMMISSIONS AND CHARGES WILL BE BORNE BY THE ACCOUNT PARTY.

THIS LETTER OF CREDIT IS NOT TRANSFERABLE OR ASSIGNABLE.

THIS LETTER OF CREDIT DOES NOT INCORPORATE AND SHALL NOT BE DEEMED MODIFIED,
AMENDED OR AMPLIFIED BY REFERENCE TO ANY DOCUMENT, INSTRUMENT OR AGREEMENT (A)
THAT IS REFERRED TO HEREIN (EXCEPT FOR THE UCP, AS DEFINED BELOW) OR (B) IN
WHICH THIS LETTER OF CREDIT IS REFERRED TO OR TO WHICH THIS LETTER OF CREDIT
RELATES.

THIS LETTER OF CREDIT SHALL BE GOVERNED BY THE UNIFORM CUSTOMS AND PRACTICE FOR
DOCUMENTARY CREDITS, 1993 REVISION, INTERNATIONAL CHAMBER OF COMMERCE
PUBLICATION NO. 500 (THE "UCP"), EXCEPT TO THE EXTENT THAT TERMS HEREOF ARE
INCONSISTENT WITH THE PROVISIONS OF THE UCP, INCLUDING BUT NOT LIMITED TO
ARTICLES 13(b) AND 17 OF THE UCP, IN WHICH CASE THE TERMS OF THE LETTER OF
CREDIT SHALL GOVERN.

THIS LETTER OF CREDIT MAY NOT BE AMENDED, CHANGED OR MODIFIED WITHOUT THE
EXPRESS WRITTEN CONSENT OF NEPOOL AND US.

WE HEREBY ENGAGE WITH YOU THAT DOCUMENTS DRAWN UNDER AND IN COMPLIANCE WITH THE
TERMS OF THIS LETTER OF CREDIT SHALL BE DULY HONORED UPON PRESENTATION AS
SPECIFIED.

PRESENTATION OF ANY DRAWING CERTIFICATE UNDER THIS STANDBY LETTER OF CREDIT MAY
BE SENT TO US BY COURIER, CERTIFIED MAIL, REGISTERED MAIL, TELEGRAM, TELEX TO
THE ADDRESS SET FORTH BELOW, OR SUCH OTHER ADDRESS AS MAY HEREAFTER BE FURNISHED
BY US. OTHER NOTICES CONCERNING THIS STANDBY LETTER OF CREDIT MAY BE SENT BY
FACSIMILE OR SIMILAR COMMUNICATIONS FACILITY TO THE RESPECTIVE ADDRESSES SET
FORTH BELOW. ALL SUCH NOTICES AND COMMUNICATIONS SHALL BE EFFECTIVE WHEN
ACTUALLY RECEIVED BY THE INTENDED RECIPIENT PARTY.

IF TO THE BENEFICIARY OF THIS LETTER OF CREDIT:


IF TO THE ACCOUNT PARTY:



IF TO US:




[signature]

[signature]




                                  ATTACHMENT 2

                               SAMPLE PERFORMANCE BOND

                                 [Insurance Company]



Bond No.

KNOW ALL MEN BY THESE PRESENTS, That the undersigned [Non-Participant
Transmission Customer], of [Non-Participant Transmission Customer's address]
hereinafter referred to as the Principal, and [insurance company], a corporation
organized and existing under the laws of the State of [insurance company's state
of incorporation], as Surety, are held and firmly bound unto the Participants in
the New England Power Pool as obligees, hereinafter referred to collectively as
the Obligee, in the sum of , lawful money of the United States of America (which
sum shall automatically be adjusted to reflect any adjustment in the Financial
Assurance Requirement applicable to the Principal under the New England Power
Pool's Financial Assurance Policy for NEPOOL Non-Participant Transmission
Customers, as in effect from time to time) for the payment of which sum, well
and truly to be made, we bind ourselves, our executors, administrators,
successors, and assigns, jointly and severally, firmly by these presents.

WHEREAS, the Principal has entered into agreements for the purchase and sale of
electric services under the Restated NEPOOL Open Access Transmission Tariff and
the ISO New England Inc. Tariff for Transmission Dispatch and Power
Administration Services, each as amended from time to time (collectively
referred to as the "Agreements"), and in strict accordance with their respective
terms.

NOW, THEREFORE, the condition of this obligation is such, that if the Principal
shall promptly and faithfully make the payments required by, and comply with
terms of, the Agreements which have been or may hereafter be in force and shall
save and keep harmless the Obligee from all loss or damage which it may sustain
or for which it may become liable on account of the issuance of said Agreements
to the Principal, then this obligation shall be void; otherwise, it shall remain
in full force and effect.

Upon notice from ISO New England Inc. of nonpayment by the Principal, Surety
will pay to ISO New England Inc., as agent for the Obligee, the amounts owed
by the Principal under the Agreements.

The Surety hereby waives notice of any alteration or extension of time made by
the Obligee.

Any suit on this bond must be instituted before the expiration of two (2) years
from the date on which the Principal's obligations under the Agreements expires.

SIGNED, SEALED AND DATED this        day of                               ,
19  .




[Seal]
[Non-Participant Transmission Customer]

Principal
By:





[Seal]
[Insurance Company]

Surety
By:






                                  ATTACHMENT 3
                               CORPORATE GUARANTY

     For and in consideration of the credit advance or sale of products on open
account by the New England Power Pool Participants from time to time
("Participants") to [Non-Participant Transmission Customer] ("Company"), the
undersigned guarantor, ("Guarantor"), the [subsidiary/affiliate] of Company,
hereby unconditionally and irrevocably guarantees the prompt and complete
payment of all amounts that Company now or hereafter owes to Participants under
the Restated NEPOOL Open Access Transmission Tariff (the "Tariff") and the ISO
New England Inc. Tariff for Transmission Dispatch and Power Administration
Services (the "ISO Tariff"), and performance by Company of any other agreements,
whether now existing or hereafter arising, between Company and Participants, as
amended from time to time (collectively referred to as the "Agreements"), in
strict accordance with their respective terms.

1. If Company does not perform its obligations in strict accordance with the
Agreements, Guarantor shall immediately pay all amounts now or hereafter due
thereunder (including, without limitation, all principal, interest, and fees)
and otherwise proceed to complete the same and satisfy all of Company's
obligations under the Agreements. This Guaranty may be satisfied by Guarantor
paying and/or performing (as appropriate) Company's obligations or by Guarantor
causing Company's obligations to be paid or performed; provided, however, that
Guarantor shall at all times remain fully responsible and liable for its
obligations hereunder notwithstanding any such payment or performance (or
failure thereof) by any third party. Participants will undertake commercially
reasonable efforts to notify Guarantor of a failure by Company to make a payment
or perform its obligations under the Agreements; provided, however, that failure
by Participants to so notify Guarantor shall not defeat, limit or otherwise
affect the rights and obligations of Participants, Company or Guarantor. Subject
to the terms and conditions set forth herein, Guarantor's obligations hereunder
shall not exceed the complete payment of all amounts that Company now or
hereafter owes to Participants under the Agreements and performance by Company
of the Agreements in strict accordance with their respective terms.

2. This Guaranty is an absolute, unconditional and continuing guaranty of the
full and punctual payment and performance by Company of each of its obligations
under the Agreements, and not of collectibility only, and is in no way
conditioned upon any requirement that Participants first attempt to collect
payment from Company or any other guarantor or surety or resort to any security
or other means of obtaining payment of all or any part of Company's obligations
or upon any other contingency. This is a continuing guaranty and shall be
binding upon Guarantor until the full, final and irrevocable payment and
performance of all of Company's obligations under the Agreements, regardless of
(i) how long after the date hereof any part of the obligations under the
Agreements is incurred by Company and (ii) the amount of the obligations under
the Agreements at any time outstanding. This Guaranty may be enforced by
Participants from time to time and as often as occasion for such enforcement may
arise.

3. The obligations hereunder are independent of the obligations of Company, and
a separate action or actions may be brought and prosecuted against Guarantor
whether action is brought against Company or whether Company be joined in any
such action or actions. Guarantor's liability under this Guaranty is not
conditioned or contingent upon genuineness, validity, regularity or
enforceability of the Agreements.

4. Guarantor authorizes Participants, without notice or demand and without
affecting its liability hereunder, from time to time to (a) renew, extend, or
otherwise change the terms of the Agreements or any part thereof, (b) take and
hold security for the payment of the Agreements, and exchange, enforce, waive
and release any such security; and (c) apply such security and direct the order
or manner of sale thereof as Participants in their sole discretion may
determine. The obligations and liabilities of Guarantor hereunder shall be
absolute and unconditional, shall not be subject to any counterclaim, set-off,
deduction or defense based upon any claim Guarantor may have against Company,
any other guarantor, or any other person or entity, and shall remain in full
force and effect until all of the obligations hereunder and under the Agreements
have been fully satisfied, without regard to, or release or discharge by, any
event, circumstance or condition (whether or not Guarantor shall have knowledge
or notice thereof) which but for the provisions of this Section might constitute
a legal or equitable defense or discharge of a guarantor or surety or which
might in any way limit recourse against Guarantor, including without limitation:
(a) any amendment or modification of, or supplement to, the terms of the
Agreements; (b) any waiver, consent or indulgence by Participants, or any
exercise or non-exercise by Participants of any right, power or remedy, under or
in respect of this Guaranty or the Agreements (whether or not Guarantor or
Company has or have notice or knowledge of any such action or inaction); (c) the
invalidity or unenforceability, in whole or in part, of the Agreements, or the
termination (except pursuant to its terms or by written agreement between
Participants and Company), cancellation or frustration of any thereof, or any
limitation or cessation of Company's liability under any thereof (other than any
limitation or cessation expressly provided for therein), including without
limitation any invalidity, unenforceability or impaired liability resulting from
Company's lack of capacity, power and/or authority to enter into the Agreements
and/or to incur any or all of the obligations thereunder, or from the execution
and delivery of any Agreement by any person acting for Company without or in
excess of authority (except to the extent the same would limit or cease
Company's liability under the Agreements); (d) any actual, purported or
attempted sale, assignment or other transfer by Participants of any Agreement or
of any of its rights, interests or obligations thereunder; (e) the taking or
holding by Participants of a security interest, lien or other encumbrance in or
on any property as security for any or all of the obligations of Company under
the Agreements or any exchange, release, non-perfection, loss or alteration of,
or any other dealing with, any such security; (f) the addition of any party as a
guarantor or surety of all or any part of the obligations of Company under the
Agreements; (g) any merger, amalgamation or consolidation of Company into or
with any other entity, or any sale, lease, transfer or other disposition of any
or all of Company's assets or any sale, transfer or other disposition of any or
all of the shares of capital stock or other securities of Company to any other
person or entity; (h) any change in the financial condition of Company or (as
applicable) of any subsidiary, affiliate, partner or controlling shareholder
thereof, or Company's entry into an assignment for the benefit of creditors, an
arrangement or any other agreement or procedure for the restructuring of its
liabilities, or Company's insolvency, bankruptcy, reorganization, dissolution,
liquidation or any similar action by or occurrence with respect to Company.

5. Guarantor unconditionally waives, to the fullest extent permitted by law: (a)
notice of any of the matters referred to in Section 4 hereof; (b) any right to
the enforcement, assertion or exercise by Participants of any of their rights,
powers or remedies under, against or with respect to (i) any of the Agreements,
(ii) any other guarantor or surety, or (iii) any security for all or any part of
the obligations of Company under the Agreements or obligations of Guarantor
hereunder; (c) any requirement of diligence and any defense based on a claim of
laches; (d) all defenses which may now or hereafter exist by virtue of any
statute of limitations, or of any stay, valuation, exemption, moratorium or
similar law, except the sole defense of full and indefeasible payment; (e) any
requirement that Guarantor be joined as a party in any action or proceeding
against Company to enforce any of the provisions of the Agreements; (f) any
requirement that Participants mitigate or attempt to mitigate damages resulting
from a default by Guarantor hereunder or from a default by Company under any of
the Agreements; (g) acceptance of this Guaranty by Participants; and (h) all
presentments, protests, notices of dishonor, demands for performance and any and
all other demands upon and notices to Company, and any and all other formalities
of any kind, the omission of or delay in performance of which might but for the
provisions of this Section constitute legal or equitable grounds for relieving
or discharging Guarantor in whole or in part from its irrevocable, absolute and
continuing obligations hereunder, it being the intention of Guarantor that its
obligations hereunder shall not be discharged except by payment and performance
and then only to the extent thereof.

6. Guarantor waives any right to require Participants to (a) proceed against
Company; (b) proceed against or exhaust any security held from Company; or (c)
pursue any other remedy in Participants' power whatsoever. So long as any
obligations remain outstanding under this Guaranty or the Agreements, Guarantor
shall not exercise any rights against Company arising as a result of payment by
Guarantor hereunder, by way of subrogation or otherwise, and will not prove any
claim in competition with Participants or their affiliates in respect of any
payment under the Agreements in bankruptcy or insolvency proceedings of any
nature; Guarantor will not claim any set-off or counterclaim against Company in
respect of any liability of Guarantor to Company and Guarantor waives any
benefit of any right to participate in any collateral which may be held by
Participants or any of their affiliates. Guarantor shall have no right of
subrogation or reimbursement, contribution or other rights against Company.

7. If after receipt of any payment of, or the proceeds of any collateral for,
all or any part of the obligations of Company under the Agreements, Participants
are compelled to surrender or voluntarily surrender such payment or proceeds to
any person because such payment or application of proceeds is or may be avoided,
invalidated, recaptured, or set aside as a preference, fraudulent conveyance,
impermissible setoff or for any other reason, whether or not such surrender is
the result of (i) any judgment, decree or order of any court or administrative
body having jurisdiction over Participants, or (ii) any settlement or compromise
by Participants of any claim as to any of the foregoing with any person
(including Company), then the obligations of Company under the Agreements, or
part thereof affected, shall be reinstated and continue and this Guaranty shall
be reinstated and continue in full force as to such obligations or part thereof
as if such payment or proceeds had not been received, notwithstanding any
previous cancellation of any instrument evidencing any such obligation or any
previous instrument delivered to evidence the satisfaction thereof. The
provisions of this Section shall survive the termination of this Guaranty and
any satisfaction and discharge of Company by virtue of any payment, court order
or any federal or state law until the full, final and irrevocable satisfaction
of all of Company's obligations under the Agreements.

8. Any indebtedness of Company now or hereafter held by Guarantor is hereby
subordinated to any indebtedness of Company to Participants; and such
indebtedness of Company to Guarantor shall be collected, enforced and received
by Guarantor as trustee for Participants and be paid over to Participants on
account of the indebtedness of Company due and owing at any time to Participants
but without reducing or affecting in any manner the liability of Guarantor under
the other provisions of this Guaranty.

9.     Guarantor represents and warrants to Participants, as an inducement to
Participants to make the credit advances or sales of products on open account
to Company, that:

a. the execution, delivery and performance by Guarantor of this Guaranty (i) are
within Guarantor's powers and have been duly authorized by all necessary action;
(ii) do not contravene Guarantor's charter documents or any law or any material
contractual restrictions binding on or affecting Guarantor or by which
Guarantor's property may be affected; and (iii) do not require any authorization
or approval or other action by, or any notice to or filing with, any public
authority or any other person except such as have been obtained or made;

b. this Guaranty constitutes the legal, valid and binding obligation of
Guarantor, enforceable in accordance with its terms, except as the
enforceability thereof may be subject to or limited by bankruptcy, insolvency,
reorganization, arrangement, moratorium or other similar laws relating to or
affecting the rights of creditors generally and by general principles of equity;
and

c. there is no action, suit or proceeding affecting Guarantor pending or
threatened before any court, arbitrator, or public authority that may materially
adversely affect Guarantor's ability to perform its obligations under this
Guaranty, except as set forth in writing to the Participants and ISO New England
Inc. prior to Participants' written authorization of this Guaranty.

10. Guarantor shall submit to Participants (i) a current credit rating agency
report regarding Guarantor promptly upon the request of Participants, (ii) a
copy of any Report on Form 8-K promptly after the filing by Guarantor of such
report with the Securities and Exchange Commission, and (iii) a balance sheet,
statement of income and such other financial statements of Guarantor as
Participants shall reasonably request within ten (10) days after such statements
are requested by Participants. Guarantor shall notify Participants in writing
within ten (10) days after a material change in the financial status of
Guarantor. For purposes of this section, a material change in financial status
includes, but is not limited to, the following: (a) a downgrade to a below
investment grade rating in the rating of Guarantor's senior long-term debt by a
major rating agency; (b) the placement of Guarantor on credit watch with
negative implication by a major credit rating agency if Guarantor's senior
long-term debt does not have an investment grade rating; (c) Guarantor's
bankruptcy or insolvency; (d) a report by Guarantor of a significant quarterly
loss or decline in earnings; (e) the resignation of a key officer of Guarantor;
and (e) the filing of a lawsuit that could materially adversely impact
Guarantor's current or future financial results. Guarantor acknowledges that
failure by it to provide the information required hereunder may result in
Participants bringing proceedings to terminate service to Company in accordance
with the procedure set forth for payment defaults in Section 8.4 of the Tariff.

11. Guarantor agrees to pay on demand all reasonable attorneys' fees and all
other costs and expenses which may be incurred by Participants in the
enforcement of this Guaranty. No terms or provisions of this Guaranty may be
changed, waived, revoked or amended without Participants' prior written consent.
Should any provision of this Guaranty be determined by a court of competent
jurisdiction to be unenforceable, all of the other provisions shall remain
effective. This Guaranty embodies the entire agreement among the parties hereto
with respect to the matters set forth herein, and supersedes all prior
agreements among the parties with respect to the matters set forth herein. No
course of prior dealing among the parties, no usage of trade, and no parol or
extrinsic evidence of any nature shall be used to supplement, modify or vary any
of the terms hereof. There are no conditions to the full effectiveness of this
Guaranty. Participants may assign this Guaranty without in any way affecting
Guarantor's liability under it, except that Guarantor shall be provided
reasonable notice of any such assignment. This Guaranty shall inure to the
benefit of Participants and their successors and assigns. This Guaranty is in
addition to the guaranties of any other guarantors and any and all other
guaranties of Company's indebtedness or liabilities to Participants.

12. This Guaranty shall be governed by the laws of the State of Connecticut,
without regard to conflicts of laws principles. Guarantor hereby irrevocably
submits to the jurisdiction of any Connecticut State or United States Federal
court sitting in Connecticut over any action or proceeding arising out of or
relating to this Guaranty or any of the Agreements, and Guarantor hereby
irrevocably agrees that all claims in respect of such action or proceeding may
be heard and determined in such Connecticut State or Federal court. Guarantor
irrevocably consents to the service of any and all process in any such action or
proceeding by the mailing of copies of such process to Guarantor at its address
set forth below its signature. Guarantor agrees that a final judgment in any
such action or proceeding shall be conclusive and may be enforced in other
jurisdictions by suit on the judgment or in any other manner provided by law.
Guarantor further waives any objection to venue in such State and any objection
to an action or proceeding in such State on the basis of forum non conveniens.
Guarantor further agrees that any action or proceeding brought against
Participants shall be brought only in Connecticut State or United States Federal
courts sitting in Connecticut. Nothing herein shall affect the right of
Participants to bring any action or proceeding against the Guarantor or its
property in the courts of any other jurisdictions.

13. GUARANTOR ACKNOWLEDGES THAT IT HAS BEEN ADVISED BY COUNSEL OF ITS CHOICE
WITH RESPECT TO THIS GUARANTY AND THAT IT MAKES THE FOLLOWING WAIVERS KNOWINGLY
AND VOLUNTARILY:

a. GUARANTOR IRREVOCABLY WAIVES TRIAL BY JURY IN ANY COURT AND IN ANY SUIT,
ACTION OR PROCEEDING OR ANY MATTER ARISING IN CONNECTION WITH OR IN ANY WAY
RELATED TO THE TRANSACTIONS CONTEMPLATED BY THIS GUARANTY, THE AGREEMENTS OR ANY
DOCUMENTS RELATED THERETO (INCLUDING CONTRACT CLAIMS, TORT CLAIMS, BREACH OF
DUTY CLAIMS, AND ALL OTHER COMMON LAW OR STATUTORY CLAIMS) AND THE ENFORCEMENT
OF ANY OF PARTICIPANTS' RIGHTS AND REMEDIES; AND

b. GUARANTOR EXPRESSLY ACKNOWLEDGES THAT THE OBLIGATIONS GUARANTEED HEREBY ARE
PART OF A COMMERCIAL TRANSACTION AS SUCH TERM IS USED AND DEFINED IN CHAPTER
903a OF THE CONNECTICUT GENERAL STATUTES AND VOLUNTARILY AND KNOWINGLY WAIVES
ANY AND ALL RIGHTS WHICH ARE OR MAY BE CONFERRED UPON IT UNDER CHAPTER 903a OF
SAID STATUTES (OR ANY OTHER STATUTE AFFECTING PREJUDGMENT REMEDIES) TO ANY
NOTICE OR HEARING OR PRIOR COURT ORDER OR THE POSTING OF ANY BOND PRIOR TO ANY
PREJUDGMENT REMEDY WHICH PARTICIPANTS MAY USE.

14. Any demand, notice, request, instruction or other communication to be given
hereunder by any party to another party shall be in writing and delivered
personally, by nationally recognized overnight courier, by certified mail,
postage prepaid and return receipt requested, by telegram, or by telecopier, as
follows:

     If to Guarantor, at:



     If to Participants, at:






     Communications given by personal delivery or mail shall be effective upon
actual receipt. Communications given by telegram or telecopier shall be
effective upon actual receipt during the recipient's normal business hours, or
at the beginning of the next business day after receipt if not received during
the recipient's normal business hours. All communications by telegram or
telecopier shall be confirmed promptly in writing by certified mail or personal
delivery. Any party may change any address to which communications are to be
given by giving notice as provided above of such change of address.

     IN WITNESS WHEREOF, the undersigned Guarantor has executed this Guaranty as
of this day of [month], 199_.

[GUARANTOR]

By:

Title:

     Corporate Officer
Address:








                                  ATTACHMENT N

                      New England Power Pool Billing Policy

This New England Power Pool ("NEPOOL") Billing Policy (the "Policy") shall
become effective on the later of (i) the Second Effective Date or (ii) the
date that is sixty (60) days after the filing of this Policy with the Federal
Energy Regulatory Commission. (FN1)

SECTION 1 - OVERVIEW

Section 1.1 - Scope. The objective of this Policy is to define the billing and
payment procedures to be utilized in administering charges and payments due
under the NEPOOL Agreement, the NEPOOL Tariff, the Interim Independent System
Operator Agreement (the "Interim ISO Agreement") between NEPOOL and ISO New
England Inc. (the "ISO"), the Amended and Restated Independent System Operator
Agreement between NEPOOL and the ISO, when such agreement becomes effective (the
"Amended ISO Agreement" and together with the Interim ISO Agreement, the "ISO
Agreement"), and the ISO's Tariff for Transmission Dispatch and Power
Administration Services (the "ISO Tariff"), in each case as amended, modified,
supplemented and restated from time to time (collectively, the
"Documents").(FN2) This Policy applies to the ISO, the NEPOOL Participants and
Non-Participant Transmission Customers for billing and payments procedures for
amounts due under the Documents, including without limitation those procedures
related to the seven markets administered by the ISO.

- ------
(FN1) Capitalized terms used but not defined in this Policy are intended to have
the meanings given to such terms in Section 1 of the Restated NEPOOL Agreement
(the "NEPOOL Agreement") or Section 1 of the Restated NEPOOL Open Access
Transmission Tariff (the "NEPOOL Tariff"), in each case as amended from time to
time.

(FN2) Unless otherwise stated herein, the ISO will act as NEPOOL's agent in
administering, managing and enforcing this Policy.




Section 1.2 - Financial Transaction Conventions. The following conventions have
been adopted in defining sums of money to be paid or received under this Policy:

a) The term "Charge" refers to a sum of money due from a Participant or a
Non-Participant Transmission Customer to the ISO, either in its individual
capacity or as billing agent for the Participants.

b) The term "Payment" refers to a sum of money due to a Participant or
Non-Participant Transmission Customer from the ISO, as remitting agent for the
Participants. Amounts due to and from the ISO include amounts collected and paid
by the ISO as billing agent for the Participants.

c) Where a Participant's or a Non-Participant Transmission Customer's total
Charges exceed its total Payments in a month, the ISO shall issue an "Invoice"
for the net Charge owed by such Participant or Non-Participant Transmission
Customer.

d) Where a Participant's or a Non-Participant Transmission Customer's total
Payments exceed its total Charges in a month, the ISO shall issue a "Remittance
Advice" for the net Payment owed to the Participant or Non- Participant
Transmission Customer. Invoices and Remittance Advices are collectively referred
to herein as "Statements."

Section 1.3 - General Process. The billing process is performed monthly, except
in the case of (i) Participants and Non-Participant Transmission Customers who
have requested and received a weekly billing schedule in accordance with the
Financial Assurance Policy for NEPOOL Members or the Financial Assurance Policy
for NEPOOL Non-Participant Transmission Customers (collectively, the "Financial
Assurance Policies") and (ii) special billings, as described below. There are
two major steps in the billing process:

a) Statement Issuance. The ISO will issue an Invoice or Remittance Advice
showing the net amounts due from or owed to a Participant or a Non- Participant
Transmission Customer for the preceding calendar month. This Statement is
determined from the preliminary statements of the seven markets, applicable
Charges due under the Documents (including amounts due under the Financial
Assurance Policies), as well as any monthly adjustments. This Statement is
normally issued not earlier than the fifth (5th) Business Day nor later than the
fifteenth (15th) day after the end of the calendar month to which such Statement
relates.

b) Electronic Funds Transfer ("EFT"). EFTs related to Invoices and Remittance
Advices are performed in a two-step process, as described below, in which all
Invoices are paid first and all Remittance Advices are paid within two Business
Days later.

Section 1.4 - Special Billings. In addition to the regular monthly billing, the
ISO will issue special, extraordinary Statements as and when required under the
Documents or in order to adjust for special circumstances. Such Statements shall
be payable in accordance with the instructions set forth therein.

Section 1.5 - Conflicts with Documents. To the extent any provision hereof
conflicts with any provision of any Document, the provision in the Document
shall govern.

SECTION 2 - TIMING AND CONTENT OF STATEMENTS.

Section 2.1 - Normal Billing Cycle. The ISO shall provide to each Participant
and Non-Participant Transmission Customer on a monthly basis one Statement for
the previous calendar month or the portion thereof capable of being settled. The
ISO shall issue the Statement typically not earlier than the fifth (5th)
Business Day nor later than the fifteenth (15th) day following the end of the
calendar month to which such Statement relates (although nothing set forth
herein shall prohibit the ISO from issuing Statements between the first and
fifth Business Days of a month). If the Statement is not issued by the 15th day
of a month, the ISO shall delay the relevant funds transfer dates as described
below.

Section 2.2 - Provisions for Weekly Billing. The ISO shall implement any weekly
billing arrangements effected under the Financial Assurance Policies in
accordance therewith and with the procedures set forth below.

Section 2.3 - Contents of Statements. Each Statement will include all of the
following line items that are applicable to the Participant or Non- Participant
Transmission Customer receiving such Statement for the month to which such
Statement relates:

a) Invoice or Remittance Advice Amount. The net amount of all Charges and
Payments owed by or due to a Participant or a Non-Participant Transmission
Customer for the relevant Statement. The ISO shall issue an Invoice where the
Participant or Non-Participant Transmission Customer owes monies. The ISO shall
issue a Remittance Advice where the Participant or Non-Participant Transmission
Customer is owed monies.

b)     NEPOOL Tariff Charges and Payments. The Charges owed by and the Payments
owed to the Participant or Non-Participant Transmission Customer under the
NEPOOL Tariff.

c) ISO Tariff Charges. The Charges owed by the Participant or Non-Participant
Transmission Customer under the ISO Tariff, categorized by the section or
schedule under which such Charges arise.

d)     Markets Charges and Payments. The Charges owed by and the Payments owed
to the Participant as a result of transactions in each of the seven markets
administered by the ISO.

e)     NEPOOL Expenses.  The Participant's pro-rata share of Pool fees and
expenses as set forth in Section 19 of the NEPOOL Agreement.

f)     Sanctions Charges. Any Charges assessed on the Participant pursuant to
Market Rule 13, the so-called Sanctions Rule.

g) Other Amounts due under the NEPOOL Agreement and the ISO Agreement. The
Charges owed by or the Payments owed to the Participant under the NEPOOL
Agreement and the ISO Agreement to the extent that those amounts are not
included in items (b) - (f) above.

h) Other Charges, Payments or Adjustments. Any other Charges, Payments, or
adjustments owed by or to the Participant or Non-Participant Transmission
Customer that are not included in items (b) - (g) above. These items may be due
to retroactive billing adjustments, late payment fees, penalties or other items
collectible under the Documents.

i)     Billing Periods. The billing period (from and to dates) covered for each
line item on the Statement. The billing periods for the various line items are
not necessarily the same because of differences in timing of settlements (e.g.
the ICAP market may be two months in arrears while hourly markets may be one
month in arrears) and because of retroactive adjustments.

j)     Payment Due Date and Time. If the Statement is an Invoice, the date and
time on which the net amount due is to be received by the ISO.

k) Wire Transfer Instructions. Details including the account number, bank name,
routing number and electronic transfer instructions which, in the case of an
Invoice, will be for the ISO account to which Charges owed by the Participant or
Non-Participant Transmission Customer are to be paid or, in the case of a
Remittance Advice, will be for the Participant's or Non- Participant
Transmission Customer's account to which the ISO shall remit Payments owed to
that Participant or Non-Participant Transmission Customer (as previously
provided to the ISO by such Participant or Non-Participant Transmission
Customer).

A sample Invoice is attached hereto as Attachment 1. A sample Remittance Advice
is attached hereto as Attachment 2.

Section 2.4 - Subsequent Adjustments to Previously Issued Statements.

a) Adjustments Requested by Participants. Participants supplying Network Load
and other input data to the ISO for use by the ISO in developing Statements
shall use reasonable care to assure that the data supplied is complete and
accurate. Should a Participant supplying input data subsequently determine that
the data supplied was incorrect, that Participant shall notify the ISO promptly
of the error and submit corrected data as soon as practicable. If the error is
detected and corrected data is provided within the time frames set forth below,
the ISO will issue corrected Statements to reflect the newly supplied data.

Type of Adjustment                             Corrected Data Must be
                                                 Submitted Within

Adjustments to Monthly                      Three (3) months from the
Network Load Submissions                    date the subject Statement
                                            for that calendar month is
                                            issued

Adjustments to EHV                          Three (3) months from the
and LV PTF Percentages for                  effective date of the
PTF Billing of Excepted                     modification to an
Transactions Submissions                    entitlement receiving EHV and
                                            LV PTF billing

Adjustments to                              Three (3) months after the
Annual Average                              annual average Network Load
Network Load                                for the current NEPOOL Tariff
(12CP) Submissions                          year has been developed

Adjustments to Annual Revenue              Three (3) months after the
Requirement Submissions                    applicable RNS rate has been
                                           established

Adjustments to                             Three (3) months after the
Annual NEPOOL Schedule 1                   applicable annual Schedule 1
Submissions                                rate has been established


If the data correction is not submitted within the applicable time frame set
forth above, the obligation of the ISO to issue corrected Statements reflecting
that adjustment shall be as set forth in a written re-billing protocol approved
by the Transmission Settlement Sub-committee (or such other NEPOOL committee as
the NEPOOL Participants Committee may determine) and posted on the ISO web-site.
The re-billing protocol shall provide, for each category of adjustment listed
above, whether and to what extent the adjustment shall be prospective or
retroactive and the timing of the adjustment. If the corrected data is not
submitted within the applicable time frame, the ISO may assess each Participant
submitting corrected data on an untimely basis its costs in generating and
issuing the corrected Statement. The written re-billing protocol shall include a
fee schedule for this purpose.

b) Adjustments Triggered by ISO Audit. The ISO will review the results of
internal and outsourced audits with the Transmission Settlement Subcommittee, or
such other NEPOOL committee as the NEPOOL Participants Committee may determine.
That Subcommittee, or other designated committee, will determine whether any
errors found are sufficiently significant to require a re- billing. The
reasonable costs to the ISO of the re-billing shall be allocated to Schedule 1
of the ISO Tariff.

c) Adjustments Reflecting Compliance with an Order of the Commission or other
Regulatory or Judicial Authority With Jurisdiction. Adjustments required to
effect compliance with an order of the Commission (or any other regulatory or
judicial authority with jurisdiction to interpret and/or enforce the provisions
of the Documents) shall be completed by the ISO in compliance with such order.
The costs of any such re-billing to the ISO shall be allocated among the NEPOOL
Participants in accordance with the provisions of Section 19.2 of the Restated
NEPOOL Agreement.



SECTION 3 - PAYMENT PROCEDURES.

All Payments made by the ISO will in all instances be made by EFT or in
immediately available funds payable to the account designated to the ISO by the
Participant or Non-Participant Transmission Customer to which such Payment is
due. Payments made by Participants or Non-Participant Transmission Customers
shall be made by EFT to the account designated by the ISO.

Section 3.1 - Invoice Payments.

a) Payment Date. Except in the case of weekly billings and special billings, all
Charges due shall be paid to and received by the ISO not later than the first
(1st) Business Day after the nineteenth (19th) day of the calendar month in
which the subject invoice was issued; provided, however, that if the Invoice is
issued on or after the sixteenth (16th) day of the calendar month, the payment
on that Invoice shall be due on the fourth (4th) Business Day after the Invoice
is issued; and provided further that a Non- Participant Transmission Customer
will in no event be required to make a payment on an Invoice any sooner than
provided in Section 8.2 of the NEPOOL Tariff.

b) Right to Alter Payment Date. The ISO may alter the dates on which payments
are due in the case of special billings and Participants and Non-Participant
Transmission Customers that are on weekly billing schedules in accordance with
the Financial Assurance Policies; provided, however, that (i) payment on any
Invoice shall not be due prior to the fourth (4th) Business Day after the
Invoice is issued, and (ii) a Non-Participant Transmission Customer shall not be
required to make a payment on an Invoice any sooner than provided in Section 8.2
of the NEPOOL Tariff.

c) Payments Received by ISO. Each Participant or Non-Participant Transmission
Customer owing monies shall remit the amount shown on its Invoice no later than
the date such payment is due. Disputed amounts shall be paid in accordance with
clause (d) below.

d) Payments Pending Resolution of a Dispute. Any Participant or Non- Participant
Transmission Customer that disputes the amount due on any Invoice for service
other than transmission service under the NEPOOL Tariff shall pay to the ISO all
amounts due on such Invoice, including those in dispute. Such payment shall in
no way prejudice the right of such Participant or Non- Participant Transmission
Customer to seek reimbursement of such disputed amounts, including accrued
interest on such amounts at the Commission's standard rate, set forth in 18
C.F.R. Section 35.19, pursuant to the Billing Dispute Resolution Procedures
provided in Section 5 below.

Any Participant or Non-Participant Transmission Customer that disputes the
amount due on any Invoice for transmission service under the NEPOOL Tariff shall
pay to the ISO all amounts not in dispute and shall pay the amount in dispute
into an independent escrow account designated by the ISO, which account shall be
established at a banking institution acceptable to the ISO and the Participant
or Non-Participant Transmission Customer challenging the amount due and shall
accrue interest at a prevailing market rate. Such amount in dispute shall be
held in escrow pending the resolution of such dispute in accordance with the
applicable Document(s). To the extent that the amount in dispute would be
payable to one or more identifiable Participants (but not to the ISO), then the
amount due to each such Participant in the billing period to which such dispute
relates shall be reduced by the portion of the total amount in dispute that
would be payable to such Participant, subject to payment with interest accrued
thereon if and when the dispute is resolved in favor of such Participant(s). To
the extent that the amount in dispute would be payable to the ISO, or the
specific Participant(s) to which such amount would be payable cannot be
identified, then the shortfall of funds available to pay Remittance Advices
resulting from the amount in dispute being held in an escrow account shall be
allocated among the Participants according to the two-step allocation process
described in Section 3.3(e) below, subject to payment to all such Participants
being allocated a portion of the shortfall, with applicable interest (if any),
once the dispute is resolved with the funds in such escrow account or with other
amounts provided by the Participant or Non-Participant Transmission Customer
losing such dispute.

Section 3.2 - ISO Payment of Remittance Advice Amounts. The Payment Date for
Remittance Advices shall be the second (2nd) Business Day after the date on
which Invoices are due in such month.

Section 3.3 - Payment Default. If the ISO, in its reasonable opinion, believes
that all or any part of any amount due to be paid by any Participant or
Non-Participant Transmission Customer will not or has not been paid when due
(other than in the case of a payment dispute) (the "Default Amount"), then the
following procedures shall apply:

a) ISO Charges Paid First. The ISO shall use monies received by it from
Participants and Non-Participant Transmission Customers to pay all amounts due
to the ISO under the ISO Tariff and ISO Agreement before making any payments to
any Participants or Non-Participant Transmission Customers.

b) Use of Set-Offs. The ISO shall use any and all rights of set-off it has under
the Documents and this Policy against a defaulting Participant or a
Non-Participant Transmission Customer to the extent necessary to pay the Default
Amount, together with any interest accrued thereon and any late charges assessed
under the Documents and the Financial Assurance Policies, due from such
Participant or Non-Participant Transmission Customer.

c) Enforcing the Security of a Defaulting Party. If and to the extent that the
procedure described in clause (b) above is insufficient to effect payment of the
Default Amount and all interest accrued thereon and late charges assessed under
the Documents and the Financial Assurance Policies, the ISO shall use the
financial assurance(s) provided by the Participant or Non- Participant
Transmission Customer under the Financial Assurance Policies to the extent
necessary to pay the Default Amount and such interest and late charges. Any use
of financial assurance(s) shall be undertaken in compliance with the Financial
Assurance Policies.

d) Action Against a Defaulting Party. If and to the extent that the procedures
described in clauses (b) and (c) above are insufficient to effect payment of the
Default Amount and all interest accrued thereon and late charges assessed under
the Documents and the Financial Assurance Policies, the ISO shall take
appropriate actions to recover the Default Amount and such accrued interest and
late charges, which actions may include, without limitation, initiating
proceedings in accordance with the appropriate dispute resolution mechanisms or
actions with NEPOOL or before the Federal Energy Regulatory Commission or a
court of competent jurisdiction against the defaulting Participant or
Non-Participant Transmission Customer. Prior to the commencement of any such
action or proceeding with respect to amounts due to Participants, the ISO shall
obtain the approval of the NEPOOL Executive Committee or its designee and shall
offer to the NEPOOL Executive Committee or its designee an opportunity to be
involved in such action or proceeding. Any amounts incurred by the ISO or any
Participant in connection with any such action or proceeding shall be paid by
the defaulting Participant or Non- Participant Transmission Customer.

e)  Reduction of Payments and Increases in Charges.

(i) If and to the extent that the procedures described in clauses (b), (c) and
(d) above do not yield sufficient funds to pay all Remittance Advice amounts in
full (after payment of amounts due to the ISO in accordance with clause (a)
above) on the date such Payments are due, the ISO shall reduce Payments to those
Participants owed monies for that billing period (the "Default Period"), pro
rata based on the amounts owed to such Participants, to the extent necessary to
clear its accounts by the close of banking business on the date such Payments
are due. As funds attributable to a Default Amount are received by the ISO
(including amounts received through financial assurances provided under the
Financial Assurance Policies or through actions or proceedings commenced against
the defaulting Participant or Non-Participant Transmission Customer) prior to
the next billing period's Statements being distributed, such funds, together
with any interest and late charges collected on the applicable Default Amount,
shall be distributed pro rata to the Participants that did not receive the full
amount of their Payments as a result of such Default Amount not being paid.

(ii) To the extent that any amount remains unpaid to Participants on the date
that Statements are distributed to Participants in the billing period
immediately following the Default Period, the Default Amount remaining unpaid
shall be reallocated among all of the Participants receiving Statements for the
Default Period (other than the Participant or Non-Participant Transmission
Customer defaulting on its payment obligations), pro rata based, for each
Participant being allocated a share of the Default Amount remaining unpaid, on
the sum of (i) all Charges due from such Participant that are reflected on its
Statement for the Default Period and (ii) all Payments due to such Participant
that are reflected on its Statement for the Default Period, without giving any
effect to the process of netting Charges against Payments on each Statement that
is the result of the ISO's single billing system. Thus, by way of example, a
Participant with $2,000 of Charges and no Payments on its Statement for the
Default Period and a Participant with $1,000 of Charges and $1,000 of Payments
on its Statement for the Default Period would be allocated an equal share of the
unpaid Default Amount under this clause (e)(ii). Each Participant that received
a Statement for the Default Period shall have the amount of its Invoice or
Remittance Advice in the billing period immediately following the Default Period
adjusted as necessary to reflect its obligation for the Default Amount remaining
unpaid under this clause (e)(ii). As funds attributable to a Default Amount are
received by the ISO (including amounts received through financial assurances
provided under the Financial Assurance Policies or through actions or
proceedings commenced against the defaulting Participant or Non-Participant
Transmission Customer) after such adjusted Statements are distributed, such
funds, together with any interest and late charges collected on the applicable
Default Amount, shall be distributed to the Participants pro rata based on their
allocation of the Default Amount under this clause (e)(ii).

f) Other Rights Against Defaulting Parties. Nothing set forth in this Policy
shall nullify, restrict or otherwise limit the rights and remedies of the ISO
and the Participants against a defaulting Participant or Non-Participant
Transmission Customer that are set forth in the Documents, the Financial
Assurance Policies or otherwise, including without limitation any late payment
charges or rights to terminate or limit trading rights of the defaulting
Participant, to the extent such rights and remedies otherwise exist.

g) Set-Off. The ISO shall apply any amount to which any defaulting Participant
or Non-Participant Transmission Customer is or will be entitled toward the
satisfaction of any of that defaulting Participant's or Non- Participant
Transmission Customer's debts to the ISO or the Participants which are incurred
under the Documents or the Financial Assurance Policies.

h) Order of Settlement. As amounts on Default Amounts are received by the ISO,
the oldest outstanding amount will be settled first in the order of the creation
of such debts.

i) Notification of Payment Default. Without limiting any of the other remedies
described above, in the event that the ISO, in its reasonable opinion, believes
that all or any part of any amount due to be paid by any Participant or any
Non-Participant Transmission Customer will not be or has not been paid within 10
days of when due (a "Payment Default"), the ISO (on its own behalf or on behalf
of NEPOOL) may (but shall not be required to) notify such Participant or
Non-Participant Transmission Customer in writing, electronically and by first
class mail sent in each case to such Participant's member or alternate on the
Participants Committee or billing contact (it being understood that the ISO will
use reasonable efforts to contact all three) or such Non-Participant
Transmission Customer's billing contact, of such Payment Default. Either
simultaneously with the giving of the notice described in the preceding sentence
or within ten days thereafter (unless the Payment Default giving rise to such
notice is cured during such period), the ISO shall notify each other member and
alternate on the NEPOOL Participants Committee and each Participant's billing
contact of the identity of the Participant or Non-Participant Transmission
Customer receiving such notice, whether such notice relates to a Payment Default
and the actions the ISO plans to take and/or has taken in response to such
Payment Default. Section 3.4 - Bankruptcy Filings. In the event any Participant
or Non- Participant Transmission Customer files a voluntary or involuntary
petition in bankruptcy or commences a proceeding under the United States
Bankruptcy Code or any other applicable law concerning insolvency,
reorganization or bankruptcy by or against such Participant or Non-Participant
Transmission Customer as debtor (the "Bankruptcy Event") and the ISO is required
to return any payments made by such Participant or Non-Participant Transmission
Customer to the bankruptcy court having jurisdiction over such Bankruptcy Event,
the ISO may avail itself of any emergency funding provisions in the ISO
Agreement to collect the amounts returned by the ISO.

SECTION 4 - WEEKLY BILLING PRINCIPLES.

The ISO shall administer weekly billing arrangements according to the following
principles:

Section 4.1 - Weekly Invoices. The ISO shall issue an Invoice each Friday to
each Participant and Non-Participant Transmission Customer for which a weekly
billing arrangement has been established to the extent such Participant's or
Non-Participant Transmission Customer's Charges exceed the Payments due to it
for the current calendar week. Remittance Advices for such Participants will
still be issued monthly, in accordance with the procedures set forth above.

Section 4.2 - Basis for Billing. The amounts for each market (except the
Installed Capability market), and all other amounts due from such Participant or
Non-Participant Transmission Customer shall be based on estimates derived by
pro-rating the most recent final monthly Statements issued for such Participant
or Non-Participant Transmission Customer. For the Installed Capability market,
the weekly amount billed for Capability Responsibility shall be based on
estimates derived by pro-rating the most recent preliminary report of the
Participant's position in the Installed Capability market.

Section 4.3 - Payment Date and Time. Each Participant or Non-Participant
Transmission Customer receiving such a weekly Invoice shall remit the amount
shown on its Invoice no later than five (5) Business Days after the date the
Invoice is issued.

Section 4.4 - Monthly Reconciliation. In connection with each monthly billing
cycle, the ISO shall reconcile the sum of the weekly Invoices issued with the
normal monthly billing quantities calculated for the Participant or
Non-Participant Transmission Customer. The ISO shall perform a true-up of any
amounts owed or due on the following weekly Statements.

SECTION 5 - BILLING DISPUTE PROCEDURES.

Section 5.1 - Requested Billing Adjustments Eligible for Resolution under
Billing Dispute Procedures. Any Participant or Non-Participant Transmission
Customer may dispute the amount due on any fully paid monthly Invoice and/or any
amount believed to be due or owed on a Remittance Advice (a "Disputed Amount").
Such party (a "Disputing Party") shall seek to recover such Disputed Amount,
including accrued interest, pursuant to this Section 5, by first submitting a
request for billing adjustment to the ISO (a "Requested Billing Adjustment" or
"RBA") in accordance with the procedures provided in this Section 5 and Market
Rule 18. A Disputing Party may seek resolution of a Requested Billing Adjustment
under this Section 5 concerning any Disputed Amount resulting from the
determination of a market clearing price, NEPOOL Tariff and/or ISO Tariff rate
by the ISO that allegedly either violates or is otherwise inconsistent with the
NEPOOL Tariff, ISO Tariff or the Market Rules, or results from error by the ISO.
Notwithstanding the foregoing, a Requested Billing Adjustment must involve a
requested change in an amount owed or believed to be owed in a Remittance Advice
that is not covered by another alternative dispute resolution procedure under
the NEPOOL Tariff, the ISO Tariff, the Interim ISO Agreement or the Market
Rules. Furthermore, a Requested Billing Adjustment must not involve Disputed
Amounts paid on a weekly Invoice pursuant to the Financial Assurance Policies,
provided, however, that this provision shall not preclude a Disputing Party from
submitting a Requested Billing Adjustment for a Disputed Amount on a fully paid
monthly Invoice which has been paid pursuant to a weekly Invoice in that month.

Section 5.2 - Effect of this Policy on Rights of Participant or Non- Participant
Transmission Customer with Respect to a Disputed Amount. Except as otherwise set
forth in this Section 5.2, nothing in this Section 5 shall in any way abridge
the right of any Participant or Non-Participant Transmission Customer to seek
legal or equitable relief under the Federal Power Act and/or any other
applicable laws with respect to any Disputed Amount. Prior to commencing a
proceeding before the Commission or other regulatory or judicial authority with
jurisdiction to resolve the dispute which is the subject of the Requested
Billing Adjustment, the Disputing Party must first submit the Requested Billing
Adjustment to the ISO for review pursuant to Section 5.3 of this Policy.

Section 5.3 - ISO Review of Requested Billing Adjustment.

Section 5.3.1 - Submission of Requested Billing Adjustment to ISO; Required
Contents of Requested Billing Adjustment. A Disputing Party shall submit a
Requested Billing Adjustment in writing to the chief financial officer of the
ISO. In its Requested Billing Adjustment, the Disputing Party must specify the
Disputed Amount at issue and specify the instance of alleged error at issue,
including a statement detailing the specific provisions of all applicable
governing documents that support the Requested Billing Adjustment. The Disputing
Party also must state the relief being requested and identify a specific person
or persons to whom all communications to the Disputing Party regarding the
Requested Billing Adjustment are to be addressed. A Disputing Party must submit
its Requested Billing Adjustment within 3 months of the date that the Invoice or
Remittance Advice containing the Disputed Amount was issued by the ISO unless
the Disputing Party could not have reasonably known of the existence of the
alleged error within such time.

Section 5.3.2 - Notice of ISO Review of Requested Billing Adjustment. Within
three (3) Business Days of the receipt by the ISO's Chief Financial Officer of a
Requested Billing Adjustment, the ISO shall prepare and submit to the Secretary
of the Participants Committee for distribution by the Secretary to all
Participants and Non-Participant Transmission Customers a notice of the
Requested Billing Adjustment ("Notice of RBA"), including, subject to the
protection of Confidential Information, the specifics of the Requested Billing
Adjustment. The Notice of RBA shall identify a specific representative of the
ISO to whom all communications regarding the Requested Billing Adjustment are to
be sent. The Secretary of the Participants Committee shall distribute the Notice
of RBA to all Participants and Non- Participant Transmission Customers by no
later than 5:00 p.m. on the next business day after receiving the Notice of RBA
from the ISO.

Section 5.3.3 - ISO Review of Requested Billing Adjustments. The ISO shall
complete its review of a Requested Billing Adjustment received pursuant to
Section 5.3 within twenty (20) business days of the date the Secretary of the
Participants Committee distributes the Notice of RBA. To the extent that either
party makes such a request and both parties agree to such request, the ISO and
Disputing Party may meet or otherwise confer during this period in an effort to
resolve the Requested Billing Adjustment.

Section 5.3.4 - Comment Period. Any Participant or Non-Participant Transmission
Customer, which desires to do so may submit to the ISO's designated
representative, on or before the tenth (10th) Business Day following the date
the Secretary of the Participants Committee distributes the Notice of RBA,
written comments to the ISO with respect to the Requested Billing Adjustment.
Any such comments are to be transmitted simultaneously to the Disputing Party.
The Disputing Party may respond to any such comments by submitting a written
response to the ISO's designated representative and to the commenting party on
or before the fifteenth (15th) Business Day following the date the Secretary of
the Participants Committee distributes the Notice of RBA. In determining the
action it will take with respect to the Requested Billing Adjustment, the ISO
shall consider the written response filed by the Disputing Party. The ISO may
but is not required to consider any written comments that are filed by any other
interested party.

Section 5.3.5 - ISO Action on Requested Billing Adjustment. The ISO shall
provide to the Disputing Party a written decision (the "RBA Decision") accepting
or denying a Requested Billing Adjustment received pursuant to Section 5.3
within twenty (20) Business Days of the date the Secretary of the Participants
Committee distributes the Notice of RBA, unless some later date is agreed upon
by the Disputing Party and the ISO. The ISO shall provide written notice and a
copy of each RBA Decision to each Participant or Non- Participant Transmission
Customer either eligible for reimbursement, denied reimbursement of a Disputed
Amount or required to provide reimbursement of a Disputed Amount because of an
RBA Decision (hereafter referred to as an "Affected Party" or the "Affected
Parties") within five (5) business days of the date the RBA Decision is
rendered. In providing such notice to any Affected Party required to provide
reimbursement of a Disputed Amount, the ISO shall specify the amount to be
reimbursed by such Affected Party and the calculations supporting the
determination of such reimbursement amount. Subsequent to the provision of the
written notice of the RBA Decision as set forth above, the ISO shall provide
each Affected Party with respect to that RBA Decision a monthly report of the
status of such RBA Decision within the dispute resolution process set forth in
this Section 5 of the Billing Policy, including a statement of the accounting
treatment of the disputed amount owed by or to that Affected Party with respect
to that RBA Decision in accordance with the most recent decision issued pursuant
to Sections 5.3.6 or 5.4 of this Billing Policy, whichever applies, with respect
to that RBA Decision. For purposes of Section 5 of this Policy, the term
"Affected Parties" shall also include the Disputing Party.

Section 5.3.6 - Finality of ISO Action on Requested Billing Adjustment. Except
as otherwise provided in this Section 5.3.6, the RBA Decision shall become final
and binding on the Affected Parties and shall not be appealable in any forum on
the twenty-first (21st) Business Day after the notice of the specific RBA
Decision at issue was provided to the Affected Parties as set forth in Section
5.3.5 above. The RBA Decision shall not become final or binding if, on or before
the twentieth (20th) Business Day after the notice of the specific RBA Decision
at issue was provided to the Affected Parties as set forth in Section 5.3.5
above, an Affected Party or Parties has appealed the RBA Decision by commencing
a proceeding before the Commission or other regulatory or judicial authority
with jurisdiction over the dispute, or has filed an appeal pursuant to Section
5.4 of this Policy. If a proceeding is commenced before the Commission or other
regulatory or judicial authority with jurisdiction over the dispute, the
Affected Party commencing that proceeding shall simultaneously transmit a copy
of their initial pleading in that proceeding to the ISO's designated
representative for that particular RBA Decision, and shall also submit to the
ISO's designated representative for that particular RBA a copy of the final
order or decision in that proceeding resolving the dispute. If any such appeal
is filed pursuant to Section 5.4 of this Policy, the RBA Decision shall have no
force or effect unless or until it is affirmed or upheld upon completion of the
appeal process selected by the Affected Party and as provided for in this
Policy.

Section 5.4 - Right of Affected Party to Review of ISO RBA Decision by AAA.

Section 5.4.1 - Right to Further Review. Any Affected Party may seek review of
an RBA Decision by an independent third party neutral by submitting, on or
before the twentieth (20th) Business Day after the notice of the specific RBA
Decision at issue was provided to the Affected Parties as set forth in Section
5.3.5 above, a request for arbitration of the Requested Billing Adjustment with
the American Arbitration Association ("AAA"). At the same time that it submits
its request to the AAA, the Affected Party commencing any such review of an RBA
Decision shall transmit its request for arbitration: (i) to the ISO's designated
representative for that particular RBA Decision; (ii) to each of the Affected
Parties; and, (iii) to the Secretary of the Participants Committee. The ISO and
any Affected Party shall be joined as parties to the arbitration. NEPOOL shall
be permitted to intervene in the arbitration if it desires to do so.

Section 5.4.2 - Finality of the AAA Neutral's Decision. Except as otherwise
provided in this Section 5.4.2, the written, final decision of the AAA neutral
(the "Neutral's Decision") shall become final and binding on the Affected
Parties, including the ISO, and shall not be appealable in any forum on the
twenty-first (21st) Business Day after the date on which the Neutral's Decision
was issued. The Neutral's Decision shall not become final or binding if on or
before the twentieth (20th) business day after the date on which the Neutral's
Decision was issued, an Affected Party or Parties or the ISO has appealed the
Neutral's Decision by commencing a proceeding before the Commission or other
regulatory or judicial authority with jurisdiction over the dispute. If any such
appeal is filed, the Neutral's Decision shall have no force or effect unless or
until it is affirmed or upheld upon completion of the appeal process.

Section 5.5 - Access to Confidential Information. Information that is deemed
confidential pursuant to the NEPOOL Information Policy in the possession,
custody or control of the ISO concerning the dollar amount in Invoices or
Remittance Advices issued by the ISO ("Confidential Information") shall be made
available under these Billing Dispute Procedures only to "Dispute
Representatives" as defined herein who have executed a confidentiality agreement
in accordance both with this Section 5.5 and the NEPOOL Information Policy
("Confidentiality Agreement"). A copy of the executed Confidentiality Agreement
for a Dispute Representative shall be provided to the ISO prior to the
disclosure of any Confidential Information to said Dispute Representative.
Confidential Information shall not be disclosed to anyone other than in
accordance with this Section 5.5, and shall be used only in connection with the
Billing Dispute Procedures provided under Section 5.

a) Potential Disputing Parties' Right of Access to Confidential Information. A
Participant or Non-Participant Transmission Customer that is a potential
Disputing Party is entitled to obtain access to Confidential Information for its
Dispute Representative, if and only if, it can demonstrate to the ISO that such
access is required to determine if it has a substantive basis for filing a
Requested Billing Adjustment with the ISO. Such demonstration by a potential
Disputing Party, at a minimum, shall include: the information submitted to the
chief financial officer of the ISO required in Section 5.3.1; and, why lack of
access to Confidential Information prevents the potential Disputing Party from
determining if it has a substantive basis for filing such a Requested Billing
Adjustment. A potential Disputing Party shall submit a request for access to
Confidential Information in writing to the ISO (an "Information Request"). The
ISO shall evaluate and respond to such an Information Request within ten (10)
days of the receipt of the Information Request, and where the need for access to
Confidential Information is demonstrated in accordance with the above, shall
provide access to such Confidential Information within fifteen (15) days of the
receipt of the Information Request.

b) Affected Parties Right of Access to Confidential Information. If the RBA
Decision is submitted to the AAA for resolution pursuant to Section 5.4, then
for purposes of that AAA proceeding a Participant or Non-Participant
Transmission Customer that is an Affected Party is entitled to obtain access to
Confidential Information for its Dispute Representative if, and only if, it can
demonstrate to the AAA Neutral that such access is required to protect its
financial interests with respect to review of an RBA Decision pending before the
Neutral. An Affected Party shall submit a request for access to Confidential
Information concerning an RBA Decision within the timeframes established by the
Neutral. The Neutral shall have the authority to enter such orders as may be
necessary to protect the Confidential Information, in accordance with applicable
NEPOOL policies including but not limited to the NEPOOL Information Policy.

c) Dispute Representatives. Dispute Representatives shall be limited to the AAA
Neutral(s), Participants, Non-Participant Transmission Customers, and third
parties retained by and/or in-house legal counsel of the AAA, Participants or
Non-Participant Transmission Customers, provided, however, that Confidential
Information may not be disclosed to a Dispute Representative to the extent the
disclosure is prohibited by Order 889. A Dispute Representative may disclose
Confidential Information to any other Dispute Representative as long as the
disclosing Dispute Representative and the receiving Dispute Representative each
have executed a Confidentiality Agreement. In the event that any Dispute
Representative to whom Confidential Information is disclosed ceases to be
engaged in a matter under these Billing Dispute Procedures, or is no longer
qualified to be a Dispute Representative under this Section, access to
Confidential Information by that person, or persons, shall be terminated and all
such Confidential Information received by that party shall be returned to the
ISO or destroyed to the satisfaction of the ISO. Even if no longer engaged as a
Dispute Representative under this Section, every person who has executed the
Confidentiality Agreement set forth below shall continue to be bound by the
provisions of this Section and such Confidentiality Agreement. All Dispute
Representatives are responsible for ensuring that persons under their
supervision or control comply with this Section and the Confidentiality
Agreement.


Re:     Requested Billing Adjustment ______________

          CONFIDENTIALITY AND NONDISCLOSURE AGREEMENT

The ISO ("Provider") agrees to make available, pursuant to Section 5 of the
NEPOOL Billing Policy, to ("Recipient") confidential and proprietary information
("Confidential Information") relevant to resolution of Requested Billing
Adjustment and any appeals thereof as provided for in said Section 5.

1.     Any information provided to Recipient and labeled "Confidential
Information" by Provider shall be Confidential Information subject to this
Agreement.

2.     The Confidential Information is received by Recipient in confidence.

3. The Confidential Information shall not be used or disclosed by the Recipient
except in accordance with the terms contained herein, with Section 5 of the
NEPOOL Billing Policy and with the NEPOOL Information Policy.

4. Only individuals who are Dispute Representatives as that term is defined in
Section 5 of the NEPOOL Billing Policy, and not entities, may be Recipients of
Confidential Information under this paragraph. By executing this Agreement, each
Recipient certifies that he/she meets the requirements of this Agreement.

5.     The following conditions shall apply to each Recipient:

a. Each Recipient will receive one (1) numbered, controlled copy of the
Confidential Information. The Recipient shall not make any copies thereof or
provide the Confidential Information to any individual or entity except one who
has executed and delivered an Agreement identical to this Agreement to the
Provider.

b.     The Recipient shall maintain a log of all persons granted access to the
Confidential Information.

c. The Recipient, by signing this Agreement acknowledges that he/she may not in
any manner disclose the Confidential Information to any person, and that he/she
may not use the Confidential Information for the benefit of any person except in
this proceeding and in accordance with the terms of this Agreement, Section 5 of
the NEPOOL Billing Policy and the NEPOOL Information Policy.

d.     The Recipient acknowledges that any violation of this Agreement may
subject the Recipient to civil actions for violation hereof.

e. Within thirty (30) days of the final decision issued with respect to the
Requested Billing Adjustment terminating all appeals with respect to this
Requested Billing Adjustment, Recipient shall return the Confidential
Information to Provider.

PROVIDER:                          RECIPIENT:

By:                                By:

Dated:                             Dated:

d) Maintenance of Confidential Information. All copies of all documents and
materials containing Confidential Information shall be maintained by Dispute
Representatives at all times in a secure place in sealed envelopes or other
appropriate containers endorsed to the effect that they are sealed pursuant to
this Section. Such documents and material shall be marked PROTECTED CONFIDENTIAL
INFORMATION and shall be maintained under seal and provided only to Dispute
Representatives as are authorized to examine and inspect such Confidential
Informational. Dispute Representatives shall provide to the ISO a list of those
persons under the supervision and/or control of the Dispute Representative who
are entitled to receive Confidential Information. Dispute Representatives shall
take all reasonable precautions to ensure that Confidential Information is not
distributed to unauthorized persons.

e) ISO Right to Object to Access to Confidential Information. Nothing in this
Section shall be construed as precluding the ISO from objecting to providing any
party access to Confidential Information on any legal grounds other than those
provided under the NEPOOL Information Policy, the NEPOOL Agreement, and/or the
Interim ISO Agreement, as they may be amended time to time.

Section 5.6 - Transition Rules. Any Disputed Amount raised with the ISO between
the Second Effective Date and the effective date of these Billing Dispute
Procedures that is unresolved as of the effective date of these Billing Dispute
Procedures as determined by the Commission shall be submitted for resolution
under these Billing Dispute Procedures as specified below. Disputed Amounts so
referred shall be termed "Pre-Existing Disputes".

a) Review of Pre-Existing Disputes. On or before the thirtieth (30th) calendar
day after the date of the Commission's order accepting this Section 5 of the
Billing Policy, the Disputing Party in a Pre-Existing Dispute shall submit to
the ISO a Request for Billing Adjustment. All parties to Pre- Existing Disputes
shall be entitled to access to Confidential Information subject to the rights
and obligations provided with respect to Confidential Information in Section 5.5
above. If a Request for Billing Adjustment with respect to a Pre-Existing
Dispute is not submitted in accordance with this Section 5.6(a), the
Pre-Existing Dispute shall be deemed resolved for purposes of this Billing
Policy and Section 21.2 of the Restated NEPOOL Agreement .

b) Release of Amounts in Escrow for Pre-Existing Disputes Other than Disputes
Involving Transmission Service Under the Tariff. All amounts at issue in a
Pre-Existing Dispute held in escrow, except for amounts at issue in a
Pre-Existing Dispute concerning amounts due with respect to transmission service
under the NEPOOL Tariff, pursuant to the provisions of Section 3.1(d) of the
NEPOOL Billing Policy and Section 21.2(c) of the NEPOOL Agreement in effect
immediately prior to the effective date of this Section 5 of the NEPOOL Billing
Policy (together, the "Former Escrow Provisions") shall be released from escrow
to the payee upon satisfaction of the following two conditions: (1) thirty (30)
calendar days have elapsed since the date of the Commission's Order accepting
this Billing Policy; and, (2) the ISO has determined that the required Financial
Assurances under this Section 5 of the Billing Policy and the relevant
provisions of Attachment L to the NEPOOL Tariff have been satisfied with respect
to the amount at issue in the Dispute. If a Participant that has received from
one or more other Participants or Non-Participant Transmission Customers an
amount the payment of which is the subject of a dispute, an amount equal to 100%
of such amount in dispute shall be included in determining that Participant's
overall financial assurance requirement and the relevant provisions of
Attachment L to the NEPOOL Tariff shall apply.

c) Release of Amounts in Escrow With Respect to Disputes Concerning Transmission
Service Under the Tariff. If the Pre-Existing Dispute concerns amounts due on
any Invoice for transmission service under the NEPOOL Tariff, any amounts held
in escrow with respect to such Pre-Existing Dispute shall remain in escrow and
shall accrue interest at a prevailing market rate. Such amount in dispute shall
be held in escrow pending the resolution of such dispute in accordance with the
applicable Document(s). To the extent that the amount in dispute would be
payable to one or more identifiable Participants (but not to the ISO), then the
amount due to each such Participant in the billing period to which such dispute
relates shall be reduced by the portion of the total amount in dispute that
would be payable to such Participant, subject to payment with interest accrued
thereon if and when the dispute is resolved in favor of such Participant(s). To
the extent that the amount in dispute would be payable to the ISO, or the
specific Participant(s) to which such amount would be payable cannot be
identified, then the shortfall of funds available to pay Remittance Advices
resulting from the amount in dispute being held in an escrow account shall be
allocated among the Participants according to the two-step allocation process
described in Section 3.3(e) below, subject to payment to all such Participants
being allocated a portion of the shortfall, with applicable interest (if any),
once the dispute is resolved with the funds in such escrow account or with other
amounts provided by the Participant or Non-Participant Transmission Customer
losing such dispute.





                                                            Attachment 1

                                 SAMPLE INVOICE
                               See attached pages




                            [Form of Sample Invoice]









                                                                Attachment 2



                            SAMPLE REMITTANCE ADVICE


                               See attached pages










                       [Form of Sample Remittance Advice]








                  Sheet Nos. 457-500 are reserved for future use.






                         ANCILLARY SERVICE SCHEDULE 1
                SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE
                               IMPLEMENTATION RULE

This rule provides detail with respect to the calculation of the rate surcharge
each year for Scheduling, System Control and Dispatch Service, which is defined
in the Tariff as the service required to schedule the movement of power through,
out of, within, or into the NEPOOL Control Area over Pool Transmission
Facilities ("PTF"). This service also includes the dispatch and security
analysis of the system. Scheduling, System Control and Dispatch Service for
transmission service over transmission facilities other than PTF is provided
under the Local Network Service Tariffs of the individual Transmission
Providers. For transmission service under the NEPOOL Tariff, this Ancillary
Service will be provided by the Independent System Operator (ISO), satellites,
and the Transmission Providers. All of the costs of the ISO will be recovered
directly by the ISO under its own tariff once that tariff becomes effective (a
January 1, 1999 effective date has been requested) and Schedule 1 of the NEPOOL
Tariff is for collection only of the revenue requirements for satellites and
Transmission Providers for System Control and Dispatch Service. Any Transmission
Customer taking Regional Network Service, Through or Out Service, or Internal
Point-to-Point Service shall be subject to the rate surcharge calculated under
Schedule 1 of the NEPOOL Tariff as described in more detail in this rule below.

NEPOOL shall make an annual informational filing on or before July 31 of each
year showing the Schedule 1 rate surcharge in effect for the period beginning
June 1 of that year through May 31 of the subsequent year. If there are any
corrections made to the information reflected in the informational filing after
it has been submitted, NEPOOL would file corrections to the informational
filing. At least thirty days before the informational filing is made with the
Commission, NEPOOL shall make available to Participants and any other interested
parties a draft of the proposed filing for review and comment prior to the
filing. The filing of the informational filing does not re-open the formula rate
set forth below for review, but rather is contestable only with respect to the
accuracy of the information contained in the informational filing. The System
Operator shall independently audit the charges in effect for the period June
1997 through May 2000 for charges under this Attachment, or direct that an
audit[s] be conducted under its supervision by an independent third party, and
shall have the discretion to conduct such audits of charges in effect beyond May
2000.

I.     DEFINITIONS

Capitalized terms used in this rule that are not defined in the NEPOOL Tariff
have the following definitions:

Scheduling and Dispatch Surcharge Rate shall equal the rate surcharge that is
determined for the applicable period beginning on June 1, 1999, in accordance
with Section II of this rule below.

PTF Transmission-Related Satellite Scheduling and Dispatch Expense shall equal
the PTF transmission related expenses incurred by the Participant from

REMVEC II, CONVEX/ESCC, and the Maine Satellite as recorded in each
Participant's FERC Form 1, Account No. 561, excluding any charges recorded in
this account that were incurred under the NEPOOL Tariff or the Local Network
Service Tariffs of each Transmission Provider as a Transmission Customer. The
expenses shall be net of any revenues, as reflected in FERC Account No. 456,
received by the Participant for providing scheduling and dispatch services,
excluding any revenues recorded in this account that where received as a result
of charges under the NEPOOL Tariff or the LNS Tariffs of each Transmission
Provider.

REMVEC II is a satellite of the ISO-NE providing security analysis of PTF.

Local PTF Transmission-Related Scheduling and Dispatch Expense shall equal the
sum of (1) each Participant's expenses as recorded in FERC Account No. 561,
excluding any ISO and satellite related expenses and any expenses recorded in
this Account, that were incurred under this Tariff or the LNS Tariffs of each
Transmission Provider as a Transmission Customer, multiplied by the PTF
Transmission Plant Allocator, (2) SCADA-related expenses as calculated in
accordance with Appendix A to this Rule, and (3) the Maine Satellite revenue
requirements as calculated in accordance with Appendix A to this Rule.

PTF Transmission Plant Allocation Factor is the factor for allocating
transmission costs and expenses between PTF and non-PTF as determined for the
applicable period pursuant to Attachment F of the NEPOOL Tariff.

II.     CALCULATION OF THE SCHEDULING AND DISPATCH SURCHARGE

A.     Surcharge for Regional Network Service Customers
For Network Customers, the scheduling and dispatch surcharge shall equal the
Network Customer's Monthly Network Load, as defined in Section 46.1 of the
NEPOOL Tariff, multiplied by the Monthly Scheduling and Dispatch Surcharge Rate
as determined in accordance with Section II.C below.

B.     Surcharge for Point-to-Point Customers

For Point to Point and Through or Out Service Customers, the Scheduling and
Dispatch Surcharge shall equal the Transmission Customer's Reserved Capacity for
each transaction scheduled for the month multiplied by the applicable Monthly,
Weekly, or Hourly Scheduling and Dispatch Surcharge Rate, as determined in
accordance with Section II.C below.

C.     Scheduling and Dispatch Surcharge Rate

The Scheduling and Dispatch Surcharge Rate will be the surcharge rate in effect
from time to time for the applicable period, determined pursuant to the formula
described below based on the prior calendar year's data. The Scheduling and
Dispatch Surcharge Rate shall be redetermined each year, with the new Surcharge
Rate going into effect on June 1 of each year, and be effective for the
succeeding twelve months.

In the case of Transmission Providers which are subject to the Commission's
jurisdiction, the data used shall be as identified in the Participant's FERC
Form 1 report for that year, and shall be based on actual data in lieu of
allocated data if specifically identified in the FERC Form 1. When FERC Form 1
data is not the direct source of the data used in the formula, the worksheets
used to develop the inputs will be as reflected in Appendix A of this Rule.

The Scheduling and Dispatch Surcharge Rate shall be equal to the sum of (1) PTF
Transmission-Related Satellite Scheduling and Dispatch Expense, (2) Local PTF
Transmission Related Scheduling and Dispatch Expense, (3) less Schedule 1
revenues from the prior year surcharges for Short-Term Point-to-Point
Transactions, and divided by the annual average of the sum of all Network
Customers Monthly Peak Load, as defined in Section 46.1 of the NEPOOL Tariff,
from the prior calendar year plus the Long-Term Firm Point-to-Point Reserved
Capacity, from the prior calendar year.

The Monthly Scheduling and Dispatch Surcharge Rate shall equal one-twelfth of
the Scheduling and Dispatch Surcharge Rate.

The Weekly Scheduling and Dispatch Surcharge Rate shall equal one-fifty- second
of the Scheduling and Dispatch Surcharge Rate.

The Daily Firm Scheduling and Dispatch Surcharge Rate shall equal one-fifth of
the Weekly Scheduling and Dispatch Surcharge Rate.

The Daily Non-Firm Scheduling and Dispatch Surcharge Rate shall equal one-
seventh of the Weekly Scheduling and Dispatch Surcharge Rate.

The Hourly Non-Firm Scheduling and Dispatch Surcharge Rate shall equal one-
twenty-fourth of the Daily Non-Firm Scheduling and Dispatch Surcharge Rate.




                               APPENDIX A-1

               NEPOOL Tariff Schedule 1 Implementation Rule
              Scheduling, System Control and Dispatch Service
                      Boston Edison Company SCADA

This service is required to schedule the movement of power through, out of,
within, or into the NEPOOL Control Area over Pool Transmission Facilities (PTF).
Service under this schedule represents the contribution to that service provided
by The Transmission Provider's own Dispatch Center, commonly referred to as
SCADA. These costs are excluded from costs in Attachment F.

Definitions:

Dispatch Center Wages and Salaries Allocation Factor: Ratio of Dispatch Center
Related Direct Wages and Salaries to Boston Edison's total Direct Wages and
Salaries excluding Administrative and General Wages and Salaries.

Dispatch Center Plant Allocation Factor: Ratio of Total Investment in
Dispatch Center Plant plus Dispatch Center Related General Plant, to Total
Plant in service.

The PTF Revenue Requirement for the Scheduling System Control and Dispatch
Service shall equal the sum of The Transmission Provider's: (A) Return and
Associated Income Taxes, (B) Dispatch Center Depreciation Expense, (C) Dispatch
Center Related Amortization of Investment Tax Credits, (D) Dispatch Center
Related Municipal Tax Expense, (E) Dispatch Center Related Payroll Tax Expense
(F) Dispatch Center Operation and Maintenance Expense, and (G) Dispatch Center
Related Administrative and General Expense; multiplied by the PTF Transmission
Plant Allocation Factor.

A.     Return and Associated Income Taxes shall equal the product of the
Dispatch Center Investment Base and the Cost of Capital Rate.

1. The Dispatch Center Investment Base will consist of (a) Dispatch Center Plant
in FERC accounts 350-359, plus (b) Dispatch Center Related General Plant, plus
(c) Dispatch Center Plant Held for Future Use, less (d) Dispatch Center Related
Depreciation Reserve, less (e) Dispatch Center Related Accumulated Deferred
Taxes, plus (f) Other Regulatory Assets, plus (g) Dispatch Center Prepayments,
plus (h) Dispatch Center Materials and Supplies, plus (i) Dispatch Center
Related Cash Working Capital.

a. Dispatch Center Plant will equal the year-end balance of the Transmission
Provider's Investment in Dispatch Center per FERC accounts 350 through
359.Dispatch Center Plant Investment is not included in PTF investment in the
Attachment F revenue requirement.

b. Dispatch Center Related General Plant shall equal the Transmission Provider's
year-end balance of Investment in General Plant multiplied by the Dispatch
Center Wages and Salaries Allocation Factor described above.

c. Dispatch Center Plant Held for Future Use shall equal the year-end balance of
Transmission related Dispatch Center Investment in FERC account 105.

d. Dispatch Center Related Depreciation Reserve shall equal the year-end balance
of Transmission Dispatch Center Depreciation Reserve, plus the year- end balance
of Dispatch Center Related General Depreciation Reserve. Dispatch Center Related
General Plant Depreciation Reserve shall equal the product of General Plant
Depreciation Reserve and the Dispatch Center Wages and Salaries Allocation
Factor described above.

e. Dispatch Center Related Accumulated Deferred Taxes shall equal the year- end
balance of Total Accumulated Deferred Income Taxes, multiplied by the Dispatch
Center Plant Allocation Factor described above.

f. Other Regulatory Assets shall equal the year-end balance of FAS 106
multiplied by the Dispatch Center Wages and Salaries Allocation Factor described
in Section (A) (2) (b) above and the year-end balance of FAS 109, net of FAS 109
liability, multiplied by the Dispatch Center Plant Allocation Factor described
in above.

g. Dispatch Center Prepayments shall equal the year-end balance of Prepayments
multiplied by the Dispatch Center Wages and Salaries Allocation Factor described
above.

h. Dispatch Center Materials and Supplies shall equal the year-end balance of
Transmission Plant Materials and Supplies multiplied times the Dispatch Center
Plant Allocation Factor described above.

i. Dispatch Center Related Cash Working Capital shall be a 12.5% allowance (45
days/360 days) of Dispatch Center Transmission Related Operation and Maintenance
Expense and Dispatch Center Transmission Related Administrative and General
Expense.

2.   The Cost of Capital Rate shall equal (a) the Weighted Cost of Capital,
plus (b) Federal Income Taxes, plus (c) State Income Taxes.

a.  the Weighted Cost of Capital will be calculated based upon the Transmission
Provider's capital structure at the end of each year and will equal the sum of

i. the Long Term Debt Component, which equals the product of the actual weighted
average embedded cost to maturity of Long Term Debt then outstanding and the
ratio that Long-Term Debt is to Total Capital.

ii. the Preferred Stock Component, which equals the product of the actual
weighted average embedded cost to maturity of Preferred Stock then outstanding
and the ratio that Preferred Stock is to Total Capital.

iii. the Return on Equity Component, which equals the product of The
Transmission Provider's Return on Equity as set in the Transmission Provider's
LNS open access tariff rate and the ratio that Common Equity is to Total
Capital.

b.     Federal Income Taxes shall equal

A + [(C+B)/D]) x FT
        1 - FT

Where FT is the Federal Income Tax Rate and A is the sum of the Preferred Stock
Component and the Return on Equity Component, as determined in Sections
A.2.(a)(ii) and (iii) above, B is Dispatch Center Related Amortization of
Investment Tax Credits, as determined in Section II.D. below, C is the Equity
AFUDC component of Dispatch Center Depreciation Expense, as defined in Section
B., and D is Dispatch Center Investment Base, as determined in A.1., above.

c.     State Income Taxes shall equal

(A + [(C+B)/D] + Federal Income Tax) x ST
                1 - ST

Where ST is the State Income Tax Rate and A is the sum of the Preferred Stock
Component and the Return on Equity Component, as determined in Section
A.2.(a)(ii), and Section A.2.(a)(iii) above, and Federal Income Tax is the rate
determined in Section A.2.(b) above.

B. Dispatch Center Depreciation Expense shall equal the sum of Transmission
Depreciation Expense for Dispatch Center Plant, plus an allocation of General
Plant Depreciation Expense calculated by multiplying General Plant Depreciation
Expense by the Dispatch Center Wages and Salaries Allocation Factor, described
in Section (A) (1) (b) above.

C. Dispatch Center Related Amortization of Investment Tax Credits shall equal
the Transmission Provider's Amortization of Investment Tax Credits multiplied
by the Dispatch Center Plant Allocation Factor described above.

D.  Dispatch Center Related Municipal Tax Expense shall equal the Transmission
Provider's total Municipal Tax Expense multiplied by the Dispatch Center Plant
Allocation Factor described above.

E. Dispatch Center Related Payroll Tax Expense shall equal the Transmission
Provider's total electric payroll tax expense, multiplied by the Dispatch Center
Wages and Salaries Allocation Factor, described above.

F. Dispatch Center Operation and Maintenance Expense shall equal all expenses
related to SCADA operation charged to FERC Account Number 561, excluding any ISO
and satellite related expenses and any expenses recorded in this Account that
were incurred under this Tariff or the LNS tariff of any Transmission Provider
as a Transmission Customer.

G. Dispatch Center Related Administrative and General Expenses shall equal the
sum of (1) Transmission Provider's Administrative and General Expenses,
excluding Accounts 924, 928 and 930.1, multiplied by the Dispatch Center Wages
and Salaries Allocation Factor, (2) Property Insurance multiplied by the
Dispatch Center Plant Allocation Factor, and (3) Expenses included in Account
928 related to FERC

Assessments multiplied by Dispatch Center Plant Allocation Factor, plus any
other Federal and State Dispatch Center related expenses or assessments, plus
specific Dispatch Center related expenses included in Account 930.1.







                               APPENDIX A-2

              NEPOOL Tariff Schedule 1 Implementation Rule
             Scheduling, System Control and Dispatch Service
                      Central Maine Power Company Satellite

I.     DEFINITIONS

Capitalized terms not otherwise defined in Section 1 of the NEPOOL Tariff and as
used in this rule have the following definitions:

A.      ALLOCATION FACTORS

1. Wages and Salaries Allocation Factor shall equal the ratio of the Satellite
Direct Wages and Salaries to total direct wages and salaries excluding
administrative and general wages and salaries.

2.  Satellite Wages and Salaries Allocation Factor shall equal the ratio of the
Transmission Satellite Direct Wages and Salaries to total Satellite Direct Wages
and Salaries.

3. Satellite PTF Allocation Factor shall equal the ratio of the Satellite PTF
Direct Wages and Salaries to the total Satellite Transmission Direct Wages and
Salaries.

4. Satellite Plant Allocation Factor shall equal the ratio of the Total
Investment in Satellite Plant to Total Plant in service.

B.     TERMS

Administrative and General Expense shall equal the Transmission Provider's
expenses as recorded in FERC Account Nos. 920-935, excluding FERC Account
Nos. 924, 928, and 930.1.

Amortization of Investment Tax Credits shall equal the Transmission
Provider's credits as recorded in FERC Account No. 411.4

Amortization of Loss on Reacquired Debt shall equal the Transmission
Provider's expenses as recorded in FERC Account No. 428.1

Other Regulatory Assets/Liabilities - FAS 106 shall equal the net of the
Transmission Provider's FAS106 balance as recorded in FERC Account 182.3 and any
FAS 106 balance as recorded in the Transmission Provider's FERC Account No. 254.

Other Regulatory Assets/Liabilities - FAS 109 shall equal the net of the
Transmission Provider's FAS 109 balance in FERC Account No. 182.3 and any FAS
109 balance as recorded in the Transmission Provider's FERC Account No. 254.

Payroll Taxes shall equal those payroll expenses as recorded in the Transmission
Provider's FERC Account Nos. 408.1 and 409.1.

Plant Held for Future Use shall equal the Transmission Provider's balance in
FERC Account No. 105.

Prepayments shall equal the Transmission Provider's prepayment balance as
recorded in FERC Account No. 165.

Property Insurance shall equal the Transmission Provider's expenses as
recorded in FERC Account No. 924.

PTF Satellite Direct Wages and Salaries shall equal the Transmission Provider's
direct wages and salaries related to providing PTF satellite services as
recorded in FERC Account No. 561.

Satellite Direct Wages and Salaries shall equal the Transmission Provider's
direct wages and salaries related to providing satellite services as recorded in
FERC Account Nos. 556, 561, and 581.

Satellite Operation and Maintenance Expense shall equal the Transmission
Provider's expenses recorded in FERC Account Nos. 556, 561, & 581, less any
costs included in FERC Account No. 561 that are otherwise recoverable pursuant
to Subpart (1) of the Local PTF Transmission Related Scheduling and Dispatch
Expense of the rule implementing the Schedule 1 rate surcharge of the NEPOOL
Tariff.

Satellite Plant Depreciation Reserve shall equal the Transmission Provider's
depreciation reserve balance for Satellite Related Plant as recorded in FERC
Account No. 108.

Materials and Supplies shall equal the Transmission Provider's balance as
recorded in FERC Account No. 154.

Satellite Related Depreciation Expense shall equal the Transmission
Provider's depreciation expense for Satellite Related Plant as recorded in
FERC Account No. 403.

Satellite Related Plant shall equal the Transmission Provider's gross plant
balances used for system control and dispatch purposes as recorded in FERC
Account Nos. 303-399. To the extent that such plant includes any amounts
recorded as transmission investment in FERC Account Nos. 350-359, such amounts
will be excluded for purposes of determining annual transmission revenue
requirements pursuant to the billing rule which implements Attachment F of the
NEPOOL Tariff.

Satellite Support Revenues shall equal the revenues received from satellite
supporters as recorded in FERC Account Nos. 454 and 456, excluding any revenues
received under Schedule 1 of the NEPOOL Tariff or the Transmission Provider's
Local Tariff.

Total Accumulated Deferred Income Taxes shall equal the net of the deferred tax
balances as recorded in FERC Account Nos. 281-283 and 190..

Total Loss on Reacquired Debt shall equal the Transmission Provider's balance as
recorded in FERC Account No. 189.

Total Municipal Tax Expense shall equal the Transmission Provider's municipal
tax expenses as recorded in FERC Account Nos. 408.1 and 409.1.

Total Plant in Service shall equal the Transmission Provider's total gross plant
balance as recorded in FERC Account Nos. 301-399.

Transmission Satellite Direct Wages and Salaries shall equal the Transmission
Provider's direct wages and salaries related to providing satellite services as
recorded in FERC Account No. 561.

II.     CALCULATION OF TOTAL SATELLITE REVENUE REQUIREMENTS

The Satellite Revenue Requirement shall equal the sum of the Satellite related
(A) Return and Associated Income Taxes, (B) Depreciation Expense, (C)
Amortization of Loss on Reacquired Debt, (D) Amortization of Investment Tax
Credits, (E) Municipal Tax Expense, (F) Payroll Tax Expense, (G) Operations and
Maintenance Expense, (H) Administrative and General, minus (I) Support Revenues.

A. Return and Associated Income Taxes shall equal the product of the Satellite
Investment Base and the Cost of Capital Rate reflected in the Transmission
Providers' Attachment F formula of the NEPOOL Tariff.

1.     Satellite Investment Base

The Satellite Investment Base will be the year end balances of Satellite
related: (a) Plant, plus (b) Plant Held for Future Use, less (c) Depreciation
Reserve, less (d) Accumulated Deferred Taxes, plus (e) Loss on Reacquired Debt,
plus (f) Other Regulatory Assets/Liabilities, plus (g) prepayments, plus (h)
Materials and Supplies, plus (i) Cash Working Capital.

(a)     Satellite Related Plant shall equal the balance of the Transmission
Provider's Investment in Satellite Plant

(b)    Satellite Related Plant Held for Future Use shall equal the balance of
Plant Held for Future Use multiplied by the Satellite Plant Allocation Factor

(c) Satellite Related Depreciation Reserve shall equal the Depreciation Reserve
for the Transmission Provider's investment in Satellite plant.

(d) Satellite Related Accumulated Deferred Taxes shall equal the Transmission
Provider's electric balance of Accumulated Deferred Income Taxes multiplied by
the Satellite Plant Allocation Factor.

(e) Satellite Related Loss on Reacquired Debt shall equal the Transmission
Provider's electric balance of Total Loss on Reacquired Debt multiplied by the
Satellite Plant Allocation Factor.

(f) Satellite Related Other Regulatory Assets/Liabilities shall equal the
Transmission Provider's electric balance of any deferred recovery of FAS 106
expenses multiplied by the Satellite Wages and Salaries Allocation Factor, plus
the Transmission Provider's electric balance of FAS 109 multiplied by the
Satellite Plant Allocation Factor.

(g) Satellite Related Prepayments shall equal the Transmission Provider's
electric balance of prepayments multiplied by the Satellite Plant Allocation
Factor.

(h)     Satellite Related Materials and Supplies shall equal the Transmission
Provider's electric balance of Plant Materials and Supplies, multiplied by
the Satellite Plant Allocation Factor.

(i) Satellite Related Cash Working Capital shall be a 12.5% allowance (45
days/360 days) of Satellite Operation and Maintenance Expense, Satellite Related
Administrative and General Expense.

2.     Cost of Capital Rate

The Cost of Capital Rate will equal (a) The Transmission Provider's Weighted
Cost of Capital, plus (b) Federal Income Tax plus (c) State Income Tax.

(a) The Weighted Cost of Capital will be calculated based upon the capital
structure at the end of each year and will equal the sum of:

(i) the long-term debt component, which equals the product of the actual
weighted average embedded cost to maturity of the Transmission Provider's
long-term debt then outstanding and the ratio that long-term debt is to the
Transmission Provider's total capital.

(ii) the preferred stock component, which equals the product of the actual
weighted average embedded cost to maturity of the Transmission Provider's
preferred stock then outstanding and the ratio that preferred stock is to the
Transmission Provider's total capital.

(iii) the return on equity component, which equals the product of the
Transmission Provider's Return on Equity as set in the Provider's RNS open
access rate and the ratio that common equity is to the Transmission Provider's
total capital.

(b)     Federal Income Tax shall equal

                    (A+[(C+B)/D]) x FT
                         1 - FT

Where FT is the Federal Income Tax Rate and A is the sum of the preferred stock
component and the return on equity component, as determined in Sections
II.A.2.(a)(ii) and (iii) above, B is the Amortization of Investment Tax Credits
as determined in Section II.D. below, C is the equity AFUDC component of
Satellite Depreciation Expense, as defined in II.B., and D is Satellite
Investment Base, as determined in II.A.1., above.

(c)     State Income Tax shall equal

                    (A+[(C+B)/D] + Federal Income Tax) x ST
                              1 - ST

Where ST is the State Income Tax Rate, A is the sum of the preferred stock
component and return on equity component determined in Sections II.A.2.(a)(ii)
and (iii) above, B is the Amortization of Investment Tax Credits as determined
in Section II.D. below, C is the equity AFUDC component of Satellite
Depreciation Expense, as defined in II.B., D is the Satellite Investment Base,
as determined in II.A.1., above and Federal Income Tax is the rate determined in
Section II.A.1.(b) above.

B.   Satellite Depreciation Expense shall equal the Satellite Plant Depreciation

Expense and Accumulated Amortization

C.  Satellite Related Amortization of Loss on Reacquired Debt shall equal the
Transmission Provider's electric balance of Loss on Reacquired Debt
multiplied by the Satellite Plant Allocation Factor.

D.  Satellite Related Amortization of Investment Tax Credits shall equal the
Transmission Provider's electric Amortization of Investment Tax Credits
multiplied by the Satellite Plant Allocation Factor.

E. Satellite Related Municipal Tax Expense shall equal the Transmission
Provider's total electric municipal tax expense multiplied by the Satellite
Plant Allocation Factor.

F. Satellite Related Payroll Tax Expense shall equal the Transmission Provider's
total electric payroll tax expense, multiplied by the Wages and Salaries
Allocation Factor.

G. Satellite Operation and Maintenance Expense shall equal the Transmission
Provider's Operation and Maintenance Expenses recorded in FERC Account Nos. 556,
561, and 581, less any costs included in FERC Account No. 561 that are otherwise
recoverable pursuant to Subpart (1) of Local PTF Transmission Related Scheduling
and Dispatch Expense of the rule implementing the Schedule 1 rate surcharge of
the NEPOOL Tariff.

H. Satellite Related Administrative and General Expenses shall equal the sum of
(1) Transmission Provider's Administrative and General Expenses multiplied by
the Wages and Salaries Allocation Factor, (2) Property Insurance multiplied by
the Satellite Plant Allocation Factor, and (3) Expenses included in Account 928
related to FERC Assessments multiplied by the Satellite Plant Allocation Factor,
plus any other Federal and State satellite related expenses or assessments, plus
specific satellite related expenses included in Account 930.1.

I.   Transmission Support Revenues shall equal the Transmission Provider's
revenue received for providing system control and dispatch service

III.    CALCULATION OF SATELLITE TRANSMISSION REVENUE REQUIREMENTS

The Total Satellite Revenue Requirements derived in Section II. above are
further multiplied by the Satellite Wages and Salaries Allocation Factor
defined in Section I. A. 2. above to determine the transmission related
revenue requirement, and further multiplied by the Satellite PTF Allocation
Factor defined in Section I. A. 3. above, to determine the PTF Transmission
related revenue requirements to be included in Schedule I of the NEPOOL Open
Access Transmission Tariff.





                        ANCILLARY SERVICE SCHEDULE 2
       (Reactive Supply And Voltage Control From Generation Sources Service)
                               IMPLEMENTATION RULE

     This rule is designed to implement the NEPOOL Open Access Transmission
Tariff Ancillary Service Schedule 2 (Reactive Supply and Voltage Control from
Generation Sources Service) ("Schedule 2"). As of the Second Effective Date,
service within the scope of Schedule 2 shall be paid by Participants and/or
Non-Participants in accordance with the formula set forth in Schedule

2. The rule defines how Participants providing Schedule 2 service shall be
compensated for providing such service.

1.      Capacity Cost (CC)

1.1 The Capacity Cost will be set to zero ($0) until a methodology for cost
determination and compensation is developed and approved by the NEPOOL Markets
Committee (MC) and the NEPOOL Tariff Committee (TC) and filed and accepted by
the Commission.

2.      Lost Opportunity Cost (LOC)

2.1 The Lost Opportunity Cost for hydro, pumped storage and thermal generating
units that are dispatched down by the ISO, a NEPOOL satellite or a NEPOOL
Participant dispatch center for the purpose of providing reactive supply and
voltage control will be calculated in a manner that is consistent with the rules
established in Market Rule and Procedure No. 6-A - Compensation For Resources
Postured For OP-4 Conditions (MRP 6-A).

2.2      LOC Data Submission

2.2.1 A NEPOOL satellite or a NEPOOL Participant dispatch center must notify the
ISO Control Room staff when a thermal, hydro, or pumped storage generating unit
has been dispatched down by the satellite or NEPOOL Participant dispatch center
for the purpose of providing reactive supply and voltage control.

2.2.2 The ISO Control Room staff will log all instances of a thermal, hydro or
pumped storage generating unit having been dispatched down by the ISO, a NEPOOL
satellite or a NEPOOL Participant dispatch center for the purpose of providing
reactive supply and voltage control.

2.2.3 The ISO Settlements staff will collect the data required for the
determination of LOCSched2 from the ISO Control Room logs, Energy Management
System, and Market System.

3. Cost of Energy Consumed (SCL)

3.1 Motoring Hydro or Pumped Storage Generating Units. The SCL associated with
hydro and pumped storage generating units that are motoring at the request of
the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the
purpose of providing reactive supply and voltage control will equal the cost of
energy to motor and will be calculated in each hour as follows: SCL = (MWhUnit *
(ECP or Actual energy cost) + UpliftSched2), where the MwhUnit are calculated
pursuant to Section 3.2.4. Actual energy cost applies only if motoring energy is
purchased through a bilateral contract. Documentation of actual energy cost is
to be provided to the ISO. The UpliftSched2 component of the SCL is related to
the increase in the Participant's Electrical Load that was caused by the
motoring of a hydro or pumped storage generating unit that was motoring at the
request of the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center
for the purpose of providing reactive supply and voltage control and any other
uplift allocations associated with providing this service and will be calculated
in each hour as follows: UpliftSched2 = MWhUnit * ((* AGC, OPCAP, TMNSR, TMOR
and TMSR Market Payments + Energy Market Uplift Payment) / * Participants'
Electrical Load + applicable ISO Tariff rates + any Emergency Purchase Cost
allocation associated with provision of this service). The UpliftSched2
component of the SCL applies only until the changes indicated in Sections 3.5
and 3.6 have been implemented.

3.2 Data submissions associated with Hydro and Pumped Storage Generating Units
that motored for the purpose of providing Reactive Supply and Voltage Control

3.2.1 A NEPOOL satellite or a NEPOOL Participant dispatch center must notify the
ISO Control Room staff of a generating unit having been instructed by the
satellite or NEPOOL Participant dispatch center to motor for the purpose of
providing reactive supply and voltage control.

3.2.2 The ISO Control Room staff will log all instances of hydro and pumped
storage generating units having been instructed by the ISO, a NEPOOL satellite
or a NEPOOL Participant dispatch center to motor for the purpose of providing
reactive supply and voltage control.

3.2.3 The ISO Settlements staff will collect the flags set by the ISO Control
Room and the ISO Control Room logs to determine which hydro or pumped storage
generating units had been instructed to motor for the purpose of providing
reactive supply and voltage control.

3.2.4 The Lead Participant will need to submit to the ISO Settlements staff the
following data for each hour that the hydro or pumped storage generating units
was motoring for the purpose of providing reactive supply and voltage control:

* The hourly incremental MWh reflecting the energy in each hour required to
support reactive supply and voltage control while motoring above that which is
required when not providing reactive supply and voltage control,

* If the energy to supply the motoring hydro or pumped storage generating unit
is being met by the hourly Energy Market, the hourly Energy Clearing Price, plus
UpliftSched2 related to the increase in the Participant's Electrical Load that
was caused by the motoring of a hydro or pumped storage generating unit that was
motoring at the request of the ISO, a NEPOOL satellite or a NEPOOL Participant
dispatch center for the purpose of providing reactive supply and voltage control
(in the hours that the unit was motored, if any) until the changes indicated in
Sections 3.5 and 3.6 below are in effect; or

If the energy to supply the motoring hydro or pumped storage generating unit is
being met by a retail power agreement, the actual cost of energy associated with
the wholesale/retail power agreement along with supporting contractual
documentation plus UpliftSched2 related to the increase in the Participant's
Electrical Load that was caused by the motoring of a hydro or pumped storage
generating unit that was motoring at the request of the ISO, a NEPOOL satellite
or a NEPOOL Participant dispatch center for the purpose of providing reactive
supply and voltage control (in the hours that the unit was motored, if any)
until the changes indicated in Sections 3.5 and 3.6 below are in effect, and

* An invoice for each motoring hydro or pumped storage generating unit that
includes a total net cost and an hourly cost detail that includes the hourly
data noted in Section 3.1.

3.3 Timing of Data Submissions by Participants for Hydro or Pumped Storage
Generating Units that motored for the purpose of providing Reactive Supply and
Voltage Control - Participants should submit their SCL data (noted in the above
three bullets, Section 3.2.4) related to the motoring of a hydro or pumped
storage generating unit for the purpose of providing reactive supply and voltage
control to ISO Settlements within fourteen (14) calendar days after the
completion of the month in which the unit was called to motor. Under no
circumstances will data submissions received three (3) calendar months or more
after the completion of the month in which the unit was called to motor be
compensated. Submittals received after the 14-day deadline will be reflected in
a single billing that will occur after the 3-month submission deadline has
passed.

3.4 Data submissions notifying the ISO of Hydro or Pumped Storage Generating
Units that have the ability to motor for the purpose of providing Reactive
Supply and Voltage Control - Direction as to whether the ECP or the actual
energy cost will be applied to the SCL calculation (the ECP is to be selected
only if the Participant does not have a wholesale/retail agreement to supply the
unit's station service requirements) must be submitted, with supporting
contractual documentation, to the ISO Settlements staff prior to the month in
which the hydro or pumped storage generating unit is called to motor for
reactive supply and voltage control. It is not intended that a Participant would
have the option to bounce back and forth between ECP and actual energy cost.

3.5 Power System Modeling of Hydro and Pumped Storage Generating Units that can
be motored for the purpose of providing Reactive Supply and Voltage Control -
The energy (MWh) required by a hydro or pumped storage generating unit that is
motoring for the purpose of providing reactive supply and voltage control should
be reported under a distinct and unique Load Asset.

The option of reporting the energy required by a hydro or pumped storage
generating unit that is motoring for the purpose of providing reactive supply
and voltage control under a distinct and unique Load Asset is currently not
available. This option will require incorporation within the appropriate Market
Rule and Procedures (e.g., MRP 20-H and MRP 20-I) and additional programming
within the Market System. Until such a time as that can be accommodated,
Participants will submit the appropriate data and be compensated through the
mechanism noted in Section 3.1 and 3.2.

3.6 Impact of Hydro or Pumped Storage Generating Units motoring for the purpose
of providing Reactive Supply and Voltage Control on the calculation of
Electrical Load and Load - The MWh reported under a distinct and unique Load
Asset (pursuant to Section 3.5) for the motoring of a hydro or pumped storage
generating unit will be excluded from the calculation of Electrical Load and
Load. The MWh that have not been reported under a distinct and unique Load Asset
(pursuant to Section 3.5) for the motoring of a hydro or pumped storage
generating unit will neither be excluded from the calculation of Electrical Load
and Load nor be compensated under Schedule 2.

3.7 Synchronous Condensers and Static Controlled VAR Regulators (SC/SCV). The
SCL will be set to zero ($0), and the cost of energy to supply reactive supply
and voltage control from the Chester SCV will be treated as losses on the NEPOOL
bulk transmission system. This treatment will be revisited by the MC and TC on
an as needed basis (e.g., upon the addition of a new SC or SCV within the NEPOOL
Control Area).

4.     Cost of Energy Produced (PC)

4.1 Thermal Generating Units. The PC associated with thermal generating units
brought on-line by the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch
center for the purpose of providing reactive supply and voltage control shall
equal the product of (i) the difference between its Dispatch Price and the
Energy Clearing Price for the hour, times (ii) the number of megawatt hours of
out-of-merit generation produced by the resource for the hour. The "Dispatch
Price" of an out-of-merit resource for an hour is the price to provide energy
from the resources, as determined pursuant to Market Rules approved by the
NEPOOL Participants Committee, to incorporate the Bid Price for such energy and
any loss adjustments, if and as appropriate under such Market Rules. The "Energy
Clearing Price" for an hour is the price determined for the hour in accordance
with Section 14.8 of the Agreement.

4.2 Hydro and Pumped Storage Generating Units. The PC associated with hydro or
pumped storage generating units that are producing real power and that have also
been brought on-line by the ISO, a NEPOOL satellite or a NEPOOL Participant
dispatch center to provide reactive supply and voltage control shall equal the
product of (i) the difference between its Dispatch Price and the Energy Clearing
Price for the hour, times (ii) the number of megawatt hours of out-of-merit
generation produced by the resource for the hour. The "Dispatch Price" of an
out-of-merit resource for an hour is the price to provide energy from the
resources, as determined pursuant to Market Rules approved by the NEPOOL
Participants Committee, to incorporate the Bid Price for such energy and any
loss adjustments, if and as appropriate under such Market Rules. The "Energy
Clearing Price" for an hour is the price determined for the hour in accordance
with Section 14.8 of the Agreement.

4.3     Data submissions with respect to PC

4.3.1 A NEPOOL satellite or a NEPOOL Participant dispatch center must notify the
ISO Control Room staff of a generating unit having been brought on-line by the
satellite or NEPOOL Participant dispatch center for the purpose of providing
reactive supply and voltage control.

4.3.2 The ISO Control Room staff will log all instances of a generating unit
having been brought on-line by the ISO, a NEPOOL satellite or a NEPOOL
Participant dispatch center for the purpose of providing reactive supply and
voltage control.

4.3.3 The ISO Settlements Hourly Markets staff will collect the flags set by the
ISO Control Room and the ISO Control Room logs to determine which generating
units have been brought on-line for the purpose of providing reactive supply and
voltage control.

4.3.4 The ISO Settlement Staff will collect the appropriate data through the
Market System for each hour that the generating unit was brought on-line for the
purpose of providing reactive supply and voltage control.



              Sheet Nos. 530-700 are reserved for future use.





                     NEPOOL TARIFF, ATTACHMENT F

                IMPLEMENTATION RULE FOR CALCULATING
                ANNUAL TRANSMISSION REVENUE REQUIREMENTS

This rule sets forth details with respect to the determination each year of the
Transmission Revenue Requirements for each Participant. Such Transmission
Revenue Requirements shall reflect the Participant's costs for Pool Transmission
Facilities ("PTF"). The Transmission Revenue Requirements will be an annual
formula rate calculation, effective June 1, based on the previous calendar
year's data, as shown below, and in the case of each Transmission Provider which
is subject to the Commission's jurisdiction, in the Participant's FERC Form 1
report for that year, and shall be based on actual data in lieu of allocated
data if specifically identified in the FERC Form 1, using end-of-year balances
for each rate base item, as set forth below.

NEPOOL shall make an annual informational filing on or before July 31 of each
year showing the Pool PTF Rate in effect for the period beginning June 1 of that
year through May 31 of the subsequent year. Further, the informational filing
with respect to the determination of the Pool PTF rate would include a breakdown
by Participant the amount of the change in PTF investment during the prior year
and the PTF retirements or additions causing such change to beginning and
end-of-year PTF balances (although beginning-of- year PTF balances are not used
in the formula itself), and any additions to PTF, retirements of PTF, and
reclassifications of PTF during the year for each Transmission Provider. If
there are any corrections made to the information reflected in the informational
filing after it has been submitted, NEPOOL would file corrections to the
informational filing. At least forty-five days before the informational filing
is made with the Commission, NEPOOL shall make available to Participants and any
other interested parties a draft of the proposed filing for review and comment
prior to the filing. The filing of the information filing does not re-open the
formula rate set forth below for review, but rather is contestable only with
respect to the accuracy of the information contained in the informational
filing.

The System Operator shall independently audit the charges in effect for the
period June 1997 through May 2000 for charges under this Attachment, or direct
that an audit[s] be conducted under its supervision by an independent third
party, and shall have the discretion to conduct such audits of charges in effect
beyond May 2000.

I.     DEFINITIONS

Capitalized terms not otherwise defined in Section 1 of the NEPOOL Tariff and as
used in this rule have the following definitions:

A.      ALLOCATION FACTORS

1. Transmission Wages and Salaries Allocation Factor shall equal the ratio of
Transmission-related direct wages and salaries including those of affiliated
Companies to the Transmission Provider's total direct wages and salaries
including those of the affiliates Companies and excluding administrative and
general wages and salaries.

2. PTF Transmission Plant Allocation Factor shall equal the ratio of PTF
Transmission Plant to Total Investment in Transmission Plant, excluding capital
leases in the Hydro-Quebec DC Facilities (HQ Leases).

3. Plant Allocation Factor shall equal the ratio of the sum of Total Investment
in Transmission Plant, excluding HQ leases, and Transmission Related General
Plant to Total Plant in service excluding HQ Leases.

B.     TERMS

Administrative and General Expense shall equal the Transmission Provider's
expenses as recorded in FERC Account Nos. 920-935, excluding FERC Account
Nos. 924, 928 and 930.1.

Amortization of Loss on Reacquired Debt shall equal the Transmission Provider's
expenses as recorded in FERC Account No. 428.1.

Amortization of Investment Tax Credits shall equal the Transmission Provider's
credits as recorded in FERC Account No. 411.4.

Depreciation Expense for Transmission Plant shall equal the Transmission
Provider's transmission expenses as recorded in FERC Account No. 403.

General Plant shall equal the Transmission Provider's gross plant balance as
recorded in FERC Account Nos. 389-399.

General Plant Depreciation Expense shall equal the Transmission Provider's
general expenses as recorded in FERC Account No. 403.

General Plant Depreciation Reserve shall equal the Transmission Provider's
general reserve balance as recorded in FERC Account No. 108.

Hydro-Quebec DC Facilities (HQ Leases) shall equal the Transmission
Provider's balance in capital leases as recorded in FERC Account Nos. 350-359
and FERC Account Nos. 389-399.

Other Regulatory Assets/Liabilities - FAS 106 shall equal the net of the
Transmission Provider's FAS106 balance as recorded in FERC Account 182.3 and any
FAS 106 balance as recorded in the Transmission Provider's FERC Account No. 254.

Other Regulatory Assets/Liabilities - FAS 109 shall equal the net of the
Transmission Provider's FAS 109 balance in FERC Account No. 182.3 and any FAS
109 balance as recorded in the Transmission Provider's FERC Account No. 254.

Payroll Taxes shall equal those payroll expenses as recorded in the Transmission
Provider's FERC Account Nos. 408.1 and 409.1.

Plant Held for Future Use shall equal the Transmission Provider's balance in
FERC Account No.105.

Prepayments shall equal the Transmission Provider's prepayment balance as
recorded in FERC Account No. 165.

Property Insurance shall equal the Transmission Provider's expenses as
recorded in FERC Account No. 924.

PTF Transmission Plant Investment shall equal the Transmission Provider's
transmission plant as defined in the Section 15.1 of the Restated NEPOOL
Agreement and determined in accordance with Attachment 1.5 of this rule, which
is entitled "Rules for Determining Investment To be Included in PTF."

Total Accumulated Deferred Income Taxes shall equal the net of the deferred
tax balance as recorded in FERC Account Nos. 281-283 and the deferred tax
balance as recorded in FERC Account No. 190.

Total Loss on Reacquired Debt shall equal the Transmission Provider's expenses
as recorded in FERC Account 189.

Total Municipal Tax Expense shall equal the Transmission Provider's municipal
tax expenses as recorded in FERC Account Nos. 408.1, 409.1.

Total Plant in Service shall equal the Transmission Provider's total gross plant
balance as recorded in FERC Account Nos. 301-399.

Total Transmission Depreciation Reserve shall equal the Transmission Provider's
transmission reserve balance as recorded in FERC Account 108.

Transmission Operation and Maintenance Expense shall equal the Transmission
Provider's expenses as recorded in FERC Account Nos. 560, 562-564 and 566- 573,
and shall exclude all HQ HVDC expenses booked to accounts 560 through 573 and
expenses already included in Transmission Support Expense, as described in
Section K which are included in FERC Account Nos. 560-573.

Transmission Plant shall equal the Transmission Provider's Gross Plant balance
as recorded in FERC Account Nos. 350-359.

Transmission Plant Materials and Supplies shall equal the Transmission
Provider's balance as assigned to transmission, as recorded in FERC Account No.
154.


II.     CALCULATION OF TRANSMISSION REVENUE REQUIREMENTS

The Transmission Revenue Requirement shall equal the sum of the Transmission
Provider's (A) Return and Associated Income Taxes, (B) Transmission Depreciation
Expense, (C) Transmission Related Amortization of Loss on Reacquired Debt, (D)
Transmission Related Amortization of Investment Tax Credits, (E) Transmission
Related Municipal Tax Expense, (F) Transmission Related Payroll Tax Expense, (G)
Transmission Operation and Maintenance Expense, (H) Transmission Related
Administrative and General Expenses, (I) Transmission Related Integrated
Facilities Charges, minus (J) Transmission Support Revenue, plus (K)
Transmission Support Expense, plus (L) Transmission-Related Expense from
Generators, plus (M) Transmission Related Taxes and Fees Charge, minus (N)
Revenue for Short-Term Transmission Service under the NEPOOL Tariff and (O)
Transmission Rents Received from Electric Property.

A.     Return and Associated Income Taxes shall equal the product of the
Transmission Investment Base and the Cost of Capital Rate.

1.     Transmission Investment Base

The Transmission Investment Base will be the year end balances of (a) PTF
Transmission Plant, plus (b) Transmission Related General Plant, plus (c)
Transmission Plant Held for Future Use, less (d) Transmission Related
Depreciation Reserve, less (e) Transmission Related Accumulated Deferred Taxes,
plus (f) Transmission Related Loss on Reacquired Debt, plus (g) Other Regulatory
Assets/Liabilities, plus (h) Transmission Prepayments, plus (i) Transmission
Materials and Supplies, plus (j) Transmission Related Cash Working Capital.

(a) PTF Transmission Plant will equal the balance of the Transmission Provider's
PTF Investment in Transmission Plant excluding (i) the Transmission Provider's
capital leases in the Hydro-Quebec DC Facilities (HQ Leases), (ii) the portion
of any facilities, the cost of which is directly assigned under Schedule 11 to
the Tariff, to the Transmission Customer or a Generator Owner or Interconnection
Requester, (iii) the Pre-1997 PTF gross plant investment associated with leased
facilities occupied by the Phase II HVDC facilities.

(b) Transmission Related General Plant shall equal the Transmission Provider's
balance of investment in General Plant multiplied by the Transmission Wages and
Salaries Allocation Factor and the PTF Transmission Plant Allocation Factor.

(c) Transmission Plant Held for Future Use shall equal the balance of
Transmission-related Plant Held for Future Use multiplied by the PTF
Transmission Plant Allocation Factor.

(d) Transmission Related Depreciation Reserve shall equal the balance of Total
Transmission Depreciation Reserve, plus the balance of Transmission Related
General Plant Depreciation Reserve. Transmission Related General Plant
Depreciation Reserve shall equal the product General Plant Depreciation Reserve
and the Transmission Wages and Salaries Allocation Factor. This sum shall be
multiplied by the PTF Transmission Plant Allocation Factor.

(e) Transmission Related Accumulated Deferred Taxes shall equal the Transmission
Provider's electric balance of Total Accumulated Deferred Income Taxes,
multiplied by the Plant Allocation Factor, further multiplied by the PTF
Transmission Plant Allocation Factor.

(f) Transmission Related Loss on Reacquired Debt shall equal the Transmission
Provider's electric balance of Total Loss on Reacquired Debt multiplied by the
Plant Allocation Factor, further multiplied by the PTF Transmission Plant
Allocation Factor.

(g) Other Regulatory Assets/Liabilities shall equal the Transmission Provider's
electric balance of any deferred rate recovery of FAS 106 expenses multiplied by
the Transmission Wages and Salaries Allocation Factor, plus the Transmission
Provider's electric balance of FAS 109 multiplied by the Plant Allocation
Factor. This sum shall be multiplied by the PTF Transmission Plant Allocation
Factor.

(h) Transmission Prepayments shall equal the Transmission Provider's electric
balance of prepayments multiplied by the Transmission Wages and Salaries
allocator and further multiplied by the PTF Transmission Plant Allocation
Factor.

(i) Transmission Materials and Supplies shall equal the Transmission Provider's
electric balance of Transmission Plant Materials and Supplies, multiplied by the
PTF Transmission Plant Allocation Factor.

(j) Transmission Related Cash Working Capital shall be a 12.5% allowance (45
days/360 days) of Transmission Operation and Maintenance Expense, Transmission
Related Administrative and General Expense and Transmission Support Expense, to
the extent that Transmission Support Expense exceeds Transmission Support
Revenue included in Paragraph J of the formula.

2.     Cost of Capital Rate

The Cost of Capital Rate will equal (a) The Transmission Provider's Weighted
Cost of Capital, plus (b) Federal Income Tax plus (c) State Income Tax.

(a) The Weighted Cost of Capital will be calculated based upon the capital
structure at the end of each year and will equal the sum of:

(i) the long-term debt component, which equals the product of the actual
weighted average embedded cost to maturity of the Transmission Provider's
long-term debt then outstanding and the ratio that long-term debt is to the
Transmission Provider's total capital.

(ii) the preferred stock component, which equals the product of the actual
weighted average embedded cost to maturity of the Transmission Provider's
preferred stock then outstanding and the ratio that preferred stock is to the
Transmission Provider's total capital.

(iii)  the return on equity component, which shall be determined as follows:

(1) For each year during the period March 1, 1997 through May 31, 2000, the
return on equity component for each of the Transmission Providers identified
below shall be the product of the Transmission Provider's Return on Equity
("ROE") as set forth below and the ratio that common equity is to the
Transmission Provider's total capital:

Bangor Hydro-Electric Company                        11.5%
Boston Edison Company                                10.65%
Central Maine Power Company                          11.00%
Commonwealth Electric Company                        10.75%
Eastern Utilities Associates                         11.22%
                                               (through May 31, 1999)
                                                     10.65%
                                               (beginning June 1, 1999)
New England Electric System                          10.65%
The United Illuminating Company                      11.5%
                                               (through May 31, 1999)
                                                     10.75%
                                               (beginning June 1, 1999)
Vermont Electric Company                             11.50%
Northeast Utilities                                  11.75%

(2) For each year during the period commencing June 1, 2000, the return on
equity component shall be determined in the same manner, and the allowed ROE for
each Transmission Provider identified above shall remain in effect for purposes
of such determination for the Provider until an amendment to its cost of service
under the Local Network Service Tariff for the Provider filed after December 31,
1999 results in a different allowed ROE for that Provider, in which case that
Provider's ROE shall be set for purposes of such determination at the ROE
ultimately determined to be just and reasonable in the proceeding involving the
applicable Local Network Service Tariff amendment.

(b)     Federal Income Tax shall equal

(A+[(C+B)/D])(FT)
     1 - FT

where FT is the Federal Income Tax Rate and A is the sum of the preferred stock
component and the return on equity component, as determined in Sections
II.A.2.(a)(ii) and (iii) above, B is Transmission Related Amortization of
Investment Tax Credits, as determined in Section II.D., below, C is the Equity
AFUDC component of Transmission Depreciation Expense , as defined in Section
II.B., and D is Transmission Investment Base, as determined in II.A.1., above.

(c)     State Income Tax shall equal

(A+[(C+B)/D] + Federal Income Tax)(ST)
            1 - ST

where ST is the State Income Tax Rate, A is the sum of the preferred stock
component and return on equity component determined in Sections II.A.2.(a)(ii)
and (iii) above, B is the Amortization of Investment Tax Credits as determined
in Section II.D. below, C is the equity AFUDC component of Transmission
Depreciation Expense, as defined in Section II.B., D is the Transmission
Investment Base, as determined in II.A.1., above and Federal Income Tax is the
rate determined in Section II.A.2.(b) above.

B. Transmission Depreciation Expense shall equal the PTF Transmission Plant
Allocation Factor, multiplied by the sum of Depreciation Expense for
Transmission Plant, plus an allocation of General Plant Depreciation Expense
calculated by multiplying General Plant Depreciation Expense by the Transmission
Wages and Salaries Allocation Factor.

C. Transmission Related Amortization of Loss on Reacquired Debt shall equal the
Transmission Provider's electric Amortization of Loss on Reacquired Debt
multiplied by the Plant Allocation Factor, and further multiplied by the PTF
Transmission Plant Allocation Factor.

D. Transmission Related Amortization of Investment Tax Credits shall equal the
Transmission Provider's electric Amortization of Investment Tax Credits
multiplied by the Plant Allocation Factor, and further multiplied by the PTF
Transmission Plant Allocation Factor.

E. Transmission Related Municipal Tax Expense shall equal the Transmission
Provider's total electric municipal tax expense multiplied by the Plant
Allocation Factor, and further multiplied by the PTF Transmission Plant
Allocation Factor.

F. Transmission Related Payroll Tax Expense shall equal the Transmission
Provider's total electric payroll tax expense, multiplied by the Transmission
Wages and Salaries Allocation Factor, further multiplied by the PTF Transmission
Plant Allocation Factor.

G.  Transmission Operation and Maintenance Expense shall equal Transmission
Operation and Maintenance Expenses multiplied by the PTF Transmission Plant
Allocation Factor.

H. Transmission Related Administrative and General Expenses shall equal the sum
of (1) Transmission Provider's Administrative and General Expenses multiplied by
the Transmission Wages and Salaries Allocation Factor, (2) Property Insurance
multiplied by the Transmission Plant Allocation Factor, and (3) Expenses
included in Account 928 related to FERC Assessments multiplied by Plant
Allocation Factor, plus any other Federal and State transmission related
expenses or assessments, plus specific transmission related expenses included in
Account 930.1. This sum shall be multiplied by the PTF Transmission Plant
Allocation Factor.

I. Transmission Related Integrated Facilities Charges shall equal the
Transmission Provider's transmission payments to affiliates for use of the PTF
integrated transmission facilities of those affiliates.

J. Transmission Support Revenues shall equal the Transmission Provider's revenue
received for PTF transmission support but excluding the support payments to
Transmission Providers or their designee pursuant to Schedule 11 and excluding
the support payments to Transmission Providers or their designee pursuant to
Schedule 12 Part 1(a), Part 1(b), Part 2 and Part 3, and excluding support
payments, if any, made to Transmission Owners or their respective designee
pursuant to Part III of this Tariff.

K. Transmission Support Expense shall equal the expense paid by Transmission
Providers or Transmission Customers for PTF transmission support other than
expenses for payments made for congestion rights or for transmission facilities
or facility upgrades placed in service on or after January 1, 1997, where the
support obligation is required to be borne by particular Participants or other
entities in accordance with the NEPOOL Tariff. Transmission Support Expenses by
any entity other than an LNS Transmission Provider, included in this provision,
shall be capped at that entity's annual payment for Regional Network Service or
its Point to Point Service for each individual Point to Point transaction from
the resource with which the support payment is associated. For the purpose of
establishing this cap, for the first five years of the Transition Period the
annual payment for RNS and Internal Point-to-Point shall be recalculated at the
Pool PTF rate.

L. Transmission-Related Expense from Generators shall equal the expenses from
generators that both (1) the Management Committee determines should be included
as transmission expense as a result of the impact of such generators on reducing
transmission costs that would otherwise be required to be paid by Transmission
Customers and (2) are reflected in a filing made by NEPOOL with the Commission
under Section 205 of the Federal Power Act and accepted by the Commission for
recovery under the NEPOOL Tariff.

M. Transmission Related Taxes and Fees Charge shall include any fee or
assessment imposed by any governmental authority on service provided under this
Section which is not specifically identified under any other section of this
rule.

N. Revenues for Short-term Transmission Service under the NEPOOL Tariff shall be
revenues distributed to each Participant, from NEPOOL, for short term service
provided under the NEPOOL Tariff, received after March 1, 1999. These revenues
will be credited pro-rata between pre-1997 and post-1996 PTF revenue
requirements in proportion to pre-1997 and post-1996 PTF Transmission Plant.

O. Transmission Rents Received from Electric Property shall equal any Account
454 Rents from electric property, associated with PTF Transmission Plant as
defined in Section II.A.1.(a) above but not reflected as a credit in
Transmission Support Revenues in paragraph K of this Attachment.

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.45.3
<SEQUENCE>6
<FILENAME>0006.txt
<DESCRIPTION>EXHIBIT 10.45.3
<TEXT>


                        CONFIDENTIAL SEPARATION AGREEMENT
                               AND GENERAL RELEASE


                  THIS AGREEMENT, made and entered into as of this 20th day of
December, 2000, by and between Northeast Utilities Service Company, a
Connecticut corporation, with its principal office in Berlin, Connecticut,
(together with each direct and indirect affiliated company that has adopted the
Employment Agreement entered into on February 25, 1997 (the "Employment
Agreement"), with Northeast Utilities Service Company, hereinafter, the
"Company"), and Hugh C. MacKenzie, a resident of Madison, Connecticut
("Executive").

                              W I T N E S S E T H:

                  WHEREAS, the Company had heretofore employed Executive under
the Employment Agreement; and

                  WHEREAS, Executive's employment has been terminated upon a
Change in Control, as that phrase is defined in the Employment Agreement,
effective December 31, 2000, and the Notice of Termination, required by Section
6.2 of the Employment Agreement, is hereby waived; and

                  WHEREAS, the Company and Executive wish to enter into an
agreement to provide for a mutual release as to any claims including, without
limitation, claims that might be asserted by Executive under the Employment
Agreement and the Age Discrimination in Employment Act, as further described
herein, and reaffirm Executive's right to indemnification;

                  NOW, THEREFORE, in consideration of the mutual promises
contained herein, the parties hereto, intending to be legally bound, hereby
agree as follows:

                  1.  The Company and Executive hereby agree that Executive's
termination upon a Change in Control, as that phrase is defined in the
Employment Agreement, shall be effective on December 31, 2000 and that the
Notice of Termination required by Section 6.2 of the Employment Agreement is
hereby waived. The Company and Executive further agree that the Employment
Agreement shall continue only to the extent provided therein as to obligations
that survive the termination of Executive's employment.

                  2.  Executive agrees and acknowledges that the Company, on a
timely basis, has paid, or agreed to pay, to Executive all other amounts due and
owing based on Executive's prior services in accordance with the terms of the
Employment Agreement or any other contract with Executive, whether express or
implied, and that the Company has no obligation, contractual or otherwise to
Executive, except as provided herein, in the Employment Agreement or any other
such contract with Executive, nor does it have any obligation to hire, rehire or
re-employ Executive in the future. Notwithstanding the foregoing, nothing
contained in this Agreement

                                      -1-
<PAGE>

shall prevent Executive from requiring the Company to fulfill its obligations
under this Agreement, under the Employment Agreement, to the extent of any
continuing obligations thereunder, under any employee benefit plan, as defined
in Section 3(3) of ERISA, maintained by the Company and in which Executive
participated, or any other contract with Executive, whether express or implied.

                  3.  In full and complete settlement of any claims that
Executive may have against the Company, including any possible violations of the
Age Discrimination in Employment Act ("ADEA"), 29 U.S.C.ss.621, et seq., in
connection with Executive's termination of employment, and for and in
consideration of the undertakings of the Company described herein, Executive
does hereby REMISE, RELEASE, AND FOREVER DISCHARGE the Company, and each of its
past, present and future subsidiaries and affiliates, their officers, directors,
shareholders, partners, employees and agents, and their respective successors
and assigns, heirs, executors and administrators (hereinafter all included
within the term "the Company"), of and from any and all manner of actions and
causes of actions, suits, debts, claims and demands whatsoever in law or in
equity, which Executive ever had, now has, or hereafter may have, or which
Executive's heirs, executors or administrators hereafter may have, by reason of
any matter, cause or thing whatsoever from the beginning of Executive's
employment to the termination of Executive's employment; and particularly, but
without limitation of the foregoing general terms, any claims arising from or
relating in any way to Executive's employment relationship or the Employment
Agreement to the extent of any obligation that does not survive Executive's
termination of employment and Executive's termination from that employment
relationship, including but not limited to, any claims which have been asserted,
could have been asserted, or could be asserted now or in the future under any
federal, state or local laws, including any claims under the Age Discrimination
in Employment Act ("ADEA"), 29 U.S.C.ss.621, et seq., and the Older Workers'
Benefit Protection Act, 29 U.S.C.ss.626(f)(1), and any claims under Section 210
or Section 211 of the Energy Reorganization Act of 1974, 42 U.S.C.ss.5851, the
National Energy Policy Act of 1992, Pub. L. No. 102-486, Title VII of the Civil
Rights Act of 1964, 42 U.S.C.ss. 2000e, et seq., the Labor Management Relations
Act, the Employee Retirement Income Security Act of 1974 ("ERISA"), the
Rehabilitation Act of 1973, the Civil Rights Act of 1991, the Americans with
Disabilities Act ("ADA"), 42 U.S.C.ss.12101, et seq., the Family and Medical
Leave Act of 1993, 29 U.S.C.ss.2601, et seq., the Fair Labor Standards Act, the
National Labor Relations Act, the Connecticut Fair Employment Practices Act,
Conn. Gen. Stat.ss.ss.46a-60 - 46a-62 (1995), and any other federal, state, or
local statute, ordinance, regulation, rule of decision or common law recognized
now or in the future and all claims for counsel fees and costs. Notwithstanding
the foregoing, nothing contained in this Agreement shall prevent Executive from
requiring the Company to fulfill its obligations under this Agreement, under the
Employment Agreement, to the extent of any continuing obligations thereunder,
under any employee benefit plan, as defined in Section 3(3) of ERISA, maintained
by the Company and in which Executive participated, or any other contract with
Executive, whether express or implied.

                  4.  Nothing in this Agreement shall be construed to prohibit
or otherwise discourage Executive from reporting, providing testimony regarding,
cooperating in, or otherwise communicating any suspected instance of illegal
activity of any nature, any nuclear

                                      -2-
<PAGE>

safety concern, workplace safety concern, or public safety concern to the U.S.
Nuclear Regulatory Commission, the U.S. Department of Labor, or any federal or
state government agency, or any matter involving the substantial misfeasance,
malfeasance or nonfeasance in the management of the Company to the Connecticut
Department of Public Utility Control. The parties further acknowledge,
understand, and agree that the provisions of this Agreement are not intended to
restrict Executive's communication with, or full cooperation in proceedings or
investigations by, any agency relating to nuclear regulatory or safety issues,
or any matter involving the substantial misfeasance, malfeasance or nonfeasance
in the management of the Company.

                  5.  Nothing in this Agreement shall limit or impair any right
Executive may otherwise have to indemnity and defense by the Company, and,
notwithstanding any contrary provision of this Agreement, (i) the Company shall
indemnify and defend Executive in connection with any action, suit or proceeding
in which Executive may be involved or with which Executive may be threatened by
reason of Executive's being or having been an officer of the Company or by
reason of Executive's being or having been a fiduciary of the Company's employee
benefit plans in the same manner contemplated by (including the payment or
advancement of any reasonable expenses as incurred) and to the fullest extent
permitted by the Declaration of Trust of Northeast Utilities as of the date
hereof, unless later limited in accordance with applicable law, or under
applicable law, (in which case Executive shall notify the Company within five
business days after receiving service of process as to the commencement of the
action, suit or proceeding and give the Company the right to control the defense
of any such action, suit or proceeding, provided that no delay in giving such
notice shall result in a forfeiture of any rights by Executive unless, and then
only to the extent that, the Company is actually prejudiced by such delay), and
(ii) Executive may join the Company in any action, suit or proceeding, or bring
any action, suit or proceeding against the Company, as may be necessary for the
protection or enforcement of such rights of indemnification and defense by the
Company.

                  6.  Except to the extent permitted by paragraph 3, Executive
further agrees and covenants that neither Executive, nor any person,
organization or other entity on Executive's behalf, will file, charge, claim,
sue or cause or permit to be filed, charged, or claimed, any action for damages,
including injunctive, declaratory, monetary or other relief against the Company,
involving any matter occurring at any time in the past up to the effective date
of this Agreement, or involving any continuing effects of any actions or
practices which may have arisen or occurred prior to the date of this Agreement,
including any charge of retaliation or discrimination under the ADEA, Title VII,
the ADA, the Workers' Compensation Act or federal, state or local laws. In
addition, Executive further agrees and covenants that should Executive, or any
other person, organization or entity on Executive's behalf, file, charge, claim,
sue or cause or permit to be filed, charged, or claimed, any action for damages,
including injunctive, declaratory, monetary or other relief, despite Executive's
agreement not to do so under this Agreement, or should Executive otherwise fail
to abide, in any material respect, by any of the terms of this Agreement, then
the Company will be relieved of all further obligations owed under the
Employment Agreement and this Agreement, Executive will forfeit all monies paid
to Executive under the Employment Agreement following Executive's termination of
employment and Executive will

                                      -3-
<PAGE>

pay all of the costs and expenses of the Company (including reasonable
attorneys' fees) incurred in the defense of any such action or undertaking.

                  7.  In full and complete settlement of any claims that the
Company may have against Executive, other than the fulfillment of Executive's
obligations under this Agreement or under the Employment Agreement, and for and
in consideration of the undertakings of Executive described herein, the Company
does hereby REMISE, RELEASE, AND FOREVER DISCHARGE Executive and Executive's
heirs, executors and administrators (hereinafter all included within the term
"Executive"), of and from any and all manner of actions and causes of actions,
suits, debts, claims and demands whatsoever in law or in equity, which the
Company ever had, now has, or hereafter may have, by reason of any civil (but
specifically not any criminal act) matter, cause or thing whatsoever by reason
of Executive's being or having been an officer of the Company from the beginning
of Executive's employment with the Company to the date of termination of
employment; and particularly, but without limitation of the foregoing general
terms, any claims arising from or relating in any way to actions taken by
Executive by reason of Executive's being or having been an officer of the
Company and Executive's termination from those relationships with the Company.

                  8.  The Company further agrees and covenants that neither it,
nor any person, organization or other entity on its behalf, will file, charge,
claim, sue or cause or permit to be filed, charged, or claimed, any action for
damages, including injunctive, declaratory, monetary or other relief against
Executive, involving any matter occurring at any time in the past up to the date
of this Agreement, or involving any continuing effects of any actions or
practices which may have arisen or occurred prior to the date of this Agreement,
by reason of Executive's being or having been an officer of the Company, so long
as Executive meets, in all material respects, Executive's obligations under this
Agreement and the Employment Agreement. In addition, the Company further agrees
and covenants that should it, or any other person, organization or entity on its
behalf, file, charge, claim, sue or cause or permit to be filed, charged, or
claimed, any action for damages, including injunctive, declaratory, monetary or
other relief, despite its agreement not to do so under this Agreement, then it
will pay all of the costs and expenses of Executive (including reasonable
attorneys' fees) incurred in the defense of any such action or undertaking.

                  9.  Executive hereby agrees and acknowledges that under this
Agreement, the Company has agreed to provide Executive with compensation ,
benefits, and covenants that are in addition to that which Executive otherwise
would have been entitled under the Employment Agreement or otherwise in the
absence of this Agreement, and that such additional compensation and covenants
are sufficient to support the covenants and agreements by Executive herein.

                  10. Executive and the Company, its officers and directors,
will not, disparage the name, business reputation or business practices of the
other. In addition, by signing this Agreement, Executive agrees not to pursue
any internal grievance with the Company.

                  11. Executive hereby certifies that Executive has read the
terms of this

                                      -4-
<PAGE>

Agreement, that Executive has been advised by the Company to consult with an
attorney and that Executive understands its terms and effects. Executive
acknowledges, further, that Executive is executing this Agreement of Executive's
own volition, without any threat, duress or coercion and with a full
understanding of its terms and effects and with the intention, as expressed in
paragraph 3 hereof, of releasing all claims recited herein in exchange for the
consideration described herein, which Executive acknowledges is adequate and
satisfactory to Executive. The Company has made no representations to Executive
concerning the terms or effects of this Agreement other than those contained in
this Agreement.

                  12. Executive hereby acknowledges that Executive was presented
with this Agreement on December 20, 2000, and that Executive was informed that
Executive had the right to consider this Agreement and the release contained
herein for a period of at least twenty-one (21) days prior to execution.
Executive also understands that Executive has the right to revoke this Agreement
for a period of seven (7) days following execution, by giving written notice to
the Senior Vice President, Secretary, and General Counsel for the Company at 107
Selden Street, Berlin, CT 06037, in which event the provisions of this Agreement
shall be null and void, and the parties shall have the rights, duties,
obligations and remedies afforded by applicable law.

                  13. This Agreement shall be interpreted and enforced under the
laws of the State of Connecticut.

                  IN WITNESS WHEREOF, the parties hereto have executed this
Agreement as of the day and year first above written.


ATTEST:                                 NORTHEAST UTILITIES SERVICE COMPANY


                                        By: /s/ CHERYL W. GRISE
- ---------------------------------          -------------------------------------
Witness                                    Cheryl W. Grise
                                           Senior Vice President, Secretary and
                                             General Counsel


                                           /s/ HUGH C. MACKENZIE
- ---------------------------------          -------------------------------------
Witness                                    Hugh C. MacKenzie

                                      -5-
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.51.3
<SEQUENCE>7
<FILENAME>0007.txt
<DESCRIPTION>EXHIBIT 10.51.3
<TEXT>


As of September 27, 2000

CL&P Receivables Corporation
107 Selden Street
Berlin, Connecticut 06037

               Re:  Fee Agreement

Ladies and Gentlemen:

This letter agreement will serve to confirm our respective understandings
regarding certain of the fees to be paid pursuant to Section 2.05(a) of the
Receivables Purchase and Sale Agreement, dated as of the date hereof, as amended
(the "Receivables Purchase Agreement"), among The Connecticut Light and Power
Company, a Connecticut corpo-ra-tion, as Collection Agent and Originator, CL&P
Receivables Corporation, a Connecticut corporation, as Seller, Corporate Asset
Funding Company, Inc., a Delaware corporation, Citibank, N.A., and Citicorp
North America, Inc., a Delaware corporation, as Agent for the Purchasers and the
Banks, as the same may be amended, modified or supple-mented from time to time.
Unless otherwise defined herein, capitalized terms used herein shall have the
meanings set forth in the Receivables Purchase Agreement.

The fees referred to in Section 2.05(a) of the Receivables Purchase Agreement
are the following:

1. The Seller shall pay to the Agent a program fee (the "Program Fee") on the
unpaid Capital outstanding from time to time at the per annum rate of 0.125
percent.

2. The Seller shall pay to the Agent a purchaser fee (the "Purchaser Fee") on
the unpaid Capital outstanding from time to time at the per annum rate of 0.02
percent.

3. The Seller shall pay to the Agent a fee (the "Investor Investment Fee") for
the account of the Conduit on the amount of the entire Purchase Limit (whether
used or unused) at the per annum rate of 0.01 percent.

4. The Seller shall pay to the Agent a liquidity fee (the "Liquidity Fee") on
the entire Purchase Limit (whether used or unused) at a per annum rate equal to
the amount set forth below opposite the actual ratings for the Originator's
long-term public senior unsecured debt from time to time:


Public Debt Rating
by
Standard and Poor's and Moody's          Fee
BBB-/Baa3 (or higher)                    0.20 percent
BB+/Ba1 (or below)                       0.325 percent


In the event that the Standard & Poor's and Moody's ratings do not correlate as
shown above, the lower rating shall be used to determine the Liquidity Fee.



All fees are payable in arrears on each Settlement Date during the term of the
Receivables Purchase Agreement until the later of the Facility Termination Date
or the date on which the Capital and Yield of all Receivable Interests have been
paid in full. The Seller shall pay such fees to the Agent by deposit of the
appropriate amounts in a special account (account number 4063- 6695) maintained
with Citibank at its address specified on the signature page to the Receivables
Purchase Agreement.

This letter replaces the Fee Agreement between the parties dated as of September
30, 1997, as amended, and applies to fees accruing from and after the date
hereof.


If the foregoing accurately reflects your under-standing, please sign and return
the duplicate copy of this letter.

Very truly yours,

CITICORP NORTH AMERICA, INC.,
         as Agent

By:
Name:
Title:
    450 Mamaroneck Avenue
    Harrison, NY  10528
Attn:  Corporate Asset Funding
Facsimile No:  914-899-7890


Agreed and accepted as of the date first above written:

CL and P RECEIVABLES CORPORATION

By:
Name:
Title:
     107 Selden Street
     Berlin, Connecticut 06037
Attn:   Assistant Treasurer
Facsimile No:   (860) 665-5457
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.52
<SEQUENCE>8
<FILENAME>0008.txt
<DESCRIPTION>EXHIBIT 10.52
<TEXT>


                                                         January 2, 2001


Northeast Utilities
107 Selden Street
Berlin, CT  06037


Credit Suisse First Boston International
One Cabot Square
London E14 4QJ


Dear Sirs:

The purpose of this letter agreement (this "Confirmation") is to confirm the
terms and conditions of the Transaction entered into between Party A and Party B
through the Arranging Agent on the Trade Date specified below (the
"Transaction"). This Confirmation constitutes a "Confirmation" as referred to in
the Agreement specified below.

This Confirmation amends, restates and supersedes in its entirety the
Confirmation dated November 3, 1999 between the parties hereto.

1. The definitions and provisions contained in the 1991 ISDA Definitions (the
"1991 Swap Definitions"), as supplemented by the 1998 Supplement to the 1991
Swap Definitions (the "Swap Definitions") and in the 1996 ISDA Equity
Derivatives Definitions (the "Equity Definitions", together with the Swap
Definitions, the "Definitions") (in each case as published by the International
Swaps and Derivatives Association, Inc.) are incorporated into this
Confirmation. In the event of any inconsistency between the Swaps Definitions
and the Equity Definitions, the Equity Definitions will govern, and between the
Definitions and the provisions and this Confirmation, this Confirmation will
govern. References herein to a "Transaction" shall be deemed to be references to
a "Swap Transaction" for the purposes of the Swap Definitions.

If Party A and Party B are parties to the 1992 ISDA Master Agreement (the
"Agreement"), this Confirmation supplements, forms a part of, and is subject to
such Agreement. If Party A and Party B are not yet parties to the Agreement,
they agree to use their best efforts promptly to negotiate, execute, and deliver
the Agreement through the Arranging Agent, including Party A's standard form of
Schedule and Addendum for Physical Delivery of Shares attached thereto and made
a part thereof, with such modifications as Party A and Party B shall in good
faith agree. Upon execution and delivery by Party A and Party B of the
Agreement, this Confirmation shall supplement, form a part of, and be subject to
such Agreement. Until Party A and Party B execute and deliver the Agreement,
this Confirmation (together with all other Confirmations of Transactions
previously entered into between them, notwithstanding anything to the contrary
therein) shall supplement, form a part of, and be subject to the 1992 ISDA
Master Agreement, as if, on the Trade Date of the first such Transaction between
them, Party A and Party B had executed that agreement (incorporating therein
Party A's standard form of Schedule and Addendum for Physical Delivery of
Shares) and had specified that the Automatic Early Termination provisions
contained in Section 6(a) of such agreement would apply.

The Agreement and each Confirmation thereunder will be governed by and construed
in accordance with the laws of the State of New York without reference to choice
of law doctrine.

Party A and Party B expressly acknowledge that, in reliance upon the other
party's entering into the Transaction evidenced by this Confirmation, each party
has made (or refrained from making) substantial financial commitments and has
taken (or refrained from taking) other material actions.

All payments in connection with this Transaction shall be made in U.S.
Dollars.

In this Confirmation, "Party A" means Credit Suisse First Boston International,
"Party B" means Northeast Utilities and "Arranging Agent" means Credit Suisse
First Boston Corporation, acting solely in its capacity as Arranging Agent for
both Party A and Party B.



2.  The terms of the Transaction to which this Confirmation relates are as
follows:

General Terms:

Trade Date:            November 3, 1999

Effective Date:        November 3, 1999

Termination            Date: June 29, 2001, subject to adjustment in accordance
                       the Following Business Day Convention, the terms of the
                       Party B Net Settlement Option, the Party A Optional
                       Termination and the Party B Optional Termination.

Transaction Type:      Equity Forward

Seller:                Party A

Buyer:                 Party B (sometimes also referred to as the "Issuer").

Shares:                Common Shares, par value 5.00 dollars, of Party B.


Closing Price on the Exchange
As of the Business Day Prior
To the Trade Date:

21.0625 dollars

Notional Amount:

Initially, an amount equal to the Accumulated Adjusted Principal Share Amount,
up to an amount equal to the Principal Share Amount, in each case multiplied by
the Initial Share Price.

Principal Share Amount:

The number of Shares that represent purchase prices in an aggregate principal
amount of 100,000,000 dollars.

Accumulated Adjusted Principal Share Amount:

On any Valuation Date during the Initial Pricing Period the aggregate number of
Shares purchased by Party A up to the Principal Share Amount, for which full
payment has been made by Party A.

Initial Share Price:

The weighted average of the Average Share Prices for all Valuation Dates
occurring during the Initial Pricing Period or, if the last day of a Calculation
Period shall occur prior to the completion of the Initial Pricing Period, the
weighted average of the Average Share Price for all Valuation Dates occurring to
and including the last day of the relevant Calculation Period.

Average Share Price:

For any Valuation Date, the weighted average price of the Shares purchased by
Party A on such Valuation Date (plus a 0.04 per share commission charged by
Party A).

Initial Pricing Period:

The earlier to occur of (i) the Business Day that is 22 trading days prior to
the acquisition by Party B of Yankee Energy System, Inc. pursuant to the terms
of the Agreement and Plan of Merger dated as of June 14, 1999 between Yankee
Energy System, Inc. and Party B (the "Merger Agreement"), which acquisition is
currently expected to be April 15, 2000, subject to extension to such later date
as is permitted by the Merger Agreement, and for which Party B has provided
written notice to Party A through the Arranging Agent and (ii) the Exchange
Business Day on which Shares with an aggregate purchase price of 100,000,000
dollars have been purchased.

Valuation Date:

In respect of the Initial Pricing Period, any Exchange Business Day on which a
Market Disruption Event has not occurred. In respect of the Final Pricing
Period, any Exchange Business Day on which a Registration Suspension Event or
Market Disruption Event has not occurred.

Exclusion Period:

The first minute of trading and the last one-half hour before the scheduled
close of trading on the Exchange.

Calculation Period:

The period from and including a Calculation Period Interest Reset Date to but
excluding the next succeeding Calculation Period Interest Reset Date, provided
that, the first Calculation Period Interest Reset Date will commence on the
Effective Date and the final Calculation Interest Period will end on and exclude
the Termination Date.

Calculation Period
Interest Reset Dates:

The 15th day of each February, May, August and November, commencing on November
15, 1999.

Party A Calculation
Period Payment Dates:

The 15th day of each February, May, August and November, commencing on November
15, 1999.

Party A Payment:

The Dividend Amount (as defined below).

Party B Calculation
Period Payment Dates:

The 15th day of each February, May, August and November, commencing on November
15, 1999.

Party B Payment:

An amount in U.S. Dollars equal to the Interest Amount determined as of the
relevant Party B Calculation Period Payment Date.

Floating Rate Option:

USD-LIBOR-BBA

Spread:

2.5 percent per annum

Designated Maturity:     3 months

Interest Amount/Net
Interest Amount:

The payment obligation of Party A and Party B on such Calculation Period Payment
Dates in respect of the Dividend Amount (defined below) and any Interest Amounts
shall be netted, such that the party obligated to pay the greater amount shall
pay to the other party, through the Agent, an amount equal to the difference
between such amounts (the "Net Interest Amount").

For each Calculation Period during the Initial Pricing Period, an amount equal
to the product of (i) the weighted average Notional Amount for such Calculation
Period and (ii) USD-LIBOR-BBA, plus Spread, and for each Calculation Period
thereafter, the product of the Notional Amount and ISD-LIBOR-BBA, plus Spread
(subject to adjustment in all cases in accordance with the Following Business
Day Convention).

In the case either Net Cash Settlement or Net Share Settlement has been
designated as the Method of Settlement, the Notional Amount (and the accrued
interest attributable thereto) shall be reduced during the Final Reference Share
Price Pricing Period by amounts equal to the Net Proceeds (defined below)
received by the Selling Agent in respect to sales of the Shares, which reduction
shall occur on the Business Day on which such Net Proceeds are received as
immediately available funds by the Selling Agent. The Calculation Agent may rely
on the information provided pursuant to "(D)-Physical Settlement" hereunder
unless the Selling Agent delivers notice of any failure to receive an
anticipated payment in respect of the Shares sold or because of any Settlement
Disruption Event or an amendment to the time of payment in respect of any Shares
sold.

Dividend Amount:             An amount in USD equal to the sum of:

(i) The aggregate amount in respect of all dividends declared by the Issuer to
which the record holder of the Principal Share Amount (provided, however, that
for purpose of determining the Dividend Amount in the case either Net Cash
Settlement or Net Share Settlement has been designated as the Method of
Settlement, the Principal Share Amount shall be reduced by the number of Shares
sold by the Selling Agent prior to the record date in respect of any dividend
declared in respect of the Shares during the Final Reference Share Price Pricing
Period) would be entitled by virtue of the occurrence of a dividend record date
during the period from the Effective Date to the Settlement Date (other than any
Lagging Dividend Payment Amount or any dividends resulting in an Adjustment due
to a Potential Adjustment Event); and

(ii) An amount representing the interest that could have been earned on such
dividends described in (i) at a rate equal to USD-LIBOR-BBA for a designated
maturity of one month (any non-conforming period shall be linearly interpolated
by the Calculation Agent) for the period from the date that such dividends were
or would have been received, for which a Party A Calculation Period Payment Date
is a compounding date; the applicable compounding rate for each compounding
period is USD-LIBOR-BBA with a designated maturity of one month, for which the
Day Count Fraction is Actual/360 and the Following Business Day Convention will
apply, and for which compounding is applicable to the Settlement Date

Lagging Dividend Payment Amount:

In the event that a dividend is declared and payable to a holder of record prior
to the Settlement Date of this Transaction but such dividend has not been paid
on or before such Settlement Date, Party A agrees to pay to Party B through the
Arranging Agent an amount equal to the dividends received by Party A in respect
of the Number of Shares on the next succeeding Business Day after the payment is
received.

Day Count Fraction:

Actual/360

Additional Party B Payment:

On the Effective Date, Party B shall pay to Party A, through the Arranging
Agent, a structuring fee equal to 1,250,000 dollars.

Party A and Party B Final Payments

Termination Settlement
Payment Options:

In respect of the Termination Date (including, in
case any Event of Default or Termination Event has occurred, the related Early
Termination Date) Party B shall elect one of the following Settlement Options
(each a "Method of Settlement"):

(A)  Gross Physical Settlement:

Unless Party B has specified Net Cash Settlement or Net Share Settlement in
accordance with the terms hereof, on the Settlement Date, Party A will through
the Arranging Agent, deliver the Principal Share Amount to Party B, and Party B
will pay to Party A an amount equal to the sum of (i) the Notional Amount and
(ii) the Net Interest Amount.

(B)  Net Cash Settlement:

If Party B has specified Net Cash Settlement as the Method of Settlement, the
Selling Agent will sell a number of Shares equal to the Principal Share Amount,
in accordance with the terms hereof. On the related Settlement Date, Party A
will pay to Party B, an amount in USD equal to the product of the Principal
Share Amount and the Final Reference Share Price, and Party B will pay to Party
A, through the Arranging Agent, an amount in USD equal to the sum of (i) the
Notional Amount and (ii) the Net Interest Amount (which will reduce the amount
due from Party B if the Net Interest Amount is negative). The payment
obligations of Party A and Party B on such date in respect of such amounts shall
be netted, such that the party obligated to pay the greater amount shall pay to
the other party, through the Arranging Agent, an amount equal to the difference
between such amounts.

If Party A is required to pay such differences on such Settlement Date the
Selling Agent, from the aggregate Net Proceeds (defined below) of the sales of
Shares, will pay such difference to Party B in accordance with the preceding
sentence and pay the remainder of such proceeds to Party A. If Party B is
obligated to pay such difference, Party B will pay such amount to Party A
through the Arranging Agent and the Selling Agent will pay the aggregate Net
Proceeds of the sales of Shares to Party A.

(C)  Net Share Settlement:

If Party B has specified Net Share Settlement as the Method of Settlement, the
Selling Agent shall sell, in accordance with the terms hereof, such number of
Shares from the Principal Share Amount that will generate aggregate Net Proceeds
equal to the sum of (i) the Notional Amount, and (ii) the Net Interest Amount.

If during the Final Reference Share Price Pricing Period Party A receives
aggregate Net Proceeds equal to the sum of (i) the Notional Amount and (ii) the
Net Interest Amount (which will reduce the amount due from Party B if the Net
Interest Amount is negative) from the sale of a number of Shares that is less
than the Principal Share Amount, on the relevant Settlement Date the Selling
Agent shall deliver to Party B, a number of Shares equal to the excess of the
Principal Share Amount less such number of Shares sold by the Selling Agent
during such period (the "Party A Net Share Settlement Delivery").

If during the Final Reference Share Price Pricing Period the Selling Agent sells
a number of Shares equal to the Principal Share Amount and Party A receives
aggregate Net Proceeds from such sales in an amount that is less than the sum of
(i) the Notional Amount and (ii) the Net Interest Amount, Party A shall notify
Party B, through the Arranging Agent, of such fact, and by 4:30 p.m. New York
time on the second Exchange Business Day following such notification Party B
shall deliver a number of additional Shares (which Party A reasonably estimates
is equal in value to the Shortfall (defined below)) (the aggregate number of
additional Shares, delivered pursuant to this Net Share Settlement methodology,
the "Party B Net Share Settlement Delivery") to the Selling Agent, which will be
sold by the Selling Agent using the Offering Method determined pursuant to this
Confirmation as described below (to the extent that such sales are required to
generate aggregate Net Proceeds equal to the excess of (A) the sum of (i) the
Notional Amount and (ii) the Net Interest Amount over (B) the aggregate Net
Proceeds received by the Selling Agent from the sale of the Principal Share
Amount (for purposes of determining the obligation of Party B in connection with
Net Share Settlement, the term "Shortfall" at anytime and from time to time
means the US Dollar amount by which the sum of (i) the Notional Amount plus (ii)
the Net Interest Amount exceeds the aggregate Net Proceeds, if any, actually
received from the sale of (i) all or a portion of the Number of Shares plus (ii)
additional Shares delivered pursuant to the Party B Net Share Settlement
Delivery)). The Selling Agent shall use its best efforts to sell only such
additional Shares as shall generate aggregate Net Proceeds equal to the
Shortfall and return the excess Shares, if any, to Party B. In the event the
additional Shares delivered by Party B to the Selling Agent are sold for an
amount that is less than the Shortfall, the Selling Agent shall notify Party B,
through the Arranging Agent, of such fact and by 4:30 p.m. New York time on the
second Exchange Business Day following such notification Party B shall deliver
additional Shares to Party A, through the Arranging Agent, and, subject to Party
B's delivery of a Sale Revocation and Designation Notice (defined below) in
connection with Physical Settlement (defined below), Party B shall continue to
so deliver additional Shares upon notification until the aggregate Net Proceeds
received by the Selling Agent from the sale of all such Shares delivered by
Party B to Party A results in a Shortfall equal to zero; provided, however, that
notwithstanding Party B's obligations set forth in Appendix A hereto, in the
event that Party B is required pursuant to this paragraph to deliver additional
Shares and is unable to deliver additional Shares which are at the time of
delivery duly authorized, validly issued, fully paid and nonassessable and free
of any liens, claims or encumbrances (except liens, claims or encumbrances
pursuant to this Transaction), or Party B otherwise fails to deliver such
additional Shares and such inability or failure continues for five Exchange
Business Days (the "Net Share Settlement Incapacity Event"), such Net Share
Settlement shall be deemed terminated and Party B shall be obligated to pay
Party A within five Business Days from the date of the Net Share Settlement
Incapacity Event an amount in cash equal to the amount of the Shortfall that has
not been received from the sale of additional Shares as of the date of the Net
Share Settlement Incapacity Event and the Selling Agent shall deliver to Party B
any additional Shares received in respect of such Shortfall and not sold by the
Selling Agent as of the date of the Net Share Settlement Incapacity Event.

The term "Net Proceeds" in respect of a sale of Shares shall mean gross proceeds
of such sale less reasonable and customary discounts, fees, commissions and
expenses (the "Sale Expenses"), including, but not limited to, reasonable
commissions, discounts, fees and expenses customarily payable to underwriter(s)
in the case of a Registered Offering (defined below) or to a placement agent in
the case of an Exempt Offering (defined below), which may include reasonable
amounts customarily payable to the Selling Agent acting as underwriter or
placement agent, as well as any additional reasonable fees and expenses of any
dealers engaged by any such underwriter or placement agent which are customarily
payable.


(D)  Physical Settlement:

In the event Party B elects either Net Cash Settlement or Net Share Settlement,
the Selling Agent agrees to provide the Calculation Agent and Party B not later
than 5:00 PM on any Business Day on which it has sold Shares a report through
the Arranging Agent of the number of Shares sold, the average sale price and the
aggregate Net Proceeds received by the Selling Agent from such sales and a
reasonable breakdown of the Sales Expenses.

At any time after the designation of the Method of Sale, and if applicable, the
Offering Method, but prior to the execution and delivery of any underwriting
agreement with respect to the Shares, Party B may deliver to the Selling Agent
and to Party A through the Arranging Agent a revocation of the Net Cash
Settlement or Net Share Settlement Method of Settlement and request the
suspension of any further sales of Shares in respect of this Transaction by the
Selling Agent (a "Sale Revocation and Designation Notice") on the Business Day
immediately following delivery of such Sale Revocation and Designation Notice.
Receipt of the Sale Revocation and Designation Notice shall obligate the Selling
Agent to suspend any sales and solicitations of orders to buy the Shares but
shall not affect Party A's obligations to perform any settlement or delivery of
Shares in connection with sales previously agreed and sales which are pending
agreement on the date such Sale Revocation and Designation Notice is received
and which have been agreed before the close of business on such date. Upon
receipt of a Sale Revocation and Designation Notice, the Selling Agent shall
report to Party B the number of Shares that remain unsold (which may be some or
all of the Principal Share Amount and any additional Shares) as of the Business
Day succeeding delivery of the Sale Revocation and Designation Notice (the
"Remaining Shares"). In the event of delivery of the Sale Revocation and
Designation Notice, Party B shall be required to deliver to Party A through the
Arranging Agent a cash amount in respect of the Remaining Shares such that the
amount paid by Party B to Party A for the Remaining Shares plus the aggregate
Net Proceeds received by the Selling Agent from the sale of other Shares in
connection with the Net Cash Settlement or the Net Share Settlement equals (i)
the Notional Amount plus (ii) the Net Interest Amount, and Party A shall be
required to deliver to Party B the Remaining Shares. Settlement and delivery of
the Remaining Shares and payment therefor shall be made to the parties through
the Arranging Agent on the second Business Day after the delivery of such Sale
Revocation and Designation Notice.

(E)  Offering Method

Upon receipt of notice designating either Net Cash Settlement or Net Share
Settlement as the Method of Settlement, Party B may determine the offering
method (the "Offering Method") including whether the Shares to be sold will be
offered pursuant to a registration statement filed or to be filed (a "Registered
Offering") pursuant to the Securities Act of 1933 (the "1933 Act"), subject to
Party A's consent to a Registered Offering, which consent shall not be
unreasonably withheld.

If Party B determines the Shares will be offered in a Registered Offering and
Party A consents to a Registered Offering (which consent shall not be
unreasonably withheld), Party B (and to the extent required therein, Party A)
will use their reasonable efforts to comply in all material respects with the
Registration Procedures set forth in Appendix A attached hereto. In the event
that Party A, and its underwriter(s), upon advice from their respective counsel,
reasonably object to the form or substance of the registration statement, Party
A will deliver to Party B through the Arranging Agent a suspension request
stating the reason or reasons for such objection ("Suspension Request") and
Party B will either (i) modify or amend the registration statement to address
such reasonable objection(s) or (ii) suspend the preparation of such
registration statement with respect to the offering of the Principal Share
Amount. In addition, if such registration statement has been filed and
identifies either Party A or the Principal Share Amount and Party B determines
not to amend or modify, or that it cannot amend or modify the registration
statement to address Party A's or its underwriter(s)' reasonable objections,
Party B will withdraw such registration statement pursuant to Rule 259 of the
1933 Act if such registration statement relates solely to the offering of the
Principal Share Amount. In the event that no registration statement has been
filed identifying Party A or the Principal Share Amount and Party B determines
not to amend or modify, or that it cannot amend or modify the registration
statement to address Party A's or its underwriter(s)' reasonable objections,
Party B may within five Business Days of the delivery of the Suspension Request
determine whether the Principal Share Amount will be sold pursuant to an
offering that is exempt from the registration requirements of the 1933 Act (an
"Exempt Offering") as the means of sale in respect of either a Net Cash
Settlement or a Net Share Settlement or designate Gross Physical Settlement as
the Method of Settlement. If, however, a registration statement identifying
Party A or the Principal Share Amount has been filed and such registration
statement is not amended to address Party A's or its underwriter(s) reasonable
objections or has been withdrawn, as set forth herein, then not later than the
third succeeding Business Day from the receipt of the Suspension Request Party B
shall deliver to Party A through the Arranging Agent a notice designating Gross
Physical Settlement as the Method of Settlement.

In the event Party A delivers to Party B through the Arranging Agent a notice
that it will not consent to Party B's determination that the Principal Share
Amount are to be sold in a Registered Offering as provided herein, Party B may,
within five Business Days from the delivery of such notice, either revoke the
Net Cash Settlement or Net Share Settlement Method of Settlement and designate
Gross Physical Settlement as the Method of Settlement or elect to have Party A
pursue the contemplated sale of Shares in connection with Net Cash Settlement or
Net Share Settlement through an Exempt Offering. If an Exempt Offering is
pursued and Party B and its counsel object to the exemption to be relied on
pursuant to which Shares are to be sold by either Party A or the Selling Agent
or the opinion of counsel to Party A or any related documentation to be used in
connection with the Exempt Offering, Party B may deliver a notice of suspension
to Party A through the Arranging Agent and Party B may either (i) designate
Gross Physical Settlement as the Method of Settlement, (ii) renew its
solicitation of Party A's consent for a Registered Offering within five Business
Days of its delivery of any notice of objection or (iii) subject to the consent
of Party A and its counsel (which consent will not be unreasonably withheld),
request an alternative Exempt Offering.

Notwithstanding the foregoing, if an Event of Default or Termination Event has
occurred and is continuing with respect to Party B, Party B will be foreclosed
from making any determination as to the Offering Method and, subject to the
terms hereof and all applicable regulatory requirements, such determination
shall be in Party A's sole discretion. In connection with any Offering Method,
Party B shall co-operate with the reasonable requirements of Party A and its
underwriter(s) and Party A and its underwriter(s) shall co-operate with the
reasonable requests of Party B, including without limitation providing such
additional information as may reasonably be required so that any offering
document to be used does not contain any untrue statement of a material fact or
omit to state a material fact necessary in order to make the statements made in
such offering document, in light of the circumstances under which they were
made, not misleading.

Final Reference Share Price:

In respect of the number of Shares sold by the Selling Agent in connection with
a Net Cash Settlement or a Net Share Settlement, the average Net Proceeds per
Share of all sales of the Shares sold by the Selling Agent in (i) transactions
on the Exchange at the exchange prices received by the Selling Agent, if any,
(ii) a Registered Offering, if any, based on the public offering price and (iii)
transactions with recognized dealers or principals in the private placement
market which are unaffiliated with Party A pursuant to an Exempt Offering, if
any, and with or through which the Selling Agent effects any sales of Shares
pursuant to a Net Cash Settlement or Net Share Settlement, which may be
shortened by the delivery of a Sale Revocation and Designation Notice by Party
B.

Final Reference Share Price Pricing Period:

The period commencing on the Termination Date, and continuing until the
completion of the deliveries and any sales of Shares related thereto required
for Net Cash Settlement or Net Share Settlement.

Notwithstanding any other provisions set forth herein, in the event that the
Settlement Date for this transaction has been delayed to a date that is the one
year anniversary of the Termination Date for any reason, including, without
limitation, because a Net Share Settlement or a Net Cash Settlement has been
designated and the Final Reference Share Price Pricing Period has not been
completed, or in the case of any designated Method of Settlement because of any
Market Disruption Event or Settlement Disruption Event, then on the Business Day
next succeeding such anniversary, Party B shall be deemed to have delivered a
Sale Revocation and Designation Notice to Party A through the Arranging Agent
suspending any further sales pursuant to the terms and conditions set forth in
"(D)- Physical Settlement". Pursuant to such paragraph (D)- Physical Settlement,
on the date such Sale and Revocation and Designation Notice is delivered any
unsold Shares shall be deemed to be Remaining Shares and the payment and
delivery procedures set forth in such paragraph shall govern the payment and
delivery obligations of the parties

Settlement Dates:

To the extent not otherwise provided for hereunder, each of (i) the third
Exchange Business Day following the end of the Final Reference Share Price
Pricing Period in the case of Net Cash Settlement or Net Share Settlement, and
(ii) the next Exchange Business day following (a) the Termination Date that
Party B specifies or is deemed to have specified in a Termination Notice
hereunder specifying Gross Physical Settlement as the Method of Settlement or
(b) the Termination Date that is applicable in the event Party B is deemed to
have specified Gross Physical Settlement as the Method of Settlement in the case
of Gross Physical Settlement.

If a Settlement Disruption Event prevents a Net Share Settlement or a Net Cash
Settlement on the day that otherwise would have been the Settlement Date, then
the Settlement Date will be the first succeeding day on which settlement can
take place through the Clearance System unless a Settlement Disruption Event
prevents settlement on each of the ten (10) consecutive Clearance System
Business Days immediately following the original date that, but for such
Settlement Disruption Event, would have been the Settlement Date. In that case,
(a) if the Shares can be delivered in any other commercially reasonable manner,
then the Settlement Date will be the first day on which settlement of a sale of
Shares executed on that tenth (10th) Clearance System Business Day customarily
would take place using such other commercially reasonable manner of delivery
(which other manner of delivery will be deemed the Clearance System for purposes
of delivery of the relevant Shares), and (b) if the Shares cannot be delivered
in any other commercially reasonable manner, then the Settlement Date will be
postponed until delivery can be effected through the Clearance System or any
other commercially reasonable manner.

Settlement Disruption Event:

An event beyond the control of the parties as a result of which (i) the
Clearance System cannot clear the transfer of the Shares or (ii) in the case of
any Shares in physical certificate form, the payment system for bank fund
transfers (e.g. the Federal Reserve wire payment system) cannot make electronic
funds payments or otherwise transfer funds in the ordinary course.

Trading Day:

An Exchange Business Day other than an Exchange Business Day on which (i) a
Market Disruption Event occurs, or (ii) Party B, by notice to Party A, through
the Arranging Agent, by 8:30 a.m., New York time, determines, on the advice of
counsel respecting applicable federal securities laws, that such day shall not
be a Trading Day for one or more purposes of this Transaction specified by Party
B in accordance with such advice.

Exchange Business Day:

Any day that is (or, but for the occurrence of a Market Disruption Event, would
have been) a Trading Day on the Exchange other than a day on which trading on
the Exchange is scheduled to close prior to its regular weekday closing time.

Market Disruption Event:

The occurrence or existence on any Exchange Business Day of any suspension of or
material limitation imposed on trading (by reason of movement in price exceeding
limits permitted by the relevant exchange or otherwise) on the Exchange in the
Shares, if, in the reasonable determination of the Calculation Agent, such
suspension or limitation prevents such day from being used as a Trading Day.

Exchange:

The New York Stock Exchange.

Calculation Agent:

Party A, whose determinations and calculations hereunder as Calculation Agent
will be binding in the absence of manifest error. Subject to the foregoing, the
Calculation Agent will have no responsibility for good faith errors or omissions
in making any determination or calculation as provided herein.

Selling Agent:

Credit Suisse First Boston Corporation. When selling any Shares pursuant to this
Transaction, the Selling Agent shall determine the number of Shares to be sold
on any Trading Day and the price or prices at which such Shares are sold,
provided, however, that it shall act in a commercially reasonable manner and on
commercially reasonable terms, and shall comply with applicable securities laws,
rules and regulations, applicable to it and the Transaction (including sales
relating thereto).

Party A and Party B hereby acknowledge and agree that the execution and delivery
of this Confirmation by the Selling Agent does not constitute a commitment or an
obligation of the Selling Agent to purchase or sell any Shares or any other
security as principal.

Party A Optional Termination:

In addition to any other termination rights that Party A may have under the
Agreement, in the event of any Merger Event, the terms of which are
Share-for-Other or Share-for-Combined, pursuant to which a registered holder of
Shares is entitled to receive cash consideration in connection with the Merger
Event, Party A shall have the right within three Business Days after the payment
of any cash consideration in connection with the Merger Event, to cause the
Transaction to terminate in part before the originally scheduled Termination
Date by giving a Termination Notice to Party B through the Arranging Agent,
designating a Termination Date not earlier than five Business Days after the
delivery date of the Termination Notice and making the Partial Termination
Payments consisting of (i) a deemed payment by Party B to Party A by means of
the Merger Termination Payment (defined below) and (ii) the payment by Party A
to Party B of the Premium Cash Merger Payment (defined below) on the date
designated as the Termination Date.

"Merger Termination Payment" means an amount equal to the product of (i) the
Termination Share Amount (defined below) and (ii) the Per Share Cash Component
(defined below).

"Termination Share Amount" means the number of Shares equal to the product of
the Principal Share Amount and a fraction, the numerator of which is equal to
the Per Share Cash Component and the denominator if which is equal to the per
share total consideration of such offer.

"Per Share Cash Component" means the per share cash component of any offer to
purchase the Shares underlying the Merger Event.

"Premium Cash Merger Payment" means the amount equal to the product of (i) the
Termination Share Amount and (ii) the result of the per share total
consideration of any offer to purchase the Shares underlying the Merger Event,
minus the Initial Share Price, provided, however, that such difference shall not
be less than zero.

Party B Optional Termination:

In addition to any other termination rights that Party B may have under the
Agreement, Party B may elect to cause this Transaction to terminate in whole, or
in part, before the originally scheduled Termination Date for any reason by
giving a Termination Notice to Party A through the Arranging Agent during the
last five Business Days prior to any Party B Calculation Period Payment Date and
designating a Termination Date.

Except for the originally scheduled Termination Date for which no written notice
is required, no Termination Date designated hereunder may be set unless Party A
has received a written notice not less than 30 Business Days, in the case of
either Net Cash Settlement or Net Share Settlement and not less than two
Business Days in the case of Gross Physical Settlement in connection with the
relevant Method of Settlement. Subject to the terms of this Transaction, Party B
shall give Party A written notice, through the Arranging Agent of the Method of
Settlement.

Registration Notice:

Party B agrees that subsequent to the Effective Date it will not file any
registration statement, amend a previously filed registration statement or
commence any of the procedures set forth in Appendix A attached hereto with
respect to any Shares that may be sold in connection with Net Cash Settlement or
Net Share Settlement without providing notice to, and receiving the consent of,
Party A, which consent shall not be unreasonably withheld.

Sale Notification:

If the Selling Agent sells any Shares acquired pursuant to this Transaction in
the Initial Transaction or in either a Net Cash Settlement or a Net Share
Settlement, such sale(s) must be in accordance with the terms and conditions set
forth herein and the Selling Agent must notify Party B of such sale(s) as
provided herein by telephonic notice, promptly confirmed in writing.

Settlement Terms:

In respect of the Termination Date Party B shall specify whether Gross Physical
Settlement, Net Cash Settlement or Net Share Settlement is to apply. In the
event Party B fails to specify the Method of Settlement as provided herein,
Party B shall be deemed to have specified Gross Physical Settlement as the
Method of Settlement in respect of such Termination Date.

Adjustment Events:

Method of Adjustment:           Calculation Agent Adjustment.

Extraordinary Events:

Consequences of Merger Events:         Following each Merger Event:

(a)    Share-for-Share:                Alternative Obligation

(b)    Share-for-Other:                Alternative Obligation

(c)    Share-for-Combined:             Alternative Obligation

Nationalization or Insolvency:         Cancellation and Payment


3.  Miscellaneous

Transfer:

Neither the Transaction nor any interest or obligation in or under the
Transaction may be transferred (whether by way of security or otherwise) by
either party without the prior written consent of the other party, except that a
party may make a transfer of the Transaction pursuant to a consolidation or
amalgamation with, or merger with or into, or transfer of all or substantially
all its assets to, another entity, or upon or after any default of the other
party. Any purported transfer that is not in compliance with this paragraph will
be void.

Party B Representation and Covenants:

On each Exchange Business Day during a Final Reference Share Price Pricing
Period, Party B hereby represents and warrants to Party A that, unless Party B
notifies Party A, through the Arranging Agent, that such day is not a Trading
Day, it has publicly disclosed all material information necessary for Party B to
be able to purchase or sell Shares in compliance with applicable federal
securities laws. Party B hereby represents and warrants to Party A that: (i) it
has entered into this Transaction in connection with the Share repurchase
program announced publicly on June 3, 1998, and July 13, 1999 for purposes
consistent with those stated in such public disclosures and (ii) on the Trade
Date and on the Settlement Date, Party B has available to it before and
immediately after any purchase of Shares pursuant to this Transaction such
orders, consents or other authorities as may be required by the SEC pursuant to
rules and regulations of the Public Utility Holding Company Act of 1935 (the
"1935 Act"), with respect to the execution, delivery and performance of the
forward purchase obligations under this Transaction , and (iii) on the filing
date of any registration statement or the commencement of any offer not
involving a public offering in the case of any Net Cash Settlement or Net Share
Settlement, the offering of Shares (or New Shares as provided herein), on the
Settlement Date and on each day during the Final Share Price Pricing Period,
will be made pursuant to the orders, consents or other authorizations that may
be required under the rules and regulations promulgated under the 1935 Act ,
which will be in full force and effect and, to Party B's knowledge, will be free
of any pending or overtly threatened proceedings contemplating the revocation or
modification of such order; provided, however, in lieu of making the
representations and warranties and agreeing the covenants set forth in clauses
(i) and (ii), delivering an opinion of counsel addressing such matters as Party
A may reasonably request and are customarily provided in connection with the
purchase and sale of common stock, including, without limitation, that Party B
is not subject to the 1935 Act, that no authorisation, consent or notice is
required in order for Party B to perform any purchase or sale obligation with
respect to the Shares other than any authorisations, consents, filings or
notices that may be required under the 1933 Act and any applicable state law
that may be required for the authorisation of any purchase of Shares. Party B
also represents that it is not subject to regulation by any state, county or
municipal agency, authority, board, council or similar body having authority or
jurisdiction over Party B within the meaning of any applicable state law, order
or regulation or any municipal government or authority with the capacity or
power to regulate electric utility or gas utility companies ("Local Regulators")
and all approvals and consents from or notices to any Local Regulator required
by Party B to execute and deliver the Confirmation and to perform the
Transaction and the related transactions contemplated thereby have been received
or given and remain in full force and effect.

Party B hereby agrees that from the Trade Date through and including the
Settlement Date, it will comply in all material respects with all corporate or,
if applicable, similar laws affecting its ability to perform its repurchase
obligations under this Transaction, including any such requirements of the SEC
or any Local Regulator. In the event that Party B reasonably believes that at
any time during the term of this Transaction Party B would be prohibited from
performing its repurchase obligations under this Transaction as currently
contemplated without delivering notice to or obtaining the consent of the SEC or
any Local Regulator, Party B will provide notice thereof through the Arranging
Agent and designate a date for Settlement, which shall be a date on which Party
B still satisfies such requirements and for which no notice or consent is
required to perform the repurchase obligations contemplated by this Transaction.

Other Provisions:

If, notwithstanding any other provision of this Confirmation, this Transaction
is terminated at a time when any law, rule or regulation, including without
limitation, the 1935 Act or any applicable state law, order or regulation,
prevents Party B from repurchasing the Number of Shares, Gross Physical
Settlement shall not apply. Each party agrees that if delivery of the Shares on
any Settlement Date is subject to any restriction imposed by a regulatory
authority (other than the federal securities laws and the rules of the SEC
affecting Registered or Exempt Offerings) that materially restricts or prevents
delivery of any such Shares, the parties will negotiate in good faith a
procedure to effect settlement of such affected Shares in a manner which
complies with any relevant rules of such regulatory authority.

Party B Undertakings:

Party B hereby agrees that if it is the object of any merger, consolidation,
amalgamation of Party B with or into another entity (and Party B is not the
surviving entity) or a third party acquires such number of Shares or the right
to control such number of Shares (or the voting power thereof) and the
acquisition of such number of Shares or the voting power with respect thereto
results in the transfer of control of Party B (within the meaning of Rule 405 of
the 1933 Act), then in the event that (i) Alternative Obligation is elected in
respect of Consequences of Merger Event - Share- for-Combined and (ii) a
material portion of Shares are exchanged or exchangeable for New Shares (as
defined in the Equity Definitions), then Party B shall cause the issuer of such
New Shares to undertake and perform each and every obligation and satisfy each
and every condition precedent of Party B arising under this Confirmation with
respect to any purchase or sale of the Shares, including, but not limited to,
the representations, agreements, and covenants that relate to the Shares and any
purchase or sale thereof, the exercise or election of any Method of Settlement
or Offering Method, the participation and preparation of any materials relating
to any registration statement in connection with any Registered Offering of
Shares, and the determinations and decisions relating thereto, modified in all
cases, mutatis mutandis, to apply to the issuer and to the New Shares. Any
failure by Party B to cause the issuer of New Shares to achieve any
undertakings, performance or satisfaction of any such obligations to the
reasonable satisfaction of Party A shall be deemed an irrevocable exercise of
Gross Physical Settlement option as the Method of Settlement that shall be
deemed to supersede any prior exercise of any Method of Settlement Option.

Cessation and Suspension:

If at any time during the Term of the Transaction Party B is subject to any
legal or regulatory requirements ("Legal Requirements") or any directly related
policies or procedures adopted by Party B with respect to the Legal
Requirements, which, in Party B's reasonable judgement requires it, or Party A
if acting on behalf of Party B, to refrain from purchasing or selling Shares on
any Trading Day, Party B shall give prompt telephonic notice of the cessation of
any further purchases or sales of Shares and the suspension of any further
purchases or sales of Shares (each, a "Cessation Notice"), which cessation and
suspension shall remain in effect until further notice from Party B. Each
telephonic notice of a Cessation Notice shall be promptly confirmed in writing.
Notwithstanding the foregoing, the delivery of a Cessation Notice shall not
affect any obligation of Party A to deliver or receive Shares in settlement of
any purchase or sale of Shares agreed prior to the delivery of the Cessation
Notice.

Issuer Repurchase Safe Harbor:

Assuming that Party B's conduct complies with the requirements of rule 10b-18
promulgated under the 1934 Act ("Rule 10b-18"), Party A will use its best
efforts to comply with the manner of purchase, time, price and volume
requirements of Rule 10b-18 in connection with its purchase of Shares under this
Transaction.

Limited Liability:

No shareholder or trustee of Party B shall be held to any liability whatever for
the payment of any sum of money or for damages or otherwise under this
Confirmation, and this Confirmation shall not be enforceable against any such
trustee in their or his or her individual capacities or capacity and this
Confirmation shall be enforceable against the trustees of Party B only as such,
and every person, firm, association, trust or corporation having any claim or
demand arising under this Confirmation and relating to Party B, its shareholders
or trustees shall look solely to the trust estate of Party B for the payment or
satisfaction thereof.

Securities Contract:

Each party hereby represents to the other that it intends this Transaction to be
a securities contract within the meaning of Section 741 of Bankruptcy Code, as
amended (11 U.S.C. Section 741).

4.  Credit Support Documents:    Party A:  None

                                 Party B:  Collateral Appendix

5.  Account Details:

Payments to Party A:  Citibank, NY

ABA Number:  021-000-089
A/C:         Credit Suisse First Boston Corp.
A/C:         40804388
FFC:         Northeast Utilities
A/C Number:  2GA3P0

Payments to Party B:      Fleet

ABA Number:  011500010
Acct No.:    50252481
Ref.:        NU Share Repurchase

Delivery of Shares to Party A:

To be advised by written notice within 30 days of the Trade Date

Delivery of Shares to Party B:

To be advised by written notice within 30 days of the Trade Date

6.  U.S. Private Placement Representations

As this Transaction may constitute the sale by Party A to Party B in the case of
this Transaction, and by Party B to Party A in the case of the Number of Shares,
in each case, through Arranging Agent, of a Security or Securities (as defined
in the 1933 Act), in addition to the representations contained in Section 3 of
the Agreement, Party B hereby represents to Party A in respect of this
Transaction and Party A represents to Party B in respect of the Number of Shares
(for purposes of this Section 6, the representation of Party A with respect to
Securities shall be made with respect to the Number of Shares and the
representation of Party B shall be made with respect to the Transaction, in
accordance with Section 3 of the Agreement), as follows:

(a) Each party is acquiring such Securities through the Arranging Agent for its
own account as principal, for investment purposes only, and not with a view to,
or for, resale, distribution or fractionalization thereof, in whole or in part,
and no other person has a direct or indirect beneficial interest in any such
Securities acquired by it through the Arranging Agent;

(b) Each party understands that the offer and sale by the other party, through
the Arranging Agent, of such Securities are intended to be exempt from
registration under the 1933 Act, by virtue of Section 4(2) thereof. In
furtherance thereof, each Party represents and warrants that (i) it has the
financial ability to bear the economic risk of its investment and has adequate
means of providing for its current needs and other contingencies, (ii) it is
experienced in investing in forward purchase contracts and similar instruments
and has determined that such securities are a suitable investment for it, and
(iii) it is an institution that qualifies as an "accredited investor" as that
term is defined in Regulation D under the 1933 Act; and

(c) Each party has been given the opportunity to ask questions of, and receive
answers from, the other party through the Arranging Agent concerning the terms
and conditions of such Securities and concerning the financial condition and
business operations of the other party and has been given the opportunity to
obtain such additional information necessary in order for each party to evaluate
the merits and risks of purchase of such Securities to the extent the issuer of
the Securities possesses such information or can acquire it without unreasonable
effort or expense.

(d)  The Shares shall bear a legend substantially as set forth below:

THE SECURITIES REPRESENTED BY THIS CERTIFICATE HAVE NOT BEEN REGISTERED UNDER
THE UNITED STATES SECURITIES ACT OF 1933 (THE "ACT") OR ANY STATE SECURITIES
LAWS ("BLUE SKY LAW") ANY MAY NOT BE SOLD, TRANSFERRED, PLEDGED OR OTHERWISE
DISPOSED OF WITHOUT REGISTRATION UNDER THE ACT AND UNDER APPLICABLE BLUE SKY LAW
OR UNLESS SUCH SALE, TRANSFER, PLEDGE OR OTHER DISPOSITION IS EXEMPT FROM
REGISTRATION THEREUNDER.

THE SALE, TRANSFER, PLEDGE OR OTHER DISPOSTION OF THIS SECURITY IS SUBJECT TO
THE AGREEMENT BETWEEN THE ISSUER, CREDIT SUISSE FIRST BOSTON CORPORATION, AS
ARRANGING AGENT, AND CREDIT SUISSE FINANCIAL PRODUCTS DATED NOVEMBER 3, 1999
(THE "AGREEMENT").

Each party hereby acknowledges that it understands and agrees that disposition
of any such Securities is restricted in the manner set forth under the
Agreement, the 1933 Act and state securities laws. For example, such Securities
have not been registered under the 1933 Act or under the securities laws of
certain states and, therefore, cannot be resold, pledged, assigned or otherwise
disposed of unless they have been registered under the 1933 Act and under the
applicable laws of such states or an exemption from such registration is
available.

9.  Matters relating to the Arranging Agent:

(a) As a broker-dealer registered with the SEC, Credit Suisse First Boston
Corporation in its capacity as Arranging Agent will be responsible for (i)
effecting this Transaction, (ii) issuing all required confirmations and
statements to Party A and Party B, (iii) maintaining books and records relating
to this Transaction as required by Rules 17a-3 and 17a-4 under the Securities
Exchange Act of 1934 (the "1934 Act") and (iv) unless otherwise requested by
Party B, receiving, delivering, and safeguarding Party B's funds and any
securities in connection with this Transaction, in compliance with Rule 15c3-3
under the Exchange Act.

(b) Credit Suisse First Boston Corporation is acting in connection with this
Transaction solely in its capacity as Arranging Agent for Party A and Party B
pursuant to instructions from Party A and Party B. Credit Suisse First Boston
Corporation shall have no responsibility or personal liability to Party A or
Party B arising from any failure by Party A or Party B to pay or perform any
obligations hereunder, or to monitor or enforce compliance by Party A or Party B
with any obligation hereunder, including without limitation, any obligations to
maintain collateral. Each of Party A and Party B agrees to proceed solely
against the other to collect or recover any securities or monies owing to it in
connection with or as a result of this Transaction. Credit Suisse First Boston
Corporation shall otherwise have no liability in respect of this Transaction,
except for its gross negligence or wilful misconduct in performing its duties as
Arranging Agent.

(c) Any and all notices, demands, or communications of any kind relating to this
Transaction, including without limitation, any option exercise notice, between
Party A and Party B shall be transmitted exclusively through the Arranging Agent
at the following address:

Credit Suisse First Boston Corporation
11 Madison Avenue
New York, NY 10010
Facsimile No.: (212) 325-8175
Telephone No.: (212) 325-8678
Attention: Ricardo Harewood

(d) The date and time of the Transaction evidenced hereby will be furnished by
the Arranging Agent to Party A and Party B upon written request.

(e) The Arranging Agent will furnish to Party B upon written request a statement
as to the source and amount of any remuneration received or to be received by
the Arranging Agent in connection with the Transaction evidenced hereby.

(f) Party A and Party B each represents and agrees (i) that this Transaction is
not unsuitable for it in the light of such party's financial situation,
investment objectives and needs and (ii) that it is entering into this
Transaction in reliance upon such tax, accounting, regulatory, legal and
financial advice as it deems necessary and not upon any view expressed by the
other or the Arranging Agent.

(g) Party A and Party B each is aware of and agrees to be bound by the rules of
the National Association of Securities Dealers, Inc. ("NASD") applicable to the
Transaction and is aware of and agrees not to violate, either alone or in
concert with others, any applicable position or exercise limits established by
the NASD.

Credit Suisse Financial Products is regulated by The Securities and Futures
Authority and has entered into this transaction as principal.





Please confirm that the foregoing correctly sets forth the terms of the
agreement by executing the copy of this Confirmation enclosed for that purpose
and returning it to us.


Yours sincerely,

CREDIT SUISSE FIRST BOSTON CORPORATION,
solely in its capacities as Arranging Agent and Selling Agent


By:
Name:
Title:


CREDIT SUISSE FIRST BOSTON INTERNATIONAL


By:
Name:
Title:


Confirmed as of the date first written above:

NORTHEAST UTILITIES


By:
Name:
Title:



                            APPENDIX A
                                TO
                     CONFIRMATION OF TRANSACTION
                             BETWEEN
               CREDIT SUISSE FIRST BOSTON INTERNATIONAL
                               AND
                       NORTHEAST UTILITIES
                   CSFBi REFERENCE NO. 5672645

Unless otherwise agreed in writing by Party A and Party B with respect to
specific sales of Shares by the Selling Agent or specific Shares to be delivered
to the Selling Agent by Party B, the provisions of this Appendix A shall apply
to all Shares in satisfaction of a Party B Net Cash Settlement or Net Share
Settlement Delivery including the resale of the Number of Shares which were
acquired in a transaction not involving any public offering and, in the case of
Net Share Settlement, any additional Shares (collectively, the "Shares").

(a) Party B shall have reserved and have available, out of its authorized but
unissued capital stock, for the purpose of effecting the payment of any Party B
Net Cash or Net Share Settlement Delivery in Shares as provided in the
Confirmation, the full number of shares of capital stock that would then be
issuable with respect to such payment.

(b) Party B shall have filed with the SEC a registration statement on Form S-3
or such other form as is acceptable to Party A; such registration statement
shall have been declared effective with respect to such Shares (the
"Registration Statement") and no stop order suspending the effectiveness of the
Registration Statement shall be in effect, and no proceedings for such purpose
shall be pending before or threatened by the Commission. Party B, at the request
of Party A, shall deliver an underwriting agreement naming Party A, or its
designee, as underwriter, together with such other agreements, certificates and
instruments as Party A may reasonably require either pursuant to such
underwriting agreement or as are customarily provided together with such
underwriting agreement.

(c) Party B shall have registered or qualified such Shares under such securities
or "blue sky" laws of such States and other jurisdictions in the United States
and Puerto Rico as Party A or any underwriter shall have reasonably requested,
and shall have done any and all other acts and things as may be reasonably
necessary to be done by Party B to enable Party A or any underwriter to
consummate the disposition in such jurisdictions of the Shares covered by the
Registration Statement; provided that Party B shall not be required to make any
filing or take any action as a result of this paragraph (c) that would required
it to qualify as a foreign corporation or file a general consent to service of
process in any jurisdiction.

(d) Party B shall have caused such Shares and the issuance thereof to be
registered with or approved by such other governmental agencies or authorities
in the United States as may be reasonably necessary to be done by Party B to
enable Party A or any underwriter to consummate the disposition of such Shares.

(e) Party B shall have (i) given Party A and its underwriter(s), if any, and
their respective counsel and accountants, the opportunity to participate in the
preparation of all materials filed with the SEC or any other governmental agency
(the "Filed Materials") prior to the first day of such Final Reference Share
Price Pricing Period, (ii) furnished to each of them copies of all such Filed
Materials (and all documents incorporated therein by reference) sufficiently in
advance of filing to provide them with a reasonable opportunity to review such
documents and comment thereon, (iii) given each of them such opportunities to
discuss the business of Party B with its officers and the independent public
accountants who have issued a report on its financial statement as shall be
reasonably necessary, in the opinion of Party A and such underwriter(s) or their
respective counsel, to conduct a reasonable investigation (within the meaning of
the 1933 Act, as amended) with respect to such Filed Materials, (iv) delivered
to Party A and its underwriter(s), if any, the financial statements of Party B
filed with the SEC, (v) included in such Filed Materials material, furnished to
Party B in writing, which in the reasonable judgement of Party A or its
underwriter(s), if any, subject to the consent of Party B (which shall not be
unreasonably withheld), should be included with respect to Party A, Party A's
underwriter(s) and the "Plan of Distribution", including, without limitation,
language to the effect that the holding by Party A of the Shares is not to be
construed as a recommendation by Party A of the investment quality thereof and
(vi) if requested by Party A, deleted from such Filed Materials any reference to
Party A if in the written opinion of counsel to Party A, in form and substance
to Party B, such reference to Party A by name or otherwise is not required by
the 1933 Act or any similar Federal statute then in force.

(f) Party B shall have furnished to Party A and any underwriter, addressed to
Party A and any such underwriter and dated the first day of the Final Reference
Share Price Pricing Period, (i) an opinion of counsel for Party B (which opinion
may be from internal counsel for Party B) and (ii) a "cold comfort" letter
signed by the independent public accountants who have issued a report on Party
B's financial statements included in such Registration Statement, covering
substantially the same matters with respect to such Shares and the offering,
sale and issuance thereof as are customarily covered in opinions of issuer's
counsel and in accountants' letters delivered to underwriter(s) in underwritten
public offerings of securities and, in the case of the accountants' letter, such
other financial matters as Party A may have reasonably requested.

(g) Party B shall have complied with all applicable provisions of the 1933 Act
and the 1934 Act and the Public Utility Holding Company Act of 1935, all
applicable rules of the SEC and all other applicable laws, rules and regulations
of any governmental or regulatory authority with respect to such Filing
Materials and such Shares and the offering, sale and issuance thereof.

(h) Party B shall have caused all such Shares to be listed on the Exchange and
on each securities exchange on which Party B has caused similar securities
issued by Party B to be listed.

(i) Party B shall have provided a transfer agent and registrar for such Shares.

(j) Party B shall have taken such other actions as Party A or any underwriter of
such Shares shall have reasonably requested in order to expedite or facilitate
the disposition of such Shares.

(k) Party B shall provide Party A and its underwriter(s), if any, with indemnity
and contribution in form and substance acceptable to Party A covering such
matters relating to the Shares, the Filed Materials, and such other matters as
Party A shall reasonably request.

(l) Party B shall have paid all customary costs and expenses reasonably incurred
in connection with the foregoing, provided, that unless otherwise agreed, Party
A and its underwriter(s) shall be responsible for the fees and expenses of their
respective counsel.

(m) Party B shall deliver all such registered Shares through the Clearance
System.

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.53.1
<SEQUENCE>9
<FILENAME>0009.txt
<DESCRIPTION>EXHIBIT 10.53.1
<TEXT>


                                 FIRST AMENDMENT

FIRST AMENDMENT, dated as of January 1, 2001 to the equity forward transaction
(the "Transaction") between Northeast Utilities ("NU") and Bank One, NA
(Illinois) evidenced by the Confirmation dated December 9, 1999 (the
"Confirmation"). Capitalized terms used and not defined herein have the meaning
given to them in the Confirmation.

WHEREAS, the parties hereto desire to amend the Transaction as described herein:

NOW THEREFORE, in consideration of the mutual agreements herein, the parties
hereto agree as follows:

1. The Termination Date of the Transaction shall be June 29, 2001, subject to
adjustment in accordance with the Modified Following Business Day Convention,
the terms of the Party B Net Settlement Option, the Party A Optional Termination
and the Party B Optional Termination.

2. January 15, 2001, April 15, 2001 and the Termination Date shall be Party A
Calculation Period Payment Dates with respect to this Transaction.

3. January 2, 2001, January 15, 2001 and April 15, 2001 shall be Calculation
Period Interest Reset Dates with respect to this Transaction.

4.  With effect from the Calculation Period commencing January 4, 2001, the
Spread shall be 2.00 percent .

5. This First Amendment constitutes the entire Agreement and understanding of
the parties with respect to its subject matter and supersedes all oral
communications and prior writings with respect thereto.

6. No amendment, modification or waiver in respect of this First Amendment will
be effective unless in writing (including a writing evidenced by a facsimile
transmission) and executed by each of the parties.

7.  This Amendment may be executed in counterparts each of which shall be
deemed to be an original.

8. This Amendment will be governed by and construed in accordance with the laws
of the State of New York (without reference to choice of law doctrine).

9. Limited Liability. No shareholder or trustee of NU shall be held to any
liability whatever for the payment of any sum of money or for damages or
otherwise under this Amendment, and this Amendment shall not be enforceable
against any such trustee in their or his or her individual capacities or
capacity and this Amendment shall be enforceable against the trustees of NU only
as such, and every person, firm, association, trust or corporation having any
claim or demand arising under this Amendment and relating to NU, its
shareholders or trustees shall look solely to the trust estate of NU for the
payment or satisfaction thereof.


IN WITNESS WHEREOF, the parties have executed this Amendment as of the date
first above written.

NORTHEAST UTILITIES               BANK ONE, NA

By:                               By:
Name:                             Name:
Title:                            Title:
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.54
<SEQUENCE>10
<FILENAME>0010.txt
<DESCRIPTION>EXHIBIT 10.54
<TEXT>

EXECUTION COPY


                                U.S.$865,500,000

                                CREDIT AGREEMENT

                            Dated as of March 9, 2000

                                      Among

                          NORTHEAST GENERATION COMPANY

                                   AS BORROWER

                                       and

                        THE INITIAL LENDERS NAMED HEREIN

                               AS INITIAL LENDERS

                                       and

                                 CITIBANK, N.A.

                             AS ADMINISTRATIVE AGENT

                                       and

                                 CITIBANK, N.A.

                               AS COLLATERAL AGENT

                                       and

                                 CITIBANK, N.A.

                               AS DEPOSITORY BANK

<PAGE>

                                TABLE OF CONTENTS

SECTION                                                                     PAGE

                                    ARTICLE I
                        DEFINITIONS AND ACCOUNTING TERMS

1.01.    Certain Defined Terms                                                1
1.02.    Computation of Time Period                                          27
1.03.    Accounting Terms                                                    27

                                   ARTICLE II
                        AMOUNTS AND TERMS OF THE ADVANCES

2.01.    The Advances                                                        28
2.02.    Making the Advances                                                 28
2.03.    Repayment of Advances                                               30
2.04.    Adjustments of the Commitments                                      30
2.05.    Prepayments                                                         30
2.06.    Interest                                                            31
2.07.    Fees                                                                32
2.08.    Conversion of Advances                                              32
2.09.    Increased Costs, Etc.                                               33
2.10.    Payments and Computations                                           35
2.11.    Taxes                                                               36
2.12.    Sharing of Payments, Etc.                                           38
2.13.    Use of Proceeds                                                     39
2.14.    Defaulting Lenders                                                  39
2.15.    Depository Trust Corporation Eligibility                            42

                                   ARTICLE III
                              CONDITIONS OF LENDING

3.01.    Conditions Precedent to the Borrowing Date                          42
3.02.    Determinations Under Section 3.01                                   51

                                        i

<PAGE>

                                   ARTICLE IV
                             SPECIAL ACCOUNTS SYSTEM

4.01.    Creation of the Collateral Accounts                                 51
4.02.    Revenues Account                                                    53
4.03.    Casualty Account                                                    55
4.04.    Investment of Funds in Collateral Accounts                          57
4.05.    Interest                                                            58
4.06.    Reports to the Borrower and the Lenders                             58
4.07.    Books and Records                                                   58

                                    ARTICLE V
                         REPRESENTATIONS AND WARRANTIES

5.01.    Representations and Warranties of the Borrower                      58

                                   ARTICLE VI
                            COVENANTS OF THE BORROWER

6.01.    Affirmative Covenants                                               65
6.02.    Negative Covenants                                                  71
6.03.    Reporting Requirements                                              73
6.04.    Financial Covenants                                                 76

                                   ARTICLE VII
                                EVENTS OF DEFAULT

7.01.    Events of Default                                                   77

                                  ARTICLE VIII
                                   THE AGENTS

8.01.    Authorization and Action                                            81
8.02.    Agent's Reliance, Etc.                                              81
8.03.    Citibank and Affiliates                                             83
8.04.    Lender Credit Decision                                              83
8.05.    Indemnification                                                     83
8.06.    Successor Agents                                                    84
8.07.    Intercreditor Arrangements                                          85
8.08.    Co-Arrangers                                                        86

                                       ii

<PAGE>


                                   ARTICLE IX
                                  MISCELLANEOUS

9.01.    Amendments, Etc.                                                    86
9.02.    Notices, Etc.                                                       87
9.03.    No Waiver; Remedies                                                 87
9.04.    Costs, Expenses, Indemnification                                    88
9.05.    Right of Set-off                                                    89
9.06.    Binding Effect                                                      90
9.07.    Assignments and Participations                                      90
9.08.    Execution in Counterparts                                           93
9.09.    Confidentiality                                                     93
9.10.    Jurisdiction, Etc.                                                  93
9.11.    Governing Law                                                       94
9.12.    Waiver of Jury Trial                                                94

                                       iii

<PAGE>

                                    SCHEDULES

Schedule I              Commitments and Applicable Lending Offices

Schedule II             Properties

Schedule 3.01(e)        Information

Schedule 5.01(d)(A-1)   CL&P Governmental Authorizations

Schedule 5.01(d)(A-2)   WMECO Governmental Authorizations

Schedule 5.01(d)(B)     Third Party Consents

Schedule 5.01(q)        Plans, Multiemployer Plans and Welfare Plans

Schedule 5.01(dd)       Liens

Schedule 5.01(ee)       Material Contracts

Schedule 5              Insurance


                                    EXHIBITS

Exhibit A-1 - Form of Tranche A Note

Exhibit A-2 - Form of Tranche B Note

Exhibit B   - Form of Notice of Borrowing

Exhibit C   - Form of Assignment and Acceptance

Exhibit D-1 - Form of Tranche A Borrower Security Agreement

Exhibit D-2 - Form of Tranche B Borrower Security Agreement

Exhibit E-1 - Form of Tranche A Enterprises Pledge Agreement

Exhibit E-2 - Form of Tranche B Enterprises Pledge Agreement

Exhibit F-1 - Form of Tranche A Mortgage

Exhibit F-2 - Form of Tranche B Mortgage

Exhibit G   - Form of Flow of Funds Memorandum

Exhibit H   - Form of Sponsor Agreement

Exhibit I   - Form of Annual Operating Budget

Exhibit J   - Form of Solvency Certificates

                                       iv

<PAGE>

                                                                  EXECUTION COPY

                                CREDIT AGREEMENT

         CREDIT AGREEMENT dated as of March 9, 2000 among Northeast Generation
Company, a Connecticut corporation (the "BORROWER"), the banks, financial
institutions and other institutional lenders listed on the signature pages
hereof as the Tranche A Initial Lenders (the "TRANCHE A INITIAL LENDERS"), the
banks, financial institutions and other institutional lenders listed on the
signature pages hereof as the Tranche B Initial Lenders (the "TRANCHE B INITIAL
LENDERS"), Citibank, N.A. ("CITIBANK"), as administrative agent (together with
any successor appointed pursuant to Article VIII, the "ADMINISTRATIVE AGENT")
for the Lenders (as hereinafter defined), Citibank, as Collateral Agent
(together with any successor appointed pursuant to Article VIII, the "COLLATERAL
AGENT") for the Secured Parties (as hereinafter defined) and Citibank, as the
Depositary Bank (the "DEPOSITARY BANK").

PRELIMINARY STATEMENTS:

         (1) The Borrower intends to acquire the generating assets owned by The
Connecticut Light and Power Company, a Connecticut corporation ("CL&P"), and
Western Massachusetts Electric Company, a Massachusetts corporation ("WMECO"),
that were awarded to the Borrower on July 2, 1999 (the "AWARD DATE") in the
auction conducted by The Connecticut Department of Public Utility Control and
its agent, J.P. Morgan, in accordance with Public Act 98-28 (of the State of
Connecticut), "An Act Concerning Electric Restructuring", on behalf of CL&P.

         (2) The Borrower has requested that the Lenders make advances to the
Borrower in an aggregate amount of $865,500,000 for the purpose of paying the
purchase price of such generating assets and otherwise as outlined herein, and
the Lenders have indicated their willingness to agree to lend such amount for
such purpose and on the terms and conditions of this Agreement.

         NOW, THEREFORE, in consideration of the premises and of the mutual
covenants and agreements contained herein, the parties hereto hereby agree as
follows:

                                    ARTICLE I

                        DEFINITIONS AND ACCOUNTING TERMS

         SECTION 1.01. CERTAIN DEFINED TERMS. As used in this Agreement, the
following terms shall have the following meanings (such meanings to be equally
applicable to both the singular and plural forms of the terms defined):

                  "ACQUISITION" means, collectively, the CL&P Acquisition and
         the WMECO Acquisition.

                  "ACQUISITION DATE" means the date on which the Acquisition is
         consummated.

                                        1

<PAGE>

                  "ACQUISITION DOCUMENTS" means the Purchase and Sale
         Agreements, the Assumption Agreements, the Interconnection Agreements,
         the Closing Agreement, the Assignment and Assumption Agreements and the
         Asset Demarcation Agreements.

                  "ADMINISTRATIVE AGENT" has the meaning specified in the
         recital of parties to this Agreement.

                  "ADMINISTRATIVE AGENT'S ACCOUNT" means the account of the
         Administrative Agent maintained by the Administrative Agent at its
         office at 399 Park Avenue, New York, New York Account No. 36852248,
         Reference: NAIB-Medium Term Finance.

                  "ADVANCE" means either a Tranche A Advance or a Tranche B
         Advance by a Lender to the Borrower pursuant to Article II, and refers
         to a Base Rate Advance or a Eurodollar Rate Advance (each of which
         shall be a "Type" of Advance).

                  "AFFILIATE" means, as to any Person, any other Person that,
         directly or indirectly, controls, is controlled by or is under common
         control with such Person or is a director or officer of such Person.
         For purposes of this definition, the term "control" (including the
         terms "controlling", "controlled by" and "under common control with")
         of a Person means the possession, direct or indirect, of the power to
         vote 5% or more of the Voting Stock of such Person or to direct or
         cause the direction of the management and policies of such Person,
         whether through the ownership of Voting Stock, by contract or
         otherwise.

                  "AGENTS" means, collectively, the Administrative Agent and the
         Collateral Agent.

                  "AGREEMENT" means this Agreement (including all schedules and
         exhibits hereto).

                  "ANNUAL OPERATING BUDGET" means the annual budget of the
         Borrower for Fiscal Year 2000, attached as Exhibit I hereto, which
         includes all administrative, operating, debt service, Capital
         Expenditures and other expenses and shall specify the aggregate amount
         of such expenses of the Borrower that are projected to be required
         during such Fiscal Year.

                  "APPLICABLE LENDING OFFICE" means, with respect to each
         Lender, such Lender's Domestic Lending Office in the case of a Base
         Rate Advance and such Lender's Eurodollar Lending Office in the case of
         a Eurodollar Rate Advance.

                                        2

<PAGE>

                  "APPLICABLE MARGIN" means:

                           (a) with respect to the Tranche A Advances, 2.00% per
                  annum; and

                           (b) with respect to the Tranche B Advances, a rate
                  per annum equal to (x) for Eurodollar Advances, 2.00% per
                  annum, and (y) for Base Rate Advances, 1.00% per annum.

                  "ARRANGER" means Citibank.


                  "ASSET DEMARCATION AGREEMENTS" means the CL&P Asset
         Demarcation Agreement and the WMECO Asset Demarcation Agreement.

                  "ASSIGNMENT AND ACCEPTANCE" means an assignment and acceptance
         entered into by a Lender and an Eligible Assignee, and accepted by the
         Administrative Agent, in accordance with Section 9.07 and in
         substantially the form of Exhibit C hereto.

                  "ASSIGNMENT AND ASSUMPTION AGREEMENTS" means the CL&P
         Assignment and Assumption Agreement and the WMECO Assignment and
         Assumption Agreement.

                  "ASSUMPTION AGREEMENTS" means the CL&P Assumption Agreement
         and the WMECO Assumption Agreement.

                  "AVAILABLE EXCESS CASH FLOW" means, for any Excess Cash Flow
         Payment Date, an amount equal to the Excess Cash Flow for such date
         MINUS the sum of (i) $4,000,000, (ii) an amount equal to all accrued
         and unpaid interest on the Advances for each Interest Period then in
         effect, and (iii) an amount equal to no more than 30 days interest
         anticipated to accrue on the Advances prior to the expiration of each
         Interest Period then in effect.

                  "AWARD DATE" has the meaning set forth in the Preliminary
         Statements to this Agreement.

                  "BASE RATE" means a fluctuating interest rate per annum in
         effect from time to time, which rate per annum shall at all times be
         equal to the highest of:

                           (a) the rate of interest announced publicly by
                  Citibank in New York as its Base Rate;

                           (b) 2 of 1% per annum above the latest three-week
                  moving average of secondary market morning offering rates for
                  three-month certificates of deposit of major U.S. money market
                  banks, as determined weekly by Citibank and adjusted for the
                  cost of reserves and estimated insurance assessments from the
                  Federal Deposit Insurance Corporation; and

                                        3

<PAGE>

                           (c) a rate equal to 2 of 1% per annum above the
                  weighted average of the rates on overnight Federal funds
                  transactions with members of the Federal Reserve System
                  arranged by Federal funds brokers, as determined for any day
                  by Citibank.

                  "BASE RATE ADVANCE" means an Advance that bears interest as
         provided in Section 2.06(a)(i).

                  "BORROWER" has the meaning specified in the recital of parties
         to this Agreement.

                  "BORROWER SECURITY AGREEMENT" means, collectively, the Tranche
         A Borrower Security Agreement and the Tranche B Borrower Security
         Agreement.

                  "BORROWER'S ACCOUNT" means the account of the Borrower
         maintained by the Borrower with Citibank at its office at 399 Park
         Avenue, New York, New York 10043, Account No. 30421332.

                  "BORROWING" means a borrowing consisting of either Tranche A
         Advances or Tranche B Advances of the same Type made on the same day by
         the Lenders.

                  "BORROWING DATE" shall mean the date Advances are made to the
         Borrower for the Acquisition.

                  "BUSINESS DAY" means a day of the year on which banks are not
         required or authorized by law to close in New York City and, if the
         applicable Business Day relates to any Eurodollar Rate Advances, on
         which dealings are carried on in the London interbank market.

                  "CAPITAL EXPENDITURES" means, for any Person for any period,
         the sum of all expenditures made, directly or indirectly, by such
         Person during such period for equipment, fixed assets, real property or
         improvements, or for replacements or substitutions therefor or
         additions thereto, that have been or should be, in accordance with
         GAAP, reflected as additions to property, plant or equipment on a
         Consolidated balance sheet of such Person or have a useful life of more
         than one year.

                  "CAPITALIZED LEASES" means all leases that have been or should
         be, in accordance with GAAP, recorded as capitalized leases.

                  "CASUALTY ACCOUNT" means the casualty account of the Borrower
         maintained pursuant to Article IV hereof by the Collateral Agent with
         Citibank's office at 111 Wall Street, New York, New York 10043, Account
         No.36114325, ABA No. 02100008-9, FBO A/C 103561 Northeast, Attention:
         Olivia Sharp.

                                        4
<PAGE>

                  "CERCLA" means the Comprehensive Environmental Response,
         Compensation and Liability Act of 1980, as amended from time to time.

                  "CERCLIS" means the Comprehensive Environmental Response,
         Compensation and Liability Information System maintained by the U.S.
         Environmental Protection Agency.

                  "CITIBANK" has the meaning specified in the recital of parties
         to this Agreement.

                  "CL&P" has the meaning set forth in the Preliminary Statements
         to this Agreement.

                  "CL&P ACQUISITION" means the acquisition by the Borrower of
         the CL&P Generating Assets.

                  "CL&P ACQUISITION DOCUMENTS" means the CL&P Asset Demarcation
         Agreement, the CL&P Assumption Agreement, the CL&P Interconnection
         Agreement and the CL&P Purchase and Sale Agreement.

                  "CL&P ASSET DEMARCATION AGREEMENT" means the Asset Demarcation
         Agreement dated as of the date of the Acquisition, between the Borrower
         and CL&P.

                  "CL&P ASSIGNMENT AND ASSUMPTION AGREEMENT" means the
         Assignment and Assumption Agreement, dated as of March 14, 2000,
         between the Borrower and CL&P.

                  "CL&P ASSUMPTION AGREEMENT" means the Assumption Agreement
         dated July 2, 1999, between Northeast Utilities and CL&P.

                  "CL&P GENERATING ASSETS" means the hydroelectric and pumped
         storage generating assets and related assets acquired or to be
         acquired, as the case may be, by the Borrower from CL&P pursuant to the
         CL&P Purchase and Sale Agreement.

                  "CL&P INDENTURE" means the Indenture of Mortgage and Deed of
         Trust dated as of May 1, 1921, as amended as of the date hereof,
         between CL&P and Bankers Trust Company.

                  "CL&P INTERCONNECTION AGREEMENT" means the Interconnection
         Agreement dated July 2, 1999, between the Borrower and CL&P.

                  "CL&P PURCHASE AND SALE AGREEMENT" means the Purchase and Sale
         Agreement dated July 2, 1999, between the Borrower and CL&P.

                  "CL&P PURCHASE PRICE" means the amount payable by the Borrower
         to CL&P for the CL&P Generating Assets pursuant to the CL&P Purchase
         and Sale Agreements.

                                        5
<PAGE>

                  "CLOSING AGREEMENT" means collectively, (a) the Closing
         Agreement, dated as of the Acquisition Date between the Borrower and
         CL&P and (b) the Closing Agreement, dated as of the Acquisition Date
         between the Borrower and WMECO.

                  "CO-ARRANGERS" means Citibank, Barclays Bank PLC, CIBC Inc.
         and TD Securities (USA) Inc.

                  "COLLATERAL" means all of the Borrower's present and future
         property and assets, real and personal, tangible and intangible,
         including, without limitation, owned real estate, leaseholds, fixtures,
         accounts, license rights, patents, trademarks, tradenames, copyrights,
         chattel paper, insurance proceeds, contract rights, cash, bank
         accounts, tax refunds, documents, instruments, general intangibles,
         inventory, equipment, vehicles and other goods and all present and
         future contracts of the Borrower, including the Acquisition Documents,
         the Project Documents and all service contracts, power purchase and
         sale contracts, operating leases and labor contracts and all other
         "Collateral" referred to in the Collateral Documents.

                  "COLLATERAL ACCOUNTS" means the Revenues Account and the
         Casualty Account.

                  "COLLATERAL AGENT" has the meaning specified in the recital of
         parties to this Agreement.

                  "COLLATERAL DOCUMENTS" means the Borrower Security Agreement,
         the Enterprises Pledge Agreement, the Mortgages, the Consents to
         Assignment and any other agreement that creates or purports to create a
         Lien in favor of the Collateral Agent for the benefit of the Tranche A
         Secured Parties or the Tranche B Secured Parties.

                  "COMMITMENT" means a Tranche A Commitment and a Tranche B
         Commitment.

                  "CONFIDENTIAL INFORMATION" means information that the Borrower
         furnishes to the Administrative Agent or any Lender in a writing
         designated as confidential, but does not include any such information
         that is or becomes generally available to the public or that is or
         becomes available to the Administrative Agent or such Lender from a
         source other than the Borrower or the Administrative Agent or any
         Lender.

                  "CONSENTS TO ASSIGNMENT" means the Consents to Assignment in
         the forms attached to either of the Borrower Security Agreements and
         executed by the counterparties to the Assigned Agreements (as defined
         in the Borrower Security Agreements).

                                        6
<PAGE>

                  "CONSOLIDATED" refers to the consolidation of accounts in
         accordance with GAAP.

                  "CONVERSION", "CONVERT" and "CONVERTED" each refer to a
         conversion of Advances of one Type into Advances of the other Type
         pursuant to Section 2.08 or 2.09.

                  "DEBT" of any Person means, without duplication, (a) all
         indebtedness of such Person for borrowed money, (b) all obligations of
         such Person for the purchase price of property or services (other than
         trade or account payables incurred in the ordinary course of business),
         (c) all obligations of such Person evidenced by notes, bonds,
         debentures or other similar instruments, (d) all obligations of such
         Person created or arising under any conditional sale or other title
         retention agreement with respect to property acquired by such Person
         (even though the rights and remedies of the seller or lender under such
         agreement in the event of default are limited to repossession or sale
         of such property), (e) all obligations of such Person as lessee under
         leases that have been or should be, in accordance with the GAAP
         applicable to such Person, recorded as capital leases, (f) all
         obligations, contingent or otherwise, of such Person in respect of
         acceptances, letters of credit or similar extensions of credit, (g) all
         obligations of such Person to purchase, redeem, retire, defease or
         otherwise make any payment in respect of any capital stock of or other
         ownership or profit interest in such Person or any other Person or any
         warrants, rights or options to acquire such capital stock, (h) net
         amounts payable under hedge agreements, (i) all Debt of others referred
         to in clauses (a) through (h) above or clause (j) below guaranteed
         directly or indirectly in any manner by such Person, or in effect
         guaranteed directly or indirectly by such Person through an agreement
         (1) to pay or purchase such Debt or to advance or supply funds for the
         payment or purchase of such Indebtedness, (2) to purchase, sell or
         lease (as lessee or lessor) property, or to purchase or sell services,
         primarily for the purpose of enabling the debtor to make payment of
         such Debt or to assure the holder of such Debt against loss, (3) to
         supply funds to or in any other manner invest in the debtor (including
         any agreement to pay for property or services irrespective of whether
         such property is received or such services are rendered) or (4)
         otherwise to assure a creditor against loss, and (j) all Debt referred
         to in clauses (a) through (i) above secured by (or for which the holder
         of such Debt has an existing right, contingent or otherwise, to be
         secured by) any lien or property (including, without limitation,
         accounts and contract rights) owned by such Person, even though such
         Person has not assumed or become liable for the payment of such
         Indebtedness.

                                        7
<PAGE>

                  "DEFAULT" means any Event of Default or any event that would
         constitute an Event of Default but for the requirement that notice be
         given (other than the notice specified in Section 7.01(a)) or time
         elapse or both.

                  "DEFAULTED ADVANCE" means, with respect to any Lender at any
         time, the portion of any Advance required to be made by such Lender to
         the Borrower pursuant to Section 2.01 at or prior to such time which
         has not been made by such Lender or by the Administrative Agent for the
         account of such Lender pursuant to Section 2.02(d) as of such time. In
         the event that a portion of a Defaulted Advance shall be deemed made
         pursuant to Section 2.14(a), the remaining portion of such Defaulted
         Advance shall be considered a Defaulted Advance originally required to
         be made pursuant to Section 2.01 on the same date as the Defaulted
         Advance so deemed made in part.

                  "DEFAULTED AMOUNT" means, with respect to any Lender at any
         time, any amount required to be paid by such Lender to the
         Administrative Agent, the Collateral Agent or any other Lender
         hereunder or under any other Loan Document at or prior to such time
         which has not been so paid as of such time, including, without
         limitation, any amount required to be paid by such Lender to (a) the
         Administrative Agent pursuant to Section 2.02(d) to reimburse the
         Administrative Agent for the amount of any Advance made by the
         Administrative Agent for the account of such Lender, (b) any other
         Lender pursuant to Section 2.12 to purchase any participation in
         Advances owing to such other Lender and (c) the Administrative Agent or
         the Collateral Agent pursuant to Section 8.05 to reimburse the
         Administrative Agent or the Collateral Agent for such Lender's ratable
         share of any amount required to be paid by the Lenders to the
         Administrative Agent or the Collateral Agent as provided therein. In
         the event that a portion of a Defaulted Amount shall be deemed paid
         pursuant to Section 2.14(b), the remaining portion of such Defaulted
         Amount shall be considered a Defaulted Amount originally required to be
         paid hereunder or under any other Loan Document on the same date as the
         Defaulted Amount so deemed paid in part.

                  "DEFAULTING LENDER" means, at any time, any Lender that, at
         such time, (a) owes a Defaulted Advance or a Defaulted Amount or (b)
         shall take any action or be the subject of any action or proceeding of
         a type described in Section 7.01(f).

                  "DEPOSITARY BANK" has the meaning specified in the recital of
         parties to this Agreement or its successor as provided in Section
         4.01(b).

                  "DISCLOSURE DOCUMENTS" means the Northeast Utilities 10-K for
         the year ended 1998 and 10-Q's for

                                        8
<PAGE>

         the fiscal quarters ended March 30, 1999, June 30, 1999 and September
         30, 1999 and Forms 8-K filed on October 19, 1999, October 29, 1999 and
         January 21, 2000 and filed on and through February 29, 2000.

                  "DOMESTIC LENDING OFFICE" means, with respect to any Lender,
         the office of such Lender specified as its "Domestic Lending Office"
         opposite its name on Schedule I hereto or in the Assignment and
         Acceptance pursuant to which it became a Lender, as the case may be, or
         such other office of such Lender as such Lender may from time to time
         specify to the Borrower and the Administrative Agent.

                  "ELIGIBLE ASSIGNEE" means (i) an Initial Lender; (ii) an
         Affiliate of an Initial Lender; (iii) a commercial bank organized under
         the laws of the United States, or any State thereof, and having total
         assets in excess of US$10,000,000,000; (iv) a savings and loan
         association or savings bank organized under the laws of the United
         States, or any State thereof, and having total assets in excess of
         US$10,000,000,000; (v) a commercial bank organized under the laws of
         any other country that is a member of the OECD or has concluded special
         lending arrangements with the International Monetary Fund associated
         with its General Arrangements to borrow, or a political subdivision of
         any such country, and having total assets in excess of
         US$10,000,000,000, so long as such bank is acting through a branch or
         agency located in the country in which it is organized or another
         country that is described in this clause (v); (vi) a finance company,
         insurance company or other financial institution or fund (whether a
         corporation, partnership, trust or other entity) that is engaged in
         making, purchasing or otherwise investing in commercial loans in the
         ordinary course of its business and having total assets in excess of
         US$10,000,000,000; and (vii) any other Person approved by the
         Administrative Agent and the Borrower, such approval not to be
         unreasonably withheld or delayed (and, in the case of the Borrower, not
         to be required if an Event of Default exists); PROVIDED, HOWEVER, that
         neither any Loan Party nor any Affiliate of any Loan Party shall
         qualify as an Eligible Assignee hereunder.

                  "ENFORCEMENT ACTION" means any action by the Collateral Agent,
         the Administrative Agent or any Lender that would have the effect of
         (a) declaring the Notes, all interest thereon and all other amounts
         payable under this Agreement and the other Loan Documents to be
         forthwith due and payable in accordance with Section 7.01 of this
         Agreement (b) exercising any right of set-off or counterclaim, (b)
         initiating any judicial or non-judicial proceedings to enforce the
         payment of any part of the outstanding Obligations or any other amounts
         owed under any Loan Document, (c)

                                        9
<PAGE>

         commencing judicial or non-judicial enforcement of any of its rights or
         remedies under any of the Collateral Documents, or (d) appointing or
         consenting to the appointment of a receiver or other similar official
         for the management of the Borrower or for the custody or control of any
         assets or proceeds of assets of the Borrower.

                  "ENGAGEMENT LETTER" means the Engagement Letter dated June 11,
         1999, and as amended on February 9, 2000, among Citibank, the Borrower
         and Northeast Utilities.

                  "ENTERPRISES PLEDGE AGREEMENT" means, collectively, the
         Tranche A Enterprises Pledge Agreement and the Tranche B Enterprises
         Pledge Agreement.

                  "ENVIRONMENTAL ACTION" means any action, suit, demand, demand
         letter, claim, notice of non-compliance or violation, notice of
         liability or potential liability, investigation, proceeding, consent
         order or consent agreement relating in any way to any Environmental
         Law, any Environmental Permit or Hazardous Material or arising from
         alleged injury or threat to health, safety or the environment,
         including, without limitation, (a) by any governmental or regulatory
         authority for enforcement, cleanup, removal, response, remedial or
         other actions or damages and (b) by any governmental or regulatory
         authority or third party for damages, contribution, indemnification,
         cost recovery, compensation or injunctive relief.

                  "ENVIRONMENTAL LAW" means any federal, state, local or foreign
         statute, law, ordinance, rule, regulation, code, order, writ, judgment,
         injunction, decree or judicial or agency interpretation, policy or
         guidance relating to pollution or protection of the environment,
         health, safety or natural resources, including, without limitation,
         those relating to the use, handling, transportation, treatment,
         storage, disposal, release or discharge of Hazardous Materials.

                  "ENVIRONMENTAL PERMIT" means any permit, approval,
         identification number, license or other authorization required under
         any Environmental Law.

                  "EQUITY" means, at any date for the Borrower, an amount equal
         to the sum of the aggregate of the par value of, or stated capital
         represented by, the outstanding common shares of the Borrower and the
         surplus, paid-in, earned and other capital (excluding capital
         redeemable at the option of the holder), if any, of the Borrower, as
         determined in accordance with GAAP, as adjusted (without duplication)
         to add the amount by which the purchase price paid by the Borrower

                                       10
<PAGE>

         exceeds the book value of the Generating Assets immediately prior to
         the Acquisition.

                  "ERISA" means the Employee Retirement Income Security Act of
         1974, as amended from time to time, and the regulations promulgated and
         rulings issued thereunder.

                  "ERISA AFFILIATE" means any Person that for purposes of Title
         IV of ERISA is a member of the controlled group of any Loan Party, or
         under common control with any Loan Party, within the meaning of Section
         414 of the Internal Revenue Code.

                  "ERISA EVENT" means (a) (i) the occurrence of a reportable
         event, within the meaning of Section 4043 of ERISA, with respect to any
         Plan unless the 30-day notice requirement with respect to such event
         has been waived by the PBGC, or (ii) the requirements of subsection (1)
         of Section 4043(b) of ERISA (without regard to subsection (2) of such
         Section) are met with respect to a contributing sponsor, as defined in
         Section 4001(a)(13) of ERISA, of a Plan, and an event described in
         paragraph (9), (10), (11), (12) or (13) of Section 4043(c) of ERISA is
         reasonably expected to occur with respect to such Plan within the
         following 30 days; (b) the application for a minimum funding waiver
         with respect to a Plan; (c) the provision by the administrator of any
         Plan of a notice of intent to terminate such Plan, pursuant to Section
         4041(a)(2) of ERISA (including any such notice with respect to a plan
         amendment referred to in Section 4041(e) of ERISA); (d) the cessation
         of operations at a facility of any Loan Party or any ERISA Affiliate in
         the circumstances described in Section 4062(e) of ERISA; (e) the
         withdrawal by any Loan Party or any ERISA Affiliate from a Multiple
         Employer Plan during a plan year for which it was a substantial
         employer, as defined in Section 4001(a)(2) of ERISA; (f) the conditions
         for imposition of a lien under Section 302(f) of ERISA shall have been
         met with respect to any Plan; (g) the adoption of an amendment to a
         Plan requiring the provision of security to such Plan pursuant to
         Section 307 of ERISA; or (h) the institution by the PBGC of proceedings
         to terminate a Plan pursuant to Section 4042 of ERISA, or the
         occurrence of any event or condition described in Section 4042 of ERISA
         that constitutes grounds for the termination of, or the appointment of
         a trustee to administer, such Plan.

                  "EUROCURRENCY LIABILITIES" has the meaning specified in
         Regulation D of the Board of Governors of the Federal Reserve System,
         as in effect from time to time.

                  "EURODOLLAR LENDING OFFICE" means, with respect to any Lender,
         the office of such Lender specified as its

                                       11
<PAGE>

         "Eurodollar Lending Office" opposite its name on Schedule I hereto or
         in the Assignment and Acceptance pursuant to which it became a Lender
         (or, if no such office is specified, its Domestic Lending Office), or
         such other office of such Lender as such Lender may from time to time
         specify to the Borrower and the Administrative Agent.

                  "EURODOLLAR RATE" means, for any Interest Period for each
         Eurodollar Rate Advance comprising part of the same Borrowing, an
         interest rate per annum equal to the rate per annum obtained by
         dividing (a) the rate that is set forth on Telerate Page Number 3750
         (or any other page that may replace such page from time to time) as of
         11:00 A.M. (London time) on the second Business Day prior to the first
         day of any interest period for U.S. Dollar deposits having a tenor
         equal to the applicable Interest Period or if none of such page 3750
         nor any successor or similar service is available, relative to any
         Eurodollar Rate Advance, the rate of interest per annum determined by
         the Administrative Agent to be the arithmetic mean (rounded upward to
         the next 0.01%) of the rates of interest per annum at which dollar
         deposits in the approximate amount of the amount to be made or
         continued as, or converted into, a Eurodollar Rate Advance by the
         Administrative Agent and having a maturity comparable to such Interest
         Period are offered in immediately available funds to the Administrative
         Agent in the London interbank market at its request at approximately
         11:00 a.m. (London time) two Business Days prior to the commencement of
         such Interest Period by (b) a percentage equal to 100% minus the
         Eurodollar Rate Reserve Percentage for such Interest Period.

                  "EURODOLLAR RATE ADVANCE" means an Advance that bears interest
         as provided in Section 2.06(a)(ii).

                  "EURODOLLAR RATE RESERVE PERCENTAGE" for any Interest Period
         for all Eurodollar Rate Advances comprising part of the same Borrowing
         means the reserve percentage applicable two Business Days before the
         first day of such Interest Period under regulations issued from time to
         time by the Board of Governors of the Federal Reserve System (or any
         successor) for determining the maximum reserve requirement (including,
         without limitation, any emergency, supplemental or other marginal
         reserve requirement) for a member bank of the Federal Reserve System in
         New York City with respect to liabilities or assets consisting of or
         including Eurocurrency Liabilities (or with respect to any other
         category of liabilities that includes deposits by reference to which
         the interest rate on Eurodollar Rate Advances is determined) having a
         term equal to such Interest Period.

                  "EVENTS OF DEFAULT" has the meaning specified in Section 7.01.

                                       12
<PAGE>

                  "EXCESS CASH FLOW" shall mean for any Excess Cash Flow Payment
         Date, the excess of (a) all cash receipts of the Borrower (including,
         but not limited to, Revenues, but excluding Net Cash Proceeds) actually
         received by the Borrower during the period from the prior Excess Cash
         Flow Payment Date (or the Borrowing Date with respect to the first
         Excess Cash Flow Payment Date) to the date immediately prior to such
         Excess Cash Flow Payment Date OVER (b) the sum (without duplication) of
         (i) Operating Costs and Permitted Capital Expenditures paid during such
         period and (ii) Obligations (other than mandatory prepayments pursuant
         to Section 2.05(b) hereof and payments of interest in respect thereof
         pursuant to Section 2.06 hereof) arising under the Loan Documents paid
         during such period. For purposes of this definition, cash receipts
         shall exclude, to the extent included, any insurance proceeds deposited
         into the Casualty Account.

                  "EXCESS CASH FLOW PAYMENT DATE" shall mean May 1, 2000, August
         1, 2000 and November 1, 2000.

                  "EXEMPT WHOLESALE GENERATOR" has the meaning specified in
         Section 32(a)(1) of the Public Utility Holding Company Act of 1935.

                  "EXTRAORDINARY RECEIPT" means any cash received by or paid to
         or for the account of any Person not in the ordinary course of
         business, including, without limitation, tax refunds, pension plan
         reversions, proceeds of insurance (other than proceeds of business
         interruption insurance to the extent such proceeds constitute
         compensation for lost earnings), condemnation awards (and payments in
         lieu thereof) and indemnity payments; PROVIDED, HOWEVER, that an
         Extraordinary Receipt shall not include cash receipts received from
         proceeds of insurance, condemnation awards (or payments in lieu
         thereof) or indemnity payments to the extent that such proceeds, awards
         or payments (A) in respect of loss or damage to equipment, fixed assets
         or real property are applied (or in respect of which expenditures were
         previously incurred) to replace or repair the equipment, fixed assets
         or real property in accordance with the terms of the Loan Documents, so
         long as such application is made within six months after the receipt of
         such proceeds or (B) are received by any Person in respect of any third
         party claim against such Person and applied to pay (or to reimburse
         such Person for its prior payment of) such claim and the costs and
         expenses of such Person with respect thereto.

                  "FEDERAL FUNDS RATE" means, for any period, a fluctuating
         interest rate per annum equal for each day during such period to the
         weighted average of the rates on overnight Federal funds transactions
         with members of the Federal Reserve System arranged by Federal funds

                                       13
<PAGE>

         brokers, as published for such day (or, if such day is not a Business
         Day, for the next preceding Business Day) by the Federal Reserve Bank
         of New York, or, if such rate is not so published for any day that is a
         Business Day, the average of the quotations for such day for such
         transactions received by the Administrative Agent from three Federal
         funds brokers of recognized standing selected by it.

                  "FEE LETTER" means the Fee Letter dated as of February 9,
         2000, among the Borrower, Northeast Utilities and the Co-Arrangers.

                  "FERC" means the Federal Energy Regulatory Commission.

                  "FISCAL YEAR" means a fiscal year of the Borrower ending on
         December 31 in any calendar year.

                  "FLOW OF FUNDS MEMORANDUM" means the memorandum regarding the
         flow of funds and procedures on the Borrowing Date, attached as Exhibit
         G hereto.

                  "GAAP" has the meaning specified in Section 1.03.

                  "GENERATING ASSETS" means the CL&P Generating Assets and the
         WMECO Generating Assets.

                  "GOVERNMENTAL AUTHORITY" means any nation or government, any
         state, province or other political subdivision thereof, and any
         governmental, executive, legislative, judicial, administrative or
         regulatory agency, department, authority, instrumentality, commission,
         board or similar body, whether federal, state, provincial, territorial,
         local or foreign.

                  "GOVERNMENTAL AUTHORIZATION" means any authorization,
         approval, consent, franchise, license, covenant, order, ruling, permit,
         certification, exemption or similar right or action of or by, or filing
         or registration with or notice to, any Governmental Authority.

                  "HAZARDOUS MATERIALS" means (a) petroleum or petroleum
         products, by-products or breakdown products, radioactive materials,
         asbestos-containing materials, polychlorinated biphenyls and radon gas
         and (b) any other chemicals, materials or substances designated,
         classified or regulated as hazardous or toxic or as a pollutant under
         any Environmental Law.

                  "HOUSATONIC SYSTEM" means the six hydroelectric plants known
         as Falls Village, Bulls Bridge, Shepaug, Stevenson, Robertsville and
         Bantam and the one pump storage generating facility known as Rocky
         River, and the other assets acquired or to be acquired by the

                                       14
<PAGE>

         Borrower from CL&P pursuant to the CL&P Purchase and Sale Agreement.

                  "INDEMNIFIED PARTY" has the meaning specified in Section
         9.04(b).

                  "INDENTURES" shall mean the CL&P Indenture and the WMECO
         Indenture.

                  "INITIAL LENDERS" means, collectively, the Tranche A Initial
         Lenders and the Tranche B Initial Lenders.

                  "INSUFFICIENCY" means, with respect to any Plan, the amount,
         if any, of its unfunded benefit liabilities, as defined in Section
         4001(a)(18) of ERISA.

                  "INSURANCE CONSULTANT" means Aon Risk Services or such other
         insurance consultant selected by the Required Lenders and consented to
         by the Borrower which shall not be unreasonably withheld or delayed.

                  "INTERCONNECTION AGREEMENTS" means the CL&P Interconnection
         Agreement and the WMECO Interconnection Agreement.

                  "INTEREST PERIOD" means, for each Eurodollar Rate Advance
         comprising part of the same Borrowing, the period commencing on the
         date of such Eurodollar Rate Advance or the date of the Conversion of
         any Base Rate Advance into such Eurodollar Rate Advance, and ending on
         the last day of the period selected by the Borrower pursuant to the
         provisions below and, thereafter, each subsequent period commencing on
         the last day of the immediately preceding Interest Period and ending on
         the last day of the period selected by the Borrower pursuant to the
         provisions below. The duration of each such Interest Period shall be
         one, two or three months, as the Borrower may, upon notice received by
         the Administrative Agent not later than 11:00 A.M. (New York City time)
         on the third Business Day prior to the first day of such Interest
         Period, select; PROVIDED, HOWEVER, that:

                           (a) no more than five Interest Periods shall be
                  outstanding at any time;

                           (b) the Borrower may not select any Interest Period
                  with respect to any Tranche B Advance that ends after the
                  Tranche B Maturity Date;

                           (c) whenever the last day of any Interest Period
                  would otherwise occur on a day other than a Business Day, the
                  last day of such Interest Period shall be extended to occur on
                  the next succeeding Business Day, PROVIDED, HOWEVER, that, if
                  such

                                       15
<PAGE>

                  extension would cause the last day of such Interest Period to
                  occur in the next following calendar month, the last day of
                  such Interest Period shall occur on the next preceding
                  Business Day; and

                           (d) whenever the first day of any Interest Period
                  occurs on a day of an initial calendar month for which there
                  is no numerically corresponding day in the calendar month that
                  succeeds such initial calendar month by the number of months
                  equal to the number of months in such Interest Period, such
                  Interest Period shall end on the last Business Day of such
                  succeeding calendar month.

                  "INTERNAL REVENUE CODE" means the Internal Revenue Code of
         1986, as amended from time to time, and the regulations promulgated and
         rulings issued thereunder.

                  "INVESTMENT" in any Person means any loan or advance to such
         Person, any purchase or other acquisition of any capital stock or other
         ownership or profit interest, warrants, rights, options, obligations or
         other securities of such Person, any capital contribution to such
         Person or any other investment in such Person, including, without
         limitation, any arrangement pursuant to which the investor incurs Debt
         of the types referred to in clause (i) or (j) of the definition of
         "DEBT" in respect of such Person.

                  "LEAD BANK LETTER" means the Lead Bank Letter dated as of June
         11, 1999, among the Borrower, Northeast Utilities and the Co-Arrangers.

                  "LENDERS" means the Tranche A Lenders and the Tranche B
         Lenders.

                  "LIEN" means any lien, security interest or other charge or
         encumbrance of any kind, or any other type of preferential arrangement,
         including, without limitation, the lien or retained security title of a
         conditional vendor and any easement, right of way or other encumbrance
         on title to real property.

                  "LOAN DOCUMENTS" means this Agreement, the Notes, the
         Collateral Documents, the Northeast Utilities Guaranties and the
         Sponsor Agreement, in each case as amended or otherwise modified from
         time to time.

                  "LOAN PARTIES" means the Borrower, NU Enterprises, Northeast
         Utilities, Select and NGS.

                  "MARGIN STOCK" has the meaning specified in Regulation U.

                                       16
<PAGE>

                  "MATERIAL ADVERSE EFFECT" means a material adverse effect on
         (i) the business, financial condition, operations, performance,
         properties or prospects of any Loan Party, (ii) the rights and remedies
         of the Administrative Agent, the Collateral Agent or the Lenders under
         any Loan Document, (iii) the Liens in favor of the Collateral Agent for
         benefit of the Secured Parties, (iv) the legality, validity or
         enforceability of any Loan Document, any Project Document, any Material
         Contract or any Acquisition Document or (v) the ability of the
         Borrower, NU Enterprises or Northeast Utilities to perform its
         obligations under any Loan Document to which it is a party.

                  "MATERIAL CONTRACT" means, collectively, the contracts set
         forth on Schedule 5.01(ee) of this Agreement and each other contract of
         the Borrower involving aggregate consideration payable to or by the
         Borrower of $10,000,000 or more in any Fiscal Year or the absence of
         which would result in a Material Adverse Effect to the Borrower or a
         material adverse effect on the operations or performance of the
         Generating Assets taken as a whole.

                  "MATURITY DATE" means the Tranche A Maturity Date and the
         Tranche B Maturity Date.

                  "METCALF & EDDY" means Metcalf & Eddy, Inc.

                  "MOODY'S" means Moody's Investors Service, Inc. and any
         successor thereto that is a nationally recognized rating agency.

                  "MORTGAGE POLICIES" has the meaning specified in Section
         3.01(m)(ix)(B).

                  "MORTGAGES" means, collectively, the Tranche A Mortgage and
         the Tranche B Mortgage.

                  "MULTIEMPLOYER PLAN" means a multiemployer plan, as defined in
         Section 4001(a)(3) of ERISA, to which any Loan Party or any ERISA
         Affiliate is making or accruing an obligation to make contributions, or
         has within any of the preceding five plan years made or accrued an
         obligation to make contributions.

                  "MULTIPLE EMPLOYER PLAN" means a single employer plan, as
         defined in Section 4001(a)(15) of ERISA, that (a) is maintained for
         employees of any Loan Party or any ERISA Affiliate and at least one
         Person other than the Loan Parties and the ERISA Affiliates or (b) was
         so maintained and in respect of which any Loan Party or any ERISA
         Affiliate could have liability under Section 4064 or 4069 of ERISA in
         the event such plan has been or were to be terminated.

                                       17
<PAGE>

                  "NEIGHBORING LANDOWNER AGREEMENTS" means a lease, license or
         other agreement between the Borrower (or a predecessor in interest of
         the Borrower) and an owner of real property adjacent to one of the
         impoundments located on the Borrower=s land, relating to recreational
         access and/or use by third party users of such impoundment.

                  "NET CASH PROCEEDS" means, with respect to any sale, lease,
         transfer or other disposition of any asset by the Borrower, or any
         Extraordinary Receipt received by or paid to or for the account of the
         Borrower, the aggregate amount of cash received from time to time
         (whether as initial consideration or through payment or disposition of
         deferred consideration) by or on behalf of the Borrower in connection
         with such transaction after deducting therefrom only (without
         duplication) (a) reasonable and customary brokerage commissions,
         underwriting fees and discounts, legal fees, finder's fees and other
         similar fees and commissions and (b) the amount of taxes payable in
         connection with or as a result of such transaction, in each case to the
         extent, but only to the extent, that the amounts so deducted are, at
         the time of receipt of such cash, actually paid to a Person that is not
         an Affiliate of such Person or any Loan Party and are properly
         attributable to such transaction or to the asset that is the subject
         thereof.

                  "NGS" means Northeast Generation Services Company, a
         Connecticut corporation.

                  "NON-FIRM POINT TO POINT AGREEMENT" refers to the Non-Firm
         Point to Point Transmission Service Agreement dated as of September 28,
         1999, between NUSCO and the Borrower.

                  "NORTHEAST UTILITIES" means Northeast Utilities, a
         Massachusetts business trust.

                  "NORTHEAST UTILITIES GUARANTIES" means the two guaranties,
         issued by Northeast Utilities in favor of the Borrower, with respect to
         the Select Power Purchase Agreement and the O&M Agreement,
         respectively.

                  "NORTHFIELD MOUNTAIN PROJECT" means the Northfield Mountain
         Pumped Storage Project that the Borrower is purchasing an 81% ownership
         interest in from CL&P pursuant to the CL&P Purchase and Sale Agreement
         and a 19% ownership interest in from WMECO pursuant to the WMECO
         Purchase and Sale Agreement.

                  "NORTHFIELD OPERATING AGREEMENT" means the Northfield Mountain
         Project Operating Agreement dated as of February 14, 1968 (as amended
         by the March 1, 1974 amendment), among CL&P, WMECO and The Hartford
         Electric Light Company.

                                       18
<PAGE>

                  "NOTE" means either a Tranche A Note or a Tranche B Note.

                  "NOTICE OF BORROWING" has the meaning specified in Section
         2.02(a).

                  "NPL" means the National Priorities List under CERCLA.

                  "NU ENTERPRISES" means NU Enterprises, Inc., a Connecticut
         corporation.

                  "NUSCO" means Northeast Utilities Services Company.

                  "NUSCO SERVICE AGREEMENT" means the Northeast Utilities
         Service Company Service Contract, dated as of January 1, 1999, as
         renewed on December 31, 1999, between the Borrower and NUSCO.

                  "OBLIGATION" means, with respect to any Person, any payment,
         performance or other obligation of such Person of any kind, including,
         without limitation, any liability of such Person on any claim, whether
         or not the right of any creditor to payment in respect of such claim is
         reduced to judgment, liquidated, unliquidated, fixed, contingent,
         matured, disputed, undisputed, legal, equitable, secured or unsecured,
         and whether or not such claim is discharged, stayed or otherwise
         affected by any proceeding referred to in Section 7.01(f). Without
         limiting the generality of the foregoing, the Obligations of the Loan
         Parties under the Loan Documents include (a) the obligation to pay
         principal, interest, charges, expenses, fees, attorneys' fees and
         disbursements, indemnities and other amounts payable by any Loan Party
         under any Loan Document and (b) the obligation of any Loan Party to
         reimburse any amount in respect of any of the foregoing that any
         Lender, in its sole discretion, may elect to pay or advance on behalf
         of such Loan Party.

                  "OECD" means the Organization for Economic Cooperation and
         Development.

                  "O&M AGREEMENT" means the Management and Operation Agreement
         dated February 1, 2000, as amended on March 1, 2000, between NGS and
         the Borrower.

                  "OPERATING ACCOUNT" means the operating account of the
         Borrower maintained by the Borrower with Fleet National Bank at its
         office at Providence, R.I., Account No. 9417547475, ABA No. 011500010,
         Ref: Northeast Generation Company, which is in the sole dominion and
         control of the Borrower.

                  "OPERATING COSTS" shall mean, for any period, the sum,
         computed without duplication, of all costs and

                                       19
<PAGE>

         expenses paid by the Borrower during such period (or, in the case of
         any future period, projected to be paid or payable during such period)
         in connection with the operation, maintenance and administration of the
         Generating Assets, including, without limiting the generality of the
         foregoing, (a) costs of operating and administering the Generating
         Assets and of maintaining them in good repair and operating condition
         (including all amounts due and payable under the O&M Agreement), (b)
         costs of insurance, (c) costs of supplies and other services acquired
         in connection with the operation and maintenance of the Generating
         Assets, (d) sales and excise taxes payable by the Borrower, (e) income
         taxes payable by the Borrower, (f) costs and fees attendant to the
         obtaining and maintaining in effect the Governmental Authorizations
         relating to the Generating Assets, (g) legal, accounting and other
         professional fees attendant to any of the foregoing and (h) payments in
         respect of Debt permitted under Section 6.02(b)(ii) and Section
         6.02(b)(iii); PROVIDED that all of the foregoing costs and expenses
         shall be determined on a cash basis and shall not include the cost of
         scheduled Capital Expenditures, depreciation, amortization and other
         non-cash items.

                  "OTHER TAXES" has the meaning specified in Section 2.11(b).

                  "PBGC" means the Pension Benefit Guaranty Corporation (or any
         successor).

                  "PERMANENT FINANCING" means the Proposed Permanent Financing
         or any other capital markets, private placement or other debt issuance
         (including, without limitation, by entering into a bank credit
         facility) by the Borrower, the purpose of which is to refinance some or
         all of the Tranche B Advances.

                  "PERMITTED CAPITAL EXPENDITURES" means, with respect to the
         Borrower, for any period, all Capital Expenditures contemplated for
         such period in the Annual Operating Budget or which the Borrower is
         otherwise permitted to incur pursuant to Section 6.02(n).

                  "PERMITTED ENCUMBRANCES" has the meaning specified in the
         Mortgages.

                  "PERMITTED HEDGE PROVIDER" means any Lender or its Affiliate
         providing a Permitted Hedge so long and only so long as such hedge
         provider remains a Lender or an Affiliate of a Lender.

                  "PERMITTED HEDGES" means any anticipatory hedge product
         purchased by the Borrower, or Northeast Utilities for the benefit of
         the Borrower, such as a treasury rate lock, treasury collar or treasury
         put, for the purpose of hedging the Borrower's anticipated

                                       20
<PAGE>

         interest rate exposure with respect to the Proposed Permanent
         Financing, PROVIDED, if the hedge product is provided by (a) a
         financial institution other than any Permitted Hedge Provider, such
         hedge provider shall not be entitled to have a lien on any properties
         or assets of the Borrower as security in respect of the hedge product,
         or (b) any Permitted Hedge Provider, such hedge provider shall be a
         Tranche B Secured Party under the Tranche B Collateral Documents
         entitled to the benefits of the Collateral under the Tranche B
         Collateral Documents pari passu with the other Tranche B Secured
         Parties, PROVIDED, FURTHER, HOWEVER, that such hedge provider shall
         have no voting rights under the Tranche B Collateral Documents.

                  "PERMITTED INVESTMENTS" means any of (a) time deposits of
         Citibank with such maturities as may be acceptable to the Collateral
         Agent, (b) commercial paper that is rated at least P-1 by Moody's and
         at least A-1+ by S&P (provided that the long-term unsecured debt
         ratings issued by Moody's and S&P for the issuer or the guarantor
         thereof are at least Aa3 and AA-, respectively), with such maturities
         and other terms as may be acceptable to the Collateral Agent in its
         sole discretion, (c) marketable obligations, maturing within 12 months
         after acquisition thereof, issued or unconditionally guaranteed by the
         United States of America or an instrumentality or agency thereof and
         entitled to the full faith and credit of the United States of America,
         (d) other than with respect to amounts in the Collateral Accounts, the
         Temp Fund of the Provident Institutional Fund, (e) investments in the
         Goldman Sachs FS Prime Obligations Fund Administration Class (463) or
         (f) such other investments as may be requested by the Borrower and
         acceptable to the Collateral Agent in its reasonable discretion.

                  "PERMITTED LIENS" means such of the following as to which no
         enforcement, collection, execution, levy or foreclosure proceeding
         shall have been commenced: (a) Liens for taxes, assessments and
         governmental charges or levies to the extent not required to be paid
         under Section 6.01(b) hereof; (b) Liens imposed by law, such as
         materialmen's, mechanics', carriers', workmen's and repairmen's Liens
         and other similar Liens arising in the ordinary course of business
         securing obligations that are not overdue for a period of more than 30
         days; (c) pledges or deposits to secure obligations under workers'
         compensation laws or similar legislation or to secure public or
         statutory obligations; and (d) easements, rights of way and other
         encumbrances on title to real property that do not render title to the
         property encumbered thereby unmarketable or materially adversely affect
         the use of such property for its present purposes.

                                       21
<PAGE>

                  "PERSON" means an individual, partnership, corporation
         (including a business trust), limited liability company, joint stock
         company, trust, unincorporated association, joint venture or other
         entity, or a government or any political subdivision or agency thereof.

                  "PLACEMENT AGENT" means the placement agent chosen by the
         Borrower in connection with the Proposed Permanent Financing.

                  "PLAN" means a Single Employer Plan or a Multiple Employer
         Plan.

                  "PLEDGED SHARES" has the meaning set forth in the Collateral
         Documents.

                  "PROJECT DOCUMENTS" means the Select Power Purchase Agreement,
         the O&M Agreement, the Northeast Utilities Guaranties, the NUSCO
         Service Agreement, any other purchase and sale agreement with respect
         to sales of the Product (as defined in the O&M Agreement) entered into
         by the Borrower and any other third party, the Interconnection
         Agreements, the Asset Demarcation Agreements, the Property Tax
         Allocation Agreement and the Non-Firm Point to Point Agreement.

                  "PROPERTY TAX ALLOCATION AGREEMENT" means (a) the Real and
         Personal Property Tax Allocation Agreement, dated as of the Acquisition
         Date between the Borrower and CL&P and (b) the Real and Personal
         Property Tax Allocation Agreement, dated as of the Acquisition Date
         between the Borrower and WMECO.

                  "PROPOSED PERMANENT FINANCING" means the private placement, in
         accordance with Rule 144A of the Securities Act of 1933, as amended
         from time to time, of debt securities proposed to be issued by the
         Borrower in an amount equal to at least the then outstanding amount of
         the Tranche B Advances hereunder to repay such Advances.

                  "PURCHASE AND SALE AGREEMENTS" means the WMECO Purchase and
         Sale Agreement and the CL&P Purchase and Sale Agreement.

                  "PURCHASE PRICE" means the aggregate amount payable by the
         Borrower to CL&P and WMECO as the purchase price for the Generating
         Assets pursuant to the Purchase and Sale Agreements.

                  "RATING AGENCIES" shall mean S&P and Moody's.

                  "REGISTER" has the meaning specified in Section 9.07(d).

                                       22
<PAGE>

                  "REGULATION U" means Regulation U of the Board of Governors of
         the Federal Reserve System, as in effect from time to time.

                  "REPLACEMENT LENDER" has the meaning specified in Section
         2.09(e).

                  "REQUIRED LENDERS" means at any time Lenders owed at least 66
         2/3% of the then aggregate unpaid principal amount of the Advances
         owing to Lenders, or, if no such principal amount is then outstanding,
         Lenders having at least 66 2/3% of the Commitments.

                  "REQUIRED RATING" means a rating of at least BBB- (or the then
         equivalent grade) from S&P and Baa3 (or the then equivalent grade) from
         Moody's.

                  "REQUIRED TRANCHE A LENDERS" means at any time the Tranche A
         Lenders owed at least 66 2/3% of the then aggregate unpaid principal
         amount of the Tranche A Advances owing to the Tranche A Lenders, or, if
         no such principal amount is then outstanding, Tranche A Lenders having
         at least 66 2/3% of the Tranche A Commitments.

                  "REQUIRED TRANCHE B LENDERS" means at any time the Tranche B
         Lenders owed at least 66 2/3% of the then aggregate unpaid principal
         amount of the Tranche B Advances owing to the Tranche B Lenders, or, if
         no such principal amount is then outstanding, Tranche B Lenders having
         at least 66 2/3% of the Tranche B Commitments.

                  "RESPONSIBLE OFFICER" means any of the chief executive
         officer, the president, the treasurer or any vice president of any Loan
         Party or any of its Subsidiaries.

                  "REVENUES" shall mean, for any period, the sum, computed
         without duplication, of all cash receipts received by the Borrower
         during such period (or, in the case of any future period, projected to
         be received during such period) pursuant to (a) the Project Documents,
         including, without limitation, (x) amounts paid by third parties such
         as guarantors and letter of credit banks, and (y) any and all damages,
         arbitration awards or other monetary settlements payable to the
         Borrower, (b) proceeds of any business interruption insurance and other
         payments received for interruption of operations (excluding proceeds of
         physical damage or liability insurance), and (c) investment earnings on
         Permitted Investments held in the Revenues Account. Revenues shall
         exclude, to the extent included, proceeds of insurance paid in respect
         of loss or damage of any Generating Asset.

                  "REVENUES ACCOUNT" means the revenues account of the Borrower
         maintained pursuant to Article IV hereof by the Collateral Agent with
         Citibank's office at 111

                                       23
<PAGE>

         Wall Street, New York, New York 10043, Account No.3611-4325, ABA No.
         0210-0008-9, FBO A/C 103560 Attention: Olivia Sharp.

                  "S&P" means Standard & Poor's Ratings Services, a division of
         The McGraw-Hill Companies, Inc., and any successor thereto that is a
         nationally recognized rating agency.

                  "SECURED OBLIGATIONS" has the meaning specified in the
         Collateral Documents.

                  "SECURED PARTIES" means the Tranche A Secured Parties and the
         Tranche B Secured Parties.

                  "SELECT" means Select Energy, Inc., a Connecticut corporation.

                  "SELECT POWER PURCHASE AGREEMENT" means the Power Purchase and
         Sale Agreement dated December 27, 1999, between Select and the
         Borrower.

                  "SINGLE EMPLOYER PLAN" means a single employer plan, as
         defined in Section 4001(a)(15) of ERISA, that (a) is maintained for
         employees of any Loan Party or any ERISA Affiliate and no Person other
         than the Loan Parties and the ERISA Affiliates or (b) was so maintained
         and in respect of which any Loan Party or any ERISA Affiliate could
         have liability under Section 4069 of ERISA in the event such plan has
         been or were to be terminated.

                  "SOLVENT" and "SOLVENCY" mean, with respect to any Person on a
         particular date, that on such date (a) the fair value of the property
         of such Person is greater than the total amount of liabilities,
         including, without limitation, contingent liabilities, of such Person,
         (b) the present fair salable value of the assets of such Person is not
         less than the amount that will be required to pay the probable
         liability of such Person on its debts as they become absolute and
         matured, (c) such Person does not intend to, and does not believe that
         it will, incur debts or liabilities beyond such Person's ability to pay
         such debts and liabilities as they mature and (d) such Person is not
         engaged in business or a transaction, and is not about to engage in
         business or a transaction, for which such Person's property would
         constitute an unreasonably small capital. The amount of contingent
         liabilities at any time shall be computed as the amount that, in the
         light of all the facts and circumstances existing at such time,
         represents the amount that can reasonably be expected to become an
         actual or matured liability.

                  "SPONSOR AGREEMENT" means the sponsor agreement of Northeast
         Utilities in favor of the Collateral Agent, substantially in the form
         of Exhibit H attached hereto.

                                       24
<PAGE>

                  "STONE & WEBSTER" means Stone & Webster Management
         Consultants, Inc.

                  "SUBSIDIARY" of any Person means any corporation, partnership,
         joint venture, limited liability company, trust or estate of which (or
         in which) more than 50% of (a) the issued and outstanding capital stock
         having ordinary voting power to elect a majority of the Board of
         Directors of such corporation (irrespective of whether at the time
         capital stock of any other class or classes of such corporation shall
         or might have voting power upon the occurrence of any contingency), (b)
         the interest in the capital or profits of such partnership, joint
         venture or limited liability company or (c) the beneficial interest in
         such trust or estate is at the time directly or indirectly owned or
         controlled by such Person, by such Person and one or more of its other
         Subsidiaries or by one or more of such Person's other Subsidiaries.

                  "TAX CERTIFICATE" has the meaning specified in Section
         6.03(m).

                  "TAX SHARING AGREEMENT" means the Amended and Restated Tax
         Allocation Agreement, dated January 1, 1990 (as amended on October 26,
         1998 and on March 1, 2000), to be entered into by the Borrower with NU
         and various other Subsidiaries of NU (a copy of which was delivered to
         the Lenders pursuant to Section 3.01(m)(xviii)), together with any
         other tax sharing agreement entered into by the Borrower in accordance
         with Section 6.02(o).

                  "TAXES" has the meaning specified in Section 2.11(a).

                  "TERMINATION DATE" means the earlier (x) December 29, 2000 or
         (y) the date of termination in whole of the Commitments pursuant to
         Section 2.04 or 7.01.

                  "THIRD PARTY CONSENTS" has the meaning specified in Section
         5.01(d).

                  "TOTAL CAPITALIZATION" means, at any date, for the Borrower,
         the sum of (i) the aggregate principal amount of all long-term and
         short-term Debt of the Borrower, and (ii) the Equity.

                  "TRANCHE A ADVANCE" has the meaning specified in Section
         2.01(a).

                  "TRANCHE A AMOUNTS" has the meaning specified in Section
         2.03(a).

                  "TRANCHE A BORROWER SECURITY AGREEMENT" means the agreement by
         the Borrower in favor of the Collateral

                                       25
<PAGE>

         Agent for the benefit of the Tranche A Secured Parties, substantially
         in the form of Exhibit D-1 attached hereto.

                  "TRANCHE A BORROWING" means a borrowing consisting of Tranche
         A Advances of the same Type made on the same day by the Tranche A
         Lenders.

                  "TRANCHE A COLLATERAL DOCUMENTS" means the Tranche A Borrower
         Security Agreement, the Tranche A Enterprises Pledge Agreement, the
         Tranche A Mortgage and the Tranche A Note.

                  "TRANCHE A COMMITMENT" has the meaning specified in Section
         2.01(a).

                  "TRANCHE A ENTERPRISES PLEDGE AGREEMENT" means the agreement
         by NU Enterprises in favor of the Collateral Agent for the benefit of
         the Tranche A Secured Parties, substantially in the form of Exhibit E-1
         attached hereto.

                  "TRANCHE A INITIAL LENDERS" has the meaning specified in the
         recital of parties to this Agreement.

                  "TRANCHE A LENDERS" means the Tranche A Initial Lenders and
         each Person, other than natural persons, that have or shall become and
         remain a party hereto as a "Tranche A Lender" pursuant to Section 9.07.

                  "TRANCHE A LIEN" has the meaning specified in Section 8.07.

                  "TRANCHE A MATURITY DATE" means the Borrowing Date.

                  "TRANCHE A MORTGAGE" means the mortgage with respect to the
         Tranche A Advances, substantially in the form of Exhibit F-1.

                  "TRANCHE A NOTE" means a promissory note of the Borrower
         payable to the order of any Tranche A Lender, in substantially the form
         of Exhibit A-1 hereto, evidencing the indebtedness of the Borrower to
         such Tranche A Lender resulting from the Tranche A Advances made by or
         owed to such Tranche A Lender.

                  "TRANCHE A OBLIGATIONS" means all Tranche A Amounts owed by
         the Borrower to the Tranche A Secured Parties under the Loan Documents.

                  "TRANCHE A SECURED PARTIES" means (a) the Tranche A Lenders
         and (b) the Collateral Agent as party to the Tranche A Collateral
         Documents.

                  "TRANCHE B ADVANCE" has the meaning specified in Section
         2.01(b).

                                       26
<PAGE>

                  "TRANCHE B BORROWER SECURITY AGREEMENT" means the agreement by
         the Borrower in favor of the Collateral Agent for the benefit of the
         Tranche B Secured Parties, substantially in the form of Exhibit D-2
         attached hereto.

                  "TRANCHE B BORROWING" means a borrowing consisting of Tranche
         B Advances of the same Type made on the same day by the Tranche B
         Lenders.

                  "TRANCHE B COLLATERAL DOCUMENTS" means the Tranche B Borrower
         Security Agreement, the Tranche B Enterprises Pledge Agreement, the
         Tranche B Mortgage and the Tranche B Note.

                  "TRANCHE B COMMITMENT" has the meaning specified in Section
         2.01(b).

                  "TRANCHE B ENTERPRISES PLEDGE AGREEMENT" means the agreement
         by NU Enterprises in favor of the Collateral Agent for the benefit of
         the Tranche B Secured Parties, substantially in the form of Exhibit E-2
         attached hereto.

                  "TRANCHE B INITIAL LENDERS" has the meaning specified in the
         recital of parties to this Agreement.

                  "TRANCHE B LENDERS" means the Tranche B Initial Lenders and
         each Person, other than natural persons, that have or shall become and
         remain a party hereto as a "Tranche B Lender" pursuant to Section 9.07.

                  "TRANCHE B LIEN" has the meaning specified in Section 8.07.

                  "TRANCHE B MATURITY DATE" means December 29, 2000.

                  "TRANCHE B MORTGAGE" means the mortgage with respect to
         Tranche B Advances, substantially in the form of Exhibit F-2.

                  "TRANCHE B NOTE" means a promissory note of the Borrower
         payable to the order of any Tranche B Lender, in substantially the form
         of Exhibit A-2 hereto, evidencing the indebtedness of the Borrower to
         such Tranche B Lender resulting from the Tranche B Advances made by or
         owed to such Tranche B Lender.

                  "TRANCHE B OBLIGATIONS" means all amounts owed by the Borrower
         to the Tranche B Secured Parties under the Loan Documents other than
         the Tranche A Amounts.

                  "TRANCHE B SECURED PARTIES" means (a) the Tranche B Lenders,
         (b) each of the Collateral Agent and the Administrative Agent as
         parties to the Tranche B Collateral Documents and the other Loan
         Documents to

                                       27
<PAGE>

         which each is a party, and (c) the Permitted Hedge Providers, if any.

                  "TYPE" has the meaning specified in the definition of
         "Advance" in this Section 1.01.

                  "UCC" means the Uniform Commercial Code as in effect from time
         to time in the State of New York.

                  "VOTING STOCK" means capital stock issued by a corporation, or
         equivalent interests in any other Person, the holders of which are
         ordinarily, in the absence of contingencies, entitled to vote for the
         election of directors (or persons performing similar functions) of such
         Person, even if the right so to vote has been suspended by the
         happening of such a contingency.

                  "WELFARE PLAN" means a welfare plan, as defined in Section
         3(1) of ERISA, that is maintained for employees of any Loan Party or in
         respect of which any Loan Party could have liability.

                  "WITHDRAWAL LIABILITY" has the meaning specified in Part I of
         Subtitle E of Title IV of ERISA.

                  "WMECO" has the meaning set forth in the Preliminary
         Statements to this Agreement.

                  "WMECO ACQUISITION" means the acquisition by the Borrower of
         the WMECO Generating Assets.

                  "WMECO ACQUISITION DOCUMENTS" means the WMECO Asset
         Demarcation Agreement, the WMECO Assumption Agreement, the WMECO
         Interconnection Agreement and the WMECO Purchase and Sale Agreement.

                  "WMECO ASSIGNMENT AND ASSUMPTION AGREEMENT" means the
         Assignment and Assumption Agreement, dated as of March 14, 2000,
         between the Borrower and WMECO.

                  "WMECO ASSET DEMARCATION AGREEMENT" means the Asset
         Demarcation Agreement dated as of the Acquisition Date, between WMECO
         and the Borrower.

                  "WMECO ASSUMPTION AGREEMENT" means the Assumption Agreement
         dated July 2, 1999, between Northeast Utilities and WMECO.

                  "WMECO GENERATING ASSETS" means the hydroelectric and pumped
         storage generating assets and related assets acquired or to be
         acquired, as the case may be, by the Borrower from WMECO pursuant to
         the WMECO Purchase and Sale Agreement.

                  "WMECO INDENTURE" means the First Mortgage Indenture and Deed
         of Trust dated as of August 1, 1954,

                                       28
<PAGE>

         as amended as of the date hereof, between WMECO and State Street Bank
         and Trust Company.

                  "WMECO INTERCONNECTION AGREEMENT" means the Interconnection
         Agreement dated July 2, 1999, between the Borrower and WMECO.

                  "WMECO PURCHASE AND SALE AGREEMENT" means the Purchase and
         Sale Agreement dated July 2, 1999, between the Borrower and WMECO.

                  "WMECO PURCHASE PRICE" means the aggregate amount payable by
         the Borrower to WMECO for the WMECO Generating Assets pursuant to the
         WMECO Purchase and Sale Agreements.

         SECTION 1.02. COMPUTATION OF TIME PERIODS. In this Agreement in the
computation of periods of time from a specified date to a later specified date,
the word "from" means "from and including" and the words "to" and "until" each
mean "to but excluding".

         SECTION 1.03. ACCOUNTING TERMS. All accounting terms not specifically
defined herein shall be construed in accordance with generally accepted
accounting principles consistent with those applied in the preparation of the
financial statements referred to in Section 5.01(f) ("GAAP").

         SECTION 1.04. REFERENCES TO OTHER AGREEMENTS. Unless otherwise provided
herein, references to any other agreement or document shall refer to such
agreement or document as amended, supplemented or otherwise modified in
accordance with the terms hereof and thereof.

                                   ARTICLE II

                        AMOUNTS AND TERMS OF THE ADVANCES

         SECTION 2.01. THE ADVANCES. (a) Each Tranche A Lender severally agrees,
on the terms and conditions hereinafter set forth, to make one advance (the
"TRANCHE A ADVANCE") to the Borrower, on the Borrowing Date, which must occur on
a Business Day during the period from the date hereof until the Termination
Date, in an aggregate amount not to exceed the amount set forth opposite such
Tranche A Lender's name on Schedule I attached hereto under the heading "Tranche
A Commitment" or, if such Tranche A Lender has entered into any Assignment and
Acceptance, set forth for such Tranche A Lender in the Register (under the
heading "Tranche A Commitment") maintained by the Administrative Agent pursuant
to Section 9.07(d), as such amount may be decreased pursuant to Section 2.04
(such Tranche A Lender's "TRANCHE A COMMITMENT"), PROVIDED, HOWEVER, that (i)
each Tranche A Lender shall make no more than one Tranche A

                                       29
<PAGE>

Advance and (ii) the Tranche A Advances and the Tranche B Advances shall be made
on the same Borrowing Date. The Tranche A Borrowing shall be in an aggregate
amount of U.S.$5,000,000 or an integral multiple of U.S.$1,000,000 in excess
thereof and shall consist of Tranche A Advances made simultaneously by the
Tranche A Lenders ratably according to their respective Tranche A Commitments.
Amounts borrowed under this Section 2.01(a) and repaid or prepaid may not be
reborrowed.

         (b) Each Tranche B Lender severally agrees, on the terms and conditions
hereinafter set forth, to make one advance (the "TRANCHE B ADVANCE") to the
Borrower, on the Borrowing Date, which must occur on a Business Day during the
period from the date hereof until the Termination Date, in an aggregate amount
not to exceed the amount set forth opposite such Tranche B Lender's name on
Schedule I attached hereto (under the heading "Tranche B Commitment") or, if
such Tranche B Lender has entered into any Assignment and Acceptance, set forth
for such Tranche B Lender in the Register under the heading "Tranche B
Commitment" maintained by the Administrative Agent pursuant to Section 9.07(d),
as such amount may be decreased pursuant to Section 2.04 (such Tranche B
Lender's "TRANCHE B COMMITMENT"), PROVIDED, HOWEVER, that (i) each Tranche B
Lender shall make no more than one Tranche B Advance and (ii) the Tranche B
Advances and the Tranche A Advances shall be made on the same Borrowing Date.
The Tranche B Borrowing shall be in an aggregate amount of U.S.$5,000,000 or an
integral multiple of U.S.$1,000,000 in excess thereof and shall consist of
Tranche B Advances made simultaneously by the Tranche B Lenders ratably
according to their respective Tranche B Commitments. Amounts borrowed under this
Section 2.01(b) and repaid or prepaid may not be reborrowed.

         SECTION 2.02. MAKING THE ADVANCES. (a) The Borrowings of the Tranche A
Advances and the Tranche B Advances shall be made on notice, given not later
than 11:00 A.M. (New York City time) on the third Business Day prior to the date
of the proposed Borrowings by the Borrower to the Administrative Agent, which
shall give to each Lender prompt notice thereof by fax. The notice of Borrowings
(the "NOTICE OF BORROWING") shall be by telephone, confirmed immediately in a
writing, in substantially the form of Exhibit B hereto, sent by fax specifying
therein the requested (i) date of the Borrowings, (ii) aggregate amount of the
Borrowings, (iii) amount of the Tranche A Borrowing and of the Tranche B
Borrowing, (iv) Type of Tranche B Advances comprising the Tranche B Borrowing,
and (v) initial Interest Period for each Eurodollar Rate Advance. Each Lender
shall, before 10:00 A.M. (New York City time) on the date of the Borrowings,
make available for the account of its Applicable Lending Office to the
Administrative Agent at the Administrative Agent's Account, in immediately
available funds, such Lender's ratable portion of each of the Borrowings. After
the Administrative Agent's receipt of such funds and upon fulfillment of the
applicable conditions

                                       30
<PAGE>

set forth in Article III, the Administrative Agent will make such funds
available in accordance with the terms of the Flow of Funds Memorandum.

         (b) Anything in subsection (a) above to the contrary notwithstanding,
the Borrower may not select Eurodollar Rate Advances for (x) any Tranche A
Advances or (y) any Borrowing if the obligation of the Lenders to make
Eurodollar Rate Advances shall then be suspended pursuant to Section 2.08 or
2.09.

         (c) The Notice of Borrowing shall be irrevocable and binding on the
Borrower. The Borrower shall indemnify each Lender against any loss, cost or
expense incurred by such Lender as a result of any failure of the Borrower to
fulfill on or before the date specified in such Notice of Borrowing the
applicable conditions set forth in Article III, including, without limitation,
any loss (including loss of anticipated profits), cost or expense incurred by
reason of the liquidation or reemployment of deposits or other funds acquired by
such Lender to fund any Advance to be made by such Lender as part of the
Borrowings when such Advance, as a result of such failure, is not made on such
date.

         (d) Unless the Administrative Agent shall have received notice from a
Lender prior to the date of the Borrowing that such Lender will not make
available to the Administrative Agent such Lender's ratable portion of each
Borrowing, the Administrative Agent may assume that such Lender has made such
portion available to the Administrative Agent on the date of the Borrowing in
accordance with subsection (a) of this Section 2.02 and the Administrative Agent
may, in reliance upon such assumption, make available to the Borrower on such
date a corresponding amount. If and to the extent that such Lender shall not
have so made such ratable portion available to the Administrative Agent, such
Lender agrees to pay to the Administrative Agent forthwith on demand such
corresponding amount together with interest thereon, for each day from the date
such amount is made available to the Borrower until the date such amount is paid
to the Administrative Agent, at the Federal Funds Rate. If such Lender shall pay
to the Administrative Agent such corresponding amount, such amount so paid shall
constitute such Lender's Advance as part of the applicable Borrowing for
purposes of this Agreement.

         (e) The failure of any Lender to make the Advance to be made by it as
part of either Borrowing shall not relieve any other Lender of its obligation,
if any, hereunder to make its Advance(s) on the date of the Borrowings, but no
Lender shall be responsible for the failure of any other Lender to make the
Advance(s) to be made by such other Lender on the date of any Borrowings. The
rights and obligations of each of the Lenders under the Agreement are several.

                                       31
<PAGE>

         SECTION 2.03. REPAYMENT OF ADVANCES. (a) TRANCHE A ADVANCES. On the
Tranche A Maturity Date, the Borrower shall repay to the Administrative Agent
for the ratable account of the Tranche A Secured Parties (i) the aggregate
outstanding principal amount of the Tranche A Advances on such date, together
with all accrued and unpaid interest on such Advances, and (ii) all fees,
expenses and other amounts owing hereunder and under the other Loan Documents in
respect of such Advances (all such amounts in clauses (i) and (ii) above, the
"TRANCHE A AMOUNTS"). If the Administrative Agent receives the repayment of the
Tranche A Amounts on the Tranche A Maturity Date but is unable to distribute the
aggregate outstanding Tranche A Amounts to the Tranche A Lenders on the Tranche
A Maturity Date, then the Administrative Agent will distribute to the Tranche A
Lenders such Tranche A Amounts plus interest thereon at a per annum rate equal
to the Federal Funds Rate on the next Business Day after the Tranche A Maturity
Date.

         (b) TRANCHE B ADVANCES. On the Tranche B Maturity Date, the Borrower
shall repay to the Administrative Agent for the ratable account of the Tranche B
Lenders the aggregate principal amount of the Tranche B Advances outstanding on
such date, together with all accrued and unpaid interest on such principal
amount and all fees, expenses and other amounts owing hereunder and under the
other Loan Documents.

         SECTION 2.04. ADJUSTMENTS OF THE COMMITMENTS. (a) On the Borrowing
Date, after giving effect to the Borrowings on such date, the aggregate
Commitments of the Lenders shall be automatically and permanently reduced to
zero.

         (b) The Borrower may not otherwise reduce or terminate any of the
Commitments.

         SECTION 2.05. PREPAYMENTS. (a) OPTIONAL. The Borrower may, upon at
least five Business Days' notice to the Administrative Agent stating the
proposed date and aggregate principal amount of the prepayment, and if such
notice is given the Borrower shall, prepay the outstanding aggregate principal
amount of the Tranche B Advances in whole or ratably among the Tranche B Lenders
in part, together with accrued interest to the date of such prepayment on the
principal amount prepaid; PROVIDED, HOWEVER, that (i) each partial prepayment
shall be in an aggregate principal amount of $10,000,000 or an integral multiple
of $1,000,000 in excess thereof and (ii) if any prepayment of a Eurodollar Rate
Advance is made on a date other than the last day of an Interest Period for such
Advance, the Borrower shall also pay any amounts owing pursuant to Section
9.04(c); PROVIDED FURTHER, HOWEVER, the Borrower may not optionally prepay any
Tranche B Advances until the Tranche A Advances have been repaid in full and all
Tranche A Commitments reduced to zero.

                                       32
<PAGE>

         (b) MANDATORY. The Borrower shall:

                  (i) on the issuance date of any Permanent Financing, prepay
         the aggregate outstanding principal amount of the Advances on such
         date, together with all accrued and unpaid interest on such principal
         amount and all fees, expenses and other amounts owing hereunder and
         under the other Loan Documents;

                  (ii) within 30 days from the date of receipt by the Borrower
         of any Net Cash Proceeds from the sale, lease, transfer or other
         disposition of any assets of the Borrower (excluding sales of obsolete
         and worn out equipment, sales of electricity and any other ordinary
         course of business sales permitted in Section 6.02(e) and sales of any
         assets, replacements for which are intended to be purchased with such
         Net Cash Proceeds), prepay an aggregate principal amount of the
         outstanding Advances together with the accrued and unpaid interest
         thereon equal to the Net Cash Proceeds from such sale, lease, transfer
         or other disposition;

                  (iii) within 30 days from the date of receipt by the Borrower
         of any Net Cash Proceeds from any Extraordinary Receipt, prepay an
         aggregate principal amount of the outstanding Advances together with
         the accrued and unpaid interest thereon equal to the Net Cash Proceeds
         from such Extraordinary Receipt; and

                  (iv) on each Excess Cash Flow Payment Date, prepay an
         aggregate principal amount of the outstanding Advances together with
         all accrued and unpaid interest thereon equal to 100% of the Available
         Excess Cash Flow.

Prepayments received pursuant to clauses (ii), (iii) and (iv) of this Section
2.05(b) shall be first applied ratably to reduce the Tranche B Advances
outstanding until all such Tranche B Advances are reduced to zero, and then
ratably to the Tranche A Advances outstanding, if any.

         SECTION 2.06. INTEREST. (a) SCHEDULED INTEREST. The Borrower shall pay
to the Administrative Agent for the ratable account of the Lenders interest on
the unpaid principal amount of each Advance from the date of such Advance until
such principal amount shall be paid in full, at the following rates per annum:

                  (i) BASE RATE ADVANCES. During such periods as such Advance is
         a Base Rate Advance, a rate per annum equal at all times to the sum of
         (A) the Base Rate in effect from time to time PLUS (B) the Applicable
         Margin in effect from time to time, payable in arrears monthly on the
         last day of each month during such periods and on the date such Base
         Rate Advance shall be Converted or paid in full.

                                       33
<PAGE>

                  (ii) EURODOLLAR RATE ADVANCES. During such periods as such
         Tranche B Advance is a Eurodollar Rate Advance, a rate per annum equal
         at all times during each Interest Period for such Tranche B Advance to
         the sum of (A) the Eurodollar Rate for such Interest Period for such
         Tranche B Advance PLUS (B) the Applicable Margin in effect from time to
         time, payable in arrears on the last day of such Interest Period and,
         if such Interest Period has a duration of more than three months, on
         each day that occurs during such Interest Period every three months
         from the first day of such Interest Period and on the date such
         Eurodollar Rate Advance shall be Converted or paid in full.

         (b) DEFAULT INTEREST. Upon the occurrence and during the continuance of
an Event of Default, the Borrower shall pay to the Administrative Agent for the
ratable account of the Lenders interest on (i) the unpaid principal amount of
each Advance, payable in arrears on the dates referred to in clause (a)(i) or
(a)(ii) above and on demand, at a rate per annum equal at all times to 2% per
annum above the rate per annum required to be paid on such Advance pursuant to
clause (a)(i) or (a)(ii) above and (ii) to the fullest extent permitted by law,
the amount of any interest, fee or other amount payable hereunder that is not
paid when due, from the date such amount shall be due until such amount shall be
paid in full, payable in arrears on the date such amount shall be paid in full
and on demand, at a rate per annum equal at all times to 2% per annum above the
rate per annum required to be paid, in the case of interest, on the Type of
Advance on which such interest has accrued pursuant to clause (a)(i) or (a)(ii)
above, and, in all other cases, on Base Rate Advances pursuant to clause (a)(i)
above.

         (c) NOTICE OF INTEREST RATE. Promptly after receipt of the Notice of
Borrowing pursuant to Section 2.02(a), the Administrative Agent shall give
notice to the Borrower and each Lender of the applicable interest rate
determined by the Administrative Agent for purposes of clause (a)(i) or (ii).

         SECTION 2.07. FEES. (a) COMMITMENT FEE. The Borrower shall pay to the
Administrative Agent for the account of the Lenders a commitment fee, from the
date hereof to the Termination Date payable quarterly in arrears and on the
Borrowing Date, with the final payment due on the Termination Date, at the rate
of 2 of 1% per annum on the average daily unused portion of each Lender's
Commitment during such period; PROVIDED, HOWEVER, that no commitment fee shall
accrue on any of the Commitments of a Defaulting Lender so long as such Lender
shall be a Defaulting Lender. This Section 2.07(a) shall supersede the paragraph
entitled "Facility Fee" in the Fee Letter from and after the date hereof.

                                       34
<PAGE>

         (b) ADMINISTRATIVE AGENT'S FEES. The Borrower shall pay to the
Administrative Agent for its own account such fees as may from time to time be
agreed between the Borrower and the Administrative Agent.

         (c) COLLATERAL AGENT'S FEES. The Borrower shall pay to the Collateral
Agent for its own account such fees as may from time to time be agreed between
the Borrower and the Collateral Agent.

         SECTION 2.08. CONVERSION OF ADVANCES. (a) OPTIONAL. The Borrower may on
any Business Day, upon notice given to the Administrative Agent not later than
11:00 A.M. (New York City time) on the third Business Day prior to the date of
the proposed Conversion and subject to the provisions of Sections 2.06 and 2.09,
Convert all or any portion of the Tranche B Advances of one Type comprising the
same Borrowing into Advances of the other Type; PROVIDED, HOWEVER, that any
Conversion of Eurodollar Rate Advances into Base Rate Advances shall be made
only on the last day of an Interest Period for such Eurodollar Rate Advances,
any Conversion of Base Rate Advances into Eurodollar Rate Advances shall be in
an amount not less than the minimum amount of $10,000,000, no Conversion of any
Advances shall result in more than five Interest Periods outstanding at any time
and each Conversion of Advances comprising part of the same Borrowing shall be
made ratably among the Lenders in accordance with their Tranche B Advances. Each
such notice of Conversion shall, within the restrictions specified above,
specify (i) the date of such Conversion, (ii) the Advances to be Converted and
(iii) if such Conversion is into Eurodollar Rate Advances, the duration of the
initial Interest Period for such Advances. Each notice of Conversion shall be
irrevocable and binding on the Borrower.

         (b) MANDATORY. (i) On the date on which the aggregate unpaid principal
amount of Eurodollar Rate Advances comprising any Borrowing shall be reduced, by
payment or prepayment or otherwise, to less than $1,000,000, such Advances shall
automatically Convert into Base Rate Advances.

         (ii) If the Borrower shall fail to select the duration of any Interest
Period for any Eurodollar Rate Advances in accordance with the provisions
contained in the definition of "Interest Period" in Section 1.01, the
Administrative Agent will forthwith so notify the Borrower and the Lenders,
whereupon each such Eurodollar Rate Advance will automatically, on the last day
of the then existing Interest Period therefor, Convert into a Base Rate Advance.

         (iii) Upon the occurrence and during the continuance of any Event of
Default, (x) each Eurodollar Rate Advance will automatically, on the last day of
the then existing Interest Period therefor, Convert into a Base Rate Advance and
(y) the obligation of the Lenders to make, or to

                                       35
<PAGE>

Convert Advances into, Eurodollar Rate Advances shall be suspended.

         SECTION 2.09. INCREASED COSTS, ETC. (a) If, due to either (i) the
introduction of or any change in or in the interpretation of any law or
regulation or (ii) the compliance with any guideline or request from any central
bank or other Governmental Authority (whether or not having the force of law),
there shall be any increase in the cost to any Lender of agreeing to make or of
making, funding or maintaining Eurodollar Rate Advances (excluding for purposes
of this Section 2.09 any such increased costs resulting from (A) Taxes or Other
Taxes (as to which Section 2.11 shall govern) and (B) changes in the basis of
taxation of overall net income or overall gross income by the United States or
by the foreign jurisdiction or state under the laws of which such Lender is
organized or has its Applicable Lending Office or any political subdivision
thereof), then the Borrower shall from time to time, upon demand by such Lender
(with a copy of such demand to the Administrative Agent), pay to the
Administrative Agent for the account of such Lender additional amounts
sufficient to compensate such Lender for such increased cost; PROVIDED, HOWEVER,
that a Lender claiming additional amounts under this Section 2.09(a) agrees to
use reasonable efforts (consistent with its internal policy and legal and
regulatory restrictions) to designate a different Applicable Lending Office if
the making of such a designation would avoid the need for, or reduce the amount
of, such increased cost that may thereafter accrue and would not, in the
reasonable judgment of such Lender, be otherwise disadvantageous to such Lender.
A certificate as to the amount of such increased cost, and the basis therefor,
submitted to the Borrower by such Lender, shall be conclusive and binding for
all purposes, absent manifest error.

         (b) If any Lender determines that compliance with any law or regulation
or any guideline or request from any central bank or other Governmental
Authority (whether or not having the force of law) affects or would affect the
amount of capital required or expected to be maintained by such Lender or any
corporation controlling such Lender and that the amount of such capital is
increased by or based upon the existence of such Lender's commitment to lend
hereunder and other commitments of such type, then, upon demand by such Lender
(with a copy of such demand to the Administrative Agent), the Borrower shall pay
to the Administrative Agent for the account of such Lender, from time to time as
specified by such Lender, additional amounts sufficient to compensate such
Lender in the light of such circumstances, to the extent that such Lender
reasonably determines such increase in capital to be allocable to the existence
of such Lender's commitment to lend. A certificate as to such amounts, and the
basis therefor, submitted to the Borrower by such Lender shall be conclusive and
binding for all purposes, absent manifest error.

                                       36
<PAGE>

         (c) If, with respect to any Eurodollar Rate Advances the Required
Tranche B Lenders notify the Administrative Agent that the Eurodollar Rate for
any Interest Period for such Tranche B Advances will not adequately reflect the
cost to such Tranche B Lenders of making, funding or maintaining their
Eurodollar Rate Advances for such Interest Period, the Administrative Agent
shall forthwith so notify the Borrower and the Tranche B Lenders, whereupon (i)
each such Eurodollar Rate Advance will automatically, on the last day of the
then existing Interest Period therefor, Convert into a Base Rate Advance and
(ii) the obligation of the Tranche B Lenders to make, or to Convert Tranche B
Advances into, Eurodollar Rate Advances shall be suspended until the
Administrative Agent shall notify the Borrower that such Tranche B Lenders have
determined that the circumstances causing such suspension no longer exist.

         (d) Notwithstanding any other provision of this Agreement, if the
introduction of or any change in or in the interpretation of any law or
regulation shall make it unlawful, or any central bank or other Governmental
Authority shall assert that it is unlawful, for any Tranche B Lender or its
Eurodollar Lending Office to perform its obligations hereunder to make
Eurodollar Rate Advances or to continue to fund or maintain Eurodollar Rate
Advances hereunder, then, on notice thereof and demand therefor by such Tranche
B Lender to the Borrower through the Administrative Agent, (i) each Eurodollar
Rate Advance will automatically, upon such demand, Convert into a Base Rate
Advance and (ii) the obligation of the Tranche B Lenders to make, or to Convert
Tranche B Advances into, Eurodollar Rate Advances shall be suspended until the
Administrative Agent shall notify the Borrower that such Tranche B Lender has
determined that the circumstances causing such suspension no longer exist;
PROVIDED, HOWEVER, that, before making any such demand, such Tranche B Lender
agrees to use reasonable efforts (consistent with its internal policy and legal
and regulatory restrictions) to designate a different Eurodollar Lending Office
if the making of such a designation would allow such Tranche B Lender or its
Eurodollar Lending Office to continue to perform its obligations to make
Eurodollar Rate Advances or to continue to fund or maintain Eurodollar Rate
Advances and would not, in the reasonable judgment of such Tranche B Lender, be
otherwise disadvantageous to such Tranche B Lender.

         (e) If the Borrower becomes obligated to pay additional amounts to any
Lender pursuant to this Section 2.09 as a result of any condition which is not
generally applicable to all Lenders then, unless the Lender to which such
conditions apply has theretofore taken steps to remove or cure, and has removed
or cured, the conditions creating the cause for such obligation to pay such
additional amounts, the Borrower may, so long as no Event of Default shall have
occurred and be continuing, designate another lender which is willing to
purchase all rights and

                                       37
<PAGE>

obligations of such Lender and which is reasonably acceptable to the
Administrative Agent and the Required Lenders (such lender being herein called a
"REPLACEMENT LENDER") to purchase for cash all of the rights and obligations of
such Lender under this Agreement and all of such Lender=s rights hereunder,
without recourse to or warranty (other than title) by, or expense to, such
Lender in an amount equal to the outstanding principal amount of the Advances
payable to such Lender plus any accrued but unpaid interest on such Advances,
expense reimbursements and indemnities (including, without limitation, under
Section 9.04(b)) and other amounts in respect of that Lender=s Commitment and
Advances hereunder. Such Lender shall consummate such sale in accordance with
such terms as promptly as reasonably practicable, and thereafter such Lender
shall no longer be a party hereto or have any obligations or rights hereunder
(except rights which, pursuant to the provisions of this Agreement, survive the
termination of this Agreement and the repayment of the Notes or the Advances),
and the Replacement Lender shall succeed to such obligations and rights.

         SECTION 2.10. PAYMENTS AND COMPUTATIONS. (a) The Borrower shall make
each payment hereunder and under the Notes, irrespective of any right of
counterclaim or set-off (except as otherwise provided in Section 2.14), not
later than 5:00 P.M. (New York City time) for principal on the Tranche A
Advances and not later than 11:00 A.M. (New York City time) for all other
amounts due hereunder on the day when due in U.S. dollars to the Administrative
Agent at the Administrative Agent's Account in immediately available funds. The
Administrative Agent will promptly thereafter cause like funds to be distributed
(i) if such payment by the Borrower is in respect of principal, interest,
commitment fees or any other Obligation then payable hereunder and under the
Notes to more than one Lender, to such Lenders for the account of their
respective Applicable Lending Offices ratably in accordance with the amounts of
such respective Obligations then payable to such Lenders and (ii) if such
payment by the Borrower is in respect of any Obligation then payable hereunder
to one Lender, to such Lender for the account of its Applicable Lending Office,
in each case to be applied in accordance with the terms of this Agreement. Upon
its acceptance of an Assignment and Acceptance and recording of the information
contained therein in the Register pursuant to Section 9.07(d), from and after
the effective date of such Assignment and Acceptance, the Administrative Agent
shall make all payments hereunder and under the Notes in respect of the interest
assigned thereby to the Lender assignee thereunder, and the parties to such
Assignment and Acceptance shall make all appropriate adjustments in such
payments for periods prior to such effective date directly between themselves.

         (b) The Borrower hereby authorizes each Lender, if and to the extent
payment owed to such Lender is not made to the Administrative Agent when due
hereunder or

                                       38
<PAGE>

under the Note held by such Lender, to charge from time to time against any or
all of the Borrower's accounts with such Lender (other than the Collateral
Accounts, access to which shall be governed by the Loan Documents) any amount so
due.

         (c) All computations of interest and fees shall be made by the
Administrative Agent on the basis of a year of 360 days, in each case for the
actual number of days (including the first day but excluding the last day)
occurring in the period for which such interest, fees or commissions are
payable. Each determination by the Administrative Agent of an interest rate, fee
or commission hereunder shall be conclusive and binding for all purposes, absent
manifest error.

         (d) Whenever any payment hereunder or under the Notes shall be stated
to be due on a day other than a Business Day, such payment shall be made on the
next succeeding Business Day, and such extension of time shall in such case be
included in the computation of payment of interest or commitment fee, as the
case may be; PROVIDED, HOWEVER, that, if such extension would cause payment of
interest on or principal of Eurodollar Rate Advances to be made in the next
following calendar month, such payment shall be made on the next preceding
Business Day.

         (e) Unless the Administrative Agent shall have received notice from the
Borrower prior to the date on which any payment is due to any Lender hereunder
that the Borrower will not make such payment in full, the Administrative Agent
may assume that the Borrower has made such payment in full to the Administrative
Agent on such date and the Administrative Agent may, in reliance upon such
assumption, cause to be distributed to each such Lender on such due date an
amount equal to the amount then due such Lender. If and to the extent the
Borrower shall not have so made such payment in full to the Administrative
Agent, each such Lender shall repay to the Administrative Agent forthwith on
demand such amount distributed to such Lender together with interest thereon,
for each day from the date such amount is distributed to such Lender until the
date such Lender repays such amount to the Administrative Agent, at the Federal
Funds Rate.

         SECTION 2.11. TAXES. (a) Any and all payments by the Borrower hereunder
or under the Notes shall be made, in accordance with Section 2.10, free and
clear of and without deduction for any and all present or future taxes, levies,
imposts, deductions, charges or withholdings, and all liabilities with respect
thereto, EXCLUDING, in the case of each Lender and the Administrative Agent,
taxes that are imposed on its overall net income by the United States and taxes
that are imposed on its overall net income (and franchise taxes imposed in lieu
thereof) by the state or foreign jurisdiction under the laws of which such
Lender or the Administrative Agent (as the case may be) is organized or any
political subdivision thereof and, in the case of

                                       39
<PAGE>

each Lender, taxes that are imposed on its overall net income (and franchise
taxes imposed in lieu thereof) by the state or foreign jurisdiction of such
Lender's Applicable Lending Office or any political subdivision thereof (all
such non-excluded taxes, levies, imposts, deductions, charges, withholdings and
liabilities in respect of payments hereunder or under the Notes being
hereinafter referred to as "TAXES"). If the Borrower shall be required by law to
deduct any Taxes from or in respect of any sum payable hereunder or under any
Note to any Lender or the Administrative Agent, (i) the sum payable shall be
increased as may be necessary so that after making all required deductions
(including deductions applicable to additional sums payable under this Section
2.11) such Lender or the Administrative Agent (as the case may be) receives an
amount equal to the sum it would have received had no such deductions been made,
(ii) the Borrower shall make such deductions and (iii) the Borrower shall pay
the full amount deducted to the relevant taxation authority or other authority
in accordance with applicable law.

         (b) In addition, the Borrower shall pay any present or future stamp,
documentary, excise, property or similar taxes, charges or levies that arise
from any payment made hereunder or under the Notes or from the execution,
delivery or registration of, performing under, or otherwise with respect to,
this Agreement or the Notes (hereinafter referred to as "OTHER TAXES").

         (c) The Borrower shall indemnify each Lender and the Administrative
Agent for and hold it harmless against the full amount of Taxes and Other Taxes,
and for the full amount of Taxes of any kind imposed by any jurisdiction on
amounts payable under this Section 2.11, imposed on or paid by such Lender or
the Administrative Agent (as the case may be) and any liability (including
penalties, additions to tax, interest and expenses) arising therefrom or with
respect thereto. This indemnification shall be made within 30 days from the date
such Lender or the Administrative Agent (as the case may be) makes written
demand therefor.

         (d) Within 30 days after the date of any payment of Taxes, the Borrower
shall furnish to the Administrative Agent, at its address referred to in Section
9.02, the original or a certified copy of a receipt evidencing such payment. In
the case of any payment hereunder or under the Notes by or on behalf of the
Borrower through an account or branch outside the United States or by or on
behalf of the Borrower by a payor that is not a United States person, if the
Borrower determines that no Taxes are payable in respect thereof, the Borrower
shall furnish, or shall cause such payor to furnish, to the Administrative
Agent, at such address, an opinion of counsel acceptable to the Administrative
Agent stating that such payment is exempt from Taxes. For purposes of this
subsection (d) and subsection (e), the terms "UNITED STATES" and "UNITED STATES

                                       40
<PAGE>

PERSON" shall have the meanings specified in Section 7701 of the Internal
Revenue Code.

         (e) Each Lender organized under the laws of a jurisdiction outside the
United States shall, on or prior to the date of its execution and delivery of
this Agreement in the case of each Initial Lender and on the date of the
Assignment and Acceptance pursuant to which it becomes a Lender in the case of
each other Lender, and from time to time thereafter as requested in writing by
the Borrower (but only so long thereafter as such Lender remains lawfully able
to do so), provide each of the Administrative Agent and the Borrower with two
original Internal Revenue Service forms W-8 ECI or W-8 BEN, as appropriate, or
any successor or other form prescribed by the Internal Revenue Service,
certifying that such Lender is exempt from or entitled to a reduced rate of
United States withholding tax on payments pursuant to this Agreement or the
Notes. If the forms provided by a Lender at the time such Lender first becomes a
party to this Agreement indicates a United States interest withholding tax rate
in excess of zero, withholding tax at such rate shall be considered excluded
from Taxes unless and until such Lender provides the appropriate form certifying
that a lesser rate applies, whereupon withholding tax at such lesser rate only
shall be considered excluded from Taxes for periods governed by such form;
PROVIDED, HOWEVER, that, if at the date of the Assignment and Acceptance
pursuant to which a Lender becomes a party to this Agreement, the Lender
assignor was entitled to payments under subsection (a) in respect of United
States withholding tax with respect to interest paid at such date, then, to such
extent, the term Taxes shall include (in addition to withholding taxes that may
be imposed in the future or other amounts otherwise includable in Taxes) United
States withholding tax, if any, applicable with respect to the Lender assignee
on such date. If any form or document referred to in this subsection (e)
requires the disclosure of information, other than information necessary to
compute the tax payable and information required on the date hereof by Internal
Revenue Service form W-8 ECI or W-8 BEN, that the Lender reasonably considers to
be confidential, the Lender shall give notice thereof to the Borrower and shall
not be obligated to include in such form or document such confidential
information.

         (f) For any period with respect to which a Lender has failed to provide
the Borrower with the appropriate form described in subsection (e) above (OTHER
THAN if such failure is due to a change in law occurring after the date on which
a form originally was required to be provided or if such form otherwise is not
required under subsection (e) above), such Lender shall not be entitled to
indemnification under subsection (a) or (c) with respect to Taxes imposed by the
United States by reason of such failure; PROVIDED, HOWEVER, that should a Lender
become subject to Taxes because of its failure to deliver a form required
hereunder, the Borrower shall take such steps as

                                       41
<PAGE>

such Lender shall reasonably request to assist such Lender to recover such
Taxes.

         SECTION 2.12. SHARING OF PAYMENTS, ETC. If any Lender shall obtain at
any time any payment (whether voluntary, involuntary, through the exercise of
any right of set-off, or otherwise) (a) on account of Obligations due and
payable to such Lender hereunder and under the Notes at such time in excess of
its ratable share (according to the proportion of (i) the amount of such
Obligations due and payable to such Lender at such time to (ii) the aggregate
amount of the Obligations due and payable to all Lenders hereunder and under the
Notes at such time) of payments on account of the Obligations due and payable to
all Lenders hereunder and under the Notes at such time obtained by all the
Lenders at such time or (b) on account of Obligations owing (but not due and
payable) to such Lender hereunder and under the Notes at such time in excess of
its ratable share (according to the proportion of (i) the amount of such
Obligations owing to such Lender at such time to (ii) the aggregate amount of
the Obligations owing (but not due and payable) to all Lenders hereunder and
under the Notes at such time) of payments on account of the Obligations owing
(but not due and payable) to all Lenders hereunder and under the Notes at such
time obtained by all of the Lenders at such time, such Lender shall forthwith
purchase from the other Lenders such participations in the Obligations due and
payable or owing to them, as the case may be, as shall be necessary to cause
such purchasing Lender to share the excess payment ratably with each of them;
PROVIDED, HOWEVER, that if all or any portion of such excess payment is
thereafter recovered from such purchasing Lender, such purchase from each other
Lender shall be rescinded and such other Lender shall repay to the purchasing
Lender the purchase price to the extent of such Lender's ratable share
(according to the proportion of (i) the purchase price paid to such Lender to
(ii) the aggregate purchase price paid to all Lenders) of such recovery together
with an amount equal to such Lender's ratable share (according to the proportion
of (i) the amount of such other Lender's required repayment to (ii) the total
amount so recovered from the purchasing Lender) of any interest or other amount
paid or payable by the purchasing Lender in respect of the total amount so
recovered. The Borrower agrees that any Lender so purchasing a participation
from another Lender pursuant to this Section 2.12 may, to the fullest extent
permitted by law, exercise all its rights of payment (including the right of
set-off) with respect to such participation as fully as if such Lender were the
direct creditor of the Borrower in the amount of such participation.

         SECTION 2.13. USE OF PROCEEDS. The proceeds of the Advances shall be
available (and the Borrower agrees that it shall use such proceeds) solely to
pay the Purchase Price for the Generating Assets and for fees, costs and
expenses incurred in connection with the Loan Documents and

                                       42
<PAGE>

related to the preparation, execution and delivery of the Loan Documents.

         SECTION 2.14. DEFAULTING LENDERS. (a) In the event that, at any one
time, (i) any Lender shall be a Defaulting Lender, (ii) such Defaulting Lender
shall owe a Defaulted Advance to the Borrower and (iii) the Borrower shall be
required to make any payment hereunder or under any other Loan Document to or
for the account of such Defaulting Lender, then the Borrower may, so long as no
Default shall occur or be continuing at such time and to the fullest extent
permitted by applicable law, set off and otherwise apply the Obligation of the
Borrower to make such payment to or for the account of such Defaulting Lender
against the Obligation of such Defaulting Lender to make such Defaulted Advance.
In the event that, on any date, the Borrower shall so set off and otherwise
apply its obligation to make any such payment against the Obligation of such
Defaulting Lender to make any such Defaulted Advance on or prior to such date,
the amount so set off and otherwise applied by the Borrower shall constitute for
all purposes of this Agreement and the other Loan Documents an Advance by such
Defaulting Lender made on the date pursuant to which such Defaulted Advance was
originally required to have been made pursuant to Section 2.01. Such Advance
shall be a Base Rate Advance and shall be considered, for all purposes of this
Agreement, to comprise part of the Borrowing in connection with which such
Defaulted Advance was originally required to have been made pursuant to Section
2.01, even if the other Advances comprising such Borrowing shall be Eurodollar
Rate Advances on the date such Advance is deemed to be made pursuant to this
subsection (a). The Borrower shall notify the Administrative Agent at any time
the Borrower exercises its right of set-off pursuant to this subsection (a) and
shall set forth in such notice (A) the name of the Defaulting Lender and the
Defaulted Advance required to be made by such Defaulting Lender and (B) the
amount set off and otherwise applied in respect of such Defaulted Advance
pursuant to this subsection (a). Any portion of such payment otherwise required
to be made by the Borrower to or for the account of such Defaulting Lender which
is paid by the Borrower, after giving effect to the amount set off and otherwise
applied by the Borrower pursuant to this subsection (a), shall be applied by the
Administrative Agent as specified in subsection (b) or (c) of this Section 2.14.

         (b) In the event that, at any one time, (i) any Lender shall be a
Defaulting Lender, (ii) such Defaulting Lender shall owe a Defaulted Amount to
the Administrative Agent or any of the other Lenders and (iii) the Borrower
shall make any payment hereunder or under any other Loan Document to the
Administrative Agent for the account of such Defaulting Lender, then the
Administrative Agent may, on its behalf or on behalf of such other Lenders and
to the fullest extent permitted by applicable law, apply at such time the amount
so paid by the Borrower to or for the account of such Defaulting Lender to the
payment of each

                                       43
<PAGE>

such Defaulted Amount to the extent required to pay such Defaulted Amount. In
the event that the Administrative Agent shall so apply any such amount to the
payment of any such Defaulted Amount on any date, the amount so applied by the
Administrative Agent shall constitute for all purposes of this Agreement and the
other Loan Documents payment, to such extent, of such Defaulted Amount on such
date. Any such amount so applied by the Administrative Agent shall be retained
by the Administrative Agent or distributed by the Administrative Agent to such
other Lenders, ratably in accordance with the respective portions of such
Defaulted Amounts payable at such time to the Administrative Agent and such
other Lenders and, if the amount of such payment made by the Borrower shall at
such time be insufficient to pay all Defaulted Amounts owing at such time to the
Administrative Agent and the other Lenders, in the following order of priority:

                  (i) FIRST, to the Administrative Agent for any Defaulted
         Amount then owing to the Administrative Agent; and

                  (ii) SECOND, to any other Lenders for any Defaulted Amounts
         then owing to such other Lenders, ratably in accordance with such
         respective Defaulted Amounts then owing to such other Lenders.

Any portion of such amount paid by the Borrower for the account of such
Defaulting Lender remaining, after giving effect to the amount applied by the
Administrative Agent pursuant to this subsection (b), shall be applied by the
Administrative Agent as specified in subsection (c) of this Section 2.14.

         (c) In the event that, at any one time, (i) any Lender shall be a
Defaulting Lender, (ii) such Defaulting Lender shall not owe a Defaulted Advance
or a Defaulted Amount and (iii) the Borrower, the Administrative Agent or any
other Lender shall be required to pay or distribute any amount hereunder or
under any other Loan Document to or for the account of such Defaulting Lender,
then the Borrower or such other Lender shall pay such amount to the
Administrative Agent to be held by the Administrative Agent, to the fullest
extent permitted by applicable law, in escrow or the Administrative Agent shall,
to the fullest extent permitted by applicable law, hold in escrow such amount
otherwise held by it. Any funds held by the Administrative Agent in escrow under
this subsection (c) shall be deposited by the Administrative Agent in an account
with Citibank, in the name and under the control of the Administrative Agent,
but subject to the provisions of this subsection (c). The terms applicable to
such account, including the rate of interest payable with respect to the credit
balance of such account from time to time, shall be Citibank's standard terms
applicable to escrow accounts maintained with it. Any interest credited to such
account from time to time shall be held by the Administrative Agent

                                       44
<PAGE>

in escrow under, and applied by the Administrative Agent from time to time in
accordance with the provisions of, this subsection (c). The Administrative Agent
shall, to the fullest extent permitted by applicable law, apply all funds so
held in escrow from time to time to the extent necessary to make any Advances
required to be made by such Defaulting Lender and to pay any amount payable by
such Defaulting Lender hereunder and under the other Loan Documents to the
Administrative Agent or any other Lender, as and when such Advances or amounts
are required to be made or paid and, if the amount so held in escrow shall at
any time be insufficient to make and pay all such Advances and amounts required
to be made or paid at such time, in the following order of priority:

                  (i) FIRST, to the Administrative Agent for any amount then due
         and payable by such Defaulting Lender to the Administrative Agent
         hereunder;

                  (ii) SECOND, to any other Lenders for any amount then due and
         payable by such Defaulting Lender to such other Lenders hereunder,
         ratably in accordance with such respective amounts then due and payable
         to such other Lenders; and

                  (iii) THIRD, to the Borrower for any Advance then required to
         be made by such Defaulting Lender pursuant to a Commitment of such
         Defaulting Lender.

In the event that any Lender that is a Defaulting Lender shall, at any time,
cease to be a Defaulting Lender, any funds held by the Administrative Agent in
escrow at such time with respect to such Lender shall be distributed by the
Administrative Agent to such Lender and applied by such Lender to the
Obligations owing to such Lender at such time under this Agreement and the other
Loan Documents ratably in accordance with the respective amounts of such
Obligations outstanding at such time.

         (d) The rights and remedies against a Defaulting Lender under this
Section 2.14 are in addition to other rights and remedies that the Borrower may
have against such Defaulting Lender with respect to any Defaulted Advance and
that the Administrative Agent or any Lender may have against such Defaulting
Lender with respect to any Defaulted Amount.

         SECTION 2.15. DEPOSITORY TRUST CORPORATION ELIGIBILITY. The Borrower
agrees to use its reasonable best efforts to cause the Tranche B Notes to be
Depository Trust Company eligible promptly after the request of the Required
Tranche B Lenders.

                                       45
<PAGE>

                                   ARTICLE III

                              CONDITIONS OF LENDING

         SECTION 3.01. CONDITIONS PRECEDENT TO THE BORROWING DATE. The
obligation of each Lender to make any Advance on the occasion of the Borrowing
Date is subject to the satisfaction of the following conditions precedent before
or concurrently with such Advance:

                  (a) The Acquisition shall be consummated strictly in
         accordance with the terms of the Purchase and Sale Agreements and in
         compliance with all applicable laws, without any waiver or amendment
         not consented to by the Lenders or that would be reasonably likely to
         have a Material Adverse Effect.

                  (b) The Acquisition Documents shall have been executed by all
         parties thereto in form and substance satisfactory to the Lenders and
         no default by any party to any thereof shall have occurred and be
         continuing that would be reasonably likely to have a Material Adverse
         Effect.

                  (c) There shall have occurred and be continuing no event which
         (i) could reasonably be expected to result in a material adverse change
         in the business, financial condition, operations, performance,
         properties or prospects of the Borrower, Northeast Utilities or NU
         Enterprises, individually or taken together as a whole, since December
         31, 1999 or (ii) in the reasonable opinion of the Lenders, could
         reasonably be expected to have a Material Adverse Effect since
         September 30, 1999 for Northeast Utilities, the Borrower or NU
         Enterprises.

                  (d) All governmental, shareholder, creditor and other third
         party consents, approvals and authorizations and all notices to or
         other such filings with any such entities and all other regulatory
         requirements applicable to (i) the transfer to the Borrower of the
         Generating Assets, (ii) the ongoing operation of such assets by the
         Borrower, (iii) the entry into and performance of the Loan Documents,
         the Acquisition Documents, the existing Material Contracts and the
         Project Documents by the Borrower, NU Enterprises, Northeast Utilities,
         CL&P, WMECO, NGS and Select, (iv) the granting of the Liens
         contemplated thereby and (v) the other transactions contemplated herein
         or therein, shall have been satisfied, obtained or made (without the
         imposition of any conditions that are not customary or otherwise
         reasonably acceptable to the Lenders) and shall be in full force and
         effect and all matters relating to such consents, authorizations and
         approvals including, without limitation, the status thereof shall be
         reasonably satisfactory to the Lenders and no law or regulation shall
         be applicable in the reasonable judgment of the Lenders that restrains,
         prevents or imposes materially adverse conditions on the Generating
         Assets, the Borrower, NU Enterprises,

                                       46
<PAGE>

         Northeast Utilities, NGS or Select or the transactions contemplated
         herein or therein.

                  (e) The written information prepared by or on behalf of the
         Borrower or Northeast Utilities and delivered to the Lenders listed on
         Schedule 3.01(e) attached hereto, taken as a whole, shall continue to
         be true and correct in all material respects, except with respect to
         forecasts and projections (including, without limitation, the forecasts
         and projections contained in business plans so updated) which shall
         have been prepared in good faith and based on reasonable assumptions,
         which assumptions continue to be fair and reasonable, and such updated
         information (including, without limitation, such updated forecasts and
         projections) shall be in form and substance reasonably satisfactory to
         the Lenders.

                  (f) There shall exist no action, suit, investigation,
         litigation or proceeding pending or threatened in any court or before
         any arbitrator or governmental instrumentality that would be reasonably
         likely to have a Material Adverse Effect other than as set forth in the
         Disclosure Documents or purports to materially adversely affect the
         Acquisition, the Acquisition Documents, this Agreement, the existing
         Material Contracts, the Project Documents or any of the other
         transactions contemplated hereby or thereby.

                  (g) The Lenders shall have received evidence reasonably
         satisfactory to them that (x) an amount at least equal to
         US$45,500,233.35 shall have been deposited in an account to be
         designated by the Administrative Agent on the date prior to the
         Borrowing, which shall remain on deposit in such account on the
         Borrowing Date, and the Administrative Agent shall have received
         irrevocable instructions to use such funds as provided in the Flow of
         Funds Memorandum and (y) an amount at least equal to $389,999,766.65
         will be available to be released from the lien of the Indentures to be
         dividended by each of CL&P and WMECO, respectively, to Northeast
         Utilities or to be used by CL&P or WMECO, respectively, to repurchase
         stock from Northeast Utilities and that each of CL&P and WMECO shall be
         capable of satisfying the conditions to such release upon the funding
         and no limitations (which have not been waived or are not otherwise
         capable of being satisfied by each of CL&P and WMECO upon the funding)
         shall exist under the Indentures and the other applicable indentures,
         credit agreements and other agreements of CL&P and WMECO and no other
         restrictions shall exist (statutory, corporate, contractual or
         otherwise) on the declaration and payment of such dividend or such
         repurchase of stock and on the investment of an amount equal to the
         Tranche A Borrowing, by Northeast Utilities into NU Enterprises and by
         NU Enterprises into the Borrower,

                                       47
<PAGE>

         respectively, and that the mechanics of executing such release,
         dividend, repurchase of stock and investment are such that the Borrower
         should be able to repay an amount equal to the Tranche A Borrowing to
         the Administrative Agent on behalf of the Lenders on the Borrowing
         Date.

                  (h) Each of CL&P and WMECO shall have taken all necessary
         corporate action and obtained all necessary governmental, creditor and
         other third party consents, approvals and authorizations to repurchase
         stock or dividend an amount equal to US$390,000,000 on such date, from
         or to Northeast Utilities, and Northeast Utilities and NU Enterprises
         each shall have taken all necessary corporate action and obtained all
         necessary governmental and third party consents, approvals and
         authorizations to invest an amount equal to the Tranche A Borrowing on
         such date in NU Enterprises (in the case of Northeast Utilities) and in
         the Borrower (in the case of NU Enterprises) and all such other
         consents, approvals and authorizations shall be in full force and
         effect, all matters relating to such consents, approvals and
         authorizations including, without limitation, the status thereof shall
         be satisfactory to the Lenders in their sole discretion and no law or
         regulation shall be applicable in the reasonable judgment of the
         Lenders that restrains, prevents or imposes materially adverse
         conditions upon the transactions contemplated thereby. The
         Administrative Agent shall have received certified copies of all
         governmental approvals and consents referenced in this clause (h) and
         any evidence of corporate action requested.

                  (i) To the extent the amount equal to the sum of (1) the
         Purchase Price, (2) all amounts payable to the Administrative Agent,
         the Collateral Agent, the Co-Arrangers and the Lenders under the Loan
         Documents, the Fee Letter, the Lead Bank Letter and the Engagement
         Letter, and (3) all transaction costs relating to the Loan Documents
         and the Acquisition, exceeds the Commitments under this Agreement and
         available on the Borrowing Date, the Borrower shall have received cash
         capital contributions in an amount sufficient to fund such excess
         amount prior to the making of the Advances and shall apply such funds
         to such excess amounts designated above as agreed with the Lenders.

                  (j) The Lenders shall be reasonably satisfied with (i) the
         Borrower's plan of remediation if required under the Connecticut
         Transfer Act or, if such plan is required but has not been finalized,
         with the results of their diligence regarding the anticipated terms of
         such plan, (ii) the results of their diligence regarding the conditions
         anticipated to be imposed as part of the FERC re-licensing of the
         Generating Assets in the Housatonic System, (iii) the conditions

                                       48
<PAGE>

         disclosed in all Phase II environmental site assessment reports from
         Metcalf & Eddy with respect to the Generating Assets, (iv) the
         information disclosed in the final report of Stone & Webster, (v) the
         results of the final report of the Insurance Consultant with respect to
         the Generating Assets, and (vi) the results of such other diligence
         they reasonably determine to undertake in connection with the
         Acquisition with respect to the Generating Assets.

                  (k) An amount equal to all accrued fees and reasonable
         expenses of the Administrative Agent, the Collateral Agent, the
         Co-Arrangers and the Lenders (including the accrued reasonable fees and
         expenses of counsel to the Administrative Agent, the Collateral Agent
         and the Depositary Bank) due and payable in accordance with the Loan
         Documents, the Fee Letter, the Engagement Letter and the Lead Bank
         Letter shall have been deposited in an account to be designated by the
         Administrative Agent on the date prior to the Borrowing, which shall
         remain on deposit in such account on the Borrowing Date, and the
         Administrative Agent shall have received irrevocable instructions to
         use such funds to pay such amounts in full.

                  (l) The Lenders shall have received a letter from the Borrower
         certifying as to the NEPOOL capability rating for each of the
         Generating Assets.

                  (m) The Administrative Agent shall have received on or before
         the Borrowing Date the following, each dated such day (unless otherwise
         specified), in form and substance reasonably satisfactory to the
         Lenders (unless otherwise specified) and (except for the Notes) in
         sufficient copies for each Lender:

                           (i)     The Notes payable to the order of the
                  Lenders.

                           (ii) Certified copies of the resolutions of the Board
                  of Directors of each Loan Party approving this Agreement, the
                  Notes, each other Loan Document, each Acquisition Document and
                  each Project Document to which it is or is to be a party, and
                  of all documents evidencing other necessary corporate action
                  and governmental and other third party approvals and consents,
                  if any, with respect to this Agreement, the Notes, each other
                  Loan Document, each Acquisition Document and each Project
                  Document.

                           (iii) A copy of the charter of each Loan Party and
                  each amendment thereto, certified (as of a date reasonably
                  near the date of the Borrowing Date) by the Secretary of State
                  of the jurisdiction of its incorporation as being a true and
                  correct copy thereof.

                                       49
<PAGE>

                           (iv) A copy of a certificate of the Secretary of
                  State of the jurisdiction of each Loan Party's organization,
                  dated reasonably near the date of the Borrowing Date, listing
                  the charter of such Loan Party and each amendment thereto on
                  file in his office and certifying that (A) such amendments are
                  the only amendments to such Loan Party's charter on file in
                  his office, (B) each Loan Party has paid all franchise taxes
                  to the date of such certificate and (C) such Loan Party is
                  duly organized and in good standing under the laws of the
                  state of the jurisdiction of its organization.

                           (v) A certificate of each of the Loan Parties, signed
                  on behalf of such Loan Party by a Responsible Officer thereof,
                  dated the Borrowing Date (the statements made in which
                  certificate shall be true on and as of the date of the
                  Borrowing), certifying as to (A) the absence of any amendments
                  to the charter (or the equivalent organizational or
                  constitutive documents) of such Loan Party since the date of
                  the certification referred to in Section 3.01(m)(iv), a copy
                  of which shall be attached to such certificate, (B) a true and
                  correct copy of the bylaws (or the equivalent organizational
                  documents) of such Loan Party as in effect on the Borrowing
                  Date, a copy of which shall be attached to such certificate,
                  and (C) the due organization and good standing of such Loan
                  Party, and the absence of any proceeding for the dissolution,
                  winding-up or liquidation (or any equivalent thereof) of such
                  Loan Party.

                           (vi) A certificate of each of the Loan Parties,
                  signed on behalf of such Loan Party by a Responsible Officer
                  thereof, dated the Borrowing Date (the statements made in such
                  certificate shall be true on and as of the date of the
                  Borrowing), certifying that:

                                    (A) all of the representations and
                           warranties of such Loan Party contained in each Loan
                           Document, Acquisition Document or Project Document to
                           which such Loan Party is or is to be a party, or
                           which are contained in any certificate, document or
                           financial or other statement furnished thereunder or
                           in connection therewith, shall be true and correct in
                           all material respects on and as of the Borrowing
                           Date, before and after giving effect to the Borrowing
                           and to the application of the proceeds therefrom, as
                           though made on and as of such date (other than any
                           such representations or warranties that, by their
                           terms, refer to a specific

                                       50
<PAGE>

                           date other than the date of the Borrowing, in which
                           case as of such specific date); and

                                    (B) no event has occurred and is continuing,
                           or would result from the Borrowing or from the
                           application of the proceeds therefrom, that
                           constitutes a Default or an Event of Default.

                           (vii) A certificate of the Secretary or an Assistant
                  Secretary of each Loan Party certifying the names and true
                  signatures of the officers of such Loan Party authorized to
                  sign this Agreement, the Notes, the Loan Documents, each
                  Acquisition Document and each Project Document to which they
                  are or are to be parties and the other documents to be
                  delivered hereunder and thereunder.

                           (viii) The Tranche A Borrower Security Agreement, the
                  Tranche B Borrower Security Agreement, the Tranche A
                  Enterprises Pledge Agreement and the Tranche B Enterprises
                  Pledge Agreement, each duly executed by each of the parties
                  thereto, together with:

                                    (A) certificates representing the Pledged
                           Shares referred to therein accompanied by undated
                           stock powers executed in blank.

                                    (B) acknowledgment copies of proper
                           financing statements, duly filed on or before the
                           Borrowing Date under the Uniform Commercial Code of
                           all jurisdictions that the Collateral Agent may deem
                           necessary or desirable in order to perfect and
                           protect the first priority liens and security
                           interests created under such Collateral Documents,
                           covering the Collateral described in such Collateral
                           Documents.

                                    (C) completed requests for information,
                           dated on or before the Borrowing Date, listing the
                           financing statements referred to in clause (B) above
                           and all other effective financing statements filed in
                           the jurisdictions referred to in clause (B) above
                           that name the Borrower or NU Enterprises as debtor,
                           together with copies of such other financing
                           statements.

                                    (D) evidence of the completion of all other
                           recordings and filings of or with respect to such
                           Collateral Documents that the Collateral Agent may
                           deem necessary or desirable in order to perfect and
                           protect the Liens created thereby.

                                       51
<PAGE>

                                    (E) evidence that all other action that the
                           Collateral Agent may deem necessary or desirable in
                           order to perfect and protect the first priority liens
                           and security interests created under such Collateral
                           Documents has been taken.

                           (ix) The Tranche A Mortgage and the Tranche B
                  Mortgage in respect of the properties listed on Schedule II
                  (in each case as amended, supplemented or otherwise modified
                  from time to time in accordance with their terms, the
                  "MORTGAGES"), duly executed by the Borrower, together with:

                                    (A) evidence that (i) counterparts of the
                           Mortgages have been duly recorded on or before the
                           Borrowing Date in all filing or recording offices
                           that the Collateral Agent may deem necessary or
                           desirable in order to create a valid first and
                           subsisting Lien on the property described therein in
                           favor of the Secured Parties and that all filing and
                           recording taxes and fees have been paid, or (ii) the
                           Title Companies (as defined below) have provided gap
                           insurance in respect to the recording of the
                           Mortgages acceptable to the Collateral Agent;

                                    (B) fully paid American Land Title
                           Association Lender's Extended Coverage title
                           insurance policies (the "MORTGAGE POLICIES") in form
                           and substance, with endorsements and in amount
                           acceptable to the Collateral Agent, issued, coinsured
                           and reinsured by title insurers acceptable to the
                           Collateral Agent (the "TITLE COMPANIES"), insuring
                           the Tranche B Mortgage to be a valid first and
                           subsisting Lien on the property described therein,
                           free and clear of all defects (including, but not
                           limited to, mechanics' and materialmen's Liens) and
                           encumbrances, excepting only Permitted Encumbrances,
                           and providing for such other affirmative insurance
                           (including endorsements for mechanics' and
                           materialmen's Liens);

                                    (C) American Land Title Association form
                           surveys for designated portions of certain properties
                           listed on Schedule II and other site drawings,
                           certified to the Collateral Agent and the issuers of
                           the Mortgage Policy in a manner reasonably
                           satisfactory to the Collateral Agent by a land
                           surveyor duly registered and licensed in the states
                           in which the property described in

                                       52
<PAGE>

                           such surveys is located and acceptable to the
                           Collateral Agent;

                                    (D) INTENTIONALLY OMITTED;

                                    (E) engineering, soils and other reports as
                           to the properties described in the Mortgages, in form
                           and substance and from professional firms acceptable
                           to the Collateral Agent;

                                    (F) such consents and agreements of lessors
                           and other third parties, and such estoppel letters
                           and other confirmations, as the Collateral Agent may
                           reasonably deem necessary;

                                    (G) evidence of the insurance required
                           hereunder;

                                    (H) evidence that all other action that the
                           Collateral Agent may deem necessary in order to
                           create valid first and subsisting Liens on the
                           property described in the Mortgages has been taken;

                                    (I) deeds transferring title to each
                           applicable property described in the Mortgages;

                                    (J) evidence of recording of each deed and
                           payment of any recording fees in respect thereof;

                                    (K) release of existing mortgages, if any,
                           together with applicable ancillary documentation,
                           including, without limitation, UCC-3 forms;

                                    (L) release of other existing encumbrances
                           (other than Permitted Encumbrances) if any, together
                           with applicable ancillary documentation;

                                    (M) applicable transfer tax forms;

                                    (N) bills of sale related to the transfer of
                           personal property;

                                    (O) certified copy of the Northfield
                           Operating Agreement;

                                    (P) certified copies of all existing
                           Material Contracts, Project Documents and material
                           operating or regulatory licenses to be assigned; and

                                       53
<PAGE>

                                    (Q) assignments of service contracts,
                           permits and warranties.

                           (x)     The Sponsor Agreement, duly executed by
                              Northeast Utilities.

                           (xi)    Certified copies of the Governmental
                  Authorizations listed on Schedules 5.01(d)(A)(1)-(2) hereof.

                           (xii) Certified copies of each of the Third Party
                  Consents listed on Schedule 5.01(d)(B) hereof, each in form
                  and substance satisfactory to the Lenders.

                           (xiii)  Evidence that the Borrower is an Exempt
                  Wholesale Generator.

                           (xiv) A solvency certificate from the chief financial
                           officer of each of CL&P and WMECO, substantially in
                           the form of Exhibit J hereto.

                           (xv) A certified copy of the Annual Operating Budget
                           of the Borrower for the year 2000.

                           (xvi) A copy of the Administrative Agent Fee Letter
                  and the Collateral Agent Fee Letter, each duly executed by
                  each of the parties thereto.

                           (xvii) (a) Written confirmation from Stone & Webster
                  that no material adverse change shall have occurred with
                  respect to the Generating Assets from that indicated in the
                  draft final report of Stone & Webster dated May 28, 1999, (b)
                  written confirmation from the Insurance Consultant that the
                  Borrower's insurance arrangements satisfy the requirements set
                  forth in the Loan Documents and (c) a market study from P.H.B.
                  Hagler Bailly ("HAGLER") which is reasonably satisfactory in
                  form and substance to the Lenders.

                           (xviii) Certified copies of the Acquisition
                  Documents, the O&M Agreement, the Select Power Purchase
                  Agreement, the Northeast Utilities Guaranties and the Tax
                  Sharing Agreement, each of which shall be in form and
                  substance satisfactory to the Lenders.

                           (xix) A favorable opinion of Edwards & Angell, LLP,
                  special counsel for the Borrower, Northeast Utilities, NU
                  Enterprises, CL&P, WMECO, NGS and Select, in form and
                  substance reasonably satisfactory to the Agents and the
                  Initial Lenders.

                                       54
<PAGE>

                           (xx) A favorable opinion of Steptoe and Johnson,
                  special FERC counsel to the Borrower, Northeast Utilities, NU
                  Enterprises, Select, NGS, CL&P and WMECO, in form and
                  substance reasonably satisfactory to the Agents and the
                  Initial Lenders.

                           (xxi) A favorable opinion of Day, Berry & Howard,
                  special Massachusetts and Connecticut energy regulatory
                  counsel and special Securities and Exchange Commission counsel
                  to the Borrower, Northeast Utilities, NU Enterprises, Select,
                  NGS, CL&P and WMECO, in form and substance reasonably
                  satisfactory to the Agents and the Initial Lenders.

                           (xxii) A favorable opinion of Robert Bersak, general
                  counsel to NUSCO in New Hampshire, in form and substance
                  reasonably satisfactory to the Agents and the Initial Lenders.

                           (xxiii) A favorable opinion of Edwards & Angell, LLP,
                  special Massachusetts and Connecticut real estate counsel to
                  the Borrower, Northeast Utilities, NU Enterprises, Select,
                  NGS, CL&P and WMECO, in form and substance reasonably
                  satisfactory to the Agents and the Initial Lenders.

                           (xxiv) A favorable opinion of Nixon Peabody special
                  New Hampshire real estate counsel to the Borrower, Northeast
                  Utilities, NU Enterprises, Select, NGS, CL&P and WMECO, in
                  form and substance reasonably satisfactory to the Agents and
                  the Initial Lenders.

                           (xxv) A favorable opinion of Kristensen, Cummings,
                  Phillips & Carol, special Vermont real estate counsel to the
                  Borrower, Northeast Utilities, Select, NGS, NU Enterprises,
                  CL&P and WMECO, in form and substance reasonably satisfactory
                  to the Agents and the Initial Lenders.

                           (xxvi) A favorable opinion of Shearman & Sterling,
                  counsel for the Administrative Agent, in form and substance
                  reasonably satisfactory to the Lenders.

                           (xxvii) Such other approvals, opinions or documents
                  as any Lender through the Administrative Agent may reasonably
                  request.

         Section 3.02. DETERMINATIONS UNDER SECTION 3.01. For purposes of
determining compliance with the conditions specified in Section 3.01, each
Lender shall be deemed to have consented to, approved or accepted or to be
satisfied

                                       55
<PAGE>

with each document or other matter required thereunder to be consented to or
approved by or acceptable or satisfactory to the Lenders unless an officer of
the Administrative Agent responsible for the transactions contemplated by the
Loan Documents and the Borrower shall have received written notice of such
objection from such Lender prior to the Borrowing specifying its objection
thereto, and, in the case of the Borrowing, such Lender shall not have made
available to the Administrative Agent such Lender's ratable portion of the
Borrowing.

                                   ARTICLE IV

                             SPECIAL ACCOUNTS SYSTEM

         SECTION 4.01. CREATION OF THE COLLATERAL ACCOUNTS. (a) The Collateral
Agent and the Borrower shall establish and maintain the Collateral Accounts.

         (b) THE DEPOSITARY BANK. (i) The Depositary Bank hereby agrees to act
as securities intermediary (as defined in the UCC) in respect of the Collateral
Accounts established with the Depositary Bank under this Agreement. The Borrower
hereby acknowledges that the Depositary Bank shall act as securities
intermediary in respect of the Collateral Accounts under this Agreement. The
Collateral Agent may, with the consent of the Borrower (which consent shall not
be unreasonably withheld), select another financial institution to act as
Depositary Bank under this Agreement, subject to the written agreement of the
replacement Depositary Bank to be bound by the terms and conditions of this
Agreement.

         (ii) The Depositary Bank acknowledges, confirms and agrees that (A) the
Collateral Accounts have been established as set forth in Section 4.01(a), (B)
each Collateral Account is a "securities account" (as defined in the UCC), (C)
the Borrower is the "entitlement holder" (as defined in the UCC) of the
Collateral Accounts, (D) all property delivered to the Depositary Bank pursuant
to this Agreement or the Collateral Documents will be promptly credited to a
Collateral Account (as specified herein), (E) all "financial assets" (as defined
in the UCC) in registered form or payable to or to order and credited to any
Collateral Account shall be registered in the name of, payable to or to the
order of, or specially endorsed to, the Depositary Bank or in blank, or credited
to another securities account maintained in the name of the Depositary Bank, and
in no case will any financial asset credited to either Collateral Account be
registered in the name of, payable to or to the order of, or specially endorsed
to, the Borrower except to the extent the foregoing have been specially endorsed
by the Borrower to the Depositary Bank or in blank, (F) the Depositary Bank
shall promptly comply with all instructions of the Collateral Agent and, to the
limited extent set forth below in this Article IV, the Borrower in

                                       56
<PAGE>

connection with the transfer or withdrawal of amounts in the Cash Collateral
Accounts and (g) the Depositary Bank shall not change the name or account number
of either Collateral Account without the prior written consent of the Collateral
Agent.

         (iii) The Depositary Bank agrees that each item of property (whether
cash, a security, an instrument or obligation, share, participation, interest or
other property whatsoever) credited to either Collateral Account shall be
treated as a "financial asset" under and as defined in Article 8 of the UCC.

         (iv) The Borrower agrees that the Depositary Bank may, and the
Depositary Bank agrees that it shall, comply with "entitlement orders" (as
defined in the UCC) originated by the Collateral Agent and relating to either
Collateral Account and any "security entitlement" (as defined in the UCC)
credited thereto without further consent by the Borrower or any other Person.

         (v) In the event that the Depositary Bank has obtained or subsequently
obtains by agreement, operation of law or otherwise a Lien or security interest
in either Collateral Account or any "security entitlement" (as defined in the
UCC) credited thereto, the Depositary Bank agrees that such Lien or security
interest shall be subordinate to the Lien and security interest of the Secured
Parties. The financial assets standing to the credit of the Collateral Accounts
will not be subject to deduction, set-off, banker's Lien, or any other right in
favor of any Person other than the rights of the Collateral Agent and the other
Secured Parties set forth in this Agreement and the other Collateral Documents
(except that the face amount of any checks which have been credited to either
Collateral Account but are subsequently returned unpaid because of uncollected
or insufficient funds). The Depositary Bank hereby waives any right of banker's
lien, set-off or counterclaim in respect of any assets contained in either
Collateral Account or otherwise that are held by the Depositary Bank hereunder.

         (vi) The Depositary Bank and the Borrower have not entered into any
agreement with respect to the Collateral Accounts or any financial assets
credited to either Collateral Account other than this Agreement and the
Collateral Documents. The Depositary Bank has not entered into any agreement
with the Borrower or any other Person purporting to limit or condition the
obligation of the Depositary Bank to comply with entitlement orders originated
by the Collateral Agent in accordance with Section 4.01(b)(iv). In the event of
any conflict between this Agreement (or any portion thereof) or any other
Collateral Document or any other agreement now existing or hereafter entered
into, the terms of this Agreement shall prevail.

         (vii)   Except for the claims and interest of the Collateral Agent and
the Borrower in each of the Collateral

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Accounts, the Depositary Bank does not know of any claim to, or interest in,
either Collateral Account or in any financial asset credited thereto. If any
Person asserts any Lien, encumbrance or adverse claim (including any writ,
garnishment, judgment, warrant of attachment, execution or similar process)
against either Collateral Account or in any financial asset credited thereto,
the Depositary Bank will promptly notify the Collateral Agent and the Borrower
thereof.

         (viii) The rights and powers granted to the Collateral Agent by the
Borrower and the Depositary Bank have been granted in order to perfect the Lien
and security interests of the Secured Parties in the Collateral Accounts, are
powers coupled with an interest and will neither be affected by the bankruptcy
of the Borrower nor the lapse of time.

         (ix) For purposes of the UCC, the Depositary Bank confirms and agrees
that the "securities intermediary's jurisdiction" (as defined in the UCC) with
respect to the Collateral Accounts is the State of New York. If the "securities
intermediary's jurisdiction" shall change from that jurisdiction specified in
the previous sentence, the Borrower shall promptly notify the Agent of such
change and of such new jurisdiction.

         (c) LIMITED BORROWER RIGHTS. The Borrower shall not have any rights
against or to monies held in the Collateral Accounts, as third party beneficiary
or otherwise, except the right to receive or make requisitions of monies held in
the Collateral Accounts, as permitted by this Agreement and to direct the
investment of monies held in the Collateral Accounts as permitted by Section
4.04. In no event shall any amounts or Permitted Investments be deposited in or
credited to either Collateral Account registered in the name of the Borrower,
payable to the order of the Borrower or specially endorsed to the Borrower
except to the extent that the foregoing have been specially endorsed to the
Depositary Bank or in blank.

         SECTION 4.02. REVENUES ACCOUNT. (a) DEPOSITS INTO THE REVENUES ACCOUNT.
The Borrower agrees and confirms that it has irrevocably instructed each party
to a Project Document in effect as of the date hereof (and shall instruct each
party to any additional Project Documents) and each other Person from whom the
Borrower is entitled to receive any:

                  (i)     Revenues payable under the Project Documents;

                  (ii) proceeds of any sale (net of the costs and expenses of
         such sale and any taxes, assessments or prior Liens) of any of the
         Generating Assets (other than such proceeds constituting Revenues); and

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<PAGE>

                  (iii)   any other cash revenues (other than amounts to be
         deposited in the Casualty Account pursuant to Section 4.03)

to pay the same directly to the Collateral Agent for the account of the Borrower
for deposit into the Revenues Account. If, notwithstanding such instructions,
the Borrower should receive any such payment, the Borrower shall hold such
payment in trust for the Collateral Agent and shall promptly deliver such
payment to the Collateral Agent for deposit into the Revenues Account in the
exact form received with any necessary endorsement.

         (b) TRANSFERS FROM THE REVENUES ACCOUNT PRIOR TO AN EVENT OF DEFAULT
AND AN ENFORCEMENT ACTION IS COMMENCED. Unless an Event of Default shall have
occurred and be continuing, an Enforcement Action shall have been initiated and
the Collateral Agent shall have received notice thereof from any Lender, the
Collateral Agent shall transfer (or cause to be transferred) from the collected
credit balance of the Revenues Account, the following amounts in the following
order of priority (and no transfer at any such priority level shall be made on
any day if any transfer remains to be made on such day at any higher priority
level):

                  FIRST, on the first Business Day of each calender month, for
         deposit into the Operating Account, an amount equal to (x) the
         Operating Costs for such month PLUS Capital Expenditures for such
         month, each as scheduled in the Annual Operating Budget for such month,
         PLUS an amount equal to any Capital Expenditures, taxes, FERC fees or
         insurance, each as scheduled in the Annual Operating Budget for future
         months that the Borrower plans to perform or pay in such month, and
         that the Borrower certifies in writing to the Collateral Agent that
         such amount is necessary to perform or pay such Capital Expenditure,
         taxes, FERC fees or insurance, as the case may be, in such month,
         (PROVIDED, that an amount equal to any such amount transferred from the
         Revenues Account to the Operating Account earlier than scheduled in the
         Annual Operating Budget as provided above shall be subtracted from the
         aggregate amount to be transferred from the Revenues Account to the
         Operating Account in the month that such expenditure was scheduled
         under the Annual Operating Budget so as to avoid duplication of amounts
         transferred from the Revenues Account to the Operating Account) PLUS
         (y) an amount not to exceed 10% of such months' scheduled Operating
         Costs and Capital Expenditures as set forth in the Annual Operating
         Budget if certified in writing by the Borrower to the Collateral Agent
         to be necessary; PROVIDED, HOWEVER the Collateral Agent shall not remit
         funds in excess of the monthly amounts listed in the Annual Operating
         Budget as requested by the Borrower in accordance with

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<PAGE>

         the foregoing more than three times without the prior written consent
         of the Required Lenders;

                  SECOND, to the Agents and the Depositary Bank, an amount equal
         to all fees, costs, expenses (including, without limitation, legal fees
         and expenses), indemnification payments, taxes and other amounts then
         due and payable by the Borrower to any Agent or the Depositary Bank
         from time to time as certified to the Collateral Agent by the Agents or
         the Depositary Bank;

                  THIRD, to the Lenders, an amount equal to the Obligations owed
         by the Borrower to the Lenders under the Loan Documents then due and
         payable (excluding mandatory prepayments pursuant to Section 2.05) as
         certified to the Collateral Agent by the Administrative Agent;

                  FOURTH, to the Lenders, the aggregate amount of any mandatory
         prepayments then due and payable pursuant to Section 2.05 as certified
         to the Collateral Agent by the Administrative Agent.

         (c) TRANSFERS FROM REVENUES ACCOUNT WHEN AN EVENT OF DEFAULT IS
CONTINUING AND AN ENFORCEMENT ACTION HAS COMMENCED. At any time that an Event of
Default shall have occurred and be continuing and an Enforcement Action has been
initiated, upon its receipt of notice thereof from any Lender or the
Administrative Agent, the Collateral Agent shall transfer (or caused to be
transferred) from the collected credit balance of the Revenues Account only
those amounts as directed in writing by the Required Lenders.

         SECTION 4.03. CASUALTY ACCOUNT. (a) DEPOSITS INTO THE CASUALTY ACCOUNT.
The Borrower agrees and confirms that it has irrevocably instructed each insurer
from whom the Borrower is entitled to receive any proceeds from any property or
casualty insurance policy to pay the same directly to the Collateral Agent for
the account of the Borrower for deposit into the Casualty Account. If,
notwithstanding such instructions, the Borrower should receive any such payment,
the Borrower shall hold such payment in trust for the Collateral Agent and shall
promptly deliver such payment to the Collateral Agent for deposit into the
Casualty Account in the exact form received with any necessary endorsement.

         (b) TRANSFERS FROM THE CASUALTY ACCOUNT PRIOR TO AN EVENT OF DEFAULT
AND AN ENFORCEMENT ACTION IS COMMENCED. Unless an Event of Default shall have
occurred and be continuing and an Enforcement Action shall have been initiated
and the Collateral Agent shall have received notice thereof from the
Administrative Agent or any Lender, the Collateral Agent shall transfer (or
cause to be transferred), from the collected credit balance of the Casualty
Account, the following amounts in the following order:

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<PAGE>

                  (i) if the net proceeds received by the Collateral Agent are
         less than U.S. $17,500,000 for any single loss or series of losses in
         the aggregate, the Collateral Agent shall transfer portions of such sum
         from the Casualty Account to the Operating Account from time to time
         upon written request from the Borrower for the purpose of making
         payments required to finance the repair, reconstruction or replacement
         of the damaged Generating Asset(s) or to reimburse the Borrower for
         such repair, reconstruction or replacement expenses actually paid by
         it, against repair, reconstruction or replacement expenses actually
         paid by it, upon delivery to the Collateral Agent of the Borrower's
         certification that the funds requested will be applied as provided in
         this clause 4.03(b)(i);

                  (ii) if the net proceeds received by the Collateral Agent is
         greater than $17,500,000 for any single loss or series of losses in the
         aggregate but less than $35,000,000 (and in the case of a series of
         losses, each additional loss over $17,500,000 shall be a material loss
         in the reasonable judgment of the Required Lenders), then at any time
         after such loss or losses and after such time as may be required by the
         Borrower to assess the extent of such loss or losses and estimate the
         insurance proceeds to be received in connection therewith, but no later
         than 45 days after receipt of such proceeds, the Borrower shall deliver
         to Stone & Webster or another independent engineer reasonably
         acceptable to the Lenders a plan for the application of such proceeds
         to repair or replace the damaged property. If, within 30 days from the
         receipt by the independent engineer of such plan, such independent
         engineer notifies the Borrower and the Administrative Agent (who shall
         notify the Lenders in order to vote as provided in this clause (b)(ii))
         that, in their reasonable judgment, in light of the nature of the loss
         or losses and the reasonableness of the plan of the Borrower, it is
         likely that, after implementation of the Borrower's plan, that (x) such
         Generating Asset(s) could be repaired in a timely manner and that the
         insurance proceeds are sufficient to cover the costs of such repair,
         the amounts on deposit in the Casualty Account shall be transferred to
         the Operating Account as and when needed for the Borrower to repair,
         reconstruct or

                                       61
<PAGE>

         replace the damaged Generating Asset(s), or (y) such Generating
         Asset(s) could not be repaired or the insurance proceeds are
         insufficient to cover the costs of such repair, the Required Lenders
         shall vote within 30 days from such notification from the independent
         engineer to determine if the amounts on deposit in the Casualty Account
         shall be applied by the Collateral Agent to prepay the Borrower's
         Obligations hereunder or if such amounts should be transferred to the
         Operating Account as and when needed for the Borrower to repair,
         reconstruct or replace the damaged Generating Asset(s); PROVIDED, if
         the Required Lenders do not vote to apply the amounts on deposit in the
         Casualty Account to prepay the Borrower's obligations within such 30
         day period, such amounts on deposit in the Casualty Account shall be
         transferred by the Collateral Agent to the Operating Account as and
         when needed for the Borrower to repair, reconstruct or replace the
         damaged Generating Asset(s). If any funds shall be transferred from the
         Casualty Account to the Operating Account under this subsection (ii),
         the Borrower must certify to the Lenders that the amounts requested
         will be applied as provided in this clause 4.03(b)(ii), and that at
         such time as such repair, reconstruction or replacement is complete,
         any balance of such sum remaining in the Casualty Account shall be
         transferred to the Revenues Account at the direction of the
         Administrative Agent or, if required under the relevant insurance
         policy or policies, shall, at the direction of the Borrower (with the
         consent of the Administrative Agent which shall not be unreasonably
         denied), be paid over to the insurer(s).

                  (iii) if the net proceeds received by the Collateral Agent is
         greater than or equal to $35,000,000 for any single loss or series of
         losses in the aggregate, the Collateral Agent shall notify the Lenders
         thereof, and the Required Lenders shall vote to determine if the
         amounts on deposit in the Casualty Account shall be applied by the
         Collateral Agent to prepay the Borrower's Obligations hereunder or if
         such amounts shall be transferred to the Operating Account for the
         Borrower to repair, reconstruct or replace the damaged Generating
         Asset(s); PROVIDED, if the Required Lenders do not vote to apply the
         amounts on deposit in the Casualty Account to prepay the Borrower's
         obligations within such 30 day period, such amounts on deposit in the
         Casualty Account shall be transferred by the Collateral Agent to the
         Operating Account as and when needed for the Borrower to repair,
         reconstruct or replace the damaged Generating Asset(s); PROVIDED,
         FURTHER, that if any funds shall be transferred to the Operating
         Account under this subsection (iii), the Borrower must certify to the
         Lenders that the amounts to be transferred from the Casualty Account
         will be applied as provided in this clause 4.03(b)(iii); and PROVIDED,
         FURTHER, HOWEVER, that at such time as such repair, reconstruction or
         replacement is complete, any balance of such sum remaining in the
         Casualty Account shall be transferred to the Revenues Account at the
         direction of the Administrative Agent or, if required under the
         relevant insurance policy or policies, shall, at the direction of the
         Borrower (with the consent of the Administrative Agent which shall not
         be unreasonably denied), be paid over to the insurer(s).

         (c) TRANSFERS FROM CASUALTY ACCOUNT WHEN AN EVENT OF DEFAULT IS
CONTINUING AND AN ENFORCEMENT ACTION HAS

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<PAGE>

COMMENCED. At any time that an Event of Default shall have occurred and be
continuing and an Enforcement Action has been initiated, upon its receipt of
notice thereof from any Lender, the Collateral Agent shall transfer (or caused
to be transferred) from the collected credit balance of the Casualty Account
only those amounts as directed in writing by the Required Lenders.

         SECTION 4.04. INVESTMENT OF FUNDS IN COLLATERAL ACCOUNTS. (a) Unless an
Event of Default shall have occurred and be continuing, the Collateral Agent
shall invest funds (and vary and redeem such investments) in the Collateral
Accounts, in the name of the Collateral Agent, as directed by the Borrower,
PROVIDED in each case that the designated investment is a Permitted Investment.
After the occurrence and during the continuance of an Event of Default,
investments in Permitted Investments shall be made as directed by the
Administrative Agent.

         (b) Whenever the Collateral Agent is directed or authorized in
accordance with the terms hereof to make a transfer of funds from the Collateral
Accounts, if, after application of all other available funds, liquidation of a
Permitted Investment is necessary to make any such transfer, the Collateral
Agent is authorized to liquidate such Permitted Investment. The Collateral Agent
shall liquidate all those Permitted Investments which can be liquidated without
interest costs or penalty before it shall liquidate any Permitted Investment the
liquidation of which would involve an interest cost or penalty. The Collateral
Agent shall have no liability with respect to any interest cost or penalty on
the liquidation of any Permitted Investment pursuant to this Section 4.04(b).

         (c) The Collateral Agent shall have no liability with respect to
Permitted Investments (or any losses resulting therefrom) made at the direction
of the Borrower or as otherwise provided in Section 4.04(a).

         (d) All references in this Agreement to the Collateral Accounts and to
cash, moneys or funds therein or balances thereof shall include the investments
in which such moneys are then invested. All investments shall be under the sole
dominion and control of the Collateral Agent, subject to the terms and
conditions of this Agreement and the Collateral Documents.

         SECTION 4.05. INTEREST. Any interest or other earnings accrued on any
balances in the Revenues Account, or on any investment thereof, shall be
credited to and accumulated in the Revenues Account and thereafter be applied
without differentiation from other funds in the Revenues Account. Any interest
or other earnings accrued on any balances in the Casualty Account, or on any
investment thereof, shall be credited to and accumulated in the Casualty Account
and thereafter be applied without differentiation from other funds in the
Casualty Account.

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<PAGE>

         SECTION 4.06. REPORTS TO THE BORROWER AND THE LENDERS. The Collateral
Agent shall deliver, or cause the Depositary Bank to deliver, to the Borrower
and each Lender within 15 Business Days after the end of the calendar month in
which the first deposit is made into either Collateral Account and each calendar
month thereafter, a report with respect to the Collateral Account, setting forth
in reasonable detail all deposits to and disbursements from such Collateral
Account during such month, including the date on which made, and the balances of
and any investments in such Collateral Account at the end of such month. The
Collateral Agent shall provide any additional information or reports relating to
the Collateral Accounts and the transactions therein reasonably requested from
time to time by the Borrower or any Lender.

         SECTION 4.07. BOOKS AND RECORDS. The Collateral Agent shall, or cause
the Depositary Bank to, maintain all books and records with respect to the
Collateral Accounts as may be necessary properly to record all transactions
carried out by it under this Agreement. The Collateral Agent shall permit the
Borrower and each Lender to examine such books and records with respect to the
Collateral Accounts, PROVIDED that any such examination shall occur upon
reasonable notice and during normal business hours.

                                    ARTICLE V

                         REPRESENTATIONS AND WARRANTIES

         SECTION 5.01. REPRESENTATIONS AND WARRANTIES OF THE BORROWER. The
Borrower represents and warrants as follows:

                  (a) The Borrower (i) is a corporation duly organized, validly
         existing and in good standing under the laws of the jurisdiction of its
         incorporation, (ii) is duly qualified and in good standing as a foreign
         corporation in each other jurisdiction in which it owns or leases
         property or in which the conduct of its business requires it to so
         qualify or be licensed and (iii) has all requisite corporate power and
         authority (including, without limitation, all Governmental
         Authorizations, licenses, permits and other approvals) to own or lease
         and operate its properties and to carry on its business as now
         conducted and as proposed to be conducted, except as noted in Section
         5.01(d) and except where the failure to so qualify or be licensed would
         not have a Material Adverse Effect. All of the outstanding capital
         stock of the Borrower has been validly issued, is fully paid and
         non-assessable and is owned by NU Enterprises free and clear of all
         Liens, except those created under the Collateral Documents.

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<PAGE>

                  (b)  The Borrower has no Subsidiaries.

                  (c) The execution, delivery and performance by the Borrower of
         this Agreement, the Notes, each other Loan Document and the Acquisition
         Documents to which it is or is to be a party, and the other
         transactions contemplated hereby and thereby, are within the Borrower's
         corporate powers, have been duly authorized by all necessary corporate
         action, and do not (i) contravene the Borrower's charter or bylaws,
         (ii) violate any law (including, without limitation, the Securities
         Exchange Act of 1934 and the Racketeer Influenced and Corrupt
         Organizations Chapter of the Organized Crime Control Act of 1970),
         rule, regulation (including, without limitation, Regulation X of the
         Board of Governors of the Federal Reserve System), order, writ,
         judgment, injunction, decree, determination or award, (iii) conflict
         with or result in the breach of, or constitute a default under, any
         Acquisition Document, existing Material Contract, Project Document,
         loan agreement, indenture, mortgage, deed of trust, material lease or
         other material instrument binding on or affecting the Borrower or any
         of its properties or (iv) except for the Liens created under the
         Collateral Documents, result in or require the creation or imposition
         of any Lien upon or with respect to any of the properties of the
         Borrower. The Borrower is not in violation of any such law, rule,
         regulation, order, writ, judgment, injunction, decree, determination or
         award or in breach of any such contract, loan agreement, indenture,
         mortgage, deed of trust, lease or other instrument, the violation or
         breach of which could have a Material Adverse Effect.

                  (d) No authorization or approval or other action by, and no
         notice to or filing with, any Governmental Authority or any third party
         is required for (i) the due execution, delivery, recordation, filing or
         performance by the Borrower of this Agreement, the Notes, any other
         Loan Document or the Acquisition Documents or the existing Material
         Contracts or the Project Documents to which it is or is to be a party
         or the other transactions contemplated hereby or thereby, (ii) the
         grant by the Borrower of the Liens granted by it pursuant to the
         Collateral Documents to which it is a party, (iii) the perfection or
         maintenance of the Liens created by the Collateral Documents to which
         it is a party (including the first priority nature thereof), (iv) the
         ongoing operation of the Generating Assets by the Borrower, except to
         the extent the absence thereof would not be reasonably likely to have a
         Material Adverse Effect or (v) the exercise by the Administrative Agent
         or any Lender of its rights under the Loan Documents or the remedies in
         respect of the Collateral pursuant to the Collateral Documents to which
         it is a party except for (A) the Governmental Authorizations listed on
         Part A-1 of

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<PAGE>

         Schedule 5.01(d) hereto with respect to the CL&P Acquisition and the
         Governmental Authorizations listed on Part A-2 of Schedule 5.01(d)
         hereto with respect to the WMECO Acquisition and (B) the amendments,
         waivers and consents listed on Part B of Schedule 5.01(d) hereto with
         respect to the Acquisition, all of which relating to the Acquisition
         shall have been duly obtained, taken, given or made and shall be in
         full force and effect on the Borrowing Date.

                  (e) This Agreement has been, and each of the Notes, each other
         Loan Document, each Acquisition Document, each existing Material
         Contract and each Project Document to which it is a party when
         delivered hereunder will have been, duly executed and delivered by the
         Borrower. This Agreement is, and each of the Notes, each other Loan
         Document, each Acquisition Document, each existing Material Document
         and each other Project Document to which it is a party when delivered
         hereunder will be, the legal, valid and binding obligation of the
         Borrower, enforceable against the Borrower in accordance with its
         terms.

                  (f) The unaudited financial statements of the Borrower for the
         fiscal year ended December 31, 1999 fairly present the financial
         condition of the Borrower on such date, in accordance with GAAP, and
         since December 31, 1999, there has been no material adverse change in
         the business, condition (financial or otherwise), operations,
         performance, properties or prospects of the Borrower.

                  (g) (i) All written information that has been or will
         hereafter be made available by the Borrower or any of its
         representatives in connection with the transactions contemplated hereby
         to the Co-Arrangers, to any Lender or to any potential Lender, is and
         will be true and correct in all material respects and does not and will
         not contain any misstatement of a material fact or omit to state a
         material fact necessary in order to make the statements contained
         therein not misleading in light of the circumstances under which such
         statements were or are made, and (ii) all financial projections, if
         any, that have been or will be prepared by the Borrower or any of its
         representatives in connection with the transactions contemplated hereby
         have been or will be prepared in good faith based upon reasonable
         assumptions at the time made.

                  (h) Other than as set forth in the Disclosure Documents, there
         is no action, suit, investigation, litigation or proceeding affecting
         the Borrower, including any Environmental Action, pending or, to the
         best of the Borrower's knowledge, threatened before any court,
         governmental agency or arbitrator that individually or in the aggregate
         (i) could have a

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<PAGE>

         Material Adverse Effect or (ii) purports to affect the legality,
         validity or enforceability of this Agreement, any Note, any other Loan
         Document, any Acquisition Document or any Project Document or the
         transactions contemplated thereby.

                  (i) Other than as set forth in the Disclosure Documents, the
         operations and properties of the Borrower, the CL&P Generating Assets
         and the WMECO Generating Assets comply in all material respects with
         all applicable Environmental Laws and Environmental Permits (except for
         any such noncompliance that has been consented to by the appropriate
         authority), all past material noncompliance with such Environmental
         Laws and Environmental Permits has been resolved without material
         ongoing obligations or costs to the Loan Parties, and no circumstances
         exist that could reasonably be expected to (i) form the basis of an
         Environmental Action against the Borrower or any of their respective
         properties or any of the Generating Assets, or (ii) cause any such
         property to be subject to any restrictions on ownership, occupancy, use
         or transferability under any Environmental Law that, in the case of
         either clause (i) or (ii), could reasonably be expected to have a
         Material Adverse Effect.

                  (j) The execution and delivery of the Loan Documents, the
         Acquisition Documents and the Project Documents to which the Borrower
         is a party and the performance by the Borrower of its obligations
         thereunder are exempt from taxes (other than income taxes), levies,
         imposts, deductions, charges and withholdings imposed by any
         Governmental Authority in the United States or any political
         subdivision or taxing authority thereof or therein, as applicable,
         except for such transfer or conveyance or mortgage recording taxes as
         shall have been paid on the Borrowing Date or as otherwise due and such
         taxes, nominal recording fees, levies, imposts, deductions, charges and
         withholdings which may have been paid or shall be paid in due course by
         the Borrower and have been disclosed to the Lenders.

                  (k) The Borrower is an Exempt Wholesale Generator. As an
         Exempt Wholesale Generator, the Borrower is (a) not subject to or
         exempt from regulation under the Public Utility Holding Company Act of
         1935 and Part II of the Federal Power Act (other than the minimum
         statutory requirements that apply to Exempt Wholesale Generators
         generally), (b) not subject to or exempt from any statute or regulation
         which prohibits or restricts the incurrence of the obligations under
         the Loan Documents or the granting of the liens contemplated thereby,
         including, without limitation, statutes or regulations relative to
         common or contract carriers or to the sale of electricity, gas, steam,
         water, telephone, telegraph or other public

                                       67
<PAGE>

         utility services, and (c) not subject to or exempt from regulation as
         an electric distribution company, a public utility, an electric
         corporation or any similar type of entity under Connecticut law or
         Massachusetts law.

                  (l) The Borrower is not engaged in the business of extending
         credit for the purpose of purchasing or carrying Margin Stock, and no
         proceeds of any Advance will be used to purchase or carry any Margin
         Stock or to extend credit to others for the purpose of purchasing or
         carrying any Margin Stock.

                  (m) The Borrower's obligations under the Loan Documents to
         which it is a party constitute direct, unconditional and unsubordinated
         obligations of the Borrower.

                  (n) Both before and after the Acquisition is consummated,
         except for the liens created or permitted pursuant to the Loan
         Documents, the Borrower has valid and uncontested legal title to its
         material properties free and clear of all liens and competing claims.

                  (o) The Borrower is in compliance in all material respects
         with all applicable laws, ordinances, rules, regulations, and
         requirements of all Governmental Authorities (including, without
         limitation, certificates, permits, franchises and other Governmental
         Authorizations necessary to the ownership of its respective properties
         or to the conduct of its respective business, environmental laws, and
         laws with respect to social security and pension fund obligations)
         except in each case to the extent where such failure to comply could
         not reasonably be expected to have a Material Adverse Effect.

                  (p) The Borrower is not an "investment company" or an
         "affiliated person" of, or "promoter" or "principal underwriter" for,
         an "investment company", as such terms are defined in the Investment
         Company Act of 1940, as amended.

                  (q) Set forth on Schedule 5.01(q) hereto is a complete and
         accurate list of all Plans, Multiemployer Plans and Welfare Plans.

                  (r) No ERISA Event has occurred or is reasonably expected to
         occur with respect to any Plan.

                  (s) Schedule B (Actuarial Information) to the most recent
         annual report (Form 5500 Series) for each Plan, copies of which have
         been filed with the Internal Revenue Service and furnished to each
         Lender, is complete and accurate and fairly presents the funding status
         of such Plan, and since the date of such

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<PAGE>

         Schedule B there has been no material adverse change in such funding
         status.

                  (t) Neither any Loan Party nor any ERISA Affiliate has
         incurred or is reasonably expected to incur any Withdrawal Liability to
         any Multiemployer Plan.

                  (u) Neither the Borrower nor any ERISA Affiliate has been
         notified by the sponsor of a Multiemployer Plan that such Multiemployer
         Plan is in reorganization or has been terminated, within the meaning of
         Title IV of ERISA, and no such Multiemployer Plan is reasonably
         expected to be in reorganization or to be terminated, within the
         meaning of Title IV of ERISA.

                  (v) Since December 31, 1999, neither the business nor the
         properties of the Borrower, the CL&P Generating Assets nor the WMECO
         Generating Assets are, or have been, affected by any fire, explosion,
         accident, strike, lockout or other labor dispute, drought, storm, hail,
         earthquake, embargo, act of God or of the public enemy or other
         casualty (whether or not covered by insurance) that could reasonably
         have a Material Adverse Effect.

                  (w) The Borrower is not a party to any indenture, loan or
         credit agreement or any lease or other agreement or instrument or
         subject to any charter or corporate restriction that, in each case,
         could reasonably be expected to have a Material Adverse Effect.

                  (x) The Collateral Documents create a valid and perfected
         first priority security interest in the Collateral, securing the
         payment of the Secured Obligations, and all filings and other actions
         deemed necessary to perfect and protect such security interest have
         been taken or will be taken as of the Borrowing Date.

                  (y) The Borrower has filed, has caused to be filed or has been
         included in all tax returns (national, departmental, local, municipal
         and foreign) required to be filed or has received appropriate filing
         extensions therefor and has paid or shall pay in due course or caused
         to be paid all taxes, assessments, fees and other charges shown thereon
         to be due, together with applicable interest and penalties, other than
         the payment of any taxes, assessment, fees or other charges (i) the
         nonpayment of which could not reasonably be expected to have a Material
         Adverse Effect or (ii) that are being contested in good faith and by
         proper proceedings and as to which appropriate reserves are being
         maintained.

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                  (z) The Borrower is, and after the consummation of each
         Acquisition and the transactions contemplated hereby will be, Solvent.

                  (aa) The Borrower has not conducted or engaged in any
         activities other than (i) the business of, and activities related to,
         electric power generation and (ii) businesses and activities otherwise
         permitted under the terms of the Loan Documents, the Acquisition
         Documents and the Project Documents.

                  (bb) No default or event of default has occurred and is
         continuing under, and as defined in, any Loan Document, Acquisition
         Document, Project Document or existing Material Contract to which the
         Borrower is a party.

                  (cc) For tax purposes, the Borrower's initial basis in the
         Generating Assets will be equal to the purchase price paid for the
         Generating Assets. The Borrower is not a party to, and is not bound by,
         any tax sharing agreement other that the Tax Sharing Agreement.

                  (dd) Set forth on Schedule 5.01(dd) hereto is a complete and
         accurate list of all Liens on the property or assets of the Borrower
         (including, without limitation, the Generating Assets), showing as of
         the date hereof the lienholder thereof, the principal amount of the
         obligations secured thereby and the property or assets of the Borrower
         subject thereto.

                  (ee) Set forth on Schedule 5.01(ee) hereto is a complete and
         accurate list of all existing Material Contracts of the Borrower,
         showing as of the date hereof the parties, subject matter and term
         thereof. Each such Material Contract has been duly authorized, executed
         and delivered by all parties thereto, has not been amended or otherwise
         modified, is in full force and effect and is binding upon and
         enforceable against all parties thereto in accordance with its terms,
         and there exists no event of default under any Material Contract by the
         Borrower or to the Borrower's knowledge by any other party thereto.

                  (ff) There are no lease or license agreements relating to
         recreational access and/or use by third party users of the impoundments
         that either are not terminable for any reason by the owner of the real
         property in question or are fully subordinated to any mortgage lien
         (regardless of the date of recording of such mortgage) placed on the
         real property in question, except for such lease or license agreements
         that would not materially adversely affect the operation of the
         Generating Assets.

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                  (gg) To the Borrower's knowledge there have been no breaches
         of the use restrictions encumbering the real property listed in the
         title commitments provided by the title company and the Borrower has no
         knowledge that there are any material use restrictions in addition to
         those listed in the title commitments provided by the title company.

                  (hh) Upon the transfer of the Generating Assets to the
         Borrower, the Borrower will own outright or be granted the right to
         access or otherwise use all facilities, improvements and rights to real
         property it will need to generate electricity as contemplated and as
         permitted by the applicable FERC licenses.

                  (ii) To the best of the Borrower=s knowledge, there are no
         Neighboring Landowner Agreements currently in effect that, if the third
         party holder of such agreement defaulted in its obligations under such
         Neighboring Landowner Agreement, such default would have a Material
         Adverse Effect.

                  (jj) To the best of the Borrowers knowledge, there have been
         no breaches of the use restrictions encumbering the real property
         listed in the Mortgage Policies and the Borrower has no knowledge that
         there are any material use restrictions in addition to those listed in
         the Mortgage Policies.

                  (kk) The Borrower is not aware of any problems relating to the
         Year 2000 date change that might materially affect its business.

                                   ARTICLE VI

                            COVENANTS OF THE BORROWER

         SECTION 6.01. AFFIRMATIVE COVENANTS. So long as any Advance shall
remain unpaid or any Lender shall have any Commitment hereunder, the Borrower
will:

                  (a) COMPLIANCE WITH LAWS, ETC. Comply in all material respects
         with all applicable laws, rules, regulations and orders, such
         compliance to include, without limitation, compliance with ERISA and
         the Racketeer Influenced and Corrupt Organizations Chapter of the
         Organized Crime Control Act of 1970, except when contested in good
         faith by appropriate proceedings and for which an adequate reserve has
         been established or where noncompliance could not reasonably be
         expected to have a Material Adverse Effect.

                  (b)  PAYMENT OF TAXES, ETC. Pay and discharge before the same
         shall become delinquent, (i) all taxes,

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         assessments and governmental charges or levies imposed upon it or upon
         its property and (ii) all lawful claims that, if unpaid, might by law
         become a Lien upon its property; PROVIDED, HOWEVER, that the Borrower
         shall not be required to pay or discharge any such tax, assessment,
         charge or claim that is being contested in good faith and by proper
         proceedings and as to which appropriate reserves are being maintained,
         unless and until any Lien resulting therefrom (other than Liens for
         unpaid municipal real property taxes not in excess of $300,000 in the
         aggregate which have attached solely by operation of law and as to
         which no Enforcement Action has been taken) attaches to its property
         and becomes enforceable against its other creditors or where nonpayment
         could not reasonably be expected to have a Material Adverse Effect.

                  (c) COMPLIANCE WITH ENVIRONMENTAL LAWS. Comply, and cause all
         lessees and other Persons operating or occupying its properties to
         comply, with all applicable Environmental Laws and Environmental
         Permits; obtain and renew all Environmental Permits necessary for its
         operations and properties; and conduct any investigation, study,
         sampling and testing, and undertake any cleanup, removal, remedial or
         other action necessary to remove and clean up all Hazardous Materials
         from any of its properties, in accordance with the requirements of all
         Environmental Laws; except where noncompliance could not reasonably be
         expected to have a Material Adverse Effect; PROVIDED, HOWEVER, that the
         Borrower shall not be required to undertake any such cleanup, removal,
         remedial or other action to the extent that its obligation to do so is
         being contested in good faith and by proper proceedings and appropriate
         reserves are being maintained with respect to such circumstances.

                  (d) OPERATION OF THE GENERATING ASSETS. Cause the Generating
         Assets to be operated and maintained and its business to be conducted,
         (i) in a prudent manner, based on industry standards for comparable
         facilities or businesses in comparable locations, and (ii) in
         accordance with applicable laws (including Environmental Laws), except
         when contested in good faith by appropriate proceedings and for which
         an adequate reserve has been established or where noncompliance could
         not reasonably be expected to have a Material Adverse Effect.

                  (e) MAINTENANCE OF INSURANCE. Maintain insurance with
         responsible and reputable insurance companies or associations of the
         type indicated on, and in such amounts and covering such risks as is
         required by law and as set forth on, Schedule 5.

                  (f) PRESERVATION OF CORPORATE EXISTENCE, ETC. Preserve and
         maintain its existence, legal structure,

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         legal name, rights (charter and statutory), permits, licenses,
         approvals, privileges and franchises, except for such rights,
         franchises, permits, licenses and approvals the failure of which to
         maintain could not reasonably be expected to have a Material Adverse
         Effect.

                  (g) VISITATION RIGHTS. Subject to Section 9.09, upon
         reasonable prior notice and during customary business hours, permit the
         Administrative Agent, the Collateral Agent or any Lender or any agents
         or representatives thereof, to examine and make copies of and abstracts
         from the records and books of account of, and visit the properties of
         the Borrower, and to discuss the affairs, finances and accounts of the
         Borrower with any of its officers or directors and with its independent
         certified public accountants.

                  (h) MAINTENANCE OF APPROVALS AND LICENSES. Obtain and maintain
         in full force and effect all Governmental Authorizations and licenses
         that may be required for the validity or enforceability of the Loan
         Documents, the Material Contracts, the Acquisition Documents and the
         Project Documents and the ongoing operations of the Generating Assets
         except where the failure to do so could not reasonably be expected to
         have a Material Adverse Effect.

                  (i) KEEPING OF BOOKS. Keep proper books of record and account,
         in which full and correct entries shall be made of all financial
         transactions and the assets and business of the Borrower in accordance
         with GAAP.

                  (j) MAINTENANCE OF PROPERTIES, ETC. Keep all property useful
         and necessary to its respective businesses in good working order and
         condition, wear and tear excepted, and not commit or suffer to exist
         any waste with respect to any of its properties except where the
         failure to do so could not reasonably be expected to have a Material
         Adverse Effect.

                  (k) PERFORMANCE OF MATERIAL CONTRACTS, ACQUISITION DOCUMENTS
         AND PROJECT Documents. Perform and observe all the material terms and
         provisions of each Material Contract, each Acquisition Document and
         each Project Document to be performed or observed by it, enforce each
         such Material Contract and each such Project Document in accordance
         with its terms, take all such action to such end and exercise all
         rights under the Material Contracts, the Acquisition Documents and the
         Project Documents as may be from time to time requested by the
         Administrative Agent and, upon request of the Administrative Agent,
         make to each other party to each such Material Contract, each such
         Acquisition Document and each such Project Document such demands and
         requests for information and reports or for action

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         as the Borrower is entitled to make under such Material Contract, such
         Acquisition Document or such Project Document.

                  (l) TRANSACTIONS WITH AFFILIATES. Conduct all transactions
         otherwise permitted under the Loan Documents with any of its Affiliates
         on terms that are fair and reasonable and no less favorable to the
         Borrower than it would obtain in a comparable arm's-length transaction
         with a Person not an Affiliate.

                  (m) COVENANT TO GIVE SECURITY. Promptly upon the reasonable
         request of the Administrative Agent or the Collateral Agent, at the
         Borrower's expense, execute and deliver, or cause the execution and
         delivery of, and thereafter register, file or record in each
         appropriate governmental office, any document or instrument
         supplemental to or confirmatory of the applicable Loan Documents
         relating to the Collateral or otherwise reasonably deemed by the
         Administrative Agent or the Collateral Agent to be necessary for the
         creation or perfection or priority or continuation of the Liens and
         security interests purported to be created by any such document; and
         protect and defend its and the Lenders' interest in the Collateral
         against Liens (other than Permitted Liens) and immediately discharge
         any such lien so asserted.

                  (n) MAINTENANCE OF PRIORITY. Take all necessary action so as
         to ensure that all Obligations of the Loan Parties under the Loan
         Documents continue to rank senior in right of payment and collateral
         security to all unsecured or unsubordinated Obligations of the Loan
         Parties.

                  (o) REGULATORY STATUS. Take all necessary action within its
         control, and otherwise use its best efforts, to ensure that (i) the
         Borrower remains exempt from all or is not subject to any regulation as
         a public utility under the Public Utility Holding Company Act of 1935
         and any other applicable federal, state and local laws or regulations
         regulating public utilities, public utility companies, public utility
         holding companies, electric utilities, electric companies, electric
         utility companies, or any similar entity, (ii) the Borrower maintains
         its status as an Exempt Wholesale Generator and (iii) the
         Administrative Agent, the Collateral Agent and each Lender will not (i)
         be subject to regulation as a "public utility" under the Federal Power
         Act, an electric distribution company, a public utility, an electric
         corporation or any similar type of entity under Connecticut law or
         Massachusetts law, or (ii) be subject to regulation by the Securities
         and Exchange Commission as a "gas utility company," "electric utility
         company," "public utility company," "holding company," an "affiliate"
         of a "holding company," a "subsidiary company" of a "holding

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<PAGE>

         company," or an "affiliate" of a "subsidiary company" of a "holding
         company" under the Public Utility Holding Company Act of 1935, or (iii)
         otherwise be deemed by any federal, state or local Governmental
         Authority to be a public utility, public utility company, public
         utility holding company, electric utility, electric company, electric
         utility company or similar entity or otherwise subject to any
         regulation relating to any such type of entity (or affiliate thereof).
         In the event that FERC denies Exempt Wholesale Generator status to the
         Borrower, the Borrower shall take all necessary actions within its
         control and without delay, and otherwise use its reasonable best
         efforts, to comply with the Public Utility Holding Company Act of 1935,
         including, but not limited to, (y) making any changes necessary to
         eliminate the basis for denial of the original application for Exempt
         Wholesale Generator status and preparing and filing a new application
         in good faith with FERC for a determination of Exempt Wholesale
         Generator status, or (z) filing an application under the relevant
         provisions of the Public Utility Holding Company Act of 1935 to qualify
         Borrower as an operating "public utility company" of Northeast
         Utilities.

                  (p)  USE OF PROCEEDS. Use the proceeds of the Advances solely
         as provided in Section 2.13.

                  (q) REQUIRED RATING. Actively assist the Placement Agent in
         obtaining a final rating letter equal to or higher than the Required
         Rating from each of the Rating Agencies for the Permanent Financing,
         such assistance to include, without limitation: (A) providing, and
         causing its respective advisors to provide, the Placement Agent and
         each of the Rating Agencies upon request with all information
         reasonably deemed necessary by either of the Rating Agencies or the
         Placement Agent to acquire the rating letter equal to or higher than
         the Required Rating, (B) assisting the Placement Agent, upon its
         reasonable request, in the preparation of all materials presented to
         the Rating Agencies to be used in connection with obtaining the rating
         letter equal to or higher than the Required Rating and (C) otherwise
         assisting the Placement Agent in obtaining a rating equal to or higher
         than the Required Rating, including by making available officers and
         advisors of the Borrower and its respective Affiliates from time to
         time to attend and make presentations regarding the business and
         prospects of the Borrower, its Affiliates and the Generating Assets, as
         appropriate, at a meeting or meetings with each of the Rating Agencies.

                  (r)  SEPARATE AND DISTINCT. Comply with the following
         undertakings:

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                           (i) It will maintain its books, financial records and
                  accounts, including checking and other bank accounts and
                  custodian and other securities safekeeping accounts, separate
                  and distinct from those of Northeast Utilities and each of the
                  other Subsidiaries of Northeast Utilities.

                           (ii) It will maintain its books, financial records
                  and accounts (including inter-entity transaction accounts) in
                  a manner so that it will not be difficult or costly to
                  segregate, ascertain or otherwise identify its assets and
                  liabilities separate and distinct from the assets and
                  liabilities of Northeast Utilities and each of the other
                  Subsidiaries of Northeast Utilities.

                           (iii) It will not commingle any of its assets, funds,
                  liabilities or business functions with the assets, funds,
                  liabilities or business functions of Northeast Utilities or
                  any of the other Subsidiaries of Northeast Utilities.

                           (iv) It will maintain corporate governance and
                  operating procedures designed to ensure its separate corporate
                  existence from Northeast Utilities and each of the other
                  Subsidiaries of Northeast Utilities, including the holding of
                  periodic and special meetings of shareholders and boards of
                  directors (or other governing body), the recordation and
                  maintenance of minutes of such meetings, and the recordation
                  and maintenance of resolutions adopted at such meetings.

                           (v) It will not be consensually merged or
                  consolidated with Northeast Utilities or any of the other
                  Subsidiaries of Northeast Utilities (other than, with respect
                  to other Subsidiaries of Northeast Utilities, for financial
                  reporting purposes).

                           (vi) It will cause all material transactions,
                  agreements and dealings between it and Northeast Utilities and
                  any of the other Subsidiaries of Northeast Utilities
                  (including transactions, agreements and dealings pursuant to
                  which the assets or property of one is used or to be used by
                  the other) to reflect the separate identity and legal
                  existence of each such entity, to be entered into in the names
                  of the persons that are parties to the transaction or
                  agreement and to be formally documented in writing.

                           (vii) It will ensure that transactions between itself
                  and any third parties will be conducted in its name as an
                  entity separate and distinct from Northeast Utilities and each
                  of the other Subsidiaries of Northeast Utilities.

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                           (viii) It will compensate all consultants,
                  independent contractors and agents from its own funds for
                  services provided to it by such consultants, independent
                  contractors and agents.

                           (ix) It will ensure that to the extent that it, on
                  the one hand, and Northeast Utilities or any of the other
                  Subsidiaries of Northeast Utilities, on the other hand,
                  jointly contract or do business with vendors or service
                  providers or share overhead expenses, the costs and expenses
                  incurred in so doing will be fairly and non-arbitrarily
                  allocated between or among such entities, with the result that
                  each such entity bears its fair share of all such costs and
                  expenses. It will ensure that to the extent that it, on the
                  one hand, and Northeast Utilities or any of the other
                  Subsidiaries of Northeast Utilities, on the other hand,
                  contracts or does business with vendors or service providers
                  where the goods or services are wholly or partially for the
                  benefit of the other, then the costs incurred in so doing will
                  be fairly and non-arbitrarily allocated to the entity for
                  whose benefit the goods or services are provided, with the
                  result that each such entity bears its fair share of all such
                  costs.

                           (x) It will have annual financial statements prepared
                  in accordance with GAAP, separate from Northeast Utilities and
                  any of the other Subsidiaries of Northeast Utilities.

                           (xi) It will not make any inter-entity loans,
                  advances, guarantees, extensions of credit or contributions of
                  capital to, from or for the benefit of Northeast Utilities or
                  any of the other Subsidiaries of Northeast Utilities without
                  proper documentation and accounting in accordance with GAAP.

                           (xii) It will cause to be prepared and maintained all
                  legally required tax returns for itself (including federal and
                  state income tax returns) separately from the tax returns of
                  Northeast Utilities and any of the other Subsidiaries of
                  Northeast Utilities, except as otherwise required or permitted
                  by law, and it will cause such tax returns to be prepared in
                  accordance with the Tax Sharing Agreement whether or not it
                  has been entered into by the parties proposed to be party
                  thereto.

                           (xiii) It will identify itself as a separate
                  Connecticut corporation and not as a division or department of
                  Northeast Utilities, any of Northeast Utilities' other
                  Subsidiaries or any

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                  other Person and identify Northeast Utilities and its other
                  Subsidiaries as separate entities and not as divisions or
                  departments of Northeast Utilities or any of its other
                  Subsidiaries.

                           (xiv) It will cause its representatives and agents to
                  hold themselves out to third parties as being representatives
                  or agents of the Borrower.

                  (s) It will cause the Incentive Payment (as defined in the
         Select Power Purchase Agreement) or the equivalent term used therein,
         if any, to be the identical dollar amount to the Incentive Payment (as
         defined in the O&M Agreement) or the equivalent term used therein, if
         any.

         SECTION 6.02. NEGATIVE COVENANTS. So long as any Advance shall remain
unpaid or any Lender shall have any Commitment hereunder, the Borrower will not,
at any time:

                  (a) LIENS, ETC. Create, incur, assume or suffer to exist any
         Lien on or with respect to any of its properties of any character
         (including, without limitation, accounts) whether now owned or
         hereafter acquired, or sign or file or suffer to exist, under the
         Uniform Commercial Code as in effect from time to time of any
         jurisdiction, a financing statement that names the Borrower as debtor,
         or sign or suffer to exist, any security agreement authorizing any
         secured party thereunder to file such financing statement, or assign
         any accounts or other right to receive income, EXCLUDING, HOWEVER, from
         the operation of the foregoing restrictions the Permitted Encumbrances
         under the Mortgages.

                  (b)  DEBT. Create, incur, assume or suffer to exist any Debt
         other than:

                           (i)     Debt under the Loan Documents;

                           (ii)    Permitted Hedges; and

                           (iii) Bonds for the conduct of its business in the
                  ordinary course not to exceed $250,000 in the aggregate
                  outstanding at any time.

                  (c) LEASE OBLIGATIONS. Create, incur, assume or suffer to
         exist any obligations as lessee for the rental or hire of real or
         personal property of any kind under leases or agreements to lease
         including Capitalized Leases having an original term of one year or
         more that would cause the direct and contingent liabilities of the
         Borrower, in respect of all such obligations to exceed $100,000 payable
         in any period of 12 consecutive months.

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                  (d)  MERGERS, ETC. Merge into or consolidate with any Person
         or permit any Person to merge into it.

                  (e)  SALES, ETC., OF ASSETS. Sell, lease, transfer or
         otherwise dispose of any of its property or assets, or grant any option
         or other right to purchase, lease or otherwise acquire any of its
         property or assets, except (i) sales of power in the ordinary course of
         its business and (ii) sales of damaged, worn-out or obsolete or other
         property that is not necessary for the proper conduct of the business
         of the Borrower or the operation of the Generating Assets for fair
         value in the ordinary course of business.

                  (f)  INVESTMENTS IN OTHER PERSONS. Make or hold any Investment
         in any Person other than Permitted Investments.

                  (g) DIVIDENDS, ETC. Declare or pay any dividends, purchase,
         redeem, retire, defease or otherwise acquire for value any of its
         capital stock or any warrants, rights or options to acquire such
         capital stock, now or hereafter outstanding, return any capital to its
         stockholders as such, make any distribution of assets, capital stock,
         warrants, rights, options, obligations or securities to its
         stockholders as such or issue or sell any capital stock or any
         warrants, rights or options to acquire such capital stock.

                  (h)  CHANGE IN NATURE OF BUSINESS. Engage in any business
         other than the business of, and activities related and incidental to,
         electric power generation.

                  (i)  CHARTER AMENDMENTS. Amend its certificate of
         incorporation or bylaws or change its corporate structure if such
         amendment or change would have a Material Adverse Effect.

                  (j)  ACCOUNTING CHANGES. Make or permit any change in (i)
         accounting policies or reporting practices, except as required by GAAP
         or (ii) its Fiscal Year.

                  (k) AMENDMENT, ETC., OF PROJECT DOCUMENTS, ACQUISITION
         DOCUMENTS AND MATERIAL CONTRACTS. With respect to any Material
         Contract, Acquisition Document or any Project Document to which it is a
         party, not to cancel or terminate, or accept any cancellation or
         termination of, or amend, modify or change in any manner (which would
         result in a Material Adverse Effect) any such Material Contract,
         Acquisition Document or any Project Document without the prior written
         approval of the Lenders.

                  (l)  NEGATIVE PLEDGE. Enter into or suffer to exist any
         agreement prohibiting or conditioning the creation or assumption of any
         Lien upon any of its

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         property or assets other than (i) in favor of the Secured Parties or
         (ii) in connection with any other Debt permitted by Section 6.02
         hereof.

                  (m)  PARTNERSHIPS, ETC. Become a general partner in any
         general or limited partnership or joint venture or similar type of
         entity.

                  (n) CAPITAL EXPENDITURES. Make any Capital Expenditures in
         excess of the Capital Expenditures included in the Annual Operating
         Budget delivered in connection with Section 3.01(m)(xv), other than
         Capital Expenditures required by a change in law or the order of a
         competent Governmental Authority, issued after the date hereof or
         Capital Expenditures requested by Select provided that Select funds the
         costs for such Capital Expenditures and that (i) if the Capital
         Expenditure costs less than $500,000 and is not expected to interfere
         with the operation of any Generating Asset, the Borrower shall deliver
         a certificate to the Lenders stating that such Capital Expenditure
         shall not result in a Material Adverse Effect to such Generating Asset
         or a Material Adverse Effect on the Borrower, and (ii) if the cost of
         the Capital Expenditure is in excess of $500,000 or would interfere
         with the operation of a Generating Asset, Stone & Webster or another
         independent engineer reasonably acceptable to the Lenders shall confirm
         to the Lenders that such Capital Expenditure would not result in a
         Material Adverse Effect to such Generating Asset or a Material Adverse
         Effect to the Borrower; PROVIDED, that Select shall have no claim
         against the Borrower for the funds advanced for any such Capital
         Expenditures, that Select shall have no Liens against the Borrower or
         the Generating Assets arising from such Capital Expenditure and that
         the title to the assets acquired or financed by such Capital
         Expenditure shall be in the name of the Borrower.

                  (o) TAX ARRANGEMENTS. Cancel or terminate, or accept any
         cancellation or termination of, or amend, modify or change in any
         manner the Tax Sharing Agreement, or enter into any new tax sharing
         agreement, without the prior written approval of the Lenders; provided,
         HOWEVER, that no such approval shall be required to the extent that
         such action or such new tax sharing agreement, as the case may be, can
         reasonably be expected not to have a Material Adverse Effect.

         SECTION 6.03. REPORTING REQUIREMENTS. So long as any Advance shall
remain unpaid or any Lender shall have any Commitment hereunder, the Borrower
will furnish to the Lenders:

                  (a)  DEFAULT NOTICE. As soon as possible and in any event
         within five Business Days after the occurrence of each Default or any
         event which would

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         reasonably likely have a Material Adverse Effect continuing on the date
         of such statement, a statement of the chief financial officer of the
         Borrower setting forth details of such Default and the action that the
         Borrower has taken and proposes to take with respect thereto.

                  (b) QUARTERLY FINANCIALS. As soon as available and in any
         event within 60 days after the end of each of the first three quarters
         of each Fiscal Year, a balance sheet of the Borrower as of the end of
         such quarter and statement of income and a statement of cash flows of
         the Borrower for the period commencing at the end of the previous
         fiscal quarter and ending with the end of such fiscal quarter and a
         statement of income and a statement of cash flows of the Borrower for
         the period commencing at the end of the previous Fiscal Year and ending
         with the end of such quarter, setting forth in each case in comparative
         form the corresponding figures for the corresponding period of the
         preceding Fiscal Year, all in reasonable detail and duly certified
         (subject to year-end audit adjustments) by the chief financial officer
         of the Borrower as having been prepared in accordance with GAAP,
         together with (i) a certificate of said officer stating that no Default
         has occurred and is continuing or, if a Default has occurred and is
         continuing, a statement as to the nature thereof and the action that
         the Borrower has taken and proposes to take with respect thereto, (ii)
         a certificate of said officer specifically confirming compliance by the
         Borrower with Section 6.01(r) and (iii) a schedule in form satisfactory
         to the Administrative Agent of the computations used by the Borrower in
         determining compliance with the covenant contained in Section 6.04,
         PROVIDED that in the event of any change in GAAP used in the
         preparation of such financial statements, the Borrower shall also
         provide, if necessary for the determination of compliance with Section
         6.04, a statement of reconciliation conforming such financial
         statements to GAAP.

                  (c) ANNUAL FINANCIALS. As soon as available and in any event
         within 120 days after the end of each Fiscal Year, a copy of the annual
         audit report for such year for the Borrower, including therein a
         balance sheet of the Borrower as of the end of such Fiscal Year and a
         statement of income and a statement of cash flows of the Borrower for
         such Fiscal Year, in each case accompanied by an opinion reasonably
         acceptable to the Required Lenders of Arthur Anderson, LLP or other
         independent public accountants of recognized standing acceptable to the
         Required Lenders, together with (i) a certificate of such accounting
         firm to the Lenders stating that in the course of the regular audit of
         the business of the Borrower, which audit was conducted by such
         accounting firm in accordance with generally accepted auditing
         standards, such accounting firm has

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         obtained no knowledge that a Default has occurred and is continuing, or
         if, in the opinion of such accounting firm, a Default has occurred and
         is continuing, a statement as to the nature thereof, (ii) a schedule in
         form satisfactory to the Administrative Agent of the computations used
         by such accountants in determining, as of the end of such Fiscal Year,
         compliance with the covenant contained in Section 6.04, PROVIDED that
         in the event of any change in GAAP used in the preparation of such
         financial statements, the Borrower shall also provide, if necessary for
         the determination of compliance with Section 6.04, a statement of
         reconciliation conforming such financial statements to GAAP, (iii) a
         certificate of the chief financial officer of the Borrower (or the
         individual performing such functions) stating that no Default has
         occurred and is continuing or, if a default has occurred and is
         continuing, a statement as to the nature thereof and the action that
         the Borrower has taken and proposes to take with respect thereto and
         (iv) a certificate of said officer specifically confirming compliance
         by the Borrower with Section 6.01(r).

                  (d) ERISA EVENTS AND ERISA REPORTS. Promptly and in any event
         within 10 days after any Loan Party or any ERISA Affiliate knows or has
         reason to know that any ERISA Event has occurred, a statement of the
         chief financial officer of the Borrower describing such ERISA Event and
         the action, if any, that such Loan Party or such ERISA Affiliate has
         taken and proposes to take with respect thereto and (ii) on the date
         any records, documents or other information must be furnished to the
         PBGC with respect to any Plan pursuant to Section 4010 of ERISA, a copy
         of such records, documents and information.

                  (e) PLAN TERMINATIONS. Promptly and in any event within ten
         Business Days after receipt thereof by any Loan Party or any ERISA
         Affiliate, copies of each notice from the PBGC stating its intention to
         terminate any Plan or to have a trustee appointed to administer any
         Plan.

                  (f) ACTUARIAL REPORTS. Promptly upon receipt thereof by any
         Loan Party or any ERISA Affiliate, a copy of the annual actuarial
         valuation report for each Plan the funded current liability percentage
         (as defined in Section 302(d)(8) of ERISA) of which is less than 90% or
         the unfunded current liability of which exceeds $5,000,000.

                  (g) PLAN ANNUAL REPORTS. Promptly and in any event within 30
         days after the filing thereof with the Internal Revenue Service, copies
         of each Schedule B (Actuarial Information) to the annual report (Form
         5500 Series) with respect to each Plan.

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                  (h) MULTIEMPLOYER PLAN NOTICES. Promptly and in any event
         within five Business Days after receipt thereof by any Loan Party or
         any ERISA Affiliate from the sponsor of a Multiemployer Plan, copies of
         each notice concerning (i) the imposition of Withdrawal Liability by
         any such Multiemployer Plan, (ii) the reorganization or termination,
         within the meaning of Title IV of ERISA, of any such Multiemployer Plan
         or (iii) the amount of liability incurred, or that may be incurred, by
         such Loan Party or any ERISA Affiliate in connection with any event
         described in clause (i) or (ii).

                  (i) LITIGATION. Promptly after the commencement thereof,
         notice of all actions, suits, investigations, litigation and
         proceedings before any court or governmental department, commission,
         board, bureau, agency or instrumentality, domestic or foreign,
         affecting the Borrower of the type described in Section 5.01(h), other
         than any actions, suits, investigations, litigation and proceedings
         that could not reasonably be expected to have a Material Adverse
         Effect.

                  (j) SECURITIES REPORTS. Promptly after the sending or filing
         thereof, copies of all proxy statements, financial statements and
         reports that any Loan Party sends to its stockholders, and copies of
         all regular, periodic and special reports, and all registration
         statements, that any Loan Party files with the Securities and Exchange
         Commission or any Governmental Authority that may be substituted
         therefor, or with any national securities exchange.

                  (k) AGREEMENT NOTICES. (i) Promptly upon receipt thereof,
         copies of all material notices, requests and other documents received
         by the Borrower under or pursuant to any Material Contract, Project
         Document, Acquisition Document or indenture, loan or credit or similar
         agreement and, from time to time upon request by the Administrative
         Agent, such information and reports regarding the Material Contracts,
         the Project Documents and the Acquisition Documents as the
         Administrative Agent may reasonably request.

                  (ii) Within 30 days from the execution thereof, deliver to the
         Administrative Agent a certified copy of any modification or amendment
         to any of the Material Contracts, Project Documents or Acquisition
         Documents.

                  (l) REVENUE AGENT REPORTS. Within 10 days after receipt,
         copies of all Revenue Agent Reports (Internal Revenue Service Form
         886), or other written proposals of the Internal Revenue Service, that
         propose, determine or otherwise set forth positive and negative
         adjustments to the Federal income tax liability of the

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         affiliated group (within the meaning of Section 1504(a)(1) of the
         Internal Revenue Code) that apply to the Borrower, of which the
         Borrower is a member aggregating $1,000,000 or more.

                  (m) TAX CERTIFICATES. Promptly, and in any event within five
         Business Days after the due date (with extensions) for filing the final
         Federal income tax return in respect of each taxable year, a
         certificate (a "TAX CERTIFICATE"), signed by the President or the chief
         financial officer of the Borrower, stating that (i) it has filed, or
         has had filed on its behalf, all tax returns required to be filed by
         it, (ii) it, and each other party to the Tax Sharing Agreement, has
         paid to the Internal Revenue Service or other taxing authority the full
         amount that it and each such other party is required to pay in respect
         of Federal income tax for such year and (iii) it has received any
         amounts payable to it, and has not paid amounts in respect of taxes
         (Federal, state, local or foreign) in excess of the amount it is
         required to pay, under any Tax Sharing Agreement in respect of such
         taxable year.

                  (n) ENVIRONMENTAL CONDITIONS. Promptly after the assertion or
         occurrence thereof, notice of any Environmental Action against or of
         any noncompliance by any Loan Party with any Environmental Law or
         Environmental Permit that (i) could reasonably be expected to have a
         Material Adverse Effect or (ii) cause any property described in the
         Mortgages to be subject to any restrictions on ownership, occupancy,
         use or transferability under any Environmental Law, except to the
         extent that such restriction could not reasonably be expected to have a
         Material Adverse Effect.

                  (o) YEAR 2000 COMPLIANCE. Promptly after discovery or
         determination thereof, notice (in reasonable detail) that any computer
         application (including those of its suppliers, vendors and customers)
         that is material to the business and operations of the Borrower will
         have a problem relating to the Year 2000 date change, except to the
         extent that such failure could not reasonably be expected to have a
         Material Adverse Effect.

                  (p) OTHER INFORMATION. Such other information respecting the
         business, condition (financial or otherwise), operations, performance,
         properties or prospects of any Loan Party or any of its Subsidiaries as
         any Lender (through the Administrative Agent) may from time to time
         reasonably request.

         SECTION 6.04. FINANCIAL COVENANTS. So long as any Advance shall remain
unpaid or any Lender shall have any Commitment hereunder, the Borrower will
maintain an Equity to Total Capitalization ratio of not less than 45%.

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                                   ARTICLE VII

                                EVENTS OF DEFAULT

         SECTION 7.01. EVENTS OF DEFAULT. If any of the following events
("EVENTS OF Default") shall occur and be continuing:

                  (a) (i) the Borrower shall fail to pay any principal of or any
         interest on any Advance when the same shall become due and payable
         (and, in the case of a non-payment of principal of the Tranche A
         Advance only, notice of such failure to pay shall have been issued by
         the Administrative Agent to the Borrower) or (ii) the Borrower or
         Northeast Utilities shall fail to make any other payment under any Loan
         Document or any Project Document in each case when the same becomes due
         and payable and such failure shall continue for 10 days; or

                  (b) any representation or warranty made by any Loan Party (or
         any of its officers) under or in connection with any Loan Document, any
         Material Contract or any Project Document shall prove to have been
         incorrect in any material respect when made or deemed made; or

                  (c) the Borrower shall fail to perform or observe any term,
         covenant or agreement contained in Section 2.13, 6.01(f), (l), (m), (o)
         or (p), 6.02, 6.03 or 6.04; or

                  (d) any Loan Party shall fail to perform any other term,
         covenant or agreement contained in any Loan Document or any Material
         Contract or any Project Document on its part to be performed or
         observed if such failure shall remain unremedied for (i) 15 days with
         respect to the Loan Documents, the Select Power Purchase Agreement and
         the Northeast Utilities Guaranties, and (ii) 30 days with respect to
         any Material Contract or any Project Document (other than the Select
         Power Purchase Agreement and the Northeast Utilities Guaranties), each
         after the earlier of the date on which (A) a Responsible Officer of any
         Loan Party becomes aware of such failure or (B) written notice thereof
         shall have been given to the Borrower by the Administrative Agent or
         any Lender; or

                  (e) the Borrower, Northeast Utilities or NU Enterprises shall
         fail to pay any principal of, premium or interest on or any other
         amount payable in respect of any Debt that is outstanding in a
         principal amount of at least $10,000,000 either individually or in the
         aggregate (but excluding Debt outstanding hereunder) of the Borrower,
         Northeast Utilities or NU Enterprises (as the case may be), when the
         same becomes due and payable (whether by scheduled maturity, required
         prepayment,

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         acceleration, demand or otherwise), and such failure shall continue
         after the applicable grace period, if any, specified in the agreement
         or instrument relating to such Debt; or any other event shall occur or
         condition shall exist under any agreement or instrument relating to any
         such Debt and shall continue after the applicable grace period, if any,
         specified in such agreement or instrument, if the effect of such event
         or condition is to accelerate, or to permit the acceleration of, the
         maturity of such Debt or otherwise to cause, or to permit the holder
         thereof to cause, such Debt to mature; or any such Debt shall be
         declared to be due and payable or required to be prepaid or redeemed
         (other than by a regularly scheduled required prepayment or
         redemption), purchased or defeased, or an offer to prepay, redeem,
         purchase or defease such Debt shall be required to be made, in each
         case prior to the stated maturity thereof; or

                  (f) the Borrower, Northeast Utilities or NU Enterprises shall
         generally not pay its debts as such debts become due, shall admit in
         writing its inability to pay its debts generally, or shall make a
         general assignment for the benefit of creditors; or any proceeding
         shall be instituted by or against the Borrower or Northeast Utilities
         or NU Enterprises seeking to adjudicate it a bankrupt or insolvent, or
         seeking liquidation, winding up, reorganization, arrangement,
         adjustment, protection, relief, or composition of it or its debts under
         any law relating to bankruptcy, insolvency or reorganization or relief
         of debtors, or seeking the entry of an order for relief or the
         appointment of a receiver, trustee, or other similar official for it or
         for any substantial part of its property and, in the case of any such
         proceeding instituted against it (but not instituted by it) that is
         being diligently contested by it in good faith, either such proceeding
         shall remain undismissed or unstayed for a period of 30 days or any of
         the actions sought in such proceeding (including, without limitation,
         the entry of an order for relief against, or the appointment of a
         receiver, trustee, custodian or other similar official for, it or any
         substantial part of its property) shall occur; or the Borrower,
         Northeast Utilities or NU Enterprises shall take any corporate action
         to authorize any of the actions set forth above in this subsection (f);
         or

                  (g) any judgment or order for the payment of money in excess
         of $10,000,000 either individually or in the aggregate shall be
         rendered against the Borrower, Northeast Utilities or NU Enterprises
         and either (i) enforcement proceedings shall have been commenced by any
         creditor upon such judgment or order or (ii) there shall be any period
         of 10 consecutive

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         days during which a stay of enforcement of such judgment or order, by
         reason of a pending appeal or otherwise, shall not be in effect; or

                  (h) any non-monetary judgment or order shall be rendered
         against the Borrower, Northeast Utilities or NU Enterprises that could
         reasonably be expected to have a Material Adverse Effect on the
         Borrower, Northeast Utilities or NU Enterprises, as the case may be,
         and either (i) enforcement proceedings shall have been commenced by any
         creditor upon such judgment or order or (ii) there shall be any period
         of 10 consecutive days during which a stay of enforcement of such
         judgment or order, by reason of a pending appeal or otherwise, shall
         not be in effect; or

                  (i) any provision of any Loan Document, Material Contract or
         Project Document after delivery thereof pursuant to Section 3.01 or
         6.01(n) shall for any reason cease to be valid and binding on or
         enforceable against any Loan Party which is party to it, or any such
         Loan Party shall so state in writing; or

                  (j) any Collateral Document after delivery thereof pursuant to
         Section 3.01 or 6.01(n) shall for any reason (other than pursuant to
         the terms thereof) cease to create a valid and perfected first priority
         lien on and security interest in the Collateral purported to be covered
         thereby; or

                  (k) any material provision of any of the Loan Documents or the
         Material Contracts or the Project Documents shall be canceled,
         terminated (other than as contemplated by its terms and the Loan
         Documents), declared by a competent court having jurisdiction to be
         null and void or shall otherwise cease to be valid and binding, or any
         material provision thereof shall be amended or modified in a manner
         that could reasonably be expected to have a Material Adverse Effect, or
         any party thereto shall deny any further liability or obligation
         thereunder; or

                  (l) Northeast Utilities shall cease to own and control
         directly or indirectly 100% of the capital stock of each of the
         Borrower, NGS, Select and NU Enterprises, and 80% of the common stock
         of each of CL&P, WMECO and Public Service Company of New Hampshire, in
         each case free and clear of all Liens other than Liens in favor of the
         Secured Parties under the Collateral Documents; or

                  (m) (i) any Person or two or more Persons acting in concert
         shall have acquired beneficial ownership (within the meaning of Rule
         13d-3 of the Securities and Exchange Commission under the Securities
         Exchange Act of 1934), directly or indirectly, of Voting Stock of
         Northeast Utilities (or other securities convertible

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         into such Voting Stock) representing 15% or more of the combined voting
         power of all Voting Stock of Northeast Utilities, other than upon the
         consummation of the proposed acquisition by Consolidated Edison Inc.
         (directly or through one of its Subsidiaries) of 100% of the capital
         stock of Northeast Utilities or (ii) during any period of up to 24
         consecutive months, commencing on June 17, 1999, individuals who at the
         beginning of such 24-month period were directors of Northeast Utilities
         shall cease for any reason to constitute a majority of the board of
         directors of Northeast Utilities, other than a change in the board of
         directors of Northeast Utilities in connection with the proposed
         acquisition directly or indirectly by Consolidated Edison Inc. of 100%
         of the capital stock of Northeast Utilities; or (iii) any Person or two
         or more Persons acting in concert shall have acquired by contract or
         otherwise, or shall have entered into a contract or arrangement that,
         upon consummation, will result in its or their acquisition of the power
         to exercise, directly or indirectly, a controlling influence over the
         management or policies of Northeast Utilities; or

                  (n) any ERISA Event shall have occurred with respect to a Plan
         and the sum (determined as of the date of occurrence of such ERISA
         Event) of the Insufficiency of such Plan and the Insufficiency of any
         and all other Plans with respect to which an ERISA Event shall have
         occurred and then exist (or the liability of the Loan Parties and the
         ERISA Affiliates related to such ERISA Event) exceeds $10,000,000; or

                  (o) any Loan Party or any ERISA Affiliate shall have been
         notified by the sponsor of a Multiemployer Plan that it has incurred
         Withdrawal Liability to such Multiemployer Plan in an amount that, when
         aggregated with all other amounts required to be paid to Multiemployer
         Plans by the Loan Parties and the ERISA Affiliates as Withdrawal
         Liability (determined as of the date of such notification), exceeds
         $10,000,000 or requires payments exceeding $2,500,000 per annum; or

                  (p) any Loan Party or any ERISA Affiliate shall have been
         notified by the sponsor of a Multiemployer Plan that such Multiemployer
         Plan is in reorganization or is being terminated, within the meaning of
         Title IV of ERISA, and as a result of such reorganization or
         termination the aggregate annual contributions of the Loan Parties and
         the ERISA Affiliates to all Multiemployer Plans that are then in
         reorganization or being terminated have been or will be increased over
         the amounts contributed to such Multiemployer Plans for the plan years
         of such Multiemployer Plans immediately preceding the plan year in
         which such reorganization or termination occurs by an amount exceeding
         $10,000,000; or

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                  (q)  the Borrower shall cease to be an Exempt Wholesale
         Generator;

then, and in any such event, the Administrative Agent (i) shall at the request,
or may with the consent, of the Required Lenders, by notice to the Borrower,
declare the obligation of each Lender to make Advances to be terminated,
whereupon the same shall forthwith terminate, and (ii) shall at the request, or
may with the consent, of the Required Lenders, by notice to the Borrower,
declare the Notes, all interest thereon and all other amounts payable under this
Agreement and the other Loan Documents to be forthwith due and payable,
whereupon the Notes, all such interest and all such amounts shall become and be
forthwith due and payable, without presentment, demand, protest or further
notice of any kind, all of which are hereby expressly waived by the Borrower;
PROVIDED, HOWEVER, that in the event of an actual or deemed entry of an order
for relief with respect to the Borrower or NU Enterprises under the Federal
Bankruptcy Code, (x) the obligation of each Lender to make Advances shall
automatically be terminated and (y) the Notes, all such interest and all such
amounts shall automatically become and be due and payable, without presentment,
demand, protest or any notice of any kind, all of which are hereby expressly
waived by the Borrower.

                                  ARTICLE VIII

                                   THE AGENTS

         SECTION 8.01. AUTHORIZATION AND ACTION. (a) Each Lender hereby appoints
and authorizes the Administrative Agent to take such action as agent on its
behalf and to exercise such powers and discretion under this Agreement and the
other Loan Documents as are delegated to the Administrative Agent by the terms
hereof and thereof, together with such powers and discretion as are reasonably
incidental thereto. As to any matters not expressly provided for by the Loan
Documents (including, without limitation, enforcement or collection of the
Notes), the Administrative Agent shall not be required to exercise any
discretion or take any action, but shall be required to act or to refrain from
acting (and shall be fully protected in so acting or refraining from acting)
upon the instructions of the Required Lenders, and such instructions shall be
binding upon all Lenders and all holders of Notes; PROVIDED, HOWEVER, that the
Administrative Agent shall not be required to take any action that exposes the
Administrative Agent to personal liability or that is contrary to this
Agreement, any other Loan Document or applicable law. The Administrative Agent
agrees to give to each Lender prompt notice of each notice given to it by the
Borrower pursuant to the terms of this Agreement.

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         (b) Each Lender hereby appoints and authorizes the Collateral Agent to
take such action as agent on its behalf and to exercise such powers and
discretion under this Agreement and the other Loan Documents as are delegated to
the Collateral Agent by the terms hereof and thereof, together with such powers
and discretion as are reasonably incidental thereto. As to any matters not
expressly provided for by the Loan Documents (including, without limitation,
enforcement of any security interest or enforcement or collection of the Notes,
giving of any consents, curing of any defaults, requesting any estoppel letters
or the determination of any Material Adverse Effect), the Collateral Agent shall
not be required to exercise any discretion or take any action, but shall be
required to act or to refrain from acting (and shall be fully protected in so
acting or refraining from acting) upon the instructions of the Required Lenders,
and such instructions shall be binding upon all Lenders and all holders of
Notes; PROVIDED, HOWEVER, that the Collateral Agent shall not be required to
take any action that exposes the Collateral Agent to personal liability or that
is contrary to this Agreement, any other Loan Document or applicable law. The
Collateral Agent agrees to give to each Lender prompt notice of each notice
given to it by the Borrower pursuant to the terms of this Agreement. The
Collateral Agent is hereby directed to execute and deliver the Borrower Security
Agreement, the Enterprises Pledge Agreement, the Mortgages and the Consents to
Assignment. For purposes of the exculpatory and protective provisions of this
Article VIII references to the Collateral Agent shall be deemed to include the
Depositary Bank.

         SECTION 8.02. AGENT'S RELIANCE, ETC. (a) Neither the Administrative
Agent nor any of its directors, officers, agents or employees shall be liable
for any action taken or omitted to be taken by it or them under or in connection
with the Loan Documents, except for its or their own gross negligence or willful
misconduct. Without limitation of the generality of the foregoing, the
Administrative Agent: (i) may treat the payee of any Note as the holder thereof
until the Administrative Agent receives and accepts an Assignment and Acceptance
entered into by the Lender that is the payee of such Note, as assignor, and an
Eligible Assignee, as assignee, as provided in Section 9.07; (ii) may consult
with legal counsel (including counsel for any Loan Party), independent public
accountants and other experts selected by it and shall not be liable for any
action taken or omitted to be taken in good faith by it in accordance with the
advice of such counsel, accountants or experts; (iii) makes no warranty or
representation to any Lender and shall not be responsible to any Lender for any
statements, warranties or representations (whether written or oral) made in or
in connection with the Loan Documents; (iv) shall not have any duty to ascertain
or to inquire as to the performance or observance of any of the terms, covenants
or conditions of any Loan Document on the part of any Loan Party or to inspect
the property (including the books and records) of any Loan Party; (v) shall not
be responsible to any Lender for the due execution, legality,

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validity, enforceability, genuineness, sufficiency or value of, or the
perfection or priority of any lien or security interest created or purported to
be created under or in connection with, any Loan Document or any other
instrument or document furnished pursuant thereto; (vi) shall incur no liability
under or in respect of any Loan Document by acting upon any notice, consent,
certificate or other instrument or writing (which may be by telegram, telecopy
or telex) believed by it to be genuine and signed or sent by the proper party or
parties; and (vii) except with respect to Section 7.01(a), shall not be deemed
to have notice of any Default or Event of Default unless and until it shall have
received notice thereof from a Lender. The Administrative Agent may fully rely
on an incumbency certificate from the Borrower and any other party as to the
persons authorized to give directions or otherwise act on behalf of the Borrower
or such other party, as the case may be.

         (b) Neither the Collateral Agent nor any of its directors, officers,
agents or employees shall be liable for any action taken or omitted to be taken
by it or them under or in connection with the Loan Documents, except for its or
their own gross negligence or willful misconduct. Without limitation of the
generality of the foregoing, the Collateral Agent: (i) may treat the payee of
any Note as the holder thereof until the Collateral Agent receives and accepts
an Assignment and Acceptance entered into by the Lender that is the payee of
such Note, as assignor, and an Eligible Assignee, as assignee, as provided in
Section 9.07; (ii) may consult with legal counsel (including counsel for any
Loan Party), independent public accountants and other experts selected by it and
shall not be liable for any action taken or omitted to be taken in good faith by
it in accordance with the advice of such counsel, accountants or experts; (iii)
makes no warranty or representation to any Lender and shall not be responsible
to any Lender for any statements, warranties or representations (whether written
or oral) made in or in connection with the Loan Documents; (iv) shall not have
any duty to ascertain or to inquire as to the performance or observance of any
of the terms, covenants or conditions of any Loan Document on the part of any
Loan Party or to inspect the property (including the books and records) of any
Loan Party; (v) shall not be responsible to any Lender for the due execution,
legality, validity, enforceability, genuineness, sufficiency or value of, or the
perfection or priority of any lien or security interest created or purported to
be created under or in connection with, any Loan Document or any other
instrument or document furnished pursuant thereto; (vi) shall incur no liability
under or in respect of any Loan Document by acting upon any notice, consent,
certificate or other instrument or writing (which may be by telegram, telecopy
or telex) believed by it to be genuine and signed or sent by the proper party or
parties, and (vii) shall not be deemed to have notice of any Default or Event of
Default unless and until it shall have received notice thereof from a Lender.
The Collateral Agent may fully rely on an incumbency

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certificate from the Borrower and any other party as to the persons authorized
to give directions or otherwise act on behalf of the Borrower or such other
party, as the case may be.

         SECTION 8.03. CITIBANK AND AFFILIATES. With respect to its Commitments,
the Advances made by it and the Notes issued to it, Citibank shall have the same
rights and powers under the Loan Documents as any other Lender and may exercise
the same as though it were not the Administrative Agent or the Collateral Agent;
and the term "Lender" shall, unless otherwise expressly indicated, include
Citibank in its individual capacity. Citibank and its affiliates may accept
deposits from, lend money to, act as trustee under indentures of, accept
investment banking engagements from and generally engage in any kind of business
with, any Loan Party, any of such Loan Party=s Subsidiaries and any Person who
may do business with or own securities of any Loan Party or any such Subsidiary,
all as if Citibank were not the Administrative Agent or the Collateral Agent and
without any duty to account therefor to the Lenders.

         SECTION 8.04. LENDER CREDIT DECISION. Each Lender acknowledges that it
has, independently and without reliance upon the Administrative Agent, the
Collateral Agent or any other Lender and based on the financial statements
referred to in Section 5.01 and such other documents and information as it has
deemed appropriate, made its own credit analysis and decision to enter into this
Agreement. Each Lender also acknowledges that it will, independently and without
reliance upon the Administrative Agent, the Collateral Agent or any other Lender
and based on such documents and information as it shall deem appropriate at the
time, continue to make its own credit decisions in taking or not taking action
under this Agreement.

         SECTION 8.05. INDEMNIFICATION. Each Lender severally agrees to
indemnify the Administrative Agent and the Collateral Agent (in each case to the
extent not promptly reimbursed by the Borrower) from and against such Lender's
ratable share (determined as provided below) of any and all liabilities,
obligations, losses, damages, penalties, actions, judgments, suits, costs,
expenses or disbursements of any kind or nature whatsoever that may be imposed
on, incurred by, or asserted against the Administrative Agent or the Collateral
Agent in any way relating to or arising out of the Loan Documents or any action
taken or omitted by the Administrative Agent, the Collateral Agent or the
Depositary Bank under the Loan Documents; PROVIDED, HOWEVER, that no Lender
shall be liable for any portion of such liabilities, obligations, losses,
damages, penalties, actions, judgments, suits, costs, expenses or disbursements
resulting from the Administrative Agent's or the Collateral Agent's gross
negligence or willful misconduct. Without limitation of the foregoing,

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each Lender agrees to reimburse the Administrative Agent and the Collateral
Agent, as the case may be, promptly upon demand for its ratable share of any
costs and expenses (including, without limitation, fees and expenses of counsel)
payable by the Borrower under Section 9.04, to the extent that the
Administrative Agent or the Collateral Agent is not promptly reimbursed for such
costs and expenses by the Borrower. For purposes of this Section 8.05, the
Lenders' respective ratable shares of any amount shall be determined, at any
time, according to the sum of (a) the aggregate principal amount of the Advances
outstanding at such time and owing to the respective Lenders, and (b) the
aggregate unused portions of their respective Commitments at such time. In the
event that any Defaulted Advance shall be owing by any Defaulting Lender at any
time, such Lender's Commitment with respect to the Defaulted Advance shall be
considered to be unused for purposes of this Section 8.05 to the extent of the
amount of such Defaulted Advance. The failure of any Lender to reimburse the
Administrative Agent or the Collateral Agent, as the case may be, promptly upon
demand for its ratable share of any amount required to be paid by the Lender to
the Administrative Agent or the Collateral Agent, as the case may be, as
provided herein shall not relieve any other Lender of its obligation hereunder
to reimburse the Administrative Agent or the Collateral Agent, as the case may
be, for its ratable share of such amount, but no Lender shall be responsible for
the failure of any other Lender to reimburse the Administrative Agent or the
Collateral Agent, as the case may be, for such other Lender's ratable share of
such amount. Without prejudice to the survival of any other agreement of any
Lender hereunder, the agreement and obligations of each Lender contained in this
Section 8.05 shall survive the payment in full of principal, interest and all
other amounts payable hereunder and under the other Loan Documents.

         SECTION 8.06. SUCCESSOR AGENTS. (a) The Administrative Agent may resign
at any time by giving written notice thereof to the Lenders and the Borrower and
may be removed at any time with or without cause by the Required Lenders. Upon
any such resignation or removal, the Required Lenders shall have the right to
appoint a successor Administrative Agent. If no successor Administrative Agent
shall have been so appointed by the Required Lenders, and shall have accepted
such appointment, within 30 days after the retiring Administrative Agent's
giving of notice of resignation or the Required Lenders' removal of the retiring
Administrative Agent, then the retiring Administrative Agent may, on behalf of
the Lenders, appoint a successor Administrative Agent, which shall be a
commercial bank organized under the laws of the United States or of any State
thereof and having a combined capital and surplus of at least $1,000,000,000.
Upon the acceptance of any appointment as Administrative Agent hereunder by a
successor Administrative Agent such successor Administrative Agent shall succeed
to and become vested with all the rights, powers, discretion, privileges and
duties of the retiring Administrative Agent, and the retiring Administrative
Agent shall be discharged from its duties and obligations under

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the Loan Documents. After any retiring Administrative Agent's resignation or
removal hereunder as Administrative Agent, the provisions of this Article VII
shall inure to its benefit as to any actions taken or omitted to be taken by it
while it was Administrative Agent under this Agreement.

         (b) The Collateral Agent may resign at any time by giving written
notice thereof to the Lenders and the Borrower and may be removed at any time
with or without cause by the Required Lenders. Upon any such resignation or
removal, the Required Lenders shall have the right to appoint a successor
Collateral Agent. If no successor Collateral Agent shall have been so appointed
by the Required Lenders, and shall have accepted such appointment, within 30
days after the retiring Collateral Agent's giving of notice of resignation or
the Required Lenders' removal of the retiring Collateral Agent, then the
retiring Collateral Agent may, on behalf of the Lenders, appoint a successor
Collateral Agent, which shall be a commercial bank organized under the laws of
the United States or of any State thereof and having a combined capital and
surplus of at least $1,000,000,000. Upon the acceptance of any appointment as
Collateral Agent hereunder by a successor Collateral Agent such successor
Collateral Agent shall succeed to and become vested with all the rights, powers,
discretion, privileges and duties of the retiring Collateral Agent, and the
retiring Collateral Agent shall be discharged from its duties and obligations
under the Loan Documents. After any retiring Collateral Agent's resignation or
removal hereunder as Collateral Agent, the provisions of this Article VIII shall
inure to its benefit as to any actions taken or omitted to be taken by it while
it was Collateral Agent under this Agreement.

         SECTION 8.07. INTERCREDITOR ARRANGEMENTS. (a) The Tranche A Secured
Parties and the Tranche B Secured Parties agree that the Collateral shall be
held by the Collateral Agent, in its capacity as such, on behalf of the Secured
Parties. The Lien of the Tranche A Mortgage, the Liens created under the Tranche
A Borrower Security Agreement, the Liens created under the Tranche A Enterprises
Pledge Agreement) and all liens and security interests created or evidenced
thereby (collectively, the "TRANCHE A LIEN") are hereby made and shall continue
to be junior, subject, and subordinate in all respects to, respectively, the
Lien of the Tranche B Mortgage, the Liens created under the Tranche B Borrower
Security Agreement, the Liens created under the Tranche B Enterprises Pledge
Agreement and all Liens and security interests created or evidenced thereby
(collectively, the "TRANCHE B LIEN") including, without limitation, after the
occurrence and during the continuance of a Default or an Event of Default. So
long as any Tranche B Obligations remain outstanding, the Tranche B Secured
Parties shall have the right to vote and instruct the Collateral Agent to act
with respect to the Collateral secured by the Tranche B Lien and the Tranche A
Lien. Once the Tranche B Obligations have been repaid in full in cash,

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the Tranche A Secured Parties shall have the right to so vote and instruct. Any
proceeds received as a result of any sale, lease, transfer or other disposition
in respect of the Collateral first shall be applied to repay the Tranche B
Obligations in full in cash, and thereafter, shall be applied to repay any
outstanding Tranche A Obligations. Each Tranche A Secured Party agrees not to
enforce or exercise any right or remedy in respect of the Collateral, or take or
receive from the Borrower or the Collateral Agent, directly or indirectly, in
cash or other property or by set-off or in any other manner, whether pursuant to
any judicial or non-judicial enforcement, collection, execution, levy or
foreclosure proceedings or otherwise, including by deed in lieu of foreclosure,
any Collateral or any part or proceeds thereof or interest therein, in each case
unless and until all Tranche B Obligations have been paid in full in cash.

         (b) The provisions of Section 8.07(a) shall apply, notwithstanding the
availability of other Collateral to the Agents or Lenders or the actual date and
time of execution, delivery, recordation, filing or perfection of the Loan
Documents, or the Liens created thereby, and notwithstanding the fact that the
Tranche B Obligations are or any claim for the Tranche B Obligations is
subordinated, avoided, disallowed or otherwise deemed unenforceable, in whole or
in part, under the Federal Bankruptcy Code or other applicable federal, state or
local law. In the event of a proceeding, whether voluntary or involuntary, for
insolvency, liquidation, reorganization, dissolution, bankruptcy or other
similar proceeding pursuant to the Federal Bankruptcy Code or other applicable
federal or state law, the amounts due under the Tranche B Obligations shall be
deemed to include all interest and breakage costs accrued on the Tranche B
Obligations, in accordance with and at the rates specified in the Loan
Documents, both for periods before and for periods after the commencement of any
such proceedings, even if the claim for such interest is not allowed pursuant to
applicable law.

         SECTION 8.08. CO-ARRANGERS. The Co-Arrangers, in their capacity as
Co-Arrangers, assume no responsibility or obligation hereunder for servicing,
syndication, enforcement or collection of the Debt resulting from the Advances,
nor any duties as agent hereunder for the Lenders. The title of "Co-Arranger" is
solely honorific and implies no fiduciary responsibility on the part of any
Co-Arranger, in its capacity as such, to the Agents or any Lender and the use of
such title does not impose on any Co-Arranger any duties or obligations greater
than those of any other Lender or entitle any Co-Arranger to any rights other
than those to which any other Lender is entitled.

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                                   ARTICLE IX

                                  MISCELLANEOUS

         SECTION 9.01. AMENDMENTS, ETC. No amendment or waiver of any provision
of this Agreement, the Notes or any other Loan Document, nor consent to any
departure by the Borrower or any other Loan Party therefrom, shall in any event
be effective unless the same shall be in writing and signed (or, in the case of
the Collateral Documents, consented to) by (x) with respect to this Agreement,
the Sponsor Agreement the Select Power Purchase Agreement and the NU Guaranties,
the Required Lenders, (y) with respect to the Tranche A Collateral Documents,
the Tranche A Required Lenders, and (z) with respect to the Tranche B Collateral
Documents, the Tranche B Required Lenders, and then such waiver or consent shall
be effective only in the specific instance and for the specific purpose for
which given; PROVIDED, HOWEVER, that (a) no amendment, waiver or consent shall,
unless in writing and signed by all of the Lenders, do any of the following at
any time: (i) waive any of the conditions specified in Section 3.01 or 3.02,
(ii) change the number of Lenders or the percentage of (x) the Commitments, or
(y) the aggregate unpaid principal amount of the Advances, in each case,
required for the Lenders or any of them to take any action hereunder, (iii)
limit Northeast Utilities' liability with respect to its Obligations under the
Sponsor Agreement or the NU Guaranties or NU Enterprises' liability under the
Enterprises Pledge Agreement, (iv) release any material portion of the
Collateral in any transaction or series of related transactions or permit the
creation, incurrence, assumption or existence of any Lien on any item of
Collateral in any transaction or series of related transactions to secure any
Obligations other than Obligations owing to the Secured Parties under the Loan
Documents, (v) amend this Section 9.01, (vi) increase the Tranche A Commitments
of the Tranche A Lenders or the Tranche B Commitments of the Tranche B Lenders,
or increase the aggregate Commitments of the Lenders or subject the Lenders to
any additional Obligations, (vii) reduce the principal of, or interest on, the
Notes or any fees or other amounts payable hereunder, (viii) postpone any date
fixed for any payment of principal of, or interest on, the Notes or any fees or
other amounts payable hereunder, (ix) reduce the Commitments, (x) limit the
liability of any Loan Party under any of the Loan Documents, (xi) modify the
second priority status of the Tranche A Collateral Documents or the
intercreditor arrangements set forth in Section 9.07 or (xi) modify or extend
the payment terms of the Select Power Purchase Agreement; and PROVIDED FURTHER
that no amendment, waiver or consent shall, unless in writing and signed by the
Administrative Agent in addition to the Lenders required above to take such
action, affect the rights or duties of the Administrative Agent under this
Agreement and that no amendment, waiver or consent shall, unless in writing and
signed by the Collateral Agent in addition to the Lenders required above to take
such action, affect the rights or duties of the Collateral Agent under this
Agreement and that no amendment, waiver or consent shall, unless in writing and

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signed by the Depositary Bank in addition to the Lenders required above to take
such action, affect the rights or duties of the Depositary Bank under this
Agreement.

         SECTION 9.02. NOTICES, ETC. All notices and other communications
provided for hereunder shall be in writing (including telegraphic, telecopy or
telex communication) and mailed, telegraphed, telecopied, telexed or delivered,
if to the Borrower, at its address at 107 Seldon Street, Berlin Ct. 06037,
Attention: Treasurer, and with respect to all communications under Article 4
hereof, with copies to (i) Supervisor, Cash Management, and (ii) Emily
Campanelli, Corporate Accounting, in both cases at the same address; if to any
Initial Lender, at its Domestic Lending Office specified opposite its name on
Schedule I hereto; if to any other Lender, at its Domestic Lending Office
specified in the Assignment and Acceptance pursuant to which it became a Lender;
if to the Administrative Agent, at its address at 399 Park Avenue, New York, New
York 10043, Attention: Santiago Pardo with a copy to 2 Penns Way, Newcastle,
Delaware 19720, Attention: Bilal Aman; and if to the Collateral Agent and the
Depositary Bank, at its address at 111 Wall Street, New York, New York 10043,
Attention: Florence Mills; or, as to each party, at such other address as shall
be designated by such party in a written notice to the other parties. All such
notices and communications shall, when mailed, telegraphed, telecopied or
telexed, be effective when deposited in the mails, delivered to the telegraph
company, transmitted by telecopier or confirmed by telex answerback,
respectively, except that notices and communications to the Administrative Agent
pursuant to Article II, III or VII shall not be effective until received by the
Administrative Agent. Delivery by telecopier of an executed counterpart of any
amendment or waiver of any provision of this Agreement or the Notes or of any
Exhibit hereto to be executed and delivered hereunder shall be effective as
delivery of a manually executed counterpart thereof.

         SECTION 9.03. NO WAIVER; REMEDIES. No failure on the part of any
Lender, the Administrative Agent, the Collateral Agent or the Depositary Bank to
exercise, and no delay in exercising, any right hereunder, under any Note or
under any other Loan Document shall operate as a waiver thereof; nor shall any
single or partial exercise of any such right preclude any other or further
exercise thereof or the exercise of any other right. The remedies herein
provided are cumulative and not exclusive of any remedies provided by law.

         SECTION 9.04. COSTS, EXPENSES, INDEMNIFICATION. (a) The Borrower agrees
to pay on demand (i) all reasonable costs and expenses of the Administrative
Agent, the Collateral Agent and the Depositary Bank in connection with the
preparation, execution, delivery, modification and amendment of the Loan
Documents (including, without limitation, (A) all due diligence, collateral
review,

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transportation, computer, duplication, appraisal, audit, insurance, consultant,
search, filing and recording fees and expenses and (B) the reasonable fees and
expenses of counsel for the Administrative Agent, the Collateral Agent and the
Depositary Bank with respect thereto, with respect to advising each of the
Administrative Agent, the Collateral Agent or the Depositary Bank, as the case
may be, as to its rights and responsibilities, or the perfection, protection or
preservation of rights or interests, under the Loan Documents, with respect to
negotiations with any Loan Party or with other creditors of any Loan Party,
arising out of any Default and with respect to presenting claims in or otherwise
participating in or monitoring any bankruptcy, insolvency or other similar
proceeding involving creditors' rights generally and any proceeding ancillary
thereto) and (ii) all reasonable costs and expenses of the Administrative Agent,
the Collateral Agent, the Depositary Bank and the Lenders in connection with the
enforcement of the Loan Documents, whether in any action, suit or litigation,
any bankruptcy, insolvency or other similar proceeding affecting creditors'
rights generally (including, without limitation, the reasonable fees and
expenses of counsel for the Administrative Agent, the Collateral Agent, the
Depositary Bank and each Lender with respect thereto).

         (b) The Borrower agrees to indemnify and hold harmless the
Administrative Agent, the Collateral Agent, the Depositary Bank, each Lender and
each of their Affiliates and their officers, directors, employees, agents and
advisors (each, an "INDEMNIFIED PARTY") from and against any and all claims,
damages, losses, liabilities and expenses (including, without limitation,
reasonable fees and expenses of counsel) that may be incurred by or asserted or
awarded against any Indemnified Party, in each case arising out of or in
connection with or by reason of (including, without limitation, in connection
with any investigation, litigation or proceeding or preparation of a defense in
connection therewith) (i) the Notes, this Agreement, the other Loan Documents or
any of the transactions contemplated hereby or thereby or (ii) the actual or
alleged presence of Hazardous Materials on any property described in the
Mortgages or any Environmental Action relating in any way to any Loan Party or
any of its Subsidiaries, except to the extent such claim, damage, loss,
liability or expense is found in a final, non-appealable judgment by a court of
competent jurisdiction to have resulted directly or indirectly from such
Indemnified Party's gross negligence or willful misconduct. In the case of an
investigation, litigation or other proceeding to which the indemnity in this
Section 9.04(b) applies, such indemnity shall be effective whether or not such
investigation, litigation or proceeding is brought by any Loan Party, its
directors, shareholders or creditors or an Indemnified Party or any Indemnified
Party is otherwise a party thereto and whether or not the transactions
contemplated hereby are consummated. The Borrower also agrees not to assert any
claim against the Administrative Agent, the Collateral Agent, the Depositary
Bank, any Lender

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or any of their Affiliates, or any of their respective officers, directors,
employees, attorneys and agents, on any theory of liability, for special,
indirect, consequential or punitive damages arising out of or otherwise relating
to this Agreement, the actual or proposed use of the proceeds of the Advances,
the other Loan Documents or any of the transactions contemplated hereby or
thereby.

         (c) If any payment of principal of, or Conversion of, any Eurodollar
Rate Advance is made by the Borrower to or for the account of a Lender other
than on the last day of the Interest Period for such Advance, as a result of a
payment or Conversion pursuant to Section 2.05, 2.08(b)(i) or 2.09(d),
acceleration of the maturity of the Notes pursuant to Section 9.01 or for any
other reason, the Borrower shall, upon demand by such Lender (with a copy of
such demand to the Administrative Agent), pay to the Administrative Agent for
the account of such Lender any amounts required to compensate such Lender for
any additional losses, costs or expenses that it may reasonably incur as a
result of such payment, including, without limitation, any loss (including loss
of anticipated profits), cost or expense incurred by reason of the liquidation
or reemployment of deposits or other funds acquired by any Lender to fund or
maintain such Advance.

         (d) If any Loan Party fails to pay when due any costs, expenses or
other amounts payable by it under any Loan Document, including, without
limitation, fees and expenses of counsel and indemnities, such amount may be
paid on behalf of such Loan Party by the Administrative Agent, the Collateral
Agent, the Depositary Bank or any Lender, in its sole discretion; PROVIDED,
HOWEVER, that such Loan Party's Obligations to pay such amounts remain unchanged
and such payment by any such Lender, the Collateral Agent, the Depositary Bank
or the Administrative Agent in no way excuses such Loan Party from such
Obligations.

         (e) Without prejudice to the survival of any other agreement of any
Loan Party hereunder or under any other Loan Document, the agreements and
obligations of the Borrower contained in Sections 2.09, 2.11 and 9.05 and this
Section 9.04 shall survive the payment in full of principal, interest and all
other amounts payable hereunder and under any of the other Loan Documents.

         SECTION 9.05. RIGHT OF SET-OFF. Upon (a) the occurrence and during the
continuance of any Event of Default and (b) the making of the request or the
granting of the consent specified by Section 7.01 to authorize the
Administrative Agent to declare the Notes due and payable pursuant to the
provisions of Section 7.01, each Lender and each of its respective Affiliates is
hereby authorized at any time and from time to time, to the fullest extent
permitted by law, to set off and otherwise apply any and all deposits (general
or special, time or demand, provisional or

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final) at any time held and other indebtedness at any time owing by such Lender
or such Affiliate to or for the credit or the account of the Borrower against
any and all of the Obligations of the Borrower now or hereafter existing under
this Agreement and the Note or Notes (if any) held by such Lender, irrespective
of whether such Lender shall have made any demand under this Agreement or such
Note or Notes and although such obligations may be unmatured. Each Lender agrees
promptly to notify the Borrower after any such set-off and application;
PROVIDED, HOWEVER, that the failure to give such notice shall not affect the
validity of such set-off and application. The rights of each Lender and its
respective Affiliates under this Section are in addition to other rights and
remedies (including, without limitation, other rights of set-off) that such
Lender and its respective Affiliates may have.

         SECTION 9.06. BINDING EFFECT. This Agreement shall become effective
when it shall have been executed by the Borrower, the Administrative Agent, the
Collateral Agent and the Depositary Bank and when the Administrative Agent shall
have been notified by each Initial Lender that such Initial Lender has executed
it and thereafter shall be binding upon and inure to the benefit of the
Borrower, the Administrative Agent, the Collateral Agent, the Depositary Bank
and each Lender and their respective successors and assigns, except that the
Borrower shall not have the right to assign its rights hereunder or any interest
herein without the prior written consent of the Lenders.

         SECTION 9.07. ASSIGNMENTS AND PARTICIPATIONS. (a) Each Lender may
assign to one or more Eligible Assignees all or a portion of its rights and
obligations under this Agreement (including, without limitation, all or a
portion of its Commitment or Commitments, the Advances owing to it and the Note
or Notes held by it); PROVIDED, HOWEVER, that (i) each such assignment shall be
of a uniform, and not a varying, percentage of all rights and obligations under
and in respect of the Tranche A Commitment or the Tranche B Commitment, as the
case may be, (ii) except in the case of an assignment to a Person that,
immediately prior to such assignment, was a Lender or all of a Lender's rights
and obligations under this Agreement, the aggregate amount of the Tranche A
Commitment and outstanding Tranche A Advances or Tranche B Commitment and
outstanding Tranche B Advances of the assigning Lender being assigned pursuant
to each such assignment (determined as of the date of the Assignment and
Acceptance with respect to such assignment) shall in no event be less than
$10,000,000 with respect to such Tranche A Commitment and $10,000,000 with
respect to such Tranche B Commitment, (iii) each such assignment shall be to an
Eligible Assignee, and (iv) the parties to each such assignment shall execute
and deliver to the Administrative Agent, for its acceptance and recording in the
Register, an Assignment and Acceptance, together with any Note or Notes subject
to such assignment and a processing and recordation fee of $4,000 payable by the
Eligible Assignee.

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         (b) Upon such execution, delivery, acceptance and recording, from and
after the effective date specified in such Assignment and Acceptance, (i) the
assignee thereunder shall be a party hereto and, to the extent that rights and
obligations hereunder have been assigned to it pursuant to such Assignment and
Acceptance, have the rights and obligations of a Lender hereunder and (ii) the
Lender assignor thereunder shall, to the extent that rights and obligations
hereunder have been assigned by it pursuant to such Assignment and Acceptance,
relinquish its rights, except such rights as survive termination of this
Agreement, and be released from its obligations under this Agreement (and, in
the case of an Assignment and Acceptance covering all or the remaining portion
of an assigning Lender's rights and obligations under this Agreement, such
Lender shall cease to be a party hereto).

         (c) By executing and delivering an Assignment and Acceptance, the
Lender assignor thereunder and the assignee thereunder confirm to and agree with
each other and the other parties hereto as follows: (i) other than as provided
in such Assignment and Acceptance, such assigning Lender makes no representation
or warranty and assumes no responsibility with respect to any statements,
warranties or representations made in or in connection with this Agreement or
any other Loan Document or the execution, legality, validity, enforceability,
genuineness, sufficiency or value of, or the perfection or priority of any lien
or security interest created or purported to be created under or in connection
with, this Agreement or any other Loan Document or any other instrument or
document furnished pursuant hereto or thereto; (ii) such assigning Lender makes
no representation or warranty and assumes no responsibility with respect to the
financial condition of the Borrower or any other Loan Party or the performance
or observance by any Loan Party of any of its obligations under any Loan
Document or any other instrument or document furnished pursuant thereto; (iii)
such assignee confirms that it has received a copy of this Agreement, together
with copies of the financial statements referred to in Section 5.01 and such
other documents and information as it has deemed appropriate to make its own
credit analysis and decision to enter into such Assignment and Acceptance; (iv)
such assignee will, independently and without reliance upon the Administrative
Agent, the Collateral Agent, such assigning Lender or any other Lender and based
on such documents and information as it shall deem appropriate at the time,
continue to make its own credit decisions in taking or not taking action under
this Agreement; (v) such assignee confirms that it is an Eligible Assignee; (vi)
such assignee appoints and authorizes the Administrative Agent and the
Collateral Agent, as the case may be, to take such action as agent on its behalf
and to exercise such powers and discretion under the Loan Documents as are
delegated to the Administrative

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Agent and the Collateral Agent, as the case may be, by the terms hereof,
together with such powers and discretion as are reasonably incidental thereto;
and (vii) such assignee agrees that it will perform in accordance with their
terms all of the obligations which by the terms of this Agreement are required
to be performed by it as a Lender.

         (d) The Administrative Agent shall maintain at its address referred to
in Section 9.02 a copy of each Assignment and Acceptance delivered to and
accepted by it and a register for the recordation of the names and addresses of
the Lenders and the Commitment of, and principal amount of the Advances owing
to, each Lender from time to time (the "REGISTER"). The entries in the Register
shall be conclusive and binding for all purposes, absent manifest error, and the
Borrower, the Administrative Agent, the Collateral Agent and the Lenders may
treat each Person whose name is recorded in the Register as a Lender hereunder
for all purposes of this Agreement. The Register shall be available for
inspection by the Collateral Agent, the Borrower or any Lender at any reasonable
time and from time to time upon reasonable prior notice.

         (e) Upon its receipt of an Assignment and Acceptance executed by an
assigning Lender and an assignee, together with any Note or Notes subject to
such assignment, the Administrative Agent shall, if such Assignment and
Acceptance has been completed and is in substantially the form of Exhibit C
hereto, (i) accept such Assignment and Acceptance, (ii) record the information
contained therein in the Register and (iii) give prompt notice thereof to the
Borrower. In the case of any assignment by a Lender, within five Business Days
after its receipt of such notice, the Borrower, at its own expense, shall
execute and deliver to the Administrative Agent in exchange for the surrendered
Note or Notes a new Note or Notes to the order of such Eligible Assignee in an
amount equal to the Commitment assumed by it pursuant to such Assignment and
Acceptance and, if the assigning Lender has retained a Commitment hereunder, a
new Note or Notes to the order of the assigning Lender in an amount equal to the
Commitment retained by it hereunder. Such new Tranche A Note or Tranche A Notes
shall be in an aggregate principal amount equal to the aggregate principal
amount of such surrendered Tranche A Note or Tranche A Notes, shall be dated the
effective date of such Assignment and Acceptance and shall otherwise be in
substantially the form of Exhibit A-1 hereto. Such new Tranche B Note or Tranche
B Notes shall be in an aggregate principal amount equal to the aggregate
principal amount of such surrendered Tranche B Note or Tranche B Notes, shall be
dated the effective date of such Assignment and Acceptance and shall otherwise
be in substantially the form of Exhibit A-2 hereto.

         (f) Each Lender may sell participations to one or more Persons (other
than any Loan Party or any of its Affiliates) in or to all or a portion of its
rights and obligations under this Agreement (including, without limitation, all
or a portion of its Commitments, the Advances owing to it and the Note or Notes
(if any) held by

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it); PROVIDED, HOWEVER, that (i) such Lender's obligations under this Agreement
(including, without limitation, its Commitments) shall remain unchanged, (ii)
such Lender shall remain solely responsible to the other parties hereto for the
performance of such obligations, (iii) such Lender shall remain the holder of
any such Note for all purposes of this Agreement, (iv) the Borrower, the
Administrative Agent, the Collateral Agent and the other Lenders shall continue
to deal solely and directly with such Lender in connection with such Lender's
rights and obligations under this Agreement and (v) no participant under any
such participation shall have any right to approve any amendment or waiver of
any provision of any Loan Document, or any consent to any departure by any Loan
Party therefrom, except to the extent that such amendment, waiver or consent
would reduce the principal of, or interest on, the Notes or any fees or other
amounts payable hereunder, in each case to the extent subject to such
participation, postpone any date fixed for any payment of principal of, or
interest on, the Notes or any fees or other amounts payable hereunder, in each
case to the extent subject to such participation, or release all or
substantially all of the Collateral.

         (g) Any Lender may, in connection with any assignment or participation
or proposed assignment or participation pursuant to this Section 9.07, disclose
to the assignee or participant or proposed assignee or participant, any
information relating to the Borrower or any other Loan Party furnished to such
Lender by or on behalf of the Borrower; PROVIDED, HOWEVER, that, prior to any
such disclosure, the assignee or participant or proposed assignee or participant
shall agree to preserve the confidentiality of any Confidential Information
received by it from such Lender.

         (h) Notwithstanding any other provision set forth in this Agreement,
any Lender may at any time create a security interest in all or any portion of
its rights under this Agreement (including, without limitation, the Advances
owing to it and the Note or Notes held by it) in favor of any Federal Reserve
Bank in accordance with Regulation A of the Board of Governors of the Federal
Reserve System.

         SECTION 9.08. EXECUTION IN COUNTERPARTS. This Agreement may be executed
in any number of counterparts and by different parties hereto in separate
counterparts, each of which when so executed shall be deemed to be an original
and all of which taken together shall constitute one and the same agreement.
Delivery of an executed counterpart of a signature page to this Agreement by
telecopier shall be effective as delivery of a manually executed counterpart of
this Agreement.

         SECTION 9.09. CONFIDENTIALITY. Neither the Administrative Agent, the
Collateral Agent, the Depositary Bank, any Lender nor any agents or
representatives thereof

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(each, a "DISCLOSING PARTY") shall disclose any Confidential Information to any
Person without the consent of the Borrower, other than (a) to the Administrative
Agent's, the Collateral Agent's or such Lender's Affiliates and their officers,
directors, employees, agents and advisors and to actual or prospective Eligible
Assignees and participants, and then only on a confidential basis, (b) as
required by any law, rule or regulation or judicial process, (c) as requested or
required by any state, federal or foreign authority or examiner regulating banks
or banking or (d) if advised by counsel of such Disclosing Party that such
disclosure is legally required.

         SECTION 9.10. JURISDICTION, ETC. (a) Each of the parties hereto hereby
irrevocably and unconditionally submits, for itself and its property, to the
nonexclusive jurisdiction of any New York State court or federal court of the
United States of America sitting in New York City, and any appellate court from
any thereof, in any action or proceeding arising out of or relating to this
Agreement or any of the other Loan Documents to which it is a party, or for
recognition or enforcement of any judgment, and each of the parties hereto
hereby irrevocably and unconditionally agrees that all claims in respect of any
such action or proceeding may be heard and determined in any such New York State
court or, to the extent permitted by law, in such federal court. Each of the
parties hereto agrees that a final judgment in any such action or proceeding
shall be conclusive and may be enforced in other jurisdictions by suit on the
judgment or in any other manner provided by law. Nothing in this Agreement shall
affect any right that any party may otherwise have to bring any action or
proceeding relating to this Agreement or any of the other Loan Documents in the
courts of any jurisdiction.

         (b) Each of the parties hereto irrevocably and unconditionally waives,
to the fullest extent it may legally and effectively do so, any objection that
it may now or hereafter have to the laying of venue of any suit, action or
proceeding arising out of or relating to this Agreement or any of the other Loan
Documents to which it is a party in any New York State or federal court. Each of
the parties hereto hereby irrevocably waives, to the fullest extent permitted by
law, the defense of an inconvenient forum to the maintenance of such action or
proceeding in any such court.

         SECTION 9.11. GOVERNING LAW. This Agreement and the Notes shall be
governed by, and construed in accordance with, the laws of the State of New
York.

         SECTION 9.12. WAIVER OF JURY TRIAL. Each of the Borrower, the
Administrative Agent, the Collateral Agent, the Depositary Bank and the Lenders
irrevocably waives all right to trial by jury in any action, proceeding or
counterclaim (whether based on contract, tort or otherwise) arising out of or
relating to any of the Loan Documents, the

                                       104
<PAGE>

Advances or the actions of the Administrative Agent, the Collateral Agent, the
Depositary Bank or any Lender in the negotiation, administration, performance or
enforcement thereof.

                                       105
<PAGE>

         IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed by their respective officers thereunto duly authorized, as of the date
first above written.

                                      BORROWER:
                                      ---------

                                         NORTHEAST GENERATION
                                         COMPANY



                                         By
                                           ------------------------------
                                           Name:
                                           Title:


                                      AGENTS:
                                      -------

                                         CITIBANK, N.A., as
                                         Administrative Agent



                                         By
                                           ------------------------------
                                           Name:
                                           Title:


                                         CITIBANK, N.A., as
                                         Collateral Agent and
                                         as Depositary Bank



                                         By
                                           ------------------------------
                                           Name:
                                           Title:

                                       106
<PAGE>

                                      TRANCHE A INITIAL LENDERS:
                                      --------------------------

                                         CITIBANK, N.A.



                                         By
                                           ------------------------------
                                           Name:
                                           Title:



                                         BARCLAYS BANK PLC



                                         By
                                           ------------------------------
                                           Name:
                                           Title:



                                         CANADIAN IMPERIAL BANK OF
                                         COMMERCE



                                         By
                                           ------------------------------
                                           Name:
                                           Title:



                                         TORONTO DOMINION (TEXAS), INC.



                                         By
                                           ------------------------------
                                           Name:
                                           Title:

                                       107
<PAGE>

                                      TRANCHE B INITIAL LENDERS:
                                      --------------------------

                                        CITIBANK, N.A.



                                       By
                                          -------------------------------
                                          Name:
                                          Title:



                                        BARCLAYS BANK PLC



                                       By
                                          -------------------------------
                                          Name:
                                          Title:



                                        CANADIAN IMPERIAL BANK OF
                                        COMMERCE



                                       By
                                          -------------------------------
                                          Name:
                                          Title:



                                        TORONTO DOMINION (TEXAS), INC.



                                       By
                                          -------------------------------
                                          Name:
                                          Title:



                                        MEESPIERSON CAPITAL CORP.



                                       By
                                          -------------------------------
                                          Name:
                                          Title:



                                        UNION BANK OF CALIFORNIA, N.A.



                                       By
                                          -------------------------------
                                          Name:
                                          Title:

                                       108




                                     SCHEDULE I

                     COMMITMENTS AND APPLICABLE LENDING OFFICES




Name of Initial Lender
Citibank, N.A.


Tranche A Commitment

US$108,875,000.00

Tranche B Commitment

US$71,666,666.67

Domestic Lending Office

Citibank, N.A.
399 Park Avenue
New York, NY 10043

Eurodollar Lending Office

Citibank, N.A.
399 Park Avenue
New York, NY 10043

Business / Credit Matters:

Citibank, N.A.
399 Park Avenue
New York, NY 10043
Attn: Santiago Pardo
Tel: (212) 559-3623
Fax: (212) 793-0092
email: santiago.pardo@citicorp.com

Administrative / Operations Matters:

Citibank, N.A.
2 Penns Way
Newcastle, Delaware
19720
Attn: Bilal Aman
Tel: (302) 894-6013
Fax: (302) 894-6120
email: bilal.aman@citicorp.com



Name of Initial Lender

Barclays Bank plc

Tranche A Commitment

US$108,875,000.00

Tranche B Commitment

US$71,666,666.67

Domestic Lending Office

Barclays Bank PLC
222 Broadway, 11th Floor
New York, NY 10038
Attn: Christine Francese
Tel: (212) 412-3721
Fax: (212) 412-5306
email: christine.francese@barclayscapital.com

Eurodollar Lending Office
Barclays Bank PLC
222 Broadway, 11th Floor
New York, NY 10038
Attn: Christine Francese
Tel: (212) 412-3721
Fax: (212) 412-5306
email: christine.francese@barclayscapital.com

Business / Credit Matters:

Barclays Bank PLC
222 Broadway, 8th Floor
New York, NY 10038
Attn: John Drake
Tel: (212) 412-1381
Fax: (212) 412-6709
email: john.drake@barclayscapital.com

Administrative / Operations Matters:

Barclays Bank PLC
222 Broadway, 11th
Floor
New York, NY 10038
Attn: Christine
Francese
Tel: (212) 412-3721
Fax: (212) 412-5306
email: christine.francese@barclayscapital.com

with a copy to:

Barclays Bank PLC
222 Broadway, 8th Floor
New York, NY 10038
Attn: Sydney Dennis
Tel: (212) 412-2470
Fax: (212) 412-6709
email: sydney.dennis@barclayscapital.com


Name of Initial Lender

Canadian Imperial Bank of Commerce

Tranche A Commitment

US$108,875,000.00

Tranche B Commitment

US$71,666,666.67

Domestic Lending Office

Canadian Imperial Bank of Commerce
Two Paces West
2727 Paces Ferry Road,
Suite 1200
Atlanta, GA 30339
Attn: Miriam McCart
Tel: (770) 319-4842
Fax: (770) 319-4950
email: mccamiri@us.cibc.com

Eurodollar Lending Office

Canadian Imperial Bank of Commerce
Two Paces West
2727 Paces Ferry Road,
Suite 1200
Atlanta, GA 30339
Attn: Miriam McCart
Tel: (770) 319-4842
Fax: (770) 319-4950
email: mccamiri@us.cibc.com

Business / Credit Matters:
CIBC World Markets
425 Lexington Avenue
New York, NY 10017
Attn: Eric Klaussmann
Tel: (212) 856-3828
Fax: (212) 885-4911
email: klaussma@us.cibc.com

with a copy to:

CIBC World Markets
C/O Utilities
Department
425 Lexington Avenue
New York, NY 10017
Attn: Jo Manger
Tel: (212) 856-3818
Fax: (212) 856-3799

Administrative / Operations Matters:
Canadian Imperial Bank
of Commerce
Two Paces West
2727 Paces Ferry Road,
Suite 1200
Atlanta, GA 30339
Attn: Beverly Bowman
Tel: (770) 319-4824
Fax: (770) 319-4950
email: bowmanbe@us.cibc.com

with a copy to:

Canadian Imperial Bank
of Commerce
Two Paces West
2727 Paces Ferry Road,
Suite 1200
Atlanta, GA 30339
Attn: Miriam McCart
Tel: (770) 319-4842
Fax: (770) 319-4950
email: mccamiri@us.cibc.com


Name of Initial Lender

Toronto Dominion (Texas), Inc.

Tranche A Commitment

US$108,875,000.00

Tranche B Commitment

US$71,666,666.67

Domestic Lending Office

Toronto Dominion
(Texas), Inc.
909 Fannin Street, 17th
Floor
Houston, TX 77010
Attn: Alva J. Jones
Tel: (713) 653-8261
Fax: (713) 951-9921
email: jonesa2@tdusa.com

Eurodollar Lending Office

Toronto Dominion
(Texas), Inc.
909 Fannin Street, 17th
Floor
Houston, TX 77010
Attn: Alva J. Jones
Tel: (713) 653-8261
Fax: (713) 951-9921
email: jonesa2@tdusa.com

Business / Credit Matters:

Toronto Dominion
Securities
31 West 52nd Street
New York, NY 10019-6101
Attn: Cori Novellino
Tel: (212) 827-7769
Fax: (212) 827-7244
email: novelc@tdusa.com

Administrative / Operations Matters:

The Toronto-Dominion Bank
909 Fannin Street, 17th
Floor
Houston, TX 77010
Attn: Alva J. Jones
Tel: (713) 653-8261
Fax: (713) 951-9921
email: jonesa2@tdusa.com



Name of Initial Lender

MeesPierson Capital Corp.

Tranche A Commitment

US$0US

Tranche B Commitment

$71,666,666.66

Domestic Lending Office

MeesPierson Capital Corp.
3 Stamford Plaza
301 Tresser Boulevard,
9th Floor
Stamford, CT 06901-3239
Attn: Marlene Ellis
Tel: (203) 705-5753
Fax: (203) 705-5888
email: mpe@meespiersonusa.com

Eurodollar Lending Office

MeesPierson Capital Corp.
3 Stamford Plaza
301 Tresser Boulevard,
9th Floor
Stamford, CT 06901-3239
Attn: Marlene Ellis
Tel: (203) 705-5753
Fax: (203) 705-5888
email: mpe@meespiersonusa.com

Business / Credit Matters:

MeesPierson Capital Corp.
3 Stamford Plaza
301 Tresser Boulevard,
9th Floor
Stamford, CT 06901-3239
Attn: Hendrik Vroege
Tel: (203) 705-5745
Fax: (203) 705-5890
email: hjv@meespiersonusa.com

with a copy to:

MeesPierson Capital Corp.
3 Stamford Plaza
301 Tresser Boulevard,
9th Floor
Stamford, CT 06901-3239
Attn: Christopher
McCall
Tel: (203) 705-5729
Fax: (203) 705-7919
email: cjm@meespiersonusa.com

Administrative / Operations Matters:
MeesPierson Capital Corp.
3 Stamford Plaza
301 Tresser Boulevard,
9th Floor
Stamford, CT 06901-3239
Attn: Marlene Ellis
Tel: (203) 705-5753
Fax: (203) 705-5888
email: mpe@meespiersonusa.com

with a copy to:

MeesPierson Capital Corp.
3 Stamford Plaza
301 Tresser Boulevard,
9th Floor
Stamford, CT 06901-3239
Attn: Peter Testa
Tel: (203) 705-5755
Fax: (203) 705-5888
email: pdt@meespiersonusa.com



Name of Initial Lender

Union Bank of California, N.A.


Tranche A Commitment

US$0

Tranche B Commitment

US$71,666,666.66

Domestic Lending Office

Union Bank of California, N.A.
Energy Capital Services
445 S. Figueroa Street,
15th Floor
Los Angeles, CA 90071
Attn: Jason DiNapoli
Tel: (213) 236-5016
Fax: (213) 236-4096
email: jason.dinapoli@uboc.com

Eurodollar Lending Office

Union Bank of California, N.A.
Energy Capital Services
445 S. Figueroa Street,
15th Floor
Los Angeles, CA 90071
Attn: Jason DiNapoli
Tel: (213) 236-5016
Fax: (213) 236-4096
email: jason.dinapoli@uboc.com

Business / Credit Matters:

Union Bank of California, N.A.
Energy Capital Services
445 S. Figueroa Street,
15th Floor
Los Angeles, CA 90071
Attn: Jason DiNapoli
Tel: (213) 236-5016
Fax: (213) 236-4096
email: jason.dinapoli@uboc.com

Administrative / Operations Matters:

Union Bank of California, N.A.
Commercial Loan
Operations
1980 Saturn Street
Monterey Park, CA 91754
Attn: Gohar Karapetyan
Tel: (323) 720-2679
Fax: (323) 724-6198

with a copy to:

Union Bank of
California, N.A.
Commercial Loan
Operations
1980 Saturn Street
Monterey Park, CA 91754
Attn: Ruby Gonzales
Tel: (323) 720-7055
Fax: (323) 724-6198

Total

$435,500,000.00

$430,000,000.00




                                      SCHEDULE 5
                                      Insurance


(A) Insurance by the Borrower: The Borrower shall procure at its own expense and
maintain in full force and effect throughout the term of this Agreement (unless
otherwise specified below) insurance policies with responsible insurance
companies with (i) a Best Insurance Reports rating of "A-" or better and an
financial size category of "IX" or higher, (ii) or a S & P financial strength
rating of ABBB+@ or higher, (iii) or other companies acceptable to the
Collateral Agent, with limits and coverage provisions sufficient to satisfy the
requirements set forth in each of the Project Documents, but in no event less
than the limits and coverage provisions set forth below.

(1) General Liability Insurance: Liability insurance on an occurrence basis,
except for claims made forms issued by the insurers AEGIS or EIM against claims
filed anywhere in the world and occurring anywhere in the world for the
Borrowers liability arising out of claims for personal injury (including bodily
injury and death) and property damage. Such insurance shall provide coverage for
products-completed operations, blanket contractual, broad form property damage,
personal injury insurance, independent contractors and sudden and accidental
pollution liability with a $100,000,000 minimum limit per occurrence for
combined bodily injury and property damage. A maximum deductible or self-insured
retention of $250,000 per occurrence shall be allowed.

(2) Automobile Liability Insurance: Automobile liability insurance for the
Borrowers liability arising out of claims for bodily injury and property damage
covering all owned (if any), leased, non-owned and hired vehicles of the
Borrower, including loading and unloading, with a $10,000,000 minimum limit per
accident for combined bodily injury and property damage and containing
appropriate no-fault insurance provisions wherever applicable. A maximum
deductible or self-insured retention of $125,000 per occurrence shall be
allowed.

(3) Aircraft Liability Insurance: If the performance of any of the Project
Documents requires the use of any aircraft that is owned, leased or chartered by
the Borrower, aircraft liability insurance insuring the Borrower with a
$25,000,000 minimum limit per occurrence for combined property damage and bodily
injury, including passengers and crew.

(4) Property Damage Insurance: Property insurance on an "all risk" basis
insuring the Borrower and the Secured Parties, as their interests may appear,
including coverage against damage or loss caused by earth movement (including
but not limited to earthquake, landslide, subsidence and volcanic eruption),
flood, turbine and machinery accidents.

(a) Property Insured: The property insurance shall provide coverage for (i) the
buildings, structures, turbine, machinery, equipment, facilities, fixtures,
supplies, fuel and other properties constituting a part of the Generating
Assets, (ii) steam and electrical transmission lines along with related
equipment for which the Borrower has an insurable interest, (iii) the cost of
recreating plans, drawings or any other documents or computer system records,
(iv) electronic equipment and (v) foundations and other property below the
surface of the ground.

(b) Additional Coverages: The property insurance shall insure (i) transit and
off-site repair including ocean marine and air transit, if applicable, with
sub-limits sufficient to insure the full replacement value of the property or
equipment prior to its being moved to or from the Generating Assets sites and
while located away from the Generating Assets sites, (ii) attorney's fees,
engineering and other consulting costs, and permit fees directly incurred in
order to repair or replace damaged insured property in a minimum amount of
$2,000,000, (iii) the cost of preventive measures to reduce or prevent a loss
(sue & labor) in an amount not less than $2,500,000, (iv) increased cost of
construction and loss to undamaged property as the result of enforcement of
building laws or ordinances with sub-limits not less than $15,000,000, (v)
debris removal with sub-limits not less than $5,000,000, (vi) expediting
expenses (defined as extraordinary expenses incurred after an insured loss to
make temporary repairs and expedite the permanent repair of the damaged property
in excess of the business interruption even if such expense does not reduce the
business interruption loss) in an amount not less than $5,000,000 and (vii) the
cleaning of civil works, channels, tunnels, equipment or other assets affected
by accidental events involving mud or water accumulation, falling rocks,
landslides and similar acts of nature that prevent the continuation of normal
activities, although no physical damage to the Generating Assets has occurred in
an amount not less than $2,000,000.

(c) Special Clauses: The property policy shall include a (i) 72 hour clause for
flood, windstorm and earthquakes, (ii) unintentional errors and omissions
clause, (iii) requirement that the insurer pay losses within 30 days after
receipt of an acceptable proof of loss or partial proof of loss and (iv) other
insurance clause making this insurance primary over any other insurance.

(d) Sum Insured: Losses shall be valued at their repair or replacement cost,
without deductible for physical depreciation or obsolescence. The property
damage policy shall insure the Generating Assets in an amount not less than
$150,000,000 per occurrence. The earth movement and flood coverage may be
insured with a sub-limit not less than $150,000,000."

(e)  Deductibles:  The property damage insurance may have deductibles of not
greater than $1,000,000 per occurrence.

(f) Prohibited Exclusions: The property damage policy shall not contain any (i)
coinsurance provision, (ii) exclusion for loss or damage resulting from
freezing, mechanical breakdown, (iii) exclusion for loss or damage covered under
any guarantee or warranty arising out of an insured peril, (iv) exclusion for
resultant damage caused by ordinary wear and tear, gradual deterioration, normal
subsidence, settling cracking, expansion or contraction or (v) a faulty
workmanship, design or materials exclusion substantially different from the DE-5
or LEG-3 exclusions.

(5) Business Interruption Insurance: Business interruption insurance insuring
the Borrower and the Secured Parties, as their interests may appear, covering
100% of the Borrowers continuing normal operating expenses including payroll and
debt service for a period of 12 months, arising from loss required to be insured
by Section(A)(4) above.

Such insurance shall (a) have a deductible no greater than 60 days per
occurrence, (b) include for a period of 2 months that portion of fixed expenses
and debt service not earned arising from an insured loss or occurrence at the
premises of any service (electricity, water, gas, etc.) supplier and the
premises of any purchaser of electricity, (c) cover loss sustained when access
to the Generating Assets sites is prevented due to an insured peril at premises
in the vicinity of the Generating Assets sites, (d) cover loss sustained due to
the action of a public authority preventing access to the Generating Assets
sites due to imminent or actual loss or destruction arising from an insured
peril at premises in the vicinity of the Generating Assets sites and (e) include
an clause allowing interim payments on account pending finalization of the claim
payment. Such insurance shall not contain any coinsurance clause or include a
waiver of such clause.

(6) Fidelity: Fidelity insurance providing coverage for employee dishonesty
including theft, computer funds transfer fraud, alteration and forgery insuring
loss of money, securities or other property resulting from any fraudulent or
dishonest act committed by the Borrowers employees, whether acting alone or in
collusion with others in an amount not less than $5,000,000.

(7)  Endorsements: All policies of liability insurance required to be maintained
by the Borrower shall be endorsed as follows:

(a) To name the Secured Parties and their respective officers and employees (and
such other Persons as may be required by the Project Documents) as additional
insureds;

(b)  To provide a severability of interests and cross liability clause;

(c) That the insurance shall be primary and not excess to or contributing with
any insurance or self-insurance maintained by the Secured Parties.

(8) Waiver of Subrogation: The Borrower hereby waives any and every claim for
recovery from the Secured Parties for any and all loss or damage covered by any
of the insurance policies to be maintained under this Agreement to the extent
that such loss or damage is recovered under any such policy. Inasmuch as the
foregoing waiver will preclude the assignment of any such claim to the extent of
such recovery, by subrogation (or otherwise), to an insurance company (or other
person), the Borrower shall give written notice of the terms of such waiver to
each insurance company which has issued, or which may issue in the future, any
such policy of insurance (if such notice is required by the insurance policy)
and shall cause each such insurance policy to be properly endorsed by the issuer
thereof to, or to otherwise contain one or more provisions that, prevent the
invalidation of the insurance coverage provided thereby by reason of such
waiver.

(B)  Amendment of Requirements:

(1) Amendment by the Required Lenders: The Required Lenders may at any time
amend the requirements of this Schedule 5 due to (i) new information not known
by the Lenders as of the date of this Agreement and which poses a material risk
to the Generating Assets or (ii) changed circumstances after the date of this
Agreement which in the reasonable judgment of the Required Lenders renders such
coverage materially inadequate.

(2) Amendment Due To Commercial Unfeasibility: In the event any insurance
(including the limits or deductibles thereof) hereby required to be maintained
shall not be reasonably available and commercially feasible in the commercial
insurance market, the Required Lenders shall not unreasonably withhold their
agreement to waive such requirement to the extent the maintenance thereof is not
so available; provided, however, that (i) the Borrower shall first request any
such waiver in writing, which request shall be accompanied by a written report
prepared by the Insurance Consultant, certifying that such insurance is not
reasonably available and commercially feasible (and, in any case where the
required amount is not so available, certifying as to the maximum amount which
is so available) and explaining in detail the basis for such conclusions; (ii)
at any time after the granting of any such waiver, but not more often than once
a year, the Required Lenders may request, and the Borrower shall furnish to the
Required Lenders within fifteen (15) days after such request, supplemental
reports reasonably acceptable to the Required Lenders from the Insurance
Consultant updating their prior report and reaffirming such conclusion; and
(iii) any such waiver shall be effective only so long as such insurance shall
not be reasonable available and commercially feasible in the commercial
insurance market, it being understood that the failure of the Borrower to timely
furnish any such supplemental report shall be conclusive evidence that such
waiver is no longer effective because such condition no longer exists, but that
such failure is not the only way to establish such non-existence. The failure at
any time to satisfy the condition to any waiver of an insurance requirement set
forth in the proviso to the preceding sentence shall not impair or be construed
as a relinquishment of the Borrower's ability to obtain a waiver of an insurance
requirement pursuant to the preceding sentence at any other time upon
satisfaction of such conditions. For the purposes of this sub-section insurance
will be considered not reasonably available and commercially feasible if it is
obtainable only at excessive costs which are not justified in terms of the risk
to be insured and is generally not being carried by or applicable to independent
power producers with operations similar to the Borrower because of such
excessive costs.

(C)  Conditions:

(1) Loss Notification: The Borrower shall promptly notify the Collateral Agent
of any single loss or event likely to give rise to a claim against an insurer
for an amount in excess of $1,000,000 covered by any insurance maintained
pursuant to Sections (A)(4) and (5).

(2) Payment of Loss Proceeds: All policies of insurance required to be
maintained pursuant to Sections (A)(4) and (5), shall provide that the proceeds
of such policies shall be payable solely to the Collateral Agent pursuant to a
standard first mortgage endorsement substantially equivalent to the Lenders Loss
Payable Endorsement 438BFU or ISO endorsement CP12181091 without contribution.

(3) Loss Adjustment and Settlement: A loss under any insurance required to be
carried under Sections (A)(4) and (5), shall be adjusted with the insurance
companies, including the filing in a timely manner of appropriate proceedings,
by the Borrower, subject to the approval of the Required Lenders if such loss is
in excess of $10,000,000. In addition the Borrower may in its reasonable
judgment consent to the settlement of any loss, provided that in the event that
the amount of the loss exceeds $10,000,000 the terms of such settlement is
concurred with by the Required Lenders.

(4) Policy Cancellation and Change: All policies of insurance required to be
maintained pursuant to this Schedule 5 shall be endorsed so that if at any time
should they be canceled, or coverage be reduced (by any party including the
insured) which affects the interests of the Secured Parties, such cancellation
or reduction shall not be effective as to the Secured Parties for 60 days,
except for non-payment of premium which shall be for 10 days, after receipt by
the Collateral Agent of written notice from such insurer of such cancellation or
reduction.

(5) Miscellaneous Policy Provisions: All policies of insurance required to be
maintained pursuant to Sections (A)(4) and (5), shall (i) not include any annual
or term aggregate limits of liability or clause requiring the payment of
additional premium to reinstate the limits after loss except as regards the
insurance applicable to the perils of flood, earth movement, sabotage and
terrorism, (ii) shall include the Secured Parties as additional insureds as
their interests may appear, and (iii) include a clause requiring the insurer to
make final payment on any claim within 30 days after the submission of proof of
loss and its acceptance by the insurer.

(6) Separation of Interests: All policies (other than in respect to liability or
workers compensation insurance) shall insure the interests of the Secured
Parties regardless of any breach or violation by the Borrower or any other party
of warranties, declarations or conditions contained in such policies, any action
or inaction of the Borrower or others, or any foreclosure relating to the
Generating Assets or any change in ownership of all or any portion of the
Generating Assets.

(7) Acceptable Policy Terms and Conditions: All policies of insurance required
to be maintained pursuant to this Schedule 5 shall contain terms and conditions
reasonably acceptable to the Required Lenders after consultation with the
Insurance Consultant.

(8) Waiver of Subrogation: All policies of insurance to be maintained by the
provisions of this Schedule 5 shall provide for waivers of subrogation in favor
of the Secured Parties and their respective officers and employees (and such
other Persons as may be required by the Project Documents).

(D) Evidence of Insurance: As of the Borrowing Date and on an annual basis at
least 10 days prior to each policy anniversary, the Borrower shall furnish the
Collateral Agent with (1) certificates of insurance or binders, in a form
acceptable to the Collateral Agent, evidencing all of the insurance required by
the provisions of this Schedule 5 and (2) a schedule of the insurance policies
held by or for the benefit of the Borrower and required to be in force by the
provisions of this Schedule 5. Such certificates of insurance/binders shall be
executed by each insurer or by an authorized representative of each insurer
where it is not practical for such insurer to execute the certificate itself.
Such certificates of insurance/binders shall identify underwriters, the type of
insurance, the insurance limits and the policy term and shall specifically list
the special provisions enumerated for such insurance required by this Schedule
5. Upon request, the Borrower will promptly furnish the Collateral Agent with
copies of all insurance policies, binders and cover notes or other evidence of
such insurance relating to the insurance required to be maintained by the
Borrower. The schedule of insurance shall include the name of the insurance
company, policy number, type of insurance, major limits of liability and
expiration date of the insurance policies.

(E) Reports: Prior to the expiration date of any required insurance policy, the
Borrower shall deliver to the Collateral Agent and the Insurance Consultant a
certificate of the Borrower stating that all insurance required to be maintained
by this Schedule 5 is in full force and effect, accompanied on each Broker
Reporting Date (as defined below) by a report or reports from the Borrower's
insurance brokers or agents that taken together show with reasonable specificity
the existence of all insurance required to be maintained by this Schedule 5
(including the scope and amount of coverage provided by, and the deductibles and
exclusions under, each required policy), and that all such insurance is then in
full force and effect and all premiums have been paid in full. The Collateral
Agent shall have the right to review copies of all policies providing the
coverage required by this Schedule 5. For the purposes of this Schedule 5,
"Broker Reporting Date" shall mean (i) any date upon which the Borrower has
renewed an insurance policy but with a different insurer, and (ii) any date upon
which an insurance policy is renewed and incorporates any changes (other than
changes of an administrative nature) from the previous corresponding insurance
policy.

The Borrower shall promptly notify the Collateral Agent of (i) any dispute with
an insurer that the Borrower, acting reasonably, considers material and might
adversely affect the payment of a claim under any policy of insurance required
to be maintained under this Schedule 5 or the ability of the Borrower to
maintain in effect any such required policy, (ii) the cancellation (or
notification concerning proposed cancellation) of any policy prior to its stated
term, (iii) the non-payment of any premium when due, (iv) the failure by the
Borrower, for any reason, to maintain in full force and effect any insurance
required by this Schedule 5, (v) any material change (other than increases in
scope of coverage) in any insurance coverage maintained by the Borrower, (vi)
any actual or, upon obtaining knowledge thereof, potential event of loss in
excess of $1,000,000 covered by such insurance, and (vii) any other information
relating to the insurance required by this Schedule 5 that may be reasonably
requested by any Lender or the Collateral Agent.

(F) Failure to Maintain Insurance: In the event the Borrower fails to take out
or maintain the full insurance coverage required by this Schedule 5, the
Collateral Agent, upon 30 days' prior notice (unless the aforementioned
insurance would lapse within such period, in which event notice should be given
as soon as reasonably possible) to the Borrower of any such failure, may (but
shall not be obligated to) take out the required policies of insurance and pay
the premiums on the same. All amounts so advanced thereof by the Collateral
Agent shall become an additional obligation of the Borrower to the Collateral
Agent, and the Borrower shall forthwith pay such amounts to the Collateral
Agent, together with interest thereon at the interest rate set forth in Section
2.06(b) of the Agreement from the date so advanced.

(G) No Duty of Collateral Agent to Verify or Review: No provision of this
Schedule 5 or any provision of this Agreement, any Acquisition Document or any
Project Document shall impose on the Collateral Agent any duty or obligation to
verify the existence or adequacy of the insurance coverage maintained by the
Borrower, nor shall the Collateral Agent be responsible for any representations
or warranties made by or on behalf of the Borrower to any insurance company or
underwriter. Any failure on the part of the Collateral Agent to pursue or obtain
the evidence of insurance required by this Agreement from the Borrower and/or
failure of the Collateral Agent to point out any non-compliance of such evidence
of insurance shall not constitute a waiver of any of the insurance requirements
in this Agreement.

(H) Maintenance of Insurance: The Borrower shall at all times maintain the
insurance coverage required under the terms of the Project Documents.

(I) Liability for Failure to Maintain Insurance: Failure to secure the requisite
insurance coverages, to comply fully with any of the provisions of this Schedule
5, or to secure such endorsements on the policies as may be necessary to carry
out the terms and provisions of this Schedule 5, shall in no way act to relieve
the Borrower from its obligations under this Schedule 5. In the event that
liability for loss or damage is denied by the underwriter(s), in full or in
part, because of breach of said insurance policies by the Borrower, or if the
Borrower fails to maintain any of the insurance herein required, the Borrower
shall hold harmless and indemnify the Secured Parties and the Agents against all
claims, demands, costs and expenses, including reasonable attorney's fees, which
would otherwise be covered by said insurance. The Borrower's indemnification
obligations under this Agreement (express or implied) shall not be limited to
the amount or scope of coverage provided by insurance which is required under
this Schedule 5.

(J) Insurance Consultant. The Borrower shall reimburse the Lenders from time to
time for the reasonable fees and expenses of the Insurance Consultant appointed
by the Required Lenders (a) to advise the Lenders with respect to the initial
contents of this Schedule 5, and the compliance by the Borrower on the Borrowing
Date with the applicable requirements of this Schedule 5, (b) if requested by
the Required Lenders, to review for compliance with the requirements of this
Schedule 5 any insurance policies or certificates with respect thereto delivered
to or made available by the Borrower pursuant to this Schedule 5, and (c) if
requested by the Required Lenders, to advise the Lenders as to whether any
change in this Schedule 5 as then in effect requested by the Borrower satisfied
the applicable requirements of this Schedule 5.





                        EXHIBIT A-1 TO THE CREDIT AGREEMENT


                        FORM OF TRANCHE A PROMISSORY NOTE

$               Dated:  , 200


FOR VALUE RECEIVED, the undersigned, Northeast Generation Company, a Connecticut
corporation (the "Borrower"), HEREBY PROMISES TO PAY
                        (the "Lender") for the account of its Applicable
Lending Office (as defined in the Credit Agreement referred to below) the
principal amount of the Tranche A Advance (as defined below) owing to the Lender
by the Borrower pursuant to the Credit Agreement dated as of March 9, 2000 (as
amended, supplemented or otherwise modified from time to time, the "Credit
Agreement"; terms defined therein being used herein as therein defined) among
the Borrower, the Lender and certain other Lenders party thereto, and Citibank,
N.A. ("Citibank"), as Administrative Agent for the Lender and such other
Lenders, as Collateral Agent for the Secured Parties and as Depositary Bank, on
the Tranche A Maturity Date.

The Borrower promises to pay interest on the unpaid principal amount of the
Tranche A Advance from the date of the Tranche A Advance until such principal
amount is paid in full, at such interest rates, and payable at such times, as
are specified in the Credit Agreement.

Both principal and interest are payable in lawful money of the United States of
America to Citibank, as Administrative Agent, at the Administrative Agent's
Account, in immediately available funds. The Tranche A Advance owing to the
Lender by the Borrower and all payments made on account of principal thereof,
shall be recorded by the Lender and, prior to any transfer hereof, endorsed on
the grid attached hereto, which is part of this Tranche A Promissory Note.

This Promissory Note is one of the Notes referred to in, and is entitled to the
benefits of, the Credit Agreement. The Credit Agreement, among other things, (i)
provides for the making of an advance (the "Tranche A Advance") by the Lender to
the Borrower in an amount not to exceed the U.S. dollar amount first above
mentioned, the indebtedness of the Borrower resulting from the Tranche A Advance
being evidenced by this Promissory Note, and (ii) contains provisions for
acceleration of the maturity hereof upon the happening of certain stated events.
The obligations of the Borrower under this Promissory Note, and the obligations
of the other Loan Parties under the Loan Documents, are secured by the
Collateral as provided in the Loan Documents.

NORTHEAST GENERATION COMPANY

By
     Name:
     Title:



                   TRANCHE A ADVANCE AND PAYMENTS OF PRINCIPAL





Date

Amount of Tranche A Advance

Amount of Principal Paid

Unpaid Principal Balance

Notation Made By







                       EXHIBIT A-2 TO THE CREDIT AGREEMENT


                        FORM OF TRANCHE B PROMISSORY NOTE


$
Dated:            , 2000

FOR VALUE RECEIVED, the undersigned, Northeast Generation Company, a Connecticut
corporation (the "Borrower"), HEREBY PROMISES TO PAY
                         (the "Lender") for the account of its Applicable
Lending Office (as defined in the Credit Agreement referred to below) the
principal amount of the Tranche B Advance (as defined below) owing to the Lender
by the Borrower pursuant to the Credit Agreement dated as of March 9, 2000 (as
amended, supplemented or otherwise modified from time to time, the "Credit
Agreement"; terms defined therein being used herein as therein defined) among
the Borrower, the Lender and certain other Lenders party thereto, and Citibank,
N.A. ("Citibank"), as Administrative Agent for the Lender and such other
Lenders, as Collateral Agent for the Secured Parties and as Depositary Bank, on
the Tranche B Maturity Date.

The Borrower promises to pay interest on the unpaid principal amount of the
Tranche B Advance from the date of the Tranche B Advance until such principal
amount is paid in full, at such interest rates, and payable at such times, as
are specified in this Agreement.

Both principal and interest are payable in lawful money of the United States of
America to Citibank, as Administrative Agent, at the Administrative Agent's
Account, in immediately available funds. The Tranche B Advance owing to the
Lender by the Borrower, and all payments made on account of principal thereof,
shall be recorded by the Lender and, prior to any transfer hereof, endorsed on
the grid attached hereto, which is part of this Tranche B Promissory Note.

This Promissory Note is one of the Notes referred to in, and is entitled to the
benefits of, the Credit Agreement. The Credit Agreement, among other things, (i)
provides for the making of an advance (the "Tranche B Advance") by the Lender to
the Borrower in an amount not to exceed the U.S. dollar amount first above
mentioned, the indebtedness of the Borrower resulting from the Tranche B Advance
being evidenced by this Promissory Note, and (ii) contains provisions for
acceleration of the maturity hereof upon the happening of certain stated events
and also for prepayments on account of principal hereof prior to the maturity
hereof upon the terms and conditions therein specified. The obligations of the
Borrower under this Promissory Note, and the obligations of the other Loan
Parties under the Loan Documents, are secured by the Collateral as provided in
the Loan Documents.

NORTHEAST GENERATION COMPANY

By
     Name:
     Title:







                     TRANCHE B ADVANCE AND PAYMENTS OF PRINCIPAL



Date

Amount of Tranche B Advance

Amount of Principal Paid or Prepaid

Unpaid Principal Balance

Notation Made By







                          EXHIBIT B TO THE CREDIT AGREEMENT

                            FORM OF NOTICE OF BORROWING



Citibank, N.A., as Administrative Agent
under the Credit Agreement
  referred to below

                                     [Date]


Attention:


Ladies and Gentlemen:

The undersigned, Northeast Generation Company, refers to the Credit Agreement
dated as of March 9, 2000 (as amended, supplemented or otherwise modified from
time to time, the "Credit Agreement", the terms defined therein being used
herein as therein defined), among the undersigned, certain Lenders party
thereto, and Citibank, N.A., as Administrative Agent for said Lenders and
Collateral Agent for the Secured Parties and Depositary Bank, and hereby gives
you notice, irrevocably, pursuant to Section 2.02 of the Credit Agreement that
the undersigned hereby requests two Borrowings under the Credit Agreement, and
in that connection sets forth below the information relating to such Borrowings
(the "Proposed Borrowing") as required by Section 2.02(a) of the Credit
Agreement:

(i)  The Business Day of the Proposed Borrowing is               , 2000.

(ii)  The aggregate amount of the Tranche A Borrowing is $     and of the
Tranche B Borrowing is $       .

(iii)  The Type of Advances comprising the Proposed Tranche B Borrowing
is [Base Rate Advances] [Eurodollar Rate Advances].

(iv)  The aggregate amount of the Proposed Borrowing is $         .

[(v) The initial Interest Period for each Eurodollar Rate Advance made as part
of the Proposed Tranche B Borrowing is month[s].]

The undersigned hereby certifies that the following statements are true on the
date hereof, and will be true on the date of the Proposed Borrowing:

(A) the representations and warranties contained in each Loan Document are
correct on and as of the date of the Proposed Borrowing, before and after giving
effect to the Proposed Borrowing and to the application of the proceeds
therefrom, as though made on and as of such date; and

(B) no event has occurred and is continuing, or would result from such Proposed
Borrowing or from the application of the proceeds therefrom, that constitutes a
Default.


Very truly yours,

NORTHEAST GENERATION COMPANY



By
     Name:
     Title:









                        EXHIBIT C TO THE CREDIT AGREEMENT


                        FORM OF ASSIGNMENT AND ACCEPTANCE


Reference is made to the Credit Agreement dated as of March 9, 2000 (as amended,
supplemented or otherwise modified from time to time, the "Credit Agreement")
among Northeast Generation Company, a Connecticut corporation (the "Borrower"),
the Lenders (as defined in the Credit Agreement) and Citibank, N.A., as
administrative agent for the Lenders (the "Administrative Agent"), as Collateral
Agent for the Secured Parties and as Depositary Bank. Terms defined in the
Credit Agreement are used herein with the same meaning.

The "Assignor" and the "Assignee" referred to on Schedule 1 hereto agree as
follows:

1. The Assignor hereby sells and assigns to the Assignee, and the Assignee
hereby purchases and assumes from the Assignor, an interest in and to the
Assignor's rights and obligations under the Credit Agreement as of the date
hereof equal to the percentage interests specified on Schedule 1 hereto of all
outstanding rights and obligations under the Credit Agreement. After giving
effect to such sale and assignment, the Assignee's Commitments and the amount of
the Advances owing to the Assignee will be as set forth on Schedule 1 hereto.

2. The Assignor (i) represents and warrants that it is the legal and beneficial
owner of the interest being assigned by it hereunder and that such interest is
free and clear of any adverse claim; (ii) makes no representation or warranty
and assumes no responsibility with respect to any statements, warranties or
representations made in or in connection with the Loan Documents or the
execution, legality, validity, enforceability, genuineness, sufficiency or value
of, or the perfection or priority of any lien or security interest created or
purported to be created under or in connection with, the Loan Documents or any
other instrument or document furnished pursuant thereto; and (iii) makes no
representation or warranty and assumes no responsibility with respect to the
financial condition of any Loan Party or the performance or observance by any
Loan Party of any of its obligations under any Loan Document or any other
instrument or document furnished pursuant thereto; and (iv) attaches the Note or
Notes held by the Assignor and requests that the Administrative Agent exchange
such Note or Notes for a new Note or Notes payable to the order of the Assignee
in an amount equal to the Commitments assumed by the Assignee pursuant hereto or
new Notes payable to the order of the Assignee in an amount equal to the
Commitments assumed by the Assignee pursuant hereto and the Assignor in an
amount equal to the Commitments retained by the Assignor under this Agreement,
respectively, as specified on Schedule 1 hereto.

3. The Assignee (i) confirms that it has received a copy of the Credit
Agreement, together with copies of the financial statements referred to in
Section 5.01 thereof and such other documents and information as it has deemed
appropriate to make its own credit analysis and decision to enter into this
Assignment and Acceptance; (ii) agrees that it will, independently and without
reliance upon the Administrative Agent, the Collateral Agent, the Assignor or
any other Lender and based on such documents and information as it shall deem
appropriate at the time, continue to make its own credit decisions in taking or
not taking action under the Credit Agreement; (iii) confirms that it is an
Eligible Assignee; (iv) appoints and authorizes the Administrative Agent and the
Collateral Agent (as the case may be) to take such action as agent on its behalf
and to exercise such powers and discretion under the Loan Documents as are
delegated to the Administrative Agent and the Collateral Agent, respectively, by
the terms thereof, together with such powers and discretion as are reasonably
incidental thereto; (v) agrees that it will perform in accordance with their
terms all of the obligations that by the terms of the Credit Agreement are
required to be performed by it as a Lender; and (vi) attaches any U.S. Internal
Revenue Service forms required under Section 2.11 of the Credit Agreement.

4. Following the execution of this Assignment and Acceptance, it will be
delivered to the Administrative Agent for acceptance and recording by the
Administrative Agent. The effective date for this Assignment and Acceptance (the
"Effective Date") shall be the date of acceptance hereof by the Administrative
Agent, unless otherwise specified on Schedule 1 hereto.

5. Upon such acceptance and recording by the Administrative Agent, as of the
Effective Date, (i) the Assignee shall be a party to the Credit Agreement and,
to the extent provided in this Assignment and Acceptance, have the rights and
obligations of a Lender thereunder and (ii) the Assignor shall, to the extent
provided in this Assignment and Acceptance, relinquish its rights and be
released from its obligations under the Credit Agreement.

6. Upon such acceptance and recording by the Administrative Agent, from and
after the Effective Date, the Administrative Agent shall make all payments under
the Credit Agreement and the Notes in respect of the interest assigned hereby
(including, without limitation, all payments of principal, interest and
commitment fees with respect thereto) to the Assignee. The Assignor and Assignee
shall make all appropriate adjustments in payments under the Credit Agreement
and the Notes for periods prior to the Effective Date directly between
themselves.

7.  This Assignment and Acceptance shall be governed by, and construed
in accordance with, the laws of the State of New York.

8. This Assignment and Acceptance may be executed in any number of counterparts
and by different parties hereto in separate counterparts, each of which when so
executed shall be deemed to be an original and all of which taken together shall
constitute one and the same agreement. Delivery of an executed counterpart of
Schedule 1 to this Assignment and Acceptance by telecopier shall be effective as
delivery of a manually executed counterpart of this Assignment and Acceptance.


IN WITNESS WHEREOF, the Assignor and the Assignee have caused Schedule 1 to this
Assignment and Acceptance to be executed by their officers thereunto duly
authorized as of the date specified thereon.


                    SCHEDULE 1 to ASSIGNMENT AND ACCEPTANCE

Percentage interest in Tranche A assigned: %

Percentage interest in Tranche B assigned: %

Assignee's Tranche A Commitment:          $

Assignee's Tranche B Commitment:          $

Aggregate outstanding principal amount of Tranche A Advances assigned: $

Aggregate outstanding principal amount of Tranche B Advances assigned: $

Principal amount of Tranche A Note payable to Assignee: $

Principal amount of Tranche B Note payable to Assignee: $

Assignor's Tranche A Commitment:          $

Assignor's Tranche B Commitment:          $

Principal amount of Tranche A Note payable to Assignor: $__________

Principal amount of Tranche B Note payable to Assignor: $

Effective Date (if other than date of acceptance by Administrative Agent): **
This date should be no earlier than five Business Days after the delivery of
this Assignment and Acceptance to the Administrative Agent. ,
200

[NAME OF ASSIGNOR], as Assignor

By
     Name:
     Title:

Dated:       , 200


[NAME OF ASSIGNEE], as Assignee

By
     Name:
     Title:

Dated:                  , 200

Domestic Lending Office:


Eurodollar Lending Office:


Accepted ** Required if the Assignee is an Eligible Assignee solely by reason of
clause (vii) the definition of Eligible Assignee.[and Approved] this day of ,
200



CITIBANK, N.A. as Administrative Agent


By

    Name

    Title


*[Approved this day of          , 200


NORTHEAST GENERATION COMPANY


By

    Name

    Title:]






                        EXHIBIT J TO THE CREDIT AGREEMENT


                         FORM OF SOLVENCY CERTIFICATE OF
                            [NAME OF COMPANY]

I, the undersigned, [Name Officer], in my capacity as Chief Financial Officer of
[Name of Company], a corporation (the "Company"), am duly authorized to execute
and deliver and make the representations and certifications made in this
Certificate and DO HEREBY CERTIFY on behalf of the Company that:

1. This certificate is hereby delivered on behalf of the Company pursuant to
Section 3.01(m)(xiv) of the Credit Agreement dated as of March 9, 2000 (as
further amended, supplemented or otherwise modified from time to time, the
"Credit Agreement") among Northeast Generation Company, certain banks, financial
institutions and other institutional lenders from time to time party thereto
(the "Lenders") and Citibank, N.A., as Administrative Agent, Collateral Agent
and Depositary Bank. Capitalized terms not otherwise defined in this Certificate
shall have the same meanings as specified therefor in the Credit Agreement.

2. I am knowledgeable and generally familiar with the properties, businesses,
prospects, financial condition and assets of the Company and have carefully
reviewed the Loan Documents, the Project Documents and the Acquisition Documents
and the contents of this Certificate and, in connection herewith, have reviewed
such other documentation and information and have made such investigations and
inquiries of the Company and directors and employees of the Company that are
necessary and prudent for a proper investigation.

3. The financial information and assumptions that underlie and form the basis
for the representations and certifications made in this Certificate were made in
good faith and were reasonable when made and continue to be reasonable as of the
date of this Certificate.

4. The Company understands that the Agents and the Lenders are relying upon the
truth and accuracy of this Certificate in connection with the transactions
contemplated by the Loan Documents, the Project Documents and the Acquisition
Documents.

5. On the date of this Certificate, immediately before and immediately after
giving pro forma effect to the [WMECO/CL&P] Acquisition and the transactions
contemplated by the Project Documents and the Acquisition Documents to occur on
or prior to the date of this Certificate, the fair value of the property and
assets of the Company is greater than the total amount of liabilities
(including, without limitation, contingent, subordinated, absolute, fixed,
matured or unmatured and liquidated or unliquidated liabilities) of the Company.

6. On the date of this Certificate, immediately before and immediately after
giving pro forma effect to the [WMECO/CL&P] Acquisition and the transactions
contemplated by the Project Documents and the Acquisition Documents to occur on
or prior to the date of this Certificate, the present fair saleable value of the
property and assets of the Company is not less than the amount that will be
required to pay the probable liability of the Company on its debts as they
become absolute and matured.

7. On the date of this Certificate, immediately before and immediately after
giving pro forma effect to the [WMECO/CL&P] Acquisition and the transactions
contemplated by the Project Documents and the Acquisition Documents to occur on
or prior to the date of this Certificate, the Company is not insolvent and the
Company will not be rendered insolvent by the transactions contemplated by the
Acquisition Documents and the Project Documents.

8. The Company has not incurred, nor does it intend to, and does not believe
that it will, incur debts or liabilities beyond its ability to pay such debts
and liabilities as they mature.

9. On the date of this Certificate, immediately before and immediately after
giving pro forma effect to the [WMECO/CL&P] Acquisition and the transactions
contemplated by the Project Documents and the Acquisition Documents to occur on
or prior to the date of this Certificate, the Company is not engaged in business
or a transaction, and is not about to engage in business or a transaction, for
which its property and assets would constitute an unreasonably small capital.

10. The Company does not intend, in consummating the [WMECO/CL&P] Acquisition
and the transactions contemplated by the Acquisition Documents and the Project
Documents to occur on or prior to the date of this Certificate, to hinder, delay
or defraud either present or future creditors or any other Person to which the
Company is or, on or after the date of this Certificate, will become indebted.

11.  In reaching the conclusions set forth in this Certificate, the
Company has considered, among other things:

(a) the cash and other current assets of the Company reflected in the
Consolidated balance sheet and pro forma statements of income of the Company and
its Subsidiaries after giving effect to the [WMECO/CL&P] Acquisition and the
transactions contemplated by the Acquisition Documents and the Project Documents
[and reflecting the estimated purchase price accounting adjustments prepared by
independent public accountants];

(b) all of the unliquidated and contingent liabilities of the Company,
including, without limitation, any claims arising out of pending or, to the best
knowledge of the undersigned, threatened litigation against the Company or any
of its property and assets and, in so doing, the Company has computed the amount
of each such unliquidated or contingent liability as the amount that, in light
of all of the facts and circumstances existing on the date of this Certificate,
represents the amount that can reasonably be expected to become an actual or
matured liability;

(c) all of the obligations and liabilities of the Company, whether matured or
unmatured, liquidated or unliquidated, disputed or undisputed, secured or
unsecured, subordinated, absolute, fixed or contingent, including, without
limitation, any claims arising out of pending or, to the best knowledge of the
undersigned, threatened litigation against the Company or any of its property
and assets;

(d)  historical and anticipated growth in the sales volume of the
Company and in the income stream generated by the Company;

(e)  the customary sales terms and the trade payables and other accounts
payable of the Company;

(f)  the amount of the credit extended to customers and by suppliers of
the Company; and

(g) the level of capital customarily maintained by the Company and, to the
extent that the Company has knowledge thereof, other entities engaged in the
same or a similar business as the businesses of the Company.

Delivery of an executed signature page to this Certificate by telecopier shall
be effective as delivery of a manually executed signature page hereof.

IN WITNESS WHEREOF, the Company has caused this Certificate to be executed by
its Chief Financial Officer thereunto duly authorized on this March , 2000.


[NAME OF COMPANY]


By
Name:
Title: Chief Financial Officer

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.54.1
<SEQUENCE>11
<FILENAME>0011.txt
<DESCRIPTION>EXHIBIT 10.54.1
<TEXT>




                        AMENDMENT NO. 1


                   dated as of July 27, 2000

                              To

                      CREDIT AGREEMENT

                   dated as of March 9, 2000

                            Among

                  NORTHEAST GENERATION COMPANY
                          as Borrower

                             and

                    THE LENDERS NAMED HEREIN
                          as Lenders

                            and

                       CITIBANK, N.A.
                   as Administrative Agent

                            and

                       CITIBANK, N.A.
                     as Collateral Agent

                            and

                        CITIBANK, N.A.
                      as Depositary Bank




AMENDMENT NO. 1 TO THE
CREDIT AGREEMENT


Dated as of July 27, 2000

AMENDMENT NO. 1 to the CREDIT AGREEMENT among NORTHEAST GENERATION COMPANY, a
Connecticut corporation (the "Borrower"), the banks, financial institutions and
other institutional lenders parties to the Credit Agreement referred to below
(collectively, the "Lenders") and CITIBANK, N.A., as administratve agent (the
"Administrative Agent") for the Lenders, collateral agent for the Secured
Parties (the "Collateral Agent") and the depositary bank (the "Depositary
Bank").

PRELIMINARY STATEMENTS:

(1) The Borrower, the Lenders, the Administrative Agent, the Collateral Agent,
and the Depositary Bank have entered into a Credit Agreement dated as of March
9, 2000 (the "Credit Agreement"). Capitalized terms not otherwise defined in
this Amendment have the same meanings as specified in the Credit Agreement.

(2) The Borrower has requested that the Credit Agreement be amended as
hereinafter set forth.

(3) The Lenders, the Administrative Agent, the Collateral Agent, and the
Depositary Bank are, on the terms and conditions stated below, willing to grant
the request of the Borrower.

Amendments to Credit Agreement

The Credit Agreement is, effective as of the date hereof and subject to the
satisfaction of the conditions precedent set forth in Section 2, hereby amended
as follows:

(a) The definition of "Excess Cash Flow" in Section 1.01 is amended by adding,
in the sixth line thereof after the phrase "Cash Flow Payment Date" the
following: "(provided, however that in the case of the November 12, 2000 Excess
Cash Flow Payment Date, the period used to measure Excess Cash Flow shall be the
period from August 1, 2000 to October 31, 2000)".

(b) The definition of "Excess Cash Flow Payment Date" in Section 1.01 is amended
by deleting the date "November 1, 2000" at the end thereof and substituting the
date "November 12, 2000".

(c)  Section  2.05(iv) is amended by adding at the end thereof before the
period, the following:

"; provided however that the amount, if any, of Available Excess Cash Flow which
is in excess of ten million U.S. dollars (10,000,000 dollars) and which
otherwise would be required to be used to prepay Advances together with accrued
and unpaid interest under this subsection on the August 1, 2000 Excess Cash Flow
Payment Date shall instead be used to prepay Advances together with accrued and
unpaid interest on September 12, 2000.

Conditions of Effectiveness

This Amendment shall become effective as of the date first above written when,
and only when the Administrative Agent shall have received counterparts of this
Amendment executed by the Borrower, the Lenders, the Collateral Agent, and the
Depositary Bank, together with the consent attached hereto executed by the
Sponsor. This Amendment is subject to the provisions of Section 9.01 of the
Credit Agreement.

Reference to and Effect on the Credit Agreement and the Notes

(a) On and after the effectiveness of this Amendment, each reference in the
Credit Agreement to "this Agreement", "hereunder", "hereof" or words of like
import referring to the Credit Agreement, and each reference in the Notes to
"the Credit Agreement", "thereunder", "thereof" or words of like import
referring to the Credit Agreement, shall mean and be a reference to the Credit
Agreement, as amended by this Amendment.

(a) The Credit Agreement and the Notes as specifically amended by this
Amendment, are and shall continue to be in full force and effect and are hereby
in all respects ratified and confirmed.

(a) The execution, delivery and effectiveness of this Amendment shall not,
except as expressly provided herein, operate as a waiver of any right, power or
remedy of any Lender, or the Administrative Agent, the Collateral Agent, or the
Depositary Bank under the Credit Agreement, nor constitute a waiver of any
provision of the Credit Agreement.

Costs.

The Borrower agrees to pay on demand all costs and expenses of the
Administrative Agent in connection with the preparation, execution and delivery
of this Amendment and the other instruments and documents to be delivered
hereunder (including, without limitation, the reasonable fees and expenses of
counsel for the Administrative Agent) in accordance with the terms of Section
9.04 of the Credit Agreement.

Execution in Counterparts

This Amendment may be executed in any number of counterparts and by different
parties hereto in separate counterparts, each of which when so executed shall be
deemed to be an original and all of which taken together shall constitute but
one and the same agreement. Delivery of an executed counterpart of a signature
page to this Amendment by telecopier shall be effective as delivery of a
manually executed counterpart of this Amendment.

Governing Law

This Amendment shall be governed by, and construed in accordance with, the laws
of the State of New York.

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed
by their respective officers thereunto duly authorized, as of the date first
above written.

NORTHEAST GENERATION COMPANY

By
Title:


CITIBANK, N.A.,
as Administrative Agent

By
Title:


CITIBANK, N.A.
As Collateral Agent and as Depositary Bank

By
Title:


Lenders:

CITIBANK, N.A.

By
Name:
Title:

BARCLAYS BANK PLC

By:
Name:
Title:

CANADIAN IMPERIAL BANK OF COMMERCE

By
Name:
Title:

TORONTO DOMINION (TEXAS), INC.

By:
Name:
Title:


FORTIS CAPITAL CORP.

(formerly MeesPierson Capital Corp.)

By:
Name:
Title:

UNION BANK OF CALIFORNIA, N.A..

By:
Name:
Title:

BANK ONE, NA

By:
Name:
Title:


CONSENT


Dated as of  July 27, 2000


The undersigned, Northeast Utilities, a Massachusetts voluntary association with
reference to the Sponsor Agreement, dated as of March 9, 2000 (the "Sponsor
Agreement") in favor of the Administrative Agent and the Lenders parties to the
Credit Agreement referred to in the foregoing Amendment, hereby consents to such
Amendment and hereby confirms and agrees that (a) notwithstanding the
effectiveness of such Amendment, the Sponsor Agreement is, and shall continue to
be, in full force and effect and is hereby ratified and confirmed in all
respects, except that, on and after the effectiveness of such Amendment, each
reference in the Sponsor Agreement to the "Credit Agreement", "thereunder",
"thereof" or words of like import and to the Notes "thereunder", "thereof", or
words of like import shall mean and be a reference to the Credit Agreement and
the Notes respectively, as amended by such Amendment.


NORTHEAST UTILITIES

By
Name:
Title:
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.54.2
<SEQUENCE>12
<FILENAME>0012.txt
<DESCRIPTION>EXHIBIT 10.54.2
<TEXT>



                          AMENDMENT NO. 2


                  dated as of November 22, 2000

                               To

                        CREDIT AGREEMENT

                     dated as of March 9, 2000

                             Among

                  NORTHEAST GENERATION COMPANY
                           as Borrower

                              and

                   THE LENDERS NAMED HEREIN
                           as Lenders

                             and

                       CITIBANK, N.A.
                  as Administrative Agent

                            and

                        CITIBANK, N.A.
                     as Collateral Agent

                            and

                       CITIBANK, N.A.
                     as Depositary Bank





AMENDMENT NO. 2 TO THE
CREDIT AGREEMENT


Dated as of November 22, 2000

AMENDMENT NO. 2 to the CREDIT AGREEMENT among NORTHEAST GENERATION COMPANY, a
Connecticut corporation (the "Borrower"), the banks, financial institutions and
other institutional lenders parties to the Credit Agreement referred to below
(collectively, the "Lenders") and CITIBANK, N.A., as administrative agent (the
"Administrative Agent") for the Lenders, collateral agent for the Secured
Parties (the "Collateral Agent") and the depositary bank (the "Depositary
Bank").

PRELIMINARY STATEMENTS:

(1) The Borrower, the Lenders, the Administrative Agent, the Collateral Agent,
and the Depositary Bank have entered into a Credit Agreement dated as of March
9, 2000, as amended by Amendment No 1 dated as of July 27, 2000 (the "Credit
Agreement"). Capitalized terms not otherwise defined in this Amendment have the
same meanings as specified in the Credit Agreement.

(2) The Borrower has requested that the Credit Agreement be amended as
hereinafter set forth.

(3) The Lenders, the Administrative Agent, the Collateral Agent, and the
Depositary Bank are, on the terms and conditions stated below, willing to grant
the request of the Borrower.

SECTION 1.  Amendments to Credit Agreement

The Credit Agreement is, effective as of the date hereof and subject to the
satisfaction of the conditions precedent set forth in Section 2 of this
amendment, hereby amended as follows:

(a) The definition of "Annual Operating Budget" in Section 1.01 is amended by
adding the following after the words "attached as Exhibit I hereto," in the
second line thereof:

"or the annual budget for the Borrower for Fiscal Year 2001 delivered pursuant
to Section 6.03(q) hereto and reasonably acceptable in form and substance to the
Lenders or as provided for in such section if no such budget has been so
delivered, as appropriate, in each case

(b) The definition of "Excess Cash Flow" in Section 1.01 is deleted in its
entirety and replaced with the following:

"shall mean for any Excess Cash Flow Payment Date, the excess of (a) all cash
receipts of the Borrower (including, but not limited to Revenues, but excluding
Net Cash Proceeds) actually received by the Borrower during the period from the
prior Excess Cash Flow Payment Date (or the Borrowing Date with respect to the
first Excess Cash Flow Payment Date) to the date immediately prior to such
Excess Cash Flow Payment Date; provided however that in the case of the November
12, 2000 Excess Cash Flow Payment Date, the period used to measure Excess Cash
Flow shall be the period from August 1, 2000 to October 31, 2000, in the case of
the February 12, 2001 Excess Cash Flow Payment Date, the period used to measure
Excess Cash Flow shall be the period from November 1, 2000 to January 31, 2001,
in the case of the May 12, 2001 Excess Cash Flow Payment Date, the period used
to measure Excess Cash Flow shall be the period from February 1, 2001 to April
30, 2001, and if the Tranche B Maturity Date is extended to September 28, 2001
as provided in Amendment No. 2 to the Credit Agreement, in the case of the
August 12, 2001 Excess Cash Flow Payment Date, the period used to measure Excess
Cash Flow shall be the period from May 1, 2001 to July 31, 2001 over (b) the sum
(without duplication) of (i) Operating Costs and Permitted Capital Expenditures
paid during such period and (ii) Obligations (other than mandatory prepayments
pursuant to Section 2.05(b) hereof and payments of interest in respect thereof
pursuant to Section 2.06 hereof) arising under the Loan Documents paid during
such period. For purposes of this definition, cash receipts shall exclude, to
the extent included, any insurance proceeds deposited into the Casualty
Account.".

(c) The definition of "Excess Cash Flow Payment Date" in Section 1.01 is amended
by deleting "and November 12, 2000" at the end thereof and substituting
",November 12, 2000, February 12, 2001, May 12, 2001, and if the Tranche B
Maturity Date is extended to September 28, 2001 as provided in Amendment No. 2
to the Credit Agreement herein, August 12, 2001".

(d) The definition of "Tranche B Maturity Date" in Section 1.01 is deleted in
its entirety and replaced with the following:

"means June 29, 2001";

provided however that if and only if the conditions precedent
referred to in      Section 3 of this Amendment are satisfied;

The definition of Tranche B Maturity Date in Section 1.01 shall be deleted in
its entirety and replaced with the following:

"means September 28, 2001."

(e)  Section 6.03 is amended by adding at the end thereof a new
subsection (q) to read as follows:

"Delivery of 2001 Annual Operating Budget. It will deliver to the Administrative
Agent, by December 1, 2000, an annual operating budget for Fiscal Year 2001 in
the form of the Annual Operating Budget for Fiscal Year 2000 and in substance
reasonably acceptable to the Lenders (the "2001 Annual Operating Budget");
provided however that should a 2001 Annual Operating Budget in form and
substance reasonably acceptable to the Lenders not be delivered to the
Administrative Agent by January 1, 2001, then until it is, for each of January
and February, 2001 the Annual Operating Budget for December, 2000 shall be
followed, and for each month from March to September, 2001, the Annual Operating
Budget for the corresponding month in the budget for Fiscal Year 2000 shall be
followed.".

SECTION 2.  Conditions of Effectiveness

This Amendment shall become effective as of the date first above written when,
and only when the Administrative Agent shall have received (i) on behalf of each
Lender, an amendment fee equal to .15 percent of the outstanding Tranche B
Advances owing to such Lender; (ii) copies of an amendment to the Tranche B
Mortgage reflecting an extension of the Tranche B Maturity Date until September
28, 2001 duly executed by the Borrower, together with (a) evidence that (1)
counterparts of such amendments to the Mortgages have been duly recorded in all
filing or recording offices that the Collateral Agent may deem appropriate and
(2) all filing and recording taxes and fees in respect thereof have been paid
and (b) such confirmation from the Title Companies as shall be satisfactory to
the Collateral Agent that the recording of such amendments to the mortgages does
not impair the validity, enforceability, or priority of the lien of the
mortgages; and (iii) counterparts of this Amendment executed by the Borrower,
the Lenders, the Collateral Agent and the Depositary Bank, together with the
consent attached hereto executed by the Sponsor provided that no Default or
Event of Default shall have occurred and be continuing at such time. This
Amendment is subject to the provisions of Section 9.01 of the Credit Agreement.
If the aforementioned conditions are not satisfied on or before November 22,
2000, then this amendment shall terminate and have no further effect other than
Section 5 and Section 7.

SECTION 3.  Conditions to Further Extension

The Tranche B Maturity Date shall be further extended to September 28, 2001
effective as of June 22, 2001, as set forth in Section 1 above, if and only if
(i) no Default or Event of Default shall have occurred and be continuing on June
22, 2001, (ii) prior to June 22, 2001 the Administrative Agent shall have
received on behalf of each Lender, an amendment fee equal to .10 percent of the
outstanding Tranche B Advances owing to such Lender on the date such fee is
paid, and (iii) the Administrative Agent shall have received, by May 30, 2001,
notice of the Borrower's intent to extend the Tranche B Maturity Date to
September 28, 2001.

SECTION 4.  Reference to and Effect on the Credit Agreement and
            the Notes

(a) On and after the effectiveness of this Amendment, each reference in the
Credit Agreement to "this Agreement", "hereunder", "hereof" or words of like
import referring to the Credit Agreement, and each reference in the Notes to
"the Credit Agreement", "thereunder", "thereof" or words of like import
referring to the Credit Agreement, shall mean and be a reference to the Credit
Agreement, as amended by this Amendment.

(b) The Credit Agreement and the Notes as specifically amended by this
Amendment, are and shall continue to be in full force and effect and are hereby
in all respects ratified and confirmed.

(c) The execution, delivery and effectiveness of this Amendment shall not
operate as a waiver of any right, power or remedy of any Lender, or the
Administrative Agent, the Collateral Agent, or the Depositary Bank under the
Credit Agreement, nor constitute a waiver of any provision of the Credit
Agreement.

SECTION 5.  Costs.

The Borrower agrees to pay on demand all costs and expenses of the
Administrative Agent in connection with the preparation, execution and delivery
of this Amendment and the other instruments and documents to be delivered
hereunder (including, without limitation, the reasonable fees and expenses of
counsel for the Administrative Agent) in accordance with the terms of Section
9.04 of the Credit Agreement.

SECTION 6.  Execution in Counterparts

This Amendment may be executed in any number of counterparts and by different
parties hereto in separate counterparts, each of which when so executed shall be
deemed to be an original and all of which taken together shall constitute but
one and the same agreement. Delivery of an executed counterpart of a signature
page to this Amendment by telecopier shall be effective as delivery of a
manually executed counterpart of this Amendment.

SECTION 7.  Governing Law

This Amendment shall be governed by, and construed in accordance with, the laws
of the State of New York.

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed
by their respective officers thereunto duly authorized, as of the date first
above written.

(Signatures Commence on the Next Page)





NORTHEAST GENERATION COMPANY

By
Title:


CITIBANK, N.A.,
as Administrative Agent

By
Title:


CITIBANK, N.A.
As Collateral Agent and as Depositary Bank

By
Title:




Lenders:


CITIBANK, N.A.

By
Name:
Title:


BARCLAYS BANK PLC

By:
Name:
Title:


CANADIAN IMPERIAL BANK OF COMMERCE

By
Name:
Title:


TORONTO DOMINION (TEXAS), INC.

By:
Name:
Title:


FORTIS CAPITAL CORP.
(formerly MeesPierson Capital Corp.)

By:
Name:
Title:


UNION BANK OF CALIFORNIA, N.A..

By:
Name:
Title:


BANK ONE, NA

By:
Name:
Title:


CONSENT


Dated as of  November[22], 2000

The undersigned, Northeast Utilities, a Massachusetts voluntary association with
reference to the Sponsor Agreement, dated as of March 9, 2000 (the "Sponsor
Agreement") in favor of the Administrative Agent and the Lenders parties to the
Credit Agreement referred to in the foregoing Amendment, hereby consents to such
Amendment and hereby confirms and agrees that (a) notwithstanding the
effectiveness of such Amendment, the Sponsor Agreement is, and shall continue to
be, in full force and effect and is hereby ratified and confirmed in all
respects, except that, on and after the effectiveness of such Amendment, each
reference in the Sponsor Agreement to the "Credit Agreement", "thereunder",
"thereof" or words of like import and to the Notes "thereunder", "thereof", or
words of like import shall mean and be a reference to the Credit Agreement and
the Notes respectively, as amended by such Amendment.

No Trustee or shareholder of Northeast Utilities shall be held to any liability
whatever for any obligations under this Consent or the Sponsor Agreement, and
this Consent shall not be enforceable against any such Trustee in their or his
or her individual capacities or capacity. This Consent shall be enforceable
against the Trustees of Northeast Utilities only as such, and every person,
firm, association, trust or corporation having any claim or demand arising under
this Consent and relating to Northeast Utilities, its shareholders, or Trustees
shall look solely to the trust estate of Northeast Utilities for the payment or
satisfaction thereof.






NORTHEAST UTILITIES

By
Name:
Title:
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.55
<SEQUENCE>13
<FILENAME>0013.txt
<DESCRIPTION>EXHIBIT 10.55
<TEXT>


             THIS TRANCHE B MORTGAGE, ASSIGNMENT OF LEASES AND RENTS, SECURITY
AGREEMENT AND FIXTURE FILING (as the same may from time to time be extended,
spread, split, consolidated, amended, modified, supplemented, restated and
renewed, this "Mortgage") made as of March , 2000 by NORTHEAST GENERATION
COMPANY, a Connecticut corporation ("Mortgagor"), having its principal office at
107 Selden Street, Berlin, Connecticut 06037 to CITIBANK, N.A., a national
banking association ("Citibank") having an address at 399 Park Avenue, New York,
New York 10005, as collateral agent (Citibank in its capacity as collateral
agent and any successor collateral agent appointed in accordance with the Credit
Agreement (as hereinafter defined), "Agent") and Depositary Bank for the Lenders
(as hereinafter defined), Agent being referred to herein as "Mortgagee".

                           W I T N E S S E T H:

            WHEREAS, Mortgagor has entered into that certain Credit Agreement
(said credit agreement, as it may be amended, modified or supplemented from time
to time, being the "Credit Agreement", a copy of which may be examined at
reasonable times at the office of Agent by persons who do or will hold an
interest in the Land (as hereinafter defined) or the Improvements (as
hereinafter defined)), dated as of March , 2000, with the lenders listed on
Schedule 1 attached hereto and made a part hereof (said lenders and any lenders
that may hereafter become parties to the Credit Agreement, being collectively
the "Lenders" and individually a "Lender") and Citibank, N.A., as Collateral
Agent, Administrative Agent and Depositary Bank;

           WHEREAS, pursuant to the Credit Agreement and subject to the terms
and conditions therein set forth, the Lenders have agreed to make Advances in
the aggregate amount of 865,500,000 dollars, comprised of the Tranche A Advance
(as defined in and to be made pursuant to Section 2.01(a) of the Credit
Agreement) of up to 435,500,000 dollars and the Tranche B Advance (as defined in
and to be made pursuant to Section 2.01(b) of the Credit Agreement) of up to
430,000,000 dollars;

          WHEREAS, to evidence such indebtedness, Mortgagor has executed and
delivered the Credit Agreement and will execute and deliver various promissory
notes (each a "Note" and collectively, the "Notes") to the order of each of the
Lenders in the amount of its Commitment, and each issued pursuant to the Credit
Agreement;

          WHEREAS, pursuant to the Credit Agreement, Mortgagor may enter into
Permitted Hedges with Permitted Hedge Providers (which are also Lenders);

          WHEREAS, the total indebtedness and liabilities to be secured by this
Mortgage are as follows (all such indebtedness and liabilities or the
instruments evidencing same, as applicable, being herein collectively called the
"Obligations"):


(i) the Tranche B Advance in the aggregate principal amount of 430,000,000
dollars, or so much thereof that may be advanced by the Lenders as the Tranche B
Advance under the Credit Agreement; plus

(ii) interest on the principal amount of the amount so advanced by the Lenders
under the Credit Agreement, as provided in the Credit Agreement; plus

(iii) all other amounts payable to the Tranche B Secured Parties and all

                                        1
<PAGE>

other obligations of Mortgagor, including the obligations of Mortgagor to the
Permitted Hedge Providers now or hereafter existing under the Permitted Hedges,
under the Credit Agreement and the Notes (but expressly excluding the Tranche A
Obligations), this Mortgage and any other document which relates to any of the
Credit Agreement or the Notes or any of the security therefor (all of the
foregoing documents, as they may be amended, modified, supplemented, extended,
restated or renewed from time to time, collectively, the "Loan Documents"); and

WHEREAS, it has been agreed that the payment and performance of the Obligations
shall be secured by a mortgage, assignment of leases and rents, security
agreement and fixture filing, as applicable, of certain property as hereinafter
identified.

NOW, THEREFORE, in consideration of the premises and other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, to
secure the punctual payment by Mortgagor when due, whether at stated maturity,
by acceleration or otherwise, of the Obligations and the performance and
observance of all other covenants, obligations and liabilities of Mortgagor
under this Mortgage, Mortgagor does hereby grant, bargain, sell, mortgage,
warrant, convey, alien, remise, release, assign, transfer, set over, deliver,
confirm and convey unto Mortgagee, upon the terms and conditions of this
Mortgage, with power of sale (to the extent permitted by law) and right of entry
as provided hereinbelow, each and all of the real and other properties described
in the Granting Clauses herein (collectively, the "Mortgaged Property").


GRANTING CLAUSES

All the estate, right, title and interest of Mortgagor in, to and under, or
derived from, the plots, pieces and parcels of land more particularly described
in Exhibit A attached hereto (the "Land");

TOGETHER with the tenements, easements, hereditaments, appurtenances and all the
estates and rights of Mortgagor in and to the Land;

TOGETHER with all buildings and improvements now or hereafter located on the
Land (hereinafter collectively referred to as the "Improvements") and all right,
title and interest, if any, of Mortgagor in and to the streets, roads, sidewalks
and alleys abutting the Land, and strips and gores within or adjoining the Land,
the air space and right to use said air space above the Land and any
transferable development or similar rights appurtenant thereto, all rights of
ingress and egress by motor vehicles to parking facilities on or within the
Land, all easements now or hereafter affecting the Land, royalties and all
rights appertaining to the use and enjoyment of the Land, including alley,
drainage, flowage, mineral, water, riparian, oil and gas rights;

TOGETHER with all property, tangible and intangible, and all additions thereto
and substitutions or replacements thereof owned by Mortgagor and now or
hereafter contained in, or used in connection with the Premises or placed on any
part thereof though not attached thereto, to the extent the same constitutes
real property in the state in which the Mortgaged Property is located (all of
the foregoing, including the items hereinafter enumerated, collectively referred
to as the "Equipment"), including turbines, control machinery and other
equipment related to the generation of hydroelectric

                                        2
<PAGE>

power, all removable window and floor coverings, furniture and furnishings,
heating, lighting, plumbing, ventilating, air conditioning, refrigerating,
incinerating and elevator plants, cooking facilities, vacuum cleaning systems,
call systems, sprinkler systems and other fire prevention and extinguishing
apparatus and materials, motors, machinery, pipes, appliances, equipment,
fittings and fixtures (the Land, together with the Improvements and the
Equipment, are hereinafter collectively referred to as the "Premises");

TOGETHER with all leases, subleases, lettings, and licenses (including all
Neighboring Landowner Agreements) of, and all other contracts, bonds and
agreements affecting the Premises or any part thereof now or hereafter entered
into, and all amendments, modifications, supplements, additions, extensions and
renewals thereof (all of the foregoing hereinafter collectively referred to as
the "Leases"), and all right, title and interest of Mortgagor thereunder,
including cash and securities deposited thereunder (as down payments, security
deposits or otherwise), the right to receive and collect the rents, security
deposits, income, proceeds, earnings, royalties, revenues, issues and profits
payable thereunder and the rights to enforce, whether at law or in equity or by
any other means, all provisions and options thereof or thereunder (all of the
foregoing hereinafter collectively referred to as the "Rents") and the right to
apply the same to the payment and performance of the Obligations;

TOGETHER with all rights, dividends and/or claims of any kind whatsoever
relating to the Premises (including damage, secured, unsecured, lien, priority
and administration claims); together with the right to take any action or file
any papers or process in any court of competent jurisdiction, which may in the
opinion of Mortgagee be necessary to preserve, protect, or enforce such rights
or claims, including the filing of any proof of claim in any insolvency
proceeding under any state, Federal or other laws and any rights, claims or
awards accruing to or to be paid to Mortgagor in its capacity as landlord under
any Lease;

TOGETHER with all unearned premiums, accrued, accruing or to accrue under
insurance policies now or hereafter obtained by Mortgagor and relating to the
Premises and all proceeds of the conversion, voluntary or involuntary, of the
Premises into cash or liquidated claims, including proceeds of hazard and title
insurance and all awards and compensation heretofore and hereafter made to the
present and all subsequent owners of the Premises by any governmental or other
lawful authorities for the taking by eminent domain, condemnation or otherwise,
of all or any part of the Premises or any easement therein, including awards for
any change of grade of streets;

TOGETHER with all right, title and interest of Mortgagor in and to all
extensions, improvements, betterments, renewals, substitutes and replacements
of, and all additions and appurtenances to, any of the foregoing hereafter
acquired by, or released to, Mortgagor or constructed, assembled or placed by
Mortgagor on the Premises and all conversions of the security constituted
thereby, immediately upon such acquisition, release, construction, assemblage,
placement or conversion, as the case may be, and in each such case, without any
further mortgage, conveyance, assignment or other act by Mortgagor, shall become
subject to the lien of this Mortgage as fully and completely, and with the same
effect, as though now owned by Mortgagor and specifically described herein.

TO HAVE AND TO HOLD the Mortgaged Property unto Mortgagee, and its respective

                                        3
<PAGE>

successors and assigns, forever.

This mortgage is granted with MORTGAGE COVENANTS.


ARTICLE I

Representations, Warranties and Covenants of Mortgagor
                  Representations, Warranties and Covenants of Mortgagor

SECTION 1.01.     Payment of Obligations. Mortgagor shall punctually pay when
due, and timely perform, the Obligations.

SECTION 1.02. Warranty of Title. Mortgagor warrants that it has good and
marketable title to the Premises, in each case free and clear of all liens,
charges and encumbrances of every kind and character, subject only to (i) the
encumbrances identified on Exhibit B-2 of each of those certain title insurance
policies of Commonwealth Land Title Insurance Company identified as Policy
Numbers G32-592535 and G32-7611866 (as endorsed pursuant to endorsement numbers
100183877 and 50570722, respectively, by First American Title Insurance
Company), (ii) Liens created under the Loan Documents, (iii) Permitted Liens,
(iv) other Liens incurred in the ordinary course of business otherwise than to
secure Debt, and (v) any extension, renewal or replacement of the Liens set
forth in the foregoing clauses (ii), (iii) and (iv), provided, however, that the
principal amount of Debt secured thereby shall not, at the time of such
extension, renewal or replacement, exceed the principal amount of Debt so
secured and that such extension, renewal, or replacement shall be limited to all
or a part of the Mortgaged Property which secured the Lien so extended, renewed
or replaced (all of the foregoing, the "Permitted Encumbrances"); has and shall
continue to have full power and lawful authority to encumber and convey the
Premises as provided herein; owns all other Mortgaged Property free and clear of
all liens, charges and encumbrances of every kind and character, subject only to
the Permitted Encumbrances; this Mortgage is and shall continue to remain a
valid and enforceable first mortgage lien on and security interest in the
Mortgaged Property, subject only to the Permitted Encumbrances. Mortgagor
further covenants that it shall preserve such title and shall forever warrant
and defend the title to the Mortgaged Property unto Mortgagee against all lawful
claims whatsoever and shall forever warrant and defend the validity,
enforceability and priority of the lien of this Mortgage against the claims of
all persons and parties whomsoever.

Mortgagor covenants that it shall, at Mortgagor's sole cost and expense and at
the request of Mortgagee, (a) promptly correct any defect or error which may be
discovered in the Loan Documents, (b) promptly do, execute, acknowledge and
deliver, and record and re-record, file and re-file and register and
re-register, any and all such instruments as may be necessary from time to time
in order to perfect and protect the lien of, and otherwise implement the terms
of, this Mortgage and (c) promptly furnish Mortgagee with evidence satisfactory
to Mortgagee of every such recording, filing or registration.

SECTION 1.03.     Operation and Maintenance. (a) Repair and Maintenance.
Mortgagor shall operate and maintain the Premises in good order, repair and
operating condition, ordinary wear and tear excepted, shall promptly make all
necessary repairs, restorations, renewals, replacements, additions and
improvements thereto,

                                        4
<PAGE>

interior and exterior, structural and nonstructural, foreseen and unforeseen, or
otherwise necessary to insure that the same as part of the security under this
Mortgage shall not in any way be diminished or impaired, and shall not cause or
allow the Premises to be misused, wasted or to deteriorate. No new building,
structure, facility or other improvement that would diminish or impair the value
of the Premises shall be constructed on the Land without Mortgagee's prior
written consent in the case of each such proposed construction.

(b) Equipment. Mortgagor shall keep and maintain the Equipment and Inventory (as
defined in the Tranche B Borrower Security Agreement) in accordance with Section
10 of the Tranche B Borrower Security Agreement.

(c) Zoning; Title Matters. Mortgagor shall not, without the prior written
consent of Mortgagee: (i) initiate or support any zoning reclassification of any
portion of the Premises upon which an Improvement owned by Mortgagor is located
or which is otherwise essential to the generation of electricity on the
Mortgaged Property (such portion, a AMaterial Portion"), seek any variance under
existing zoning ordinances applicable to any Material Portion of the Premises or
use or permit the use of any Material Portion of the Premises in a manner which
would result in such use becoming a non-conforming use under applicable zoning
ordinances; (ii) modify or amend any of the Permitted Encumbrances in any
material respect; (iii) impose any restrictive covenants or encumbrances upon
any Material Portion of the Premises, execute or file any subdivision plat
affecting any Material Portion of the Premises or consent to the annexation of
any Material Portion of the Premises to any municipality; or (iv) permit or
suffer any Material Portion of the Premises to be used by the public or any
person in such manner as might make reasonably possible a claim of adverse usage
or possession or of any implied dedication or easement.

(d) Status of the Premises. (i) The Premises is not located in an area
identified by the Secretary of Housing and Urban Development or a successor
thereto as an area having special flood hazards pursuant to the terms of the
National Flood Insurance Act of 1968, or the Flood Disaster Protection Act of
1973, as amended, or any successor law; or if the Premises is located in such an
area, Mortgagor shall obtain and maintain insurance against damage or loss by
flood on such basis and in such amounts as shall be required by Mortgagee; (ii)
the Premises is served by all utilities required for the current use thereof;
(iii) Mortgagor has access to the Land and the Improvements by public roads or
by irrevocable easement approved by Mortgagee; and (iv) there is no condemnation
or similar proceeding pending or, to the best knowledge of Mortgagor, threatened
affecting any part of the Premises that might materially adversely affect the
Premises.

(e) Use. Mortgagor shall use the Premises for substantially the same use as in
effect as of the date hereof and for no other use unless consented to in writing
by Mortgagee.

(f) Compliance with Terms of Leases. Mortgagor shall make all payments and
otherwise perform all obligations in respect of all Leases to which it is a
party lessee, keep such Leases in full force and effect and not allow such
Leases to lapse or be terminated or any rights to renew such leases to be
forfeited or canceled, notify the Mortgagee of any default by any party with
respect to such Leases and cooperate with the Mortgagee in all respects to cure
any such default, except, in any case, where the failure to do so, either
individually or in the aggregate, would not reasonably be expected to

                                        5
<PAGE>

have a Material Adverse Effect.

SECTION 1.04.     Insurance. Mortgagor shall maintain in effect insurance in the
amounts and otherwise as required pursuant to Section 6.01(e) of the Credit
Agreement, which Section 6.01(e) of the Credit Agreement is incorporated herein
by reference.

SECTION 1.05. Liens and Liabilities. (a) Discharge of Liens. Mortgagor shall
pay, bond or otherwise discharge, from time to time when the same shall become
due, all claims and demands of mechanics, materialmen, laborers and others
which, if unpaid, might result in, or permit the creation of, a lien on the
Mortgaged Property.

(b) Creation of Liens. Mortgagor shall not, without Mortgagee's consent, create,
place or permit to be created or placed or allow to remain, and shall discharge
and release within ten (10) days of the placing thereof, any deed of trust,
mortgage, trust deed, voluntary or involuntary lien, security interest or other
encumbrance against or covering the Mortgaged Property, other than the Permitted
Encumbrances, whether or not subordinate hereto.

(c) No Consent. Nothing in this Mortgage shall be deemed or construed in any way
as constituting the consent or request by Mortgagee, express or implied, to any
contractor, subcontractor, laborer, mechanic or materialman for the performance
of any labor or the furnishing of any material for any improvement,
construction, alteration or repair of the Premises. Mortgagor further agrees
that Mortgagee does not stand in any fiduciary relationship to Mortgagor.

SECTION 1.06.     Taxes and Other Charges.
(a) Taxes on the Premises. Mortgagor shall promptly pay when due and before any
penalty or interest may be added thereto, all taxes, assessments, vault, water
and sewer rents, rates, charges and assessments, levies, permits, inspection and
license fees and other governmental and quasi-governmental charges and any
penalties or interest for non-payment thereof, heretofore or hereafter imposed,
or which may become a lien, upon the Mortgaged Property or arising with respect
to the occupancy, use or possession thereof (collectively, "Impositions").
Mortgagor shall also pay any penalty, interest or cost for non-payment of
Impositions which may become due and payable.

(b) Receipts. Mortgagor shall furnish to Mortgagee upon Mortgagee's request,
proof of payment at the time same is made, and thereafter, upon receipt,
validated receipts showing payment in full of all Impositions.

(c) Increased Costs. In the event of the enactment after the date hereof of any
law in the state in which the Mortgaged Property is located or any other
governmental entity deducting from the value of the Mortgaged Property for the
purpose of taxation any lien or security interest thereon, or changing in any
way the laws for the taxation of mortgages, deeds of trust or other liens or
debts secured thereby, or the manner of collection of such taxes, so as to
affect this Mortgage, the Obligations, Mortgagee or the holders of the
Obligations, then, and in such event, Mortgagor shall, on demand, pay to
Mortgagee or such holder, or reimburse Mortgagee or such holder for payment of,
all taxes, assessments, charges or liens for which Mortgagee or such holder is
or may be liable as a result thereof, provided that if any such payment or
reimbursement shall be unlawful or would constitute usury or render the
Obligations wholly or partially usurious under applicable law,

                                        6
<PAGE>

then Mortgagee may, at its option, declare the Obligations immediately due and
payable or require Mortgagor to pay or reimburse Mortgagee for payment of the
lawful and non-usurious portion thereof.

SECTION 1.07.     Damage and Destruction.

(a) Mortgagor's Obligations. In the event of any damage to or loss or
destruction of the Premises, Mortgagor shall (i) promptly notify Mortgagee of
such event and take such steps as shall be necessary to preserve any undamaged
portion of the Premises and (ii) unless otherwise instructed by Mortgagee and so
long as any insurance proceeds paid to Mortgagee hereunder in respect of such
damage or destruction are made available by Mortgagee to Mortgagor (but without
imposing on Mortgagor any obligation to make such proceeds available to
Mortgagor other than as expressly required pursuant to Section 4.03(b) of the
Credit Agreement), promptly commence and diligently pursue to completion the
restoration, replacement and rebuilding of the Premises to the condition of the
Premises affected thereby immediately prior to such damage, loss or destruction
in accordance with plans and specifications approved, and with other provisions
for the preservation of the security hereunder established, by Mortgagee.

(b) Mortgagee's Rights; Application of Proceeds. In the event that (i) any
portion of the Premises is so damaged, destroyed or lost, (ii) such damage,
destruction or loss is covered, in whole or in part, by insurance required by
Section 1.04 hereof, and (iii) a claim is made by Mortgagee or Mortgager against
such insurance policy, then the proceeds of such insurance policy shall be
applied as provided in Section 4.03(b) of the Credit Agreement.

(c) Effect on the Obligations. Notwithstanding any loss, damage or destruction
referred to in this Section 1.07, Mortgagor shall continue to pay and perform
the Obligations as provided herein. Any reduction in the Obligations resulting
from such application shall be deemed to take effect only on the date of receipt
by Mortgagee of such insurance proceeds and application against the Obligations,
provided that if prior to the receipt by Mortgagee of such insurance proceeds
the Mortgaged Property shall have been sold on foreclosure of this Mortgage, or
shall have been transferred by deed in lieu of foreclosure of this Mortgage,
Mortgagee shall have the right to receive the same to the extent of any
deficiency found to be due upon such sale, with interest thereon at the rate and
as provided in the Credit Agreement together with attorneys' fees and
disbursements incurred by Mortgagee in connection with the collection thereof.

SECTION 1.08. Condemnation. (a) Mortgagor's Obligations; Proceedings. Mortgagor,
promptly upon obtaining knowledge of any pending or threatened institution of
any proceedings for the condemnation of the Premises, or of any right of eminent
domain, or of any other proceedings arising out of injury or damage to or
decrease in the value of the Premises, including a change in grade of any
street, shall notify Mortgagee of the threat or pendency thereof. Mortgagee may
participate in any such proceedings, and Mortgagor from time to time shall
execute and deliver to Mortgagee all instruments requested by Mortgagee or as
may be required to permit such participation. Mortgagor shall, at its expense,
diligently prosecute any such proceedings, shall deliver to Mortgagee copies of
all papers served in connection therewith and shall consult and cooperate with
Mortgagee, its attorneys and agents, in the carrying on and defense of any such
proceedings; provided that no settlement of any such proceeding shall be made by
Mortgagor without Mortgagee's consent, which consent shall not be unreasonably
withheld.

                                        7
<PAGE>

(b) Trustee's and Mortgagee's Rights to Proceeds. All proceeds of condemnation
awards or proceeds of sale in lieu of condemnation, and all judgments, decrees
and awards for injury or damage to the Premises greater than $5,000,000
(collectively, "Awards") are hereby assigned and shall be paid to Mortgagee.
Mortgagor authorizes Mortgagee to collect and receive the same, to give receipts
and acquittances therefor, and to appeal from any Awards.

(c) Application of Proceeds. Mortgagee shall have the right to apply any Awards,
first, to reimburse Mortgagee for all reasonable costs and expenses, and,
second, the remainder thereof in the manner provided in Section 4.03(b) of the
Credit Agreement as if such Awards were insurance proceeds. In the event that
Mortgagor shall have received all or any portion of such Awards, Mortgagor, upon
demand from Mortgagee, shall pay to Mortgagee an amount equal to the amount so
received by Mortgagor, to be applied as Mortgagee shall have the right pursuant
to this Section 1.08(c). Notwithstanding anything herein or at law or in equity
to the contrary, none of the Awards paid to Mortgagee under this Section 1.08(c)
shall be deemed trust funds and Mortgagee shall be entitled to dispose of the
same as provided in this Section 1.08(c).

(d) Effect on the Obligations. Notwithstanding any condemnation, taking or other
proceeding referred to in this Section 1.08, Mortgagor shall continue to pay and
perform the Obligations as provided herein. Any reduction in the Obligations
resulting from such application shall be deemed to take effect only on the date
of receipt by Mortgagee of such Awards and application against the Obligations,
provided that if prior to the receipt by Mortgagee of such Awards the Mortgaged
Property shall have been sold on foreclosure of this Mortgage, or shall have
been transferred by deed in lieu of foreclosure of this Mortgage, Mortgagee
shall have the right to receive the same to the extent of any deficiency found
to be due upon such sale, with interest thereon at the rate and as provided in
the Credit Agreement together with attorneys' fees and disbursements incurred by
Mortgagee in connection with the collection thereof.

SECTION 1.09. Contest. Notwithstanding anything to the contrary contained in
Section 1.03(c), Section 1.05 or Section 1.06 hereof, Mortgagor shall have the
right to contest in good faith and at its own expense the validity or
applicability of any duty or obligation described in Section 1.03(c) hereof, the
validity of any lien, encumbrance, charge or security referred to in Section
1.05 hereof and any Imposition imposed upon the Premises (a "Contest") by an
appropriate legal proceeding which proceeding must operate to prevent the
collection of such Impositions or other realization thereon and the sale or
forfeiture of the Mortgaged Property or any part thereof to satisfy the same;
provided that during the pendency of such Contest, Mortgagor shall provide
security reasonably satisfactory to Mortgagee (which security may be in the form
of a bond or undertaking deposited into a court, in either case sufficient to
remove the lien, encumbrance, charge or security in question), assuring the
discharge of Mortgagor's obligations that are the subject of such Contest
("Contested Impositions") and of any additional interest, charge, penalty or
expense arising from or incurred as a result of such Contest; and provided,
further, that if at any time payment of such Contested Impositions shall become
necessary to prevent (a) the delivery of a tax deed conveying the Mortgaged
Property because of non-payment or (b) the imposition of any civil or criminal
penalty or liability on Mortgagee or the holders of the Obligations, Mortgagor
shall pay the same in sufficient time to avoid the delivery of such

                                        8
<PAGE>

tax deed or the imposition of any such penalty or liability.


                                   ARTICLE II

                  Assignment of Leases, Rents and Other Sums

SECTION 2.01. Assignment. (a) Mortgagor hereby absolutely and presently
bargains, sells, transfers, assigns and sets over to Mortgagee, as further
security for the payment of the Obligations, all of its right, title and
interest in and to the Leases and the Rents payable thereunder and all rights of
Mortgagor thereunder and any and all deposits held as security under the Leases,
whether before or after foreclosure or during the full period of redemption, if
any, and shall, upon demand, deliver to Mortgagee an executed counterpart of
each Lease. The assignment of the Leases and Rents, and of the aforesaid rights
with respect thereto, is intended to be and is an absolute present assignment
from Mortgagor to Mortgagee and not merely the passing of a security interest.
Such assignment and grant shall continue in effect until the Obligations are
paid, the execution of this Mortgage constituting and evidencing the irrevocable
consent of Mortgagor to the entry upon and taking possession of the Premises by
Mortgagee pursuant to such grant, whether foreclosure has been instituted or not
and without applying for a receiver. Until the occurrence of an Event of Default
hereunder, Mortgagor shall be entitled, subject to any provisions of the Loan
Documents and the Permitted Hedges providing otherwise, to collect and receive
the Rents and agrees to apply the same in the ordinary course of business. Such
right of Mortgagor to collect and receive said Rents shall be automatically
revoked upon the occurrence of an Event of Default and thereafter Mortgagee
shall have the right and authority to exercise any of the rights or remedies
referred to or set forth in Article V hereof. In addition, upon such an Event of
Default, Mortgagor shall promptly pay to Mortgagee (i) all rent prepayments and
security or other deposits paid to Mortgagor pursuant to any lease assigned
hereunder and (ii) all charges for services or facilities or for escalation
which were paid pursuant to any such Lease to the extent allocable to any period
from and after such Event of Default. Nothing contained in this Section 2.01(a)
shall be construed to bind Mortgagee to the performance of any of the covenants,
conditions or provisions contained in any Lease or otherwise to impose any
obligation on Mortgagee prior to accepting receipt of such Rent (including any
liability under the covenant of quiet enjoyment contained in any Lease or under
any applicable law in the event that any tenant shall have been joined as a
party defendant in any action to foreclose this Mortgage and shall have been
barred and foreclosed thereby of all right, title and interest and equity of
redemption in the Premises), except that Mortgagee shall be accountable for any
money actually received pursuant to such assignment. Mortgagor hereby further
grants to Mortgagee the right, after the occurrence of an Event of Default
hereunder, to notify the tenant under any Lease of the assignment thereof and
(1) to demand that the tenant under any Lease pay all amounts due thereunder
directly to Mortgagee, (2) to enter upon and take possession of the Premises for
the purpose of collecting the Rents, (3) to dispossess by the usual summary
proceedings any tenant defaulting in the payment thereof, (4) to let the
Premises, or any part thereof, and (5) to apply the Rents, after payment of all
necessary charges and expenses, on account of the Obligations.

(b) Mortgagor shall, as and when requested from time to time by Mortgagee,

                                        9
<PAGE>

execute, acknowledge and deliver to Mortgagee, in form reasonably acceptable to
Mortgagee and Mortgagor, one or more general or specific assignments of the
lessor's interest under any Lease. Mortgagor shall, on demand, pay to Mortgagee,
or reimburse Mortgagee for the payment of any reasonable costs or expenses
incurred in connection with the preparation or recording of any such assignment.

SECTION 2.02. Leases and Rents. (a) Mortgagor shall (i) perform or cause to be
performed all the lessor's obligations under any Lease, (ii) enforce (including
the termination and cancellation of any Lease, so long as the same is a bona
fide enforcement of Mortgagor's right as lessor under any such Lease and such
termination or cancellation, either by itself or in the aggregate with other
terminations and cancellations, shall not diminish or impair the security of
this Mortgage) the performance by the lessee under its respective Lease of all
of said lessee's obligations thereunder, (iii) give Mortgagee prompt notice and
a copy of any notice of default, event of default, termination or cancellation
sent or received by Mortgagor in respect of any Lease producing an annual income
to Mortgagor of $100,000 or more (such Lease, a AMaterial Lease"); but nothing
contained herein shall preclude Mortgagor from modifying, supplementing or
amending any existing Lease or preclude Mortgagor from entering, subject to
Section 2.02(b) hereof, into additional Leases which may, from time to time, be
modified, supplemented, amended, terminated or cancelled by Mortgagor subject to
the provisions of this Section 2.02(a).

(b) Mortgagor agrees that any Lease, the termination of which could reasonably
be expected to have a Material Adverse Effect, shall contain the following
provision:

A[Tenant] acknowledges and agrees that this [Lease] is subject and subordinate
to that certain Tranche B Mortgage, Assignment of Leases and Rents, Security
Agreement and Fixture Filing, dated as of March __, 2000, made by [Landlord] in
favor of Citibank, N.A. as collateral agent for the lenders listed therein
(together with any amendment, assignment or other modification thereof made at
any time, the AMortgage"), such subordination being self-operative and requiring
no further instrument of subordination. If at any time the mortgagee under the
Mortgage (together with successors and assigns of such mortgagee, AMortgagee")
or any other person or the successors or assigns of any of the foregoing shall
succeed to the rights of [Landlord] (any such successor, a ASuccessor
Landlord"), then [Tenant] shall, at the election and upon the request of any
Successor Landlord, fully and completely attorn to and recognize such Successor
Landlord as the landlord under this [Lease] upon the then executory terms of
this [Lease], except that such Successor Landlord shall not be (a) liable for
any act or omission of any previous [landlord] under this [Lease], (b) obligated
to repair, replace, rebuild or restore any portion of the [premises demised
under the Lease] in the event of damage, destruction or taking by eminent
domain, (c) subject to any offset or defense which [Tenant] may have against any
previous [landlord] under this [Lease], (d) bound by any amendment or
modification of the [Lease] unless Mortgagee has approved such amendment or
modification in advance, and (e) obligated to perform any work in the [premises
demised under the Lease] other than work that is required to be performed under
the [Lease]. If any act or omission by [Landlord] shall give [Tenant] the right,
immediately or after the lapse of time, to cancel or terminate this [Lease] in
whole or in part or to claim such cancellation or termination on the basis of a
partial or total eviction, [Tenant] shall not exercise any such right until (1)
it shall have given written notice of such act or omission to Mortgagee, and (2)

                                       10
<PAGE>

a reasonable period for remedying such act or omission shall have elapsed
following such notice and following the time when Mortgagee shall have become
entitled under this Mortgage to remedy the same."

(c) (i) Except as provided in Section 2.02(a) hereof, Mortgagor shall not,
without Mortgagee's consent, (A) assign, mortgage, pledge or otherwise transfer,
dispose of or encumber, whether by operation of law or otherwise, any Lease or
the Rents, (B) accept or permit the acceptance of a prepayment of any amounts
payable under such Lease for more than one month in advance of the due date
therefor, (C) enter into, amend, modify, cancel, terminate or accept a surrender
of any Lease or (D) enter into any Lease (1) with Mortgagor or any affiliate of
Mortgagor or its constituent partners or (2) which would be a "disqualified
lease", as defined in Section ' 168(h)(1)(B)(ii) of the Internal Revenue Code of
1986, as amended.

(ii) Supplementing the provisions of Section 2.02(c)(i) hereof, if the lessee
under any Lease (or any receiver, trustee, custodian or other party who succeeds
to the rights of any lessee) rejects or disaffirms such Lease pursuant to any
bankruptcy law, Mortgagor hereby assigns to Mortgagee the proceeds of any claims
(including the right to retain or apply any security deposits) that Mortgagor
may have against the lessee (or receiver, trustee, custodian or other party who
succeeds to the rights of any lessee) and any guarantor of any of the Leases,
under any one or more of the Leases or any guaranty thereof based upon any
breach by such lessee of the terms and provisions of the applicable Lease
(including any claim that Mortgagor may have by reason of a termination,
rejection or disaffirmance of such Lease pursuant to any bankruptcy law), and
the use and occupancy of the premises demised thereby, whether or not pursuant
to the applicable Lease (including any claim for use and occupancy arising under
any bankruptcy law). Mortgagor, immediately upon obtaining knowledge of any such
breach or use by any such lessee, shall notify Mortgagee of any such breach or
use. Except in respect of any Lease that is not a Material Lease (in which case
Mortgagor shall proceed in Mortgagor's and Mortgagee's behalf pursuant to
Section 2.02(c)(ii)(B) hereof), Mortgagee shall have the sole right to elect,
either:

(A) to proceed against such lessee or guarantor as if it were the named lessor
thereunder, in Mortgagor's name or in Mortgagee's name as agent for Mortgagor,
and Mortgagor agrees to cooperate with Mortgagee in such action and shall
execute any and all documents reasonably required in furtherance of such action;
or

(B) to have Mortgagor proceed in Mortgagor's and Mortgagee's behalf in which
event Mortgagee may participate in any such proceedings, and Mortgagor from time
to time shall deliver to Mortgagee all instruments reasonably requested by
Mortgagee or as may be required to permit such participation. Mortgagor shall,
at its expense, diligently prosecute any such proceedings, shall deliver to
Mortgagee copies of all papers served in connection therewith and shall consult
and cooperate with Mortgagee, its attorneys and agents, in the carrying on and
defense of any such proceedings; provided that no settlement of any such
proceeding shall be made by Mortgagor without Mortgagee's consent.


                                   ARTICLE III

                  Additional Advances; Expenses; Indemnity

                                       11
<PAGE>

SECTION 3.01. Additional Advances and Disbursements. (a) Mortgagor agrees that
if an Event of Default occurs hereunder, then Mortgagee shall have the right
without notice to Mortgagor to advance all or any part of amounts owing or to
perform any or all required actions. No such advance or performance shall be
deemed to have cured such default by Mortgagor or any Event of Default with
respect thereto. All sums advanced and all expenses incurred by Mortgagee in
connection with such advances or actions, and all other sums advanced or
expenses incurred by Mortgagee hereunder or under applicable law (whether
required or optional and whether indemnified hereunder or not) shall be part of
the Obligations, shall bear interest at the rate and as provided in the Credit
Agreement and shall be secured by this Mortgage.

(b) This Mortgage secures not only existing indebtedness, but also future or
additional protective advances made in each case pursuant hereto or to the
Credit Agreement, the Permitted Hedges, if any, whether such advances are
obligatory or optional.

SECTION 3.02. Other Expenses. Mortgagor shall pay or, within ten (10) days of
demand therefor, reimburse Mortgagee or any holder of the Obligations for the
payment of any and all reasonable costs or expenses (including reasonable
attorneys' fees and disbursements) incurred in connection with (a) an Event of
Default by Mortgagor hereunder, or (b) the exercise or enforcement by or on
behalf of Mortgagee or any holder of the Obligations of any of its rights or of
Mortgagor's obligations under the Loan Documents or the Permitted Hedges.

SECTION 3.03. Indemnity. Mortgagor shall indemnify and hold harmless Mortgagee,
the holders of the Obligations and their respective officers, directors,
employees and agents (the "indemnified parties") from and against any and all
losses, damages, claims, costs and expenses (including attorneys' fees and
disbursements) which may be imposed on, incurred by or asserted against any of
the indemnified parties in connection with any transaction in any way connected
with the Mortgaged Property, the Loan Documents or the Permitted Hedges, except
to the extent any such loss, damage, claim, cost or expense is the result of the
willful misconduct or gross negligence of the indemnified party. Any amount
payable under this Section 3.03 shall be deemed a demand obligation, shall be
added to and become a part of the Obligations, shall bear interest at the rate
and as provided in the Credit Agreement if not paid within ten (10) days of
demand therefore, and shall be secured by this Mortgage.

SECTION 3.04. Interest After Default. If any payment due hereunder, under the
other Loan Documents or under a Permitted Hedge is not paid in full when due,
whether by acceleration or otherwise, then the same shall bear interest
hereunder at the rate and as provided in the Credit Agreement, and such interest
shall be added to and become a part of the Obligations and shall be secured
hereby.


                                   ARTICLE IV

                  Sale or Transfer of the Premises

SECTION 4.01.     Continuous Ownership. Mortgagor acknowledges that the
continuous ownership of the Mortgaged

                                       12
<PAGE>

Property by Mortgagor, except as otherwise permitted in the other Loan
Documents, is of a material nature to the transaction hereinabove described and
Mortgagee's agreement to create the Obligations. Mortgagor=s causing the
following activities, whether voluntarily or involuntarily, without Mortgagee=s
prior written consent, shall subject Mortgagor to the remedies set forth at
Section 5.02 hereof: (a) other than in respect of a parcel of the Mortgaged
Property that is not a Material Portion of the Premises transferred in the
context of a settlement with an adjoining landowner regarding the ownership or
use of such parcel, selling, leasing, granting, conveying, assigning or
otherwise transferring, by operation of law or otherwise, or (b) granting an
option which or taking any action which pursuant to the terms of any agreement
to which Mortgagor is a party may result in any transaction described in clause
(a) above of, the Mortgaged Property, or any legal, beneficial or equitable
interest (excluding interests in Leases that are not Material Leases) therein
(the foregoing, collectively or severally, "Transfer"). For purposes of this
Mortgage, but without limiting the foregoing, (i) the issuance of any equity
interest in Mortgagor (whether stock, partnership interest or otherwise) not in
accordance with and pursuant to the Loan Documents and the Permitted Hedges,
shall be deemed a Transfer of the Mortgaged Property, (ii) a Transfer of all or
substantially all of the assets of Mortgagor shall be deemed a Transfer of the
Mortgaged Property, (iii) subject to Section 1.03(c) hereof, the execution and
delivery of any documentation relating to a proposed zoning lot merger or the
execution and delivery of any other documentation effecting or purporting to
effect, or the taking or suffering of any other action effecting or purporting
to effect, a transfer of, or the granting of a right to utilize, any development
rights appurtenant to the Mortgaged Property shall be deemed a Transfer of the
Mortgaged Property, and (iv) any person or legal representative of Mortgagor to
whom Mortgagor's interest in the Mortgaged Property passes by operation of law,
or otherwise, shall be bound by the provisions of this Mortgage. The provisions
of this Section 4.01 shall apply to each and every such Transfer of all or any
portion of the Mortgaged Property or any legal or equitable interest therein,
regardless whether or not Mortgagee has consented to, or waived by its action or
inaction its rights hereunder with respect to any previous Transfer of all or
any portion of the Mortgaged Property or any legal or equitable interest
therein.


                                    ARTICLE V

                  Defaults and Remedies

SECTION 5.01.     Events of Default. The term "Event of Default", as used in
this Mortgage, shall mean the occurrence of any of the following events:

(a) if default shall be made in the payment, after any applicable notice and
cure period, of any amounts required to be paid under the Notes, hereunder or
under any other Loan Document or under a Permitted Hedge, whether of principal,
interest, premium, fee or otherwise, and whether on any stated due date, upon
demand, at maturity or upon acceleration; or

(b) an Event of Default, as such term is defined in the Credit Agreement; or

(c) subject to Mortgagor=s right to contest same set forth in Section 1.09
hereof, if the Mortgaged Property shall be taken, attached or sequestered on
execution or other process of law in any action against Mortgagor; or

                                       13
<PAGE>

(d) if Mortgagor shall fail at any time to obtain, provide, maintain, keep in
force or, within ten (10) days after request therefor, deliver to Mortgagee, the
insurance policies required by Section 1.04 hereof; or

(e) subject to Mortgagor=s right to contest same set forth in Section 1.09
hereof, if any claim of priority (except a claim based upon a Permitted
Encumbrance) to this Mortgage or any other document or instrument securing the
Obligations by title, lien or otherwise shall be upheld by any court of
competent jurisdiction or shall be consented to by Mortgagor.

SECTION 5.02. Remedies. Upon the occurrence of any one or more Events of
Default, or any Transfer without the consent of Mortgagee, Mortgagee may, in
addition to any rights or remedies available to it hereunder or under the other
Loan Documents or the Permitted Hedges and to the extent permitted by applicable
law, take such action personally or by its agents or attorneys, with or without
entry, and without notice, demand, presentment or protest (each and all of which
are hereby waived except as expressly provided otherwise herein), as it deems
necessary or advisable to protect and enforce its rights and remedies against
Mortgagor and in and to the Mortgaged Property, including the following actions,
each of which may be pursued concurrently or otherwise, at such time and in such
order as Mortgagee may determine, in its sole discretion, without impairing or
otherwise affecting its other rights or remedies:

(a) declare the entire balance of the Obligations to be immediately due and
payable, and upon any such declaration, the entire unpaid balance of the
Obligations shall become and be immediately due and payable, without
presentment, demand, protest or further notice of any kind, all of which are
hereby expressly waived by Mortgagor (except as expressly provided otherwise
herein); or

(b) institute a proceeding or proceedings, judicial or otherwise, for the
complete or partial foreclosure of this Mortgage under any applicable provision
of law; or

(c) sell the Mortgaged Property, and all estate, right, title, interest, claim
and demand of Mortgagor therein, and all rights of redemption thereof, at one or
more sales, as an entirety or in parcels, with such elements of real and/or
personal property, and at such time and place and upon such terms as it may deem
expedient, or as may be required by applicable law, and in the event of a sale,
by foreclosure or otherwise, of less than all of the Mortgaged Property, this
Mortgage shall continue as a lien and security interest on the remaining portion
of the Mortgaged Property; or

(d) institute an action, suit or proceeding in equity for the specific
performance of any of the provisions contained in the Loan Documents or the
Permitted Hedges; or

(e) apply for the appointment of a receiver, custodian, trustee, liquidator or
conservator of the Mortgaged Property, to be vested with the fullest powers
permitted under applicable law, as a matter of right and without regard to, or
the necessity to disprove, the adequacy of the security for the Obligations or
the solvency of Mortgagor or any other person liable for the payment of the
Obligations, and Mortgagor and each other person so liable waives or shall be
deemed to have waived such necessity and consents or shall be deemed to have
consented to such appointment; or

                                       14
<PAGE>

(f) enter upon the Premises, and exclude Mortgagor and its agents and servants
wholly therefrom, without liability for trespass, damages or otherwise, and take
possession of all books, records and accounts relating thereto and all other
Mortgaged Property, and Mortgagor agrees to surrender possession of the
Mortgaged Property and of such books, records and accounts to Mortgagee on
demand after the happening of any Event of Default; and having and holding the
same may use, operate, manage, preserve, control and otherwise deal therewith
and conduct the business thereof, either personally or by its superintendents,
managers, agents, servants, attorneys or receivers, without interference from
Mortgagor; and upon each such entry and from time to time thereafter may, at the
expense of Mortgagor and the Mortgaged Property, without interference by
Mortgagor and as Mortgagee may deem reasonably advisable, (i) insure or reinsure
the Premises, (ii) make all necessary or proper repairs, renewals, replacements,
alterations, additions, betterments and improvements thereto and thereon and
(iii) in every such case in connection with the foregoing have the right to
exercise all rights and powers of Mortgagor with respect to the Mortgaged
Property, either in Mortgagor's name or otherwise; or

(g) with or without the entrance upon the Premises, collect, receive, sue for
and recover in its own name all Rents and cash collateral derived from the
Mortgaged Property, and after deducting therefrom all costs, expenses and
liabilities of every character reasonably incurred by Mortgagee in collecting
the same and in using, operating, managing, preserving and controlling the
Mortgaged Property, and otherwise in exercising Mortgagee's rights under
subsection (f) of this Section 5.02, including all amounts necessary to pay
Impositions, insurance premiums and other charges due and payable in connection
with the Premises, as well as compensation for services provided, in respect of
the management of the Premises, by Mortgagee or a third party acting on behalf
of Mortgagee, to apply the remainder as provided in Section 5.05 hereof; or

(h) release any portion of the Mortgaged Property for such consideration as
Mortgagee may require without, as to the remainder of the Mortgaged Property, in
any way impairing or affecting the lien or priority of this Mortgage, or
improving the position of any subordinate lienholder with respect thereto,
except to the extent that the Obligations shall have been reduced by the actual
monetary consideration, if any, received by Mortgagee for such release and
applied to the Obligations, and may accept by assignment, pledge or otherwise
any other property in place thereof as Mortgagee may require without being
accountable for so doing to any other lienholder; or

(i) take all actions permitted under the UCC; or

(j) take any other action, or pursue any other right or remedy, as Mortgagee may
have under applicable law, and Mortgagor does hereby grant the same to
Mortgagee.

In the event that Mortgagee shall exercise any of the rights or remedies set
forth in subsections (f) and (g) of this Section 5.02, Mortgagee shall not be
deemed to have entered upon or taken possession of the Mortgaged Property except
upon the exercise of its option to do so, evidenced by its demand and overt act
for such purpose, nor shall it be deemed a beneficiary or mortgagee in
possession by reason of such entry or taking possession. Mortgagee shall not be
liable to account for any action taken pursuant to any such exercise other than
for Rents actually received by Mortgagee, nor liable for any loss sustained by
Mortgagor resulting from any failure to let the Premises, or

                                       15
<PAGE>

from any other act or omission of Mortgagee except to the extent such loss is
caused by the willful misconduct or bad faith of Mortgagee or its agents or
representatives.

SECTION 5.03. Rights Pertaining to Sales. Subject to the provisions or other
requirements of law and except as otherwise provided herein, the following
provisions shall apply to any sale or sales of all or any portion of the
Mortgaged Property under or by virtue of this Article V, whether made under the
power of sale herein granted or by virtue of judicial proceedings or of a
judgment or decree of foreclosure and sale:

(a) Mortgagee may conduct any number of sales from time to time. The power of
sale set forth in Section 5.02(c) hereof shall not be exhausted by any one or
more such sales as to any part of the Mortgaged Property which shall not have
been sold, nor by any sale which is not completed or is defective in Mortgagee's
opinion, until the Obligations shall have been paid in full.

(b) Any sale may be postponed or adjourned by public announcement at the time
and place appointed for such sale or for such postponed or adjourned sale
without further notice. Without limiting the foregoing, in case Mortgagee shall
have proceeded to enforce any right or remedy under this Mortgage by receiver,
entry or otherwise, and such proceedings have been discontinued or abandoned for
any such reason or shall have been determined adversely to Mortgagee, then in
every such case Mortgagor and Mortgagee shall be restored to their former
positions and rights hereunder, and all rights, powers and remedies of Mortgagee
shall continue as if no such proceeding had been taken.

(c) After each sale, Mortgagee or an officer of any court empowered to do so
shall execute and deliver to the purchaser or purchasers at such sale a good and
sufficient instrument or instruments granting, conveying, assigning and
transferring all right, title and interest of Mortgagor in and to the property
and rights sold and shall receive the proceeds of said sale or sales and apply
the same as herein provided. Mortgagee is hereby appointed the true and lawful
attorney-in-fact of Mortgagor, which appointment is irrevocable and shall be
deemed to be coupled with an interest, in Mortgagor's name and stead, to make
all necessary conveyances, assignments, transfers and deliveries of the property
and rights so sold, and for that purpose Mortgagee may execute all necessary
instruments of conveyance, assignment, transfer and delivery, and may substitute
one or more persons with like power, Mortgagor hereby ratifying and confirming
all that said attorney or such substitute or substitutes shall lawfully do by
virtue thereof. Nevertheless, Mortgagor, if requested by Mortgagee, shall ratify
and confirm any such sale or sales by executing and delivering to Mortgagee or
such purchaser or purchasers all such instruments as may be advisable, in
Mortgagee's judgment, for the purposes as may be designated in such request.

(d) Any and all statements of fact or other recitals made in any of the
instruments referred to in subsection (c) of this Section 5.03 given by
Mortgagee as to nonpayment of the Obligations, or as to the occurrence of any
Event of Default, or as to Mortgagee having declared all or any of the
Obligations to be due and payable, or as to the request to sell, or as to notice
of time, place and terms of sale and of the property or rights to be sold having
been duly given, or as to any other act or thing having been duly done by
Mortgagor or by Mortgagee in connection with the exercise of the remedies
described in this Section 5.03(d) shall be taken as conclusive and

                                       16
<PAGE>

binding against all persons as to evidence of the truth of the facts so stated
and recited absent manifest error. Mortgagee may appoint or delegate any one or
more persons as agent to perform any act or acts necessary or incident to any
sale so held, including the posting of notices and the conduct of sale.

(e) The receipt of Mortgagee for the purchase money paid at any such sale, or
the receipt of any other person authorized to receive the same, shall be
sufficient discharge therefor to any purchaser of any property or rights sold as
aforesaid, and no such purchaser, or its representatives, grantees or assigns,
after paying such purchase price and receiving such receipt, shall be bound to
see to the application of such purchase price or any part thereof upon or for
any trust or purpose of this Mortgage or, in any manner whatsoever, be
answerable for any loss, misapplication or nonapplication of any such purchase
money, or part thereof, or be bound to inquire as to the authorization,
necessity, expediency or regularity of any such sale.

(f) Any such sale or sales shall operate to divest all of the estate, right,
title, interest, claim and demand whatsoever, whether at law or in equity, of
Mortgagor in and to the properties and rights so sold, and shall be a perpetual
bar both at law and in equity against Mortgagor and any and all persons claiming
or who may claim the same, or any part thereof or any interest therein, by,
through or under Mortgagor to the fullest extent permitted by applicable law.

(g) Upon any such sale or sales, Mortgagee may bid for and acquire the Mortgaged
Property and, in lieu of paying cash therefor, may make settlement for the
purchase price by crediting against the Obligations the amount of the bid made
therefor, after deducting therefrom the reasonable expenses of the sale, the
cost of any enforcement proceeding hereunder, and any other sums which Mortgagee
is authorized to deduct under the terms hereof, to the extent necessary to
satisfy such bid.

(h) In the event that Mortgagor, or any person claiming by, through or under
Mortgagor, shall transfer or refuse or fail to surrender possession of the
Mortgaged Property after any sale thereof, then Mortgagor, or such person, shall
be deemed a tenant at sufferance of the purchaser at such sale, subject to
eviction by means of forcible entry and unlawful detainer proceedings, or
subject to any other right or remedy available hereunder or under applicable
law.

(i) Upon any such sale, it shall not be necessary for Mortgagee or any public
officer acting under execution or order of court to have present or
constructively in its possession any of the Mortgaged Property. (j) In the event
a foreclosure hereunder shall be commenced by Mortgagee, Mortgagee may at any
time before the sale of the Mortgaged Property abandon the sale, and may
institute suit for the collection of the Obligations and for the foreclosure of
this Mortgage, or in the event that Mortgagee should institute a suit for
collection of the Obligations, and for the foreclosure of this Mortgage,
Mortgagee may at any time before the entry of final judgment in said suit
dismiss the same and require Mortgagee to sell the Mortgaged Property in
accordance with the provisions of this Mortgage.

(k) This mortgage is based upon the STATUTORY CONDITION and upon the further
condition that all covenants and agreements of Mortgagor in this Mortgage, all
other instruments executed in connection therewith and in all other mortgages,
debts and obligations of or from Mortgagor to Mortgagee shall be

                                       17
<PAGE>

kept and fully performed, and, upon any breach of the same, Mortgagee shall have
the STATUTORY POWER OF SALE and any other powers given by statute.

SECTION 5.04. Expenses. In any proceeding, judicial or otherwise, to foreclose
this Mortgage or enforce any other remedy of Mortgagee under the Loan Documents
or under any Permitted Hedge, there shall be allowed and included as an addition
to and a part of the Obligations in the decree for sale or other judgment or
decree all reasonable expenditures and expenses which may be paid or incurred in
connection with the exercise by Mortgagee of any of its rights and remedies
provided or referred to in Section 5.02 hereof, or any comparable provision of
any other Loan Document or any Permitted Hedge, together with interest thereon
at the rate and as provided in the Credit Agreement, and the same shall be part
of the Obligations and shall be secured by this Mortgage.

SECTION 5.05. Application of Proceeds. The purchase money, proceeds or avails of
any sale referred to in Section 5.02 hereof, together with any other sums which
may be held by Mortgagee hereunder, whether under the provisions of this Article
V or otherwise, shall, except as herein expressly provided to the contrary, be
applied as follows:

First: To the payment of the reasonable costs and expenses of any such sale,
including all amounts due hereunder, and of any judicial proceeding wherein the
same may be made, and of all reasonable expenses, liabilities and advances made
or incurred by Mortgagee hereunder, together with interest thereon as provided
herein, and all Impositions and other charges, except any Impositions or other
charges subject to which the Mortgaged Property shall have been sold.

Second: To the payment in full of the monetary Obligations (including principal,
interest, premium and fees) in such order as Mortgagee may elect.

Third: To the payment of any other sums secured hereunder or required to be paid
by Mortgagor pursuant to any provision of the Loan Documents or the Permitted
Hedges.

Fourth: To the extent permitted by applicable law, to be set aside by Mortgagee
as adequate security in its judgment for the payment of sums which would have
been paid by application under clauses First through Third above to Mortgagee,
arising out of an obligation or liability with respect to which Mortgagor has
agreed to indemnify Mortgagee, but which sums are not yet due and payable or
liquidated.

Fifth: To the payment of any withholding tax requirements of the Foreign
Investment in Real Property Tax Act of 1980, as amended.

Sixth: To the payment of the surplus, if any, to whomsoever may be lawfully
entitled to receive the same.

SECTION 5.06. Additional Provisions as to Remedies. (a) No delay or omission by
Mortgagee to exercise any right or remedy hereunder upon any default or Event of
Default shall impair such exercise, or be construed to be a waiver of any such
default or Event of Default.

(b) The failure, refusal or waiver (by consent, waiver or otherwise) of

                                       18
<PAGE>

Mortgagee to assert any right or remedy hereunder upon any default or Event of
Default or other occurrence shall not be construed as waiving such right or
remedy upon any other or subsequent default or Event of Default or other
occurrence.

(c) Mortgagee shall not have any obligation to pursue any rights or remedies it
may have under any other agreement prior to pursuing its rights or remedies
hereunder or under the other Loan Documents or under any Permitted Hedge.

(d) Acceptance of any payment after the occurrence of any default or Event of
Default shall not be deemed a waiver or a cure of such default or Event of
Default, and acceptance of any payment less than any amount then due shall be
deemed an acceptance on account only.

(e) In the event that Mortgagee shall have proceeded to enforce any right or
remedy hereunder by foreclosure, sale, entry or otherwise, and such proceeding
shall be discontinued, abandoned or determined adversely for any reason, then
Mortgagor and Mortgagee shall be restored to their former positions and rights
hereunder with respect to the Mortgaged Property, subject to the lien hereof.

(f) Each right of Mortgagee provided for in this Mortgage shall be cumulative
and shall be in addition to every other right provided for in this Mortgage or
now or hereafter existing at law or in equity, by statute or otherwise, and the
exercise by Mortgagee of any one or more of such rights shall not preclude the
simultaneous or later exercise by Mortgagee of any other such right.

SECTION 5.07.     Waiver of Rights and Defenses. To the full extent Mortgagor
may lawfully do so, Mortgagor agrees with Mortgagee as follows:

(a) Mortgagor shall not claim or take the benefit of any statute or rule of law
now or hereafter in force providing for any appraisement, valuation, stay,
extension, moratorium or redemption, or of any statute of limitations, and
Mortgagor, for itself and its heirs, devisees, representatives, successors and
assigns, and for any and all persons ever claiming an interest in the Mortgaged
Property (other than Mortgagee), hereby waives and releases all rights of
redemption, valuation, appraisement, notice of intention to mature or declare
due the whole of the Obligations, and all rights to a marshaling of the assets
of Mortgagor, including the Mortgaged Property, or to a sale in inverse order of
alienation, in the event of foreclosure of the liens and security interests
created hereunder.

(b) Mortgagor shall not have or assert and hereby waives any right under any
statute or rule of law pertaining to any of the matters set forth in subsection
(a) of this Section 5.07(a) hereof, to the administration of estates of
decedents or to any other matters whatsoever to defeat, reduce or affect any of
the rights or remedies of Mortgagee hereunder.


                                   ARTICLE VI

                  Release of Lien

SECTION 6.01. Release of Lien. Subject to the

                                       19
<PAGE>

full payment of all of the AObligations" defined in the fourth AWhereas" clause
of the Tranche A Mortgage, if all of the Obligations shall be fully paid, then
and in that event only all rights and obligations hereunder (except for the
rights and obligations set forth in Section 3.03 hereof) shall terminate and the
Mortgaged Property shall become wholly released and cleared of the liens,
security interests, conveyances and assignments evidenced hereby. In such event
Mortgagee shall, at the request of Mortgagor, deliver to Mortgagor within ten
(10) Business Days, in recordable form, all such documents as shall be necessary
to release the Mortgaged Property from the liens, security interests,
conveyances and assignments created or evidenced hereby. Moreover, this Mortgage
is subject to the provisions of Section 25 of the Borrower Security Agreement,
which grants to Mortgagor the right, upon certain terms and conditions, to
obtain Mortgagee's consent to release, or cause to be released, from the liens,
security interests, conveyances and assignments evidenced by this Mortgage, from
time to time, all or any portion of the Mortgaged Property.


                                   ARTICLE VII

                  Additional Provisions

SECTION 7.01. Provisions as to Payments, Advances. To the extent that any part
of the Obligations is used to pay indebtedness secured by any Permitted
Encumbrance or other outstanding lien, security interest, charge or prior
encumbrance against the Mortgaged Property or to pay in whole or in part the
purchase price therefor, Mortgagee shall be subrogated to any and all rights,
security interests and liens held by any owner or holder of the same, whether or
not the same are released.

SECTION 7.02. Separability. If all or any portion of any provision of this
Mortgage or any other Loan Document or any Permitted Hedge shall be held to be
invalid, illegal or unenforceable in any respect or in any jurisdiction, then
such invalidity, illegality or unenforceability shall not affect any other
provision hereof or thereof, and such provision shall be limited and construed
in such jurisdiction as if such invalid, illegal or unenforceable provision or
portion thereof were not contained herein or therein.

SECTION 7.03. Notices. Any notice, demand, consent, approval, direction,
agreement or other communication (any "Notice") required or permitted hereunder
shall be in writing and shall be validly given if mailed by United States mail,
certified mail, return receipt requested, postage prepaid, or by a
nationally-recognized overnight courier, addressed as follows to the person
entitled to receive the same:

(a)  If to Mortgagor:

Northeast Generation Company
107 Selden Street
Berlin, Connecticut 06037
Attention: Treasurer

and a copy to:

Edwards & Angell, LLP


                                       20
<PAGE>

90 State House Square
Hartford, Connecticut 06103
Attention: Justin M. Sullivan, Esq.

(b)  If to Mortgagee:

Citibank, N.A., as Collateral Agent
111 Wall Street, 5th Floor
New York, New York 10005
Attention: Florence Mills, Senior Trust Officer

Any Notice shall be deemed to have been validly given hereunder when so mailed
or sent by courier. Any person shall have the right to specify, from time to
time, as its address or addresses for purposes of this Mortgage, any other
address or addresses upon giving three (3) days' notice thereof to each other
person then entitled to receive notices or other instruments hereunder.

SECTION 7.04. Right to Deal. In the event that ownership of the Mortgaged
Property becomes vested in a person other than Mortgagor, Mortgagee may, without
notice to Mortgagor, deal with such successor or successors in interest with
reference to this Mortgage or the Obligations in the same manner as with
Mortgagor, without in any way vitiating or discharging Mortgagor's liability
hereunder or for the payment of the Obligations or being deemed a consent to
such vesting.

SECTION 7.05. Continuation of Lease. (a) Upon the foreclosure of the lien
created hereby on the Mortgaged Property, as herein provided, any Leases then
existing shall not be destroyed or terminated as a result of such foreclosure
unless Mortgagee or any purchaser at a foreclosure sale shall so elect by notice
to the lessee in question.

(b) If both the lessor's and the lessee's interest under any Lease which
constitutes a part of the Premises shall at any time become vested in any one
person, this Mortgage and the lien and security interest created hereby shall
not be destroyed or terminated by the application of the doctrine of merger and,
in such event, Mortgagee shall continue to have and enjoy all of the rights and
privileges of Mortgagee hereunder as to each separate estate.

SECTION 7.06. Applicable Law. This Mortgage shall be governed by, and construed
in accordance with, the internal law of the State in which the Mortgaged
Property is located without regard to principles of conflicts of laws, except
that the internal laws of the State of New York (without regard to principles of
conflicts of laws) shall govern (i) those terms and conditions contained in the
Notes and the Credit Agreement which are incorporated by reference herein and
(ii) the resolution of issues arising under the Notes and the Credit Agreement
to the extent that such resolution is necessary to the interpretation of this
Mortgage.

SECTION 7.07. Sole Discretion of Mortgagee. Except as expressly provided herein,
whenever Mortgagee's judgment, consent or approval is required hereunder for any
matter, or shall have an option or election hereunder, such judgment, the
decision whether or not to consent to or approve the same or the exercise of
such option or election shall be in the sole discretion of Mortgagee.

SECTION 7.08.     Provisions as to Covenants and

                                       21
<PAGE>

Agreements. All of Mortgagor's covenants and agreements hereunder shall run with
the land and time is of the essence as to the time periods stated herein in
which such covenants and agreements are to be performed.

SECTION 7.09. Matters to be in Writing. This Mortgage cannot be altered,
amended, modified, terminated, waived, released or discharged except in a
writing signed by the party against whom enforcement is sought.

SECTION 7.10. Submission to Jurisdiction. Without limiting the right of
Mortgagee to bring any action or proceeding against the undersigned or its
property arising out of or relating to the Obligations (an "Action") in the
courts of other jurisdictions, Mortgagor hereby irrevocably submits to the
jurisdiction of the state court or Federal court in each jurisdiction in which
the Mortgaged Property is located, and Mortgagor hereby irrevocably agrees that
any Action may be heard and determined in such state or federal court. Mortgagor
hereby irrevocably waives, to the fullest extent that it may effectively do so,
the defense of an inconvenient forum to the maintenance of any Action in the
jurisdiction. Mortgagor hereby agrees that the summons and complaint or any
other process in any Action may be served in accordance with the rules of the
applicable jurisdiction.

SECTION 7.11.     Construction of Provisions. The following rules of
construction shall be applicable for all purposes of this Mortgage and all
documents or instruments supplemental hereto, unless the context otherwise
requires:

(a) All Article, Section and Exhibit captions herein are used for reference only
and in no way limit or describe the scope or intent of, or in any way affect,
this Mortgage.

(b) The terms "include", "including" and similar terms shall be construed as if
followed by the phrase "without being limited to".

(c) The terms "Land", "Improvements", "Equipment", "Mortgaged Property" and
"Premises" shall be construed as if followed by the phrase "or any part
thereof".

(d) The term "Obligations" shall be construed as if followed by the phrase "or
any other sums secured hereby, or any part thereof".

(e) Words of masculine, feminine or neuter gender shall mean and include the
correlative words of the other genders, and words importing the singular number
shall mean and include the plural number, and vice versa.

(f) The term "person" shall include natural persons, firms, partnerships,
corporations and any other public and private legal entities.

(g) The term "provisions", when used with respect hereto or to any other
document or instrument, shall be construed as if preceded by the phrase "terms,
covenants, agreements, requirements, conditions and/or".

(h) The cover page of and all recitals set forth in, and all Exhibits to, this
Mortgage are hereby incorporated in this Mortgage.

                                       22
<PAGE>

(i) All obligations of Mortgagor hereunder shall be performed and satisfied by
or on behalf of Mortgagor at Mortgagor's sole cost and expense.

(j) The term "lease" shall mean "tenancy, subtenancy, lease or sublease", the
term "lessor" shall mean "landlord, sublandlord, lessor and sublessor" and the
term "lessee" shall mean "tenant, subtenant, lessee and sublessee".

(k) No inference in favor of or against any party shall be drawn from the fact
that such party has drafted any portion hereof.

(l) Terms capitalized herein that are not defined herein shall have the meanings
set forth for them in the Credit Agreement.

(m) In the event that any inconsistencies between the terms of the Credit
Agreement and the terms of this Mortgage are discerned, the terms of the Credit
Agreement shall govern.

SECTION 7.12. Successors and Assigns. The provisions hereof shall be binding
upon Mortgagor and the heirs, devisees, representatives, successors and
permitted assigns of Mortgagor, including successors in interest of Mortgagor in
and to all or any part of the Mortgaged Property, and shall inure to the benefit
of Mortgagee, the holders of the Obligations and their respective heirs,
successors, legal representatives, substitutes and assigns. Where two or more
persons have executed this Mortgage, the obligations of such persons shall be
joint and several.

SECTION 7.13.     Counterparts. This Mortgage may be executed in counterparts,
each of which shall be deemed to be an original, but all of which shall
constitute one and the same agreement.

SECTION 7.14. Agency. Mortgagee may deal with the Mortgaged Property and may
issue, as applicable, any release to be given hereunder pursuant to Section 4.02
or Section 6.01 hereof or grant any consent or approval or take any other
action, required or permitted hereunder, without reference to or the approval of
the holders of the Obligations and any third party (including any title
insurance company issuing a title insurance policy, or a commitment to issue a
title insurance policy, in connection with the Mortgaged Property) may
conclusively rely on the due authority of Mortgagee to do any or all of the
foregoing.

SECTION 7.15. The Security Agreement. In the event that a valid and enforceable
security interest has been created in any of the Mortgaged Property under the
terms of the Borrower Security Agreement and the terms of the Borrower Security
Agreement are inconsistent with the terms of this Mortgage, then with respect to
such Mortgaged Property, the terms of the Borrower Security Agreement shall be
controlling in the case of Equipment and the terms of this Mortgage shall be
controlling in all other cases.


                                  ARTICLE VIII

                  Fixture Filing

SECTION 8.01.     Fixture Filing. A portion of the Mortgaged Property is or is
to become fixtures upon the Premises. To the

                                       23
<PAGE>

extent permitted by applicable law, Mortgagor covenants and agrees that the
filing of this Mortgage in the real estate records of the county or other
municipality in which the Mortgaged Property is located, as applicable, shall
also operate from the time of filing as a fixture filing with respect to all
goods constituting part of the Mortgaged Property which are or are to become
fixtures related to the real estate described herein. For such purpose, the
following information is set forth:

(a) Name and Address of Debtor:
Mortgagor, a Connecticut corporation, having an address at 107 Selden Street,
Berlin, Connecticut 06037.

(b) Name and Address of Secured Party:

Citibank, N.A., as collateral agent for the Lenders listed on Exhibit B hereto,
having an address at 111 Wall Street, 5th Floor, New York, New York 10005,
Attention: Florence Mills, Senior Trust Officer.

(c) This document covers goods which are or are to become fixtures.

(d) The name of the record owner is Northeast Generation Company.

                                       24
<PAGE>

IN WITNESS WHEREOF, the undersigned has executed under seal this Mortgage the
day first set forth above.

Signed, sealed and delivered Mortgagor in the presence of the following
   witnesses:

By:
      Name:
Name:                                          Title:
Address:


Name:
Address:
By:
      Name:
Name:                                          Title:
Address:

[Corporate Seal]
Name:
Address:                             [Address]

                                       25
<PAGE>

                                 ACKNOWLEDGMENT

STATE OF                            )
)        ss.:
COUNTY                                   )

On this __ day of March, 2000, before me, the undersigned officer, personally
appeared ___________________, personally known and acknowledged
[himself][herself] to me to be the ___________________ of Northeast Generation
Company, a Connecticut Corporation, that as such officer, being duly authorized
to do so pursuant to its bylaws or a resolution of its board of directors,
executed and acknowledged the foregoing instrument for the purposes therein
contained as [his][her] free and voluntary act and deed.

IN WITNESS WHEREOF, I hereunto set my hand and official seal.



- ------------------------------
Notary Public


[Notary Seal/stamp]                       My Commission Expires:

- ------------------------------

                                       26
<PAGE>

                                   SCHEDULE 1

                                 List of Lenders


Lender                                      Address

Citibank, N.A.                              Citibank, N.A.
399 Park Avenue
New York, New York 10043

Barclays Bank PLC                           Barclays Bank PLC
222 Broadway, 11th Floor
New York, New York 10038
Attention: Christine Francese

Canadian Imperial Bank of Commerce          Canadian Imperial Bank of Commerce
Two Paces West
2727 Paces Ferry Road, Suite 1200
Atlanta, Georgia 30339
Attention: Miriam McCart

Toronto Dominion (Texas), Inc.              Toronto Dominion (Texas), Inc.
909 Fannin Street, 17th Floor
Houston, Texas 77010
Attention: Alva J. Jones

Mees Pierson Capital Corp.                  Mees Pierson Capital Corp.
3 Stamford Plaza
301 Tresser Boulevard, 9th Floor
Stamford, Connecticut 06901-3239
Attention: Marlene Ellis

Union Bank of California, N.A.              Union Bank of California, N.A.
Energy Capital Services
445 S. Figueroa Street, 15th Floor
Los Angeles, California 90071
Attention: Jason DiNapoli

                                       27
<PAGE>

                                    EXHIBIT A

                               Description of Land

                                       28
<PAGE>

EXHIBIT F-2
FORM OF TRANCHE B MORTGAGE
This instrument was prepared by the attorney referenced below in consultation
with counsel admitted to practice in the state in which the property is located,
and when recorded, counterparts should be returned to:

Shearman & Sterling
599 Lexington Avenue
New York, New York 10022
Attention:  John L. Opar, Esq. (60/22)
          ===========================================================

                    TRANCHE B MORTGAGE, ASSIGNMENT OF LEASES
AND RENTS, SECURITY AGREEMENT AND FIXTURE FILING

                          NORTHEAST GENERATION COMPANY,
                                    Mortgagor

                                       to

           CITIBANK, N.A., as collateral agent for the Lenders listed
                  on Schedule 1 hereto and as provided herein,
                                    Mortgagee

                             Dated: March ___, 2000

This instrument is a mortgage, assignment of leases and rents, security
agreement and fixture filing. This instrument encumbers property located in
Connecticut, Massachusetts, New Hampshire and Vermont. The total outstanding
principal amount of indebtedness secured by this instrument shall not exceed
Eight Hundred Sixty-Five Million, Five Hundred Thousand Dollars ($865,500,000).
The latest potential date of maturity of the obligations secured hereunder is
December 29, 2000. This instrument contains after-acquired property provisions
and secures obligations containing provisions for changes in interest rates,
extensions of time for payment and other modifications in the terms of the
obligations.

The mailing address of Mortgagee (as hereinafter defined) is

Citibank, N.A., as Collateral Agent
111 Wall Street, 5th Floor
New York, New York 10005
Attention: Florence Mills, Senior Trust Officer

                                       29
<PAGE>
                                TABLE OF CONTENTS

Page

Recitals....................................................................

ARTICLE I         Representations, Warranties and Covenants of Mortgagor

SECTION 1.01.  Payment of Obligations.......................................4
SECTION 1.02.  Warranty of Title............................................4
SECTION 1.03.  Operation and Maintenance....................................5
SECTION 1.04.  Insurance....................................................6
SECTION 1.05.  Liens and Liabilities........................................6
SECTION 1.06.  Taxes and Other Charges......................................7
SECTION 1.07.  Damage and Destruction.......................................8
SECTION 1.08.  Condemnation.................................................8
SECTION 1.09.  Contest......................................................9

ARTICLE II        Assignment of Leases, Rents and Other Sums

SECTION 2.01.  Assignment..................................................10
SECTION 2.02.  Leases and Rents............................................11

ARTICLE III       Additional Advances; Expenses; Indemnity

SECTION 3.01.  Additional Advances and Disbursements.......................13
SECTION 3.02.  Other Expenses..............................................14
SECTION 3.03.  Indemnity...................................................14
SECTION 3.04.  Interest After Default......................................14

ARTICLE IV        Sale or Transfer of the Premises

SECTION 4.01.  Continuous Ownership........................................15

ARTICLE V         Defaults and Remedies

SECTION 5.01.  Events of Default...........................................16
SECTION 5.02.  Remedies....................................................16
SECTION 5.03.  Rights Pertaining to Sales..................................18
SECTION 5.04.  Expenses....................................................21
SECTION 5.05.  Application of Proceeds.....................................21
SECTION 5.06.  Additional Provisions as to Remedies........................22
SECTION 5.07.  Waiver of Rights and Defenses...............................23

ARTICLE VI        Release of Lien

SECTION 6.01.  Release of Lien.............................................23

                        ARTICLE VII Additional Provisions

SECTION 7.01.  Provisions as to Payments, Advances.........................24
SECTION 7.02.  Separability................................................24
SECTION 7.03.  Notices.....................................................24
SECTION 7.04.  Right to Deal...............................................25
SECTION 7.05.  Continuation of Lease.......................................25
SECTION 7.06.  Applicable Law..............................................25
SECTION 7.07.  Sole Discretion of Mortgagee................................26


                                       30
<PAGE>

SECTION 7.08.  Provisions as to Covenants and Agreements...................26
SECTION 7.09.  Matters to be in Writing....................................26
SECTION 7.10.  Submission to Jurisdiction..................................26
SECTION 7.11.  Construction of Provisions..................................26
SECTION 7.12.  Successors and Assigns......................................27
SECTION 7.13.  Counterparts................................................28
SECTION 7.14.  Agency......................................................28
SECTION 7.15.  The Security Agreement......................................28

ARTICLE VIII      Fixture Filing

SECTION 8.01.  Fixture Filing..............................................28

                                       31
<PAGE>

                                                                            PAGE


Exhibit A         Description of Land
Exhibit B         List of Lenders

                                       32

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-12
<SEQUENCE>14
<FILENAME>0014.txt
<DESCRIPTION>EXHIBIT 12
<TEXT>


NORTHEAST UTILITIES                                                   Exhibit 12

Ratio of Earnings to Fixed Charges

(Thousands of Dollars)
<TABLE>
<CAPTION>

                                               YEAR         YEAR         YEAR         YEAR         YEAR
                                               1996         1997         1998         1999         2000
                                             ---------    ---------    ---------    ---------    ---------
<S>                                          <C>          <C>          <C>          <C>          <C>
Earnings, as defined:

    Net income (loss) before
      extraordinary item                     $  38,929    $(129,962)   $(146,753)   $  34,216    $ 205,295
       Income taxes                             96,110        1,948        5,939       98,611      161,725
       Equity in earnings of regional
         nuclear generating and
         transmission companies                 (6,649)      (4,653)      (1,456)      (2,905)     (13,667)
       Minority interest                         9,300        9,300        9,300        9,300        9,300
       Fixed charges, as below                 298,193      291,348      292,622      279,851      311,176
                                             ---------    ---------    ---------    ---------    ---------
    Total earnings, as defined:              $ 435,883    $ 167,981    $ 159,652    $ 419,073    $ 673,829
                                             =========    =========    =========    =========    =========

Fixed Charges, as defined:

    Interest on long-term debt               $ 285,463    $ 282,095    $ 273,824    $ 258,093    $ 200,697
    Other interest                              (7,470)     (10,114)      (4,735)       5,558       98,605
    Rental interest factor - capital            14,100       13,600       18,300       13,700        8,657
    Rental interest factor - 1/3 operating       6,100        5,767        5,233        2,500        3,217
                                             ---------    ---------    ---------    ---------    ---------
    Total fixed charges, as defined          $ 298,193    $ 291,348    $ 292,622    $ 279,851    $ 311,176
                                             =========    =========    =========    =========    =========

Ratio of earnings to fixed charges                1.46         0.58         0.55         1.50         2.17
                                             =========    =========    =========    =========    =========
</TABLE>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13.1
<SEQUENCE>15
<FILENAME>0015.txt
<DESCRIPTION>ANNUAL REPORT OF CL&P
<TEXT>



                               2000 Annual Report

            The Connecticut Light and Power Company and Subsidiaries

                                     Index


Contents                                                                Page
- --------                                                                ----

Management's Discussion and Analysis of Financial
  Condition and Results of Operations.............................        1

Report of Independent Public Accountants..........................       12

Consolidated Statements of Income.................................       13

Consolidated Statements of Comprehensive Income...................       13

Consolidated Balance Sheets.......................................     14-15

Consolidated Statements of Common Stockholder's Equity............       16

Consolidated Statements of Cash Flows.............................       17

Notes to Consolidated Financial Statements........................       18

Selected Consolidated Financial Data..............................       41

Consolidated Quarterly Financial Data (Unaudited).................       41

Consolidated Statistics (Unaudited)...............................       42

Preferred Stockholder and Bondholder Information..................   Back Cover




The Connecticut Light and Power Company and Subsidiaries

- -------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
- -------------------------------------------------------------------------------

FINANCIAL CONDITION
- -------------------

Overview
- --------

The Connecticut Light and Power Company's (CL&P or the company), the Northeast
Utilities (NU) system's (NU system) largest operating subsidiary, earnings
totaled $148.1 million in 2000, compared with a loss of $13.6 million in 1999
and $195.7 million in 1998.  The 2000 results represented CL&P's first annual
profit since 1995.  CL&P benefited from the return to service of the
Millstone 2 unit in May 1999 and the strong performance of the Millstone 2
and 3 units in 2000.  Millstone 2 operated at a capacity factor of 82 percent
in 2000, while Millstone 3 operated at a capacity factor of virtually 100
percent in 2000.  However, management projects that CL&P's earnings will
decline in 2001 as a result of the expected sale of CL&P's share of the
Millstone units, other rate adjustments and the pending resolution of the
over-earnings docket.  Although CL&P's earnings are expected to decline, its
return on equity is not expected to be compromised.

In 2000, CL&P's revenues increased to $2.94 billion, up 20 percent from $2.45
billion in 1999, primarily due to higher wholesale revenues.  Revenues were
$2.39 billion in 1998.  This growth in revenues was offset by a 5 percent
retail rate decrease on January 1, 2000, for customers of CL&P.

Consolidated Edison, Inc. Merger
- --------------------------------

In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the
approvals needed to complete the merger announced in October 1999.
Shareholders from both companies approved the merger in April 2000, and all
state regulatory approvals were granted by the end of the year.  Additionally,
the Federal Energy Regulatory Commission (FERC) approved the merger in May
2000, the Nuclear Regulatory Commission approved the transaction in August
2000, and the United States Department of Justice approved the merger in
February 2001.  Necessary approval from the Securities and Exchange Commission
(SEC) was expected to be received in mid-March 2001.

On February 28, 2001, NU's Board of Trustees requested that Con Edison provide
reasonable assurance, in writing, that it intended to comply with the terms of
the definitive merger agreement between the two companies.  This included
assurances that Con Edison would consummate the pending merger at the price
set forth in the agreement promptly following the receipt of SEC approval.
The original request for assurance was to be received by March 2, 2001, however
that date was later extended to March 5, 2001.  On March 5, 2001, Con Edison
advised NU that it was not willing to close the merger on the agreed terms.
NU notified Con Edison that it was treating its refusal to proceed on the terms
set forth in the merger agreement as a repudiation and breach of the merger
agreement, and that NU would file suit to obtain the benefits of the
transaction as negotiated for NU shareholders.  On March 6, 2001, Con Edison
filed suit in the U.S. District Court for the Southern District of New York
(Southern District), seeking declaratory judgment that NU failed to satisfy
conditions precedent under the merger agreement.  On March 12, 2001, NU filed
suit against Con Edison in the Southern District seeking damages in excess of
$1 billion arising from Con Edison's breach of the merger agreement.  NU cannot
predict the outcome of this matter nor its effect on NU.

Liquidity
- ---------

CL&P's net cash flows provided by operating activities decreased to $259.9
million in 2000 compared to $299.4 million in 1999 and $364.1 million in 1998.
Reductions in depreciation and amortization expense, primarily as a result of
industry restructuring resulted in a decrease in net cash flows from
operations.  Industry restructuring in Connecticut required a retail rate
reduction of 5 percent on January 1, 2000, further reducing cash flows from
operations.  These decreases were offset by a $161.7 million increase in net
income for the year ended December 31, 2000, compared with the same periods in
1999 and 1998 which increased cash flows from operating activities.  Finally,
the payment of taxes which occurred in 2000 related to the 1999 sale of
generation assets, also decreased cash flows from operations.  Cash flows from
operations partially met the payment of CL&P's common and preferred dividends
($79.4 million) and investments in electric utility plant, nuclear fuel and
nuclear decommissioning trusts ($269.1 million).  The level of common dividends
totaled $72 million in 2000, as compared to no common dividends paid in 1999
and 1998.  The level of preferred dividends decreased to $7.4 million in
2000, compared with $12.8 million in 1999 and $14.1 million in 1998, reflecting
CL&P's ongoing effort to reduce preferred stock outstanding.  CL&P currently
forecasts construction expenditures ranging from $206 million to $231.1 million
for the year 2001.

The transfer of 1,289 megawatts (MW) of hydroelectric generation assets to
Northeast Generation Company, an affiliated company, from CL&P and Western
Massachusetts Electric Company (WMECO) in March 2000, produced a significant
source of cash for CL&P and WMECO.  CL&P used this cash to retire long-term
debt, preferred stock and to return equity capital to the parent company.
Financing activities for 2000 included $578.6 million for the retirement of
long-term debt, preferred stock and common stock, compared with $639.8 million
for 1999 and $80.7 million in 1998.

In November 2000, CL&P and WMECO reduced their revolving credit agreement to
$350 million from $500 million to reflect lower borrowing needs post-
restructuring.  This agreement was renewed with more favorable terms as a
result of the NU system's improving credit profile.  In January 2001, Moody's
Investors Service and Standard and Poor's upgraded their credit ratings for
CL&P primarily as a result of the anticipated sale of the Millstone units and
NU's general financial recovery.  In February 2001, Fitch IBCA upgraded its
credit ratings for CL&P.  These upgrades return CL&P's unsecured debt to
investment grade ratings for the first time in five years and will save the
NU system in excess of $4.7 million annually in financing costs.

For further information regarding CL&P's borrowing facilities, see Note 2,
"Short-Term Debt," to the consolidated financial statements.

In 2001, NU expects to reduce the capitalization of its regulated electric
operating companies significantly as a result of continued asset sales and
securitization of stranded costs.  CL&P expects to receive gross proceeds
of $843.2 million as a result of the sale of its ownership interests in the
Millstone units to Dominion Resources, Inc. (Dominion).  This sale is expected
to close as early as the end of March 2001.  The cash proceeds are expected
to be used to repay subsidiary debt and capital lease obligations and to
return equity capital to the parent company.

By the end of 2002, CL&P expects to complete the auction of its share of the
Seabrook Station nuclear unit (Seabrook).  Cash proceeds will be used to
retire debt and to return equity capital to the parent company.

In November 2000, the Connecticut Department of Public Utility Control (DPUC)
approved CL&P's request to securitize an amount not to exceed $1.55 billion
of approved, eligible stranded costs, primarily related to above-market
purchased-power contracts and generation-related regulatory assets.  CL&P
plans to use approximately $400 million of those proceeds to reduce debt with
the remaining proceeds to be used to buydown and buyout above-market
purchased-power contracts and to return equity capital to the parent company.
However, the Office of Consumer Counsel (OCC) has appealed the securitization
order to the Connecticut Superior Court.  On March 1, 2001, CL&P and the OCC
entered into an agreement to settle this issue.  Under the agreement, pending
DPUC approval, the OCC agreed to withdraw its appeal of the securitization
order and not take any action that would affect the timing and the amount of
securitization financing to be undertaken.  The DPUC approved the agreement
on March 12, 2001.  The OCC withdrew its appeal on March 16, 2001.
Securitization for CL&P is expected to take place by the end of the
first quarter 2001.

Restructuring
- -------------

As a result of industry restructuring, CL&P stopped supplying power directly
to customers in 2000.  Instead, CL&P became an energy delivery company,
delivering electricity to customers that is produced by other companies and
sometimes bought by customers through intermediaries.  In 2000, customers in
Connecticut had the option of choosing alternative power suppliers or relying
on CL&P to acquire the power for them through standard offer service.  To date
virtually all customers are receiving power through standard offer service.
In 1999, under the oversight of the DPUC, CL&P secured four-year fixed-price
contracts with three suppliers to provide power to customers who choose
standard offer service.  CL&P is fully recovering from retail customers the
cost of buying power from these three standard offer suppliers and expects to
continue recovery through the expiration of the contracts on December 31, 2003.
As of January 1, 2000, Select Energy, Inc. (Select Energy), an affiliated
company, became responsible for 50 percent of CL&P's standard offer load for
the entire standard offer period, or approximately 2,000 MW annually at peak.
Two other unaffiliated suppliers became responsible for the balance of CL&P's
standard offer load also for the entire standard offer period.

CL&P continues to generate power through either direct ownership of generating
plants, such as Millstone 2 and 3 and Seabrook, or through purchased-power
contracts.  CL&P sold its share of the capacity associated with Millstone 2
and 3 and Seabrook to Select Energy and five unaffiliated companies.  These
contracts will expire on December 31, 2001.  The revenues generated from these
contracts are expected to recover CL&P's share of the nuclear operating costs
through the divestiture of the Millstone units.

For further information regarding commitments and contingencies related to
restructuring, see Note 9A, "Commitments and Contingencies - Restructuring,"
to the consolidated financial statements.

Regional Transmission Organization
- ----------------------------------

Pursuant to FERC Order 888 (issued in April 1996), the NU system companies,
including CL&P, operate their transmission system under an open access,
nondiscriminatory transmission tariff.

In December 1999, the FERC issued an order calling on all transmission owners
to voluntarily join Regional Transmission Organizations (RTOs) in order to
boost competition in electric markets.  In general, each of these organizations
would be an independent operator over all transmission facilities, and would
perform, among other functions, tariff administration, construction planning
and reliability management for the particular regional transmission system.
NU's active voting interest in such an organization would be limited to 5
percent under the proposal.

The NU system companies, including CL&P, and other parties have appealed this
order.  Of primary concern to NU is the ratemaking authority granted to RTOs
and its impact on the ability of transmission owners to earn appropriate
returns on their transmission investment under the organizational structure
and the minimum functions proposed in the order.  The NU system companies,
including CL&P, were required to participate in a collaborative process
established by the FERC beginning in March of 2000.  On January 16, 2001,
NU along with the Independent System Operator and five other New England
transmission owning utilities filed a proposal to establish a New England RTO.

Nuclear Plant Performance and Divestiture
- -----------------------------------------

Millstone
The Millstone units completed one of their best years ever in 2000.
Millstone 2 operated at a capacity factor of 82 percent in 2000 and completed
a refueling outage in early June more than four days ahead of schedule.
The 40-day, 21-hour outage set a world record for a refueling that included a
full generator rewind.  Millstone 3 operated at virtually a 100 percent
capacity factor in 2000 and ran for 585 consecutive days before beginning a
scheduled refueling outage on February 3, 2001.  Millstone 3 is expected to
return to service by the end of the first quarter of 2001.

On August 7, 2000, CL&P and certain other joint owners reached an agreement
to sell substantially all of the Millstone units, located in Waterford,
Connecticut, to Dominion, for approximately $1.3 billion, including
approximately $105 million for nuclear fuel.  Dominion has also agreed to
assume responsibility for decommissioning the three units and NU will transfer
to Dominion all funds in the Millstone decommissioning trust.  Additionally,
NU is obligated to top-off the decommissioning trust if its value does not
equal an agreed upon amount at closing.  That amount is pursuant to the
purchase and sale agreement (PSA) with Dominion, subject to adjustment for
delays in the closing of the sale and Millstone 1 not meeting the "cold and
dark" condition specified in the PSA.

If the transaction is consummated as proposed, CL&P would receive gross
proceeds of approximately $843.2 million on a pretax basis for its respective
ownership interest.  The proceeds from the sale of this interest will be used
to reduce the company's stranded costs under restructuring and the cash
proceeds will be used to repay subsidiary debt and capital lease obligations
and to return equity capital to the parent company.

In preparation for the divestiture of the Millstone units, it was discovered
that two full-length irradiated fuel rods are missing.  NU believes that the
two rods remain stored in the Millstone 1 spent fuel pool or were shipped in
a shielded cask to a facility licensed to accept radioactive material.
NU's investigation into the location of the two rods is ongoing.
NU is responsible for any potential liabilities, which are not determinable
at this time, related to these missing fuel rods.

NU currently expects to close on the sale of Millstone as early as the end
of March 2001.

Seabrook
Seabrook operated at a capacity factor of 78 percent in 2000.  The unit began a
scheduled refueling outage on October 21, 2000.  The outage was extended by
approximately two months as a result of the need to repair extensive problems
with a back-up diesel generator.  Seabrook returned to service on January 29,
2001.

On December 15, 2000, NU filed its divestiture plan for Seabrook, including
CL&P's 4.06 percent ownership interest, with the New Hampshire Public Utilities
Commission and the DPUC.  NU hopes to complete the sale in 2002.

Yankee Companies
In 1999, the Vermont Yankee Nuclear Power Corporation (VYNPC) agreed to sell
its nuclear generating unit for $22 million to an unaffiliated company.  Among
other commitments, the acquiring company agreed to assume the obligation to
decommission the unit after it is taken out of service, and the owners of VYNPC
(including CL&P) agreed to fund their shares of the decommissioning costs up to
a negotiated amount.  Subsequent to the time that agreement was executed, the
original proposed acquiring company increased its purchase price and three
other unaffiliated companies have indicated their interest in buying VYNPC's
generating unit on terms that have not been disclosed.  On February 14, 2001,
the Vermont Public Service Board dismissed the acquiring company's petition for
approval and VYNPC agreed to work with the Vermont regulators to develop an
auction process for the sale of the unit.  At present, CL&P expects that the
unit will be sold, but the identity of the owner and the terms of sale,
including price, future decommissioning obligations and future power purchase
obligations, are not known.

Nuclear Decommissioning
In connection with the aforementioned sale of the Millstone units, Dominion has
agreed to assume responsibility for decommissioning the Millstone units.

For further information regarding nuclear decommissioning, see Note 10,
"Nuclear Decommissioning and Plant Closure Costs," to the consolidated
financial statements.

Spent Nuclear Fuel Disposal Costs
The United States Department of Energy (DOE) originally was scheduled to begin
accepting delivery of spent nuclear fuel in 1998.  However, delays in
confirming the suitability of a permanent storage site continually have
postponed plans for the DOE's long-term storage and disposal site.  Extended
delays or a default by the DOE could lead to consideration of costly
alternatives.  CL&P has the primary responsibility for the interim storage of
its spent nuclear fuel prior to divestiture of its nuclear units.

For further information regarding spent nuclear fuel disposal costs, see
Note 9D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs,"
to the consolidated financial statements.

Other Matters
- -------------

Environmental Matters
CL&P is subject to environmental laws and regulations structured to mitigate
or remove the effect of past operations and to improve or maintain the quality
of the environment.  For further information regarding environmental matters,
see Note 9C, "Commitments and Contingencies - Environmental Matters," to the
consolidated financial statements.

Other Commitments and Contingencies
For further information regarding other commitments and contingencies, see
Note 9, "Commitments and Contingencies," to the consolidated financial
statements.

Forward Looking Statements
This discussion and analysis includes forward looking statements, which are
statements of future expectations and not facts including, but not limited
to, statements regarding future earnings, refinancings, the use of proceeds
from restructuring, and the recovery of operating costs.  Words such as
estimates, expects, anticipates, intends, plans, and similar expressions
identify forward looking statements.  Actual results or outcomes could differ
materially as a result of further actions by state and federal regulatory
bodies, competition and industry restructuring, changes in economic conditions,
changes in historical weather patterns, changes in laws, developments in legal
or public policy doctrines, technological developments, and other presently
unknown or unforeseen factors.

RESULTS OF OPERATIONS
- ---------------------

The components of significant income statement variances for the past two
years are provided in the table below.


                                          Income Statement Variances
                                             (Millions of Dollars)

                               2000 over/(under) 1999   1999 over/(under) 1998
                               -----------------------------------------------
                                  Amount    Percent        Amount    Percent
                                  ------    -------        ------    -------

Operating Revenues                 $483        20%          $  66        3%

Operating Expenses:
Fuel, purchased and
  net interchange power             738        80            (143)     (13)
Other operation                     (68)      (14)            (41)      (8)
Maintenance                         (82)      (38)            (53)     (20)
Depreciation                        (76)      (39)            (23)     (10)
Amortization of regulatory
  assets, net                      (350)      (78)            327       (a)
Federal and state
  income taxes                        9         7             134       (a)
Taxes other than income taxes       (37)      (21)              4        3
Gain on sale of utility plant       286       100            (286)       -
                                   ----       ---            ----      ---
Total operating expenses            420        18             (81)      (3)
                                   ----       ---            ----      ---

Operating income                     63        36             147       (a)
                                   ----       ---            ----      ---

Other Income:
Equity in earnings of
  regional nuclear
  generating companies                7        (a)             (5)     (76)
Nuclear related costs                39        73              90       63
Other, net                           19        73             (20)      (a)
Other income taxes                   (6)      (16)            (30)     (45)
                                   ----       ---            ----      ---
Net other income                     59        (a)             35       42
Interest charges, net               (40)      (29)              -        -
                                   ----       ---            ----      ---
Net income/(loss)                  $162        (a)           $182       93
                                   ====       ===            ====      ===

(a) Percent greater than 100.

Operating Revenues
Operating revenues increased by $483 million or 20 percent in 2000, primarily
due to higher wholesale revenues ($510 million), primarily as a result of the
sale of the output from Millstone 2 and 3, and the amortization of the gain
on the transfer of certain hydroelectric generation assets ($25 million)
partially offset by lower retail revenues ($51 million).  Retail revenues
decreased primarily as a result of a 5 percent retail rate decrease ($108
million), partially offset by higher retail sales ($27 million) and by the
impact of Millstone 2 being returned to rate base ($30 million).  Retail sales
increased by 0.4 percent in 2000.

Operating revenues increased by $66 million or 3 percent in 1999, primarily due
to higher wholesale revenues ($72 million).  The wholesale revenue increase is
primarily due to higher energy sales and related capacity and transmission
revenues.  Retail revenues decreased primarily due to a retail rate reduction
($55 million) and lower fuel clause revenues ($33 million), partially offset by
the impact of Millstone 2 and 3 being returned to CL&P's rate base ($13
million) and higher retail sales ($62 million).  Retail kilowatt-hour sales
increased by 2.9 percent.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased in 2000, primarily
due to the transition, under industry restructuring, of purchasing full
requirements for customers from standard offer suppliers, in addition to the
remaining fuel costs of the nuclear units and cogenerators.

Fuel, purchased and net interchange power expense decreased in 1999, primarily
due to lower replacement power costs due to the return to service of Millstone
2 and 3, partially offset by higher purchased-power costs as a result of a
high sales demand.

Other Operation and Maintenance
Other operation and maintenance (O&M) expenses decreased in 2000, primarily due
to lower spending at the nuclear units ($56 million), the decommissioning
status of Millstone 1 ($14 million), lower expenses due to the sale of certain
fossil generation assets ($65 million), and lower administrative and general
expenses ($26 million), partially offset by higher customer service expenses
($39 million).

Other O&M expenses decreased in 1999, primarily due to lower costs at the
Millstone units ($107 million), lower conservation and load management
amortization ($14 million), and lower fossil O&M expenses ($7 million),
partially offset by the recognition of environmental insurance proceeds in
1998 ($9 million), higher transmission expenses ($12 million), and higher
storm costs ($12 million).

Depreciation
Depreciation expense decreased in 2000, primarily due to the effect of
discontinuing Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation," for the generation portion
of the business and the resulting reclassification of depreciable nuclear plant
balances to regulatory assets ($70 million), the sale of certain fossil
generation assets and the transfer of certain hydroelectric generation assets.

Depreciation decreased in 1999 primarily due to the retirement of Millstone 1.

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased in 2000, primarily due to
changes in amortization levels as a result of industry restructuring ($128
million), the amortization in 1999 of the gain on the sale of fossil plants
($286 million), and the completion of the amortization of CL&P's cogeneration
deferral in the first quarter of 1999 ($6 million).  These decreases were
partially offset by higher amortization associated with the reclassified
nuclear plant balances ($70 million).

Amortization of regulatory assets, net increased in 1999, primarily due to
the increased amortization associated with the gain on the sale of fossil
generation assets ($286 million), the amortization of CL&P's Millstone 1
remaining investment ($51 million) and the amortization associated with the
reclassified nuclear plant balances transferred to regulatory assets ($19
million).  These increases were partially offset by the completion of the
amortization of the cogeneration deferral in the first quarter of 1999
($23 million).

Federal and State Income Taxes
Federal and state income taxes increased in 2000 and 1999, primarily due
to higher book taxable income.

Taxes Other Than Income Taxes
Taxes other than income taxes decreased in 2000, primarily due to lower
Connecticut gross earnings tax ($18 million) and lower local property taxes
($7 million).

Gain on Sale of Utility Plant
CL&P recorded a gain on the sale of its fossil generation assets in 1999.
A corresponding amount of amortization expense was recorded.

Equity Earnings of Regional Nuclear Generating Companies
Equity earnings of regional nuclear generating companies increased in 2000,
primarily due to higher earnings from the Connecticut Yankee Atomic Power
Company (CYAPC) as a result of a favorable rate settlement.

Equity earnings of regional nuclear generating companies decreased in 1999,
primarily due to lower earnings from CYAPC.

Nuclear Related Costs
Nuclear related costs in 2000 are comprised of the settlement of Millstone 3
joint owner litigation, net of insurance proceeds ($9 million) and a settlement
with the town of Wallingford ($5 million).

In comparison, nuclear related costs in 1999 are comprised of one-time charges
related to the write-off of capital projects as a result of the Connecticut
standard offer decision ($11 million), the settlement of Millstone 3 joint
owner litigation, net of insurance proceeds ($22 million) and the write-off
of Connecticut Municipal Electric Energy Cooperative (CMEEC) nuclear costs
($20 million).  Nuclear related costs in 1998 are comprised of a write-off
of the Millstone 1 entitlement formerly held by CMEEC ($28 million), and the
write-off of an unrecoverable Millstone 1 cost as a result of the February
1999 rate decision ($115 million).

Other, Net
Other, net, increased in 2000, primarily due to the 1999 write-off of stranded
costs in relation to the treatment of market-based contracts ($15 million).

Other, net, decreased in 1999, primarily due to the 1999 write-off of stranded
costs in relation to the treatment of market-based contracts.

Interest Charges, Net
Interest charges, net, decreased in 2000, primarily due to reacquisitions and
retirements of long-term debt in 2000.


REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
- ----------------------------------------

To the Board of Directors
   of The Connecticut Light and Power Company:

We have audited the accompanying consolidated balance sheets of The Connecticut
Light and Power Company (a Connecticut corporation and a wholly owned
subsidiary of Northeast Utilities) and subsidiaries as of December 31, 2000
and 1999, and the related consolidated statements of income, comprehensive
income, common stockholder's equity and cash flows for each of the three
years in the period ended December 31, 2000.  These financial statements are
the responsibility of the company's management.  Our responsibility is to
express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.  We believe that
our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of The Connecticut Light
and Power Company and subsidiaries as of December 31, 2000 and 1999, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States.



                                    /s/ ARTHUR ANDERSEN LLP
                                        ARTHUR ANDERSEN LLP



Hartford, Connecticut
January 23, 2001 (except with
respect to the matter discussed
in Note 15, as to which the
date is March 13, 2001)


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31,                        2000         1999         1998
- ------------------------------------------------------------------------------------------
                                                            (Thousands of Dollars)
<S>                                                 <C>          <C>          <C>
Operating Revenues................................. $ 2,935,922  $ 2,452,855  $ 2,386,864
                                                    ------------ ------------ ------------
Operating Expenses:
  Operation -
    Fuel, purchased and net interchange power.....    1,665,806      927,989    1,070,677
    Other.........................................      412,230      480,138      520,518
  Maintenance......................................     136,141      217,961      271,317
  Depreciation.....................................     117,305      193,776      216,509
  Amortization of regulatory assets, net...........      97,315      447,776      120,884
  Federal and state income taxes...................     130,994      122,059      (11,642)
  Taxes other than income taxes....................     137,846      174,884      170,347
  Gain on sale of utility plant....................        -        (286,477)        -
                                                    ------------ ------------ ------------
        Total operating expenses...................   2,697,637    2,278,106    2,358,610
                                                    ------------ ------------ ------------
Operating Income...................................     238,285      174,749       28,254
                                                    ------------ ------------ ------------
Other Income/(Loss):
  Equity in earnings of regional nuclear
    generating companies...........................       8,246        1,506        6,241
  Nuclear related costs............................     (14,099)     (53,031)    (143,239)
  Other, net.......................................      (7,071)     (25,962)      (6,075)
  Minority interest in loss of subsidiary..........      (9,300)      (9,300)      (9,300)
  Income taxes.....................................      30,940       36,921       67,127
                                                    ------------ ------------ ------------
        Other income/(loss), net...................       8,716      (49,866)     (85,246)
                                                    ------------ ------------ ------------
        Income/(loss) before interest charges......     247,001      124,883      (56,992)
                                                    ------------ ------------ ------------

Interest Charges:
  Interest on long-term debt.......................      89,841      127,533      133,192
  Other interest...................................       9,025       10,918        5,541
                                                    ------------ ------------ ------------
        Interest charges, net......................      98,866      138,451      138,733
                                                    ------------ ------------ ------------

Net Income/(Loss).................................. $   148,135  $   (13,568) $  (195,725)
                                                    ============ ============ ============

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Net Income/(Loss).................................. $   148,135  $   (13,568) $  (195,725)
                                                    ------------ ------------ ------------
Other comprehensive income, net of tax:
  Unrealized gains on securities...................          90           38          638
  Minimum pension liability adjustments............        -            -            (260)
                                                    ------------ ------------ ------------
        Other comprehensive income, net of tax.....          90           38          378
                                                    ------------ ------------ ------------
Comprehensive Income/(Loss)                         $   148,225  $   (13,530) $  (195,347)
                                                    ============ ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.



THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
AT DECEMBER 31,                                                  2000           1999
- ----------------------------------------------------------------------------------------
                                                                (Thousands of Dollars)
<S>                                                          <C>           <C>
ASSETS
- ------

Utility Plant, at original cost:
  Electric................................................  $  5,756,098   $  5,811,126

     Less: Accumulated provision for depreciation.........     4,210,429      4,234,771
                                                            -------------  -------------
                                                               1,545,669      1,576,355
  Construction work in progress...........................       128,835        115,529
  Nuclear fuel, net.......................................        79,672         80,766
                                                            -------------  -------------
     Total net utility plant..............................     1,754,176      1,772,650
                                                            -------------  -------------
Other Property and Investments:
  Nuclear decommissioning trusts, at market...............       536,912        516,796
  Investments in regional nuclear generating
   companies, at equity...................................        41,395         54,472
  Other, at cost..........................................        33,708         36,696
                                                            -------------  -------------
                                                                 612,015        607,964
                                                            -------------  -------------
Current Assets:
  Cash....................................................         5,461            364
  Investment in securitizable assets......................        98,146        107,620
  Notes receivable from affiliated companies..............        38,000           -
  Receivables less accumulated provision for
   uncollectible accounts of $300 in 2000 and 1999........        29,245         19,680
  Accounts receivable from affiliated companies...........       103,763          3,390
  Fuel, materials and supplies, at average cost...........        36,332         37,603
  Prepayments and other...................................        32,291         35,163
                                                            -------------  -------------
                                                                 343,238        203,820
                                                            -------------  -------------
Deferred Charges:
  Regulatory assets.......................................     1,835,967      2,564,095
  Unamortized debt expense................................        14,794         16,323
  Prepaid pension.........................................       170,672        113,465
  Other...................................................        33,336         19,967
                                                            -------------  -------------
                                                               2,054,769      2,713,850
                                                            -------------  -------------

Total Assets..............................................  $  4,764,198   $  5,298,284
                                                            =============  =============
</TABLE>
The accompanying notes are an integral part of these financial statements.



THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
AT DECEMBER 31,                                                    2000           1999
- ------------------------------------------------------------------------------------------
                                                                  (Thousands of Dollars)
<S>                                                           <C>            <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------

Capitalization:
  Common stock, $10 par value - authorized
   24,500,000 shares; 7,584,884 shares outstanding in 2000
   and 12,222,930 shares outstanding in 1999................  $     75,849   $    122,229
  Capital surplus, paid in..................................       413,192        665,598
  Retained earnings.........................................       243,197        153,254
  Accumulated other comprehensive income....................           506            416
                                                              -------------  -------------
           Total common stockholder's equity................       732,744        941,497
  Preferred stock not subject to mandatory redemption.......       116,200        116,200
  Preferred stock subject to mandatory redemption...........          -            79,789
  Long-term debt............................................     1,072,688      1,241,051
                                                              -------------  -------------
           Total capitalization.............................     1,921,632      2,378,537
                                                              -------------  -------------
Minority Interest in Consolidated Subsidiary................       100,000        100,000
                                                              -------------  -------------
Obligations Under Capital Leases............................        39,910         50,969
                                                              -------------  -------------
Current Liabilities:
  Notes payable to banks....................................       115,000         90,000
  Notes payable to affiliated company.......................          -            11,700
  Long-term debt and preferred stock - current portion......       160,000        178,755
  Obligations under capital leases - current portion........        89,959         93,431
  Accounts payable..........................................       153,944        101,106
  Accounts payable to affiliated companies..................       122,106          3,215
  Accrued taxes.............................................        32,901        169,214
  Accrued interest..........................................        13,995         18,640
  Other.....................................................        31,324         26,347
                                                              -------------  -------------
                                                                   719,229        692,408
                                                              -------------  -------------
Deferred Credits and Other Long-term Liabilities:
  Accumulated deferred income taxes.........................       977,439        999,473
  Accumulated deferred investment tax credits...............        99,771        107,064
  Decommissioning obligation - Millstone 1..................       580,320        580,320
  Deferred contractual obligations..........................       160,590        238,142
  Other.....................................................       165,307        151,371
                                                              -------------  -------------
                                                                 1,983,427      2,076,370
                                                              -------------  -------------
Commmitments and Contingencies (Note 9)

Total Capitalization and Liabilities........................  $  4,764,198   $  5,298,284
                                                              =============  =============
</TABLE>
The accompanying notes are an integral part of these financial statements.



THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------
                                                                              Accumulated
                                                      Capital    Retained        Other
                                           Common    Surplus,    Earnings    Comprehensive
                                           Stock      Paid In       (a)         Income         Total
- -------------------------------------------------------------------------------------------------------
                                                         (Thousands of Dollars)


<S>                                      <C>        <C>         <C>                  <C>    <C>
Balance at January 1, 1998............   $122,229   $ 641,333   $ 419,972   $        -      $1,183,534

    Net loss for 1998.................                           (195,725)                    (195,725)
    Cash dividends on preferred stock.                            (14,139)                     (14,139)
    Capital stock expenses, net.......                  2,764                                    2,764
    Capital contribution from
      Northeast Utilities.............                 20,000                                   20,000
    Gain on repurchase of
      preferred stock.................                     59                                       59
    Other comprehensive income........                                                378          378
                                         ---------  ----------  ----------  --------------  -----------
Balance at December 31, 1998..........    122,229     664,156     210,108             378      996,871

    Net loss for 1999.................                            (13,568)                     (13,568)
    Cash dividends on preferred stock.                            (12,832)                     (12,832)
    Capital stock expenses, net.......                  1,442                                    1,442
    Allocation of benefits - ESOP.....                            (30,454)                     (30,454)
    Other comprehensive income........                                                 38           38
                                         ---------  ----------  ----------  --------------  -----------
Balance at December 31, 1999..........    122,229     665,598     153,254             416      941,497

    Net income for 2000...............                            148,135                      148,135
    Cash dividends on preferred stock.                             (7,402)                      (7,402)
    Cash dividends on common stock....                            (72,014)                     (72,014)
    Redemption of preferred stock.....                   (749)                                    (749)
    Repurchase of common stock........    (46,380)   (253,620)                                (300,000)
    Capital stock expenses, net.......                  1,963                                    1,963
    Tax benefit for 1993-1999 from
     reduction of NU parent
     losses (b).......................                             21,461                       21,461
    Allocation of benefits - ESOP.....                               (237)                        (237)
    Other comprehensive income........                                                 90           90
                                         ---------  ----------  ----------  --------------  -----------
Balance at December 31, 2000..........   $ 75,849   $ 413,192   $ 243,197   $         506   $  732,744
                                         =========  ==========  ==========  ==============  ===========
</TABLE>

(a) The company has no dividend restrictions.  However, the company has a 30%
    common equity test to meet and therefore, at December 31, 2000, cannot pay
    out approximately $152.9 million in equity.

(b) In June 1999, CL&P paid NU parent $30.5 million for NU shares issued from
    1992 through 1998 on behalf of its employees in accordance with NU's 401(k)
    plan.  This transaction resulted in a reduction of the NU parent loss and
    a tax benefit to CL&P.  The amount in 2000 represents the remaining
    previously unallocated 1993 through 1999 NU parent losses.

The accompanying notes are an integral part of these financial statements.



THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------
                                                               For the Years Ended December 31,
- -----------------------------------------------------------------------------------------------
(Thousands of Dollars)                                             2000       1999       1998
- -----------------------------------------------------------------------------------------------
<S>                                                            <C>        <C>        <C>
Operating Activities:
  Net income/(loss)........................................... $ 148,135  $ (13,568) $(195,725)
  Adjustments to reconcile to net cash
   provided by operating activities:
    Depreciation..............................................   117,305    193,776    216,509
    Deferred income taxes and investment tax credits, net.....     5,672   (140,459)   (65,689)
    Amortization of regulatory assets, net ...................    97,315    447,776    120,884
    Amortization of recoverable energy costs..................     4,155     12,702     30,745
    Nuclear related costs.....................................    14,099     53,031    143,239
    Tax benefit for 1993-1999 from
      reduction of NU parent losses...........................    21,461        -          -
    Allocation of ESOP benefits...............................      (237)   (30,454)       -
    Gain on sale of utility plant.............................    25,444   (286,477)       -
    Net other (uses)/sources of cash..........................  (112,915)  (141,675)    43,297
  Changes in working capital:
    Receivables...............................................  (109,938)       837     29,914
    Fuel, materials and supplies..............................     1,271     34,379      9,896
    Accounts payable..........................................   171,729    (49,477)   (63,592)
    Accrued taxes.............................................  (136,313)   149,818    (13,621)
    Investments in securitizable assets.......................     9,474     52,633     45,372
    Other working capital (excludes cash).....................     3,204     16,585     62,901
                                                               ---------- ---------- ----------
Net cash flows provided by operating activities...............   259,861    299,427    364,130
                                                               ---------- ---------- ----------
Investing Activities:
  Investments in plant:
    Electric utility plant....................................  (208,249)  (180,982)  (132,194)
    Nuclear fuel..............................................   (35,709)   (26,198)    (8,444)
                                                               ---------- ---------- ----------
    Net cash flows used for investments in plant..............  (243,958)  (207,180)  (140,638)

  Investment in NU system Money Pool..........................   (38,000)     6,600     (6,600)
  Investments in nuclear decommissioning trusts...............   (25,133)   (54,582)   (54,106)
  Other investment activities, net............................    10,246       (355)    (1,655)
  Net proceeds from the transfer/sale of utility plant........   686,807    516,912        -
  Capital contributions from Northeast Utilities..............       -          -       20,000
                                                               ---------- ---------- ----------
Net cash flows provided by/(used in) investing activities.....   389,962    261,395   (182,999)
                                                               ---------- ---------- ----------
Financing Activities:
  Net increase/(decrease) in short-term debt..................    13,300     91,700    (86,300)
  Reacquisitions and retirements of long-term debt............  (179,071)  (620,010)   (45,006)
  Reacquisitions and retirements of preferred stock...........   (99,539)   (19,750)   (35,711)
  Repurchase of common shares.................................  (300,000)       -          -
  Cash dividends on preferred stock...........................    (7,402)   (12,832)   (14,139)
  Cash dividends on common stock..............................   (72,014)       -          -
                                                               ---------- ---------- ----------
Net cash flows used in financing activities...................  (644,726)  (560,892)  (181,156)
                                                               ---------- ---------- ----------

Net increase/(decrease) in cash for the period................     5,097        (70)       (25)
Cash - beginning of period....................................       364        434        459
                                                               ---------- ---------- ----------
Cash - end of period.......................................... $   5,461  $     364  $     434
                                                               ========== ========== ==========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
  Interest, net of amounts capitalized........................ $  96,735  $ 142,398  $ 110,119
                                                               ========== ========== ==========
  Income taxes................................................ $ 226,380  $  19,754  $ (46,747)
                                                               ========== ========== ==========
Increase in obligations:
  Niantic Bay Fuel Trust...................................... $   6,535  $   4,752  $  10,208
                                                               ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ------------------------------------------

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     A.  About The Connecticut Light and Power Company
         The Connecticut Light and Power Company (CL&P or the company) along
         with the Public Service Company of New Hampshire (PSNH), Western
         Massachusetts Electric Company (WMECO), North Atlantic Energy
         Corporation (NAEC), and Holyoke Water Power Company (HWP) are the
         operating companies comprising the Northeast Utilities system (NU
         system) and are wholly owned by Northeast Utilities (NU).  The NU
         system serves in excess of 30 percent of New England's electric needs
         and is one of the 25 largest electric utility systems in the country
         as measured by revenues.  The NU system furnishes franchised retail
         electric service in Connecticut, New Hampshire and western
         Massachusetts through CL&P, PSNH and WMECO.  NAEC sells all of its
         entitlement to the capacity and output of the Seabrook Station nuclear
         unit (Seabrook) to PSNH under the terms of two life-of-unit, full cost
         recovery contracts.  HWP, also is engaged in the production and
         distribution of electric power.

         On March 1, 2000, NU completed its acquisition of Yankee Energy
         System, Inc., the parent company of Yankee Gas Services Company,
         Connecticut's largest natural gas distribution system.

         NU is registered with the Securities and Exchange Commission (SEC)
         as a holding company under the Public Utility Holding Company Act of
         1935 (1935 Act) and the NU system, including CL&P, is subject to
         provisions of the 1935 Act.  Arrangements among the NU system
         companies, outside agencies and other utilities covering
         interconnections, interchange of electric power and sales of utility
         property are subject to regulation by the Federal Energy Regulatory
         Commission (FERC) and/or the SEC.  CL&P is subject to further
         regulation for rates, accounting and other matters by the FERC and
         the Connecticut Department of Public Utility Control (DPUC).

         Several wholly owned subsidiaries of NU provide support services for
         the NU system companies, including CL&P, and, in some cases, for other
         New England utilities.  Northeast Utilities Service Company (NUSCO)
         provides centralized accounting, administrative, information
         resources, engineering, financial, legal, operational, planning,
         purchasing, and other services to the NU system companies, including
         CL&P.  Northeast Nuclear Energy Company acts as agent for the NU
         system companies and other New England utilities in operating the
         Millstone nuclear units.  North Atlantic Energy Service Corporation
         has operational responsibility for Seabrook.  In addition, CL&P has
         established a special purpose subsidiary whose business consists of
         the purchase and resale of receivables.

     B.  Presentation
         The consolidated financial statements of CL&P include the accounts of
         all subsidiaries.  Intercompany transactions have been eliminated in
         consolidation.

         The preparation of financial statements in conformity with accounting
         principles generally accepted in the United States requires management
         to make estimates and assumptions that affect the reported amounts of
         assets and liabilities and disclosure of contingent liabilities at the
         date of the financial statements and the reported amounts of revenues
         and expenses during the reporting period.  Actual results could differ
         from those estimates.

         Certain reclassifications of prior years' data have been made to
         conform with the current year's presentation.

         All transactions among affiliated companies are on a recovery of cost
         basis which may include amounts representing a return on equity and
         are subject to approval by various federal and state regulatory
         agencies and the DPUC.

     C.  New Accounting Standards
         Derivative Instruments:  Effective January 1, 2001, CL&P adopted
         Statement of Financial Accounting Standards (SFAS) No. 133,
         "Accounting for Derivative Instruments and Hedging Activities,"
         as amended.  SFAS No. 133 requires that derivative instruments be
         recorded as an asset or liability measured at its fair value and that
         changes in the fair value of derivative instruments be recognized
         currently in earnings unless specific hedge accounting criteria are
         met.

         In order to implement SFAS No. 133 by January 1, 2001, NU established
         a cross-functional project team to identify all derivative
         instruments, measure the fair value of those derivative instruments,
         designate and document various hedge relationships, and evaluate the
         effectiveness of those hedge relationships.  NU has completed the
         process of identifying all derivative instruments and has established
         appropriate fair value measurements of those derivative instruments in
         place at January 1, 2001.  In addition, for those derivative
         instruments which are hedging an identified risk, NU has designated
         and documented all hedging relationships anew.

         Management believes the adoption of this new standard will not have a
         material impact on CL&P's financial position or results of operations.

         Transfers of Financial Assets: In September 2000, the Financial
         Accounting Standards Board (FASB) issued SFAS No. 140, "Accounting
         for Transfers and Servicing of Financial Assets and Extinguishments
         of Liabilities - a Replacement of FASB Statement No. 125."  SFAS No.
         140 revises the criteria for accounting for securitizations, other
         financial asset transfers and collateral and introduces new
         disclosures, but otherwise carries forward most of the provisions of
         SFAS No. 125, "Accounting for Transfers and Servicing of Financial
         Assets and Extinguishments of Liabilities," without amendment.
         SFAS No. 140 is effective for transfers and servicing of financial
         assets and extinguishments of liabilities occurring after March 31,
         2001, and is effective for recognition and reclassification of
         collateral and for disclosures relating to securitization transactions
         and collateral for fiscal years ending after December 15, 2000.  The
         adoption of the disclosure requirements under SFAS No. 140 did not
         have a material impact on CL&P's consolidated financial statements.

         Revenue Recognition: In December 1999, the SEC issued Staff Accounting
         Bulletin (SAB) No. 101, "Revenue Recognition."  The adoption of SAB
         No. 101, as amended, did not have a material impact on CL&P's
         consolidated financial statements.

     D.  Investments and Jointly Owned Electric Utility Plant
         Regional Nuclear Generating Companies:  CL&P owns common stock in four
         regional nuclear companies (Yankee Companies).  CL&P's ownership
         interests in the Yankee Companies at December 31, 2000 and 1999, which
         are accounted for on the equity method due to CL&P's ability to
         exercise significant influence over their operating and financial
         policies are 34.5 percent of the Connecticut Yankee Atomic Power
         Company (CYAPC), 24.5 percent of the Yankee Atomic Electric Company
         (YAEC), 12 percent of the Maine Yankee Atomic Power Company (MYAPC),
         and 9.5 percent of the Vermont Yankee Nuclear Power Corporation
         (VYNPC).  CL&P's total equity investment in the Yankee Companies at
         December 31, 2000 and 1999, is $41.4 million and $54.5 million,
         respectively.  Each Yankee Company owns a single nuclear generating
         unit.  However, VYNPC is the only unit still in operation at
         December 31, 2000.

         Millstone:  CL&P has an 81 percent joint ownership interest in both
         Millstone 1, a 660 megawatt (MW) nuclear unit, which is currently in
         decommissioning status, and Millstone 2, an 870 MW nuclear generating
         unit.  CL&P has a 52.93 percent joint ownership interest in Millstone
         3, a 1,154 MW nuclear generating unit.  On August 7, 2000, CL&P and
         certain other joint owners reached an agreement to sell substantially
         all of the Millstone units to Dominion Resources, Inc. (Dominion) for
         approximately $1.3 billion, including approximately $105 million for
         nuclear fuel.  NU currently expects to close on the sale of Millstone
         as early as the end of March 2001.

         Seabrook:  CL&P has a 4.06 percent joint ownership interest in
         Seabrook, a 1,148 MW nuclear generating unit.  CL&P expects to auction
         its joint ownership interest in Seabrook, jointly with NAEC, in 2001
         with a closing on the sale expected in 2002.

         Plant-in-service and the accumulated provision for depreciation for
         CL&P's share of Millstone 2 and 3 and Seabrook are as follows:

         ----------------------------------------------------------------------
         At December 31,                                 2000         1999
         ----------------------------------------------------------------------
                                                       (Millions of Dollars)
         Plant-in-service
         Millstone 2...............................   $  779.7      $  771.7
         Millstone 3...............................    1,924.7       1,915.1
         Seabrook..................................      174.7         173.9
         Accumulated provision for depreciation
         Millstone 2...............................   $  779.1      $  743.3
         Millstone 3...............................    1,815.0       1,822.8
         Seabrook..................................      164.0         165.7
         ----------------------------------------------------------------------

     E.  Depreciation
         The provision for depreciation is calculated using the straight-line
         method based on estimated remaining useful lives of depreciable
         utility plant-in-service, adjusted for salvage value and removal
         costs, as approved by the appropriate regulatory agency where
         applicable.  Except for major facilities, depreciation rates are
         applied to the average plant-in-service during the period.  Major
         facilities are depreciated from the time they are placed in service.
         When plant is retired from service, the original cost of the plant,
         including costs of removal less salvage, is charged to the accumulated
         provision for depreciation.  The costs of closure and removal of
         nonnuclear facilities are accrued over the life of the plant as a
         component of depreciation.  The depreciation rates for the several
         classes of electric plant-in-service are equivalent to a composite
         rate of 3 percent in 2000, 3.3 percent in 1999 and 3.2 percent in
         1998.

         As a result of discontinuing the application of SFAS No. 71
         "Accounting for the Effects of Certain Types of Regulation," for
         CL&P's generation business in 1999, including CL&P's ownership
         interest in Seabrook, the company recorded a charge to accumulated
         depreciation for the nuclear plant in excess of the estimated fair
         market value at the time in the amount of $1.7 billion and a
         corresponding regulatory asset was created.

     F.  Revenues
         Revenues are based on authorized rates applied to each customer's
         use of electricity.  In general, rates can be changed only through
         a formal proceeding before the DPUC.  Regulatory commissions also
         have authority over the terms and conditions of nontraditional rate-
         making arrangements.  At the end of each accounting period, CL&P
         accrues a revenue estimate for the amount of energy delivered but
         unbilled.

     G.  Regulatory Accounting and Assets
         The accounting policies of CL&P and the accompanying consolidated
         financial statements conform to accounting principles generally
         accepted in the United States applicable to rate-regulated enterprises
         and historically reflect the effects of the rate-making process in
         accordance with SFAS No. 71.  As a result of final restructuring
         orders issued in 1999, CL&P discontinued the application of SFAS No.
         71 for the generation portion of its business.

         CL&P's transmission and distribution business will continue to be
         cost-based and management believes the application of SFAS No. 71
         continues to be appropriate.  Management continues to believe it is
         probable that CL&P will recover its investments in long-lived assets,
         including regulatory assets through charges to their transmission and
         distribution customers generally over periods which end between the
         years 2015 through 2026, subject to certain adjustments.  The majority
         for CL&P will be recovered through a transition charge over a 12-year
         period.  In addition, all material regulatory assets are earning a
         return.  The components of CL&P's regulatory assets are as follows:

         ----------------------------------------------------------------------
         At December 31,                                 2000        1999
         ----------------------------------------------------------------------
                                                       (Millions of Dollars)

         Recoverable nuclear costs...............      $1,122.4    $1,781.9
         Income taxes, net.......................         371.9       399.5
         Unrecovered contractual obligations.....         171.8       228.9
         Recoverable energy costs, net...........          85.2        89.5
         Other...................................          84.7        64.3
                                                       --------    --------
                                                       $1,836.0    $2,564.1
                                                       ========    ========
         ----------------------------------------------------------------------

         As a result of discontinuing the application of SFAS No. 71 in 1999
         for CL&P's generation business, the company reclassified nuclear plant
         in excess of its estimated fair market value from plant to regulatory
         assets.  As of December 31, 2000 and 1999, excluding the impact of the
         transfer of generation assets to Northeast Generation Company in 2000,
         the unamortized balance ($1.35 billion and $1.38 billion,
         respectively) is classified as recoverable nuclear costs.  Also
         included in that regulatory asset component for 2000 and 1999 are
         $344.3 million and $401.9 million, respectively, which includes
         Millstone 1 recoverable nuclear costs relating to the recoverable
         portion of the undepreciated plant and related assets ($51.2 million
         and $101.9 million, respectively) and the decommissioning and closure
         obligation ($293.1 million and $300 million, respectively).

    H.   Income Taxes
         The tax effect of temporary differences (differences between the
         periods in which transactions affect income in the financial
         statements and the periods in which they affect the determination of
         taxable income) is accounted for in accordance with the rate-making
         treatment of the applicable regulatory commissions.

         The tax effect of temporary differences, including timing differences
         accrued under previously approved accounting standards, that give
         rise to the accumulated deferred tax obligation is as follows:

         ----------------------------------------------------------------------
         At December 31,                                 2000        1999
         ----------------------------------------------------------------------
                                                       (Millions of Dollars)

         Accelerated depreciation and
           other plant-related differences.......       $800.0      $845.6

         Regulatory assets -
           income tax gross up...................        142.6       153.7

         Other...................................         34.8         0.2
                                                        ------      ------
                                                        $977.4      $999.5
                                                        ======      ======
        -----------------------------------------------------------------------

    I.  Unrecovered Contractual Obligations
        Under the terms of contracts with the Yankee Companies, the
        shareholder-sponsored companies, including CL&P, are responsible for
        their proportionate share of the remaining costs of the units,
        including decommissioning.  As management expects that CL&P will be
        allowed to recover these costs from its customers, CL&P has recorded a
        regulatory asset, with a corresponding obligation, on its consolidated
        balance sheet.

    J.  Recoverable Energy Costs
        Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed for
        its proportionate share of the costs of decontaminating and
        decommissioning uranium enrichment plants owned by the United States
        Department of Energy (DOE) (D&D Assessment).  The Energy Act requires
        that regulators treat D&D Assessments as a reasonable and necessary
        current cost of fuel, to be fully recovered in rates like any other
        fuel cost.  CL&P is currently recovering these costs through rates.
        As of December 31, 2000 and 1999, CL&P's total D&D Assessment deferrals
        were $24.1 million and $26.9 million, respectively.

        Through December 31, 1999, CL&P had an energy adjustment clause under
        which fuel prices above or below base-rate levels were charged to or
        credited to customers.  Coincident with the start of restructuring, the
        energy adjustment clause was terminated.  Energy costs deferred and not
        yet collected under the energy adjustment clause amounted to $61.1
        million and $62.6 million at December 31, 2000 and 1999, respectively.
        This balance is recorded as a generation-related stranded cost and will
        be recovered through a transition charge mechanism pending final
        DPUC approval.

2.   SHORT-TERM DEBT
     Limits:  The amount of short-term borrowings that may be incurred by CL&P
     is subject to periodic approval by either the SEC under the 1935 Act or by
     state regulators.  Currently, SEC authorization allows CL&P to incur total
     short-term borrowings up to a maximum of $375 million.  In addition, the
     charter of CL&P contains preferred stock provisions restricting the amount
     of unsecured debt the company may incur.  As of December 31, 2000, CL&P's
     charter permits CL&P to incur $245 million of additional unsecured debt.

     Credit Agreement:  On November 17, 2000, CL&P and WMECO entered into a
     364-day revolving credit facility for $350 million, replacing the previous
     $500 million facility which was to expire on November 17, 2000.  CL&P may
     draw up to $200 million under the facility which, until the nuclear
     divestiture, is secured by second mortgages on Millstone 2 and 3.  Once
     CL&P and WMECO receive the proceeds from securitization, the $350 million
     revolving credit facility will be reduced to $250 million, with a $150
     million limit for CL&P.  Unless extended, the credit facility will expire
     on November 16, 2001.  At December 31, 2000 and 1999, there were $115
     million and $90 million, respectively, in borrowings under these
     facilities.

     Under the aforementioned credit agreement, CL&P may borrow at fixed or
     variable rates plus an applicable margin based upon certain debt ratings,
     as rated by the lower of Standard and Poor's or Moody's Investors Service.
     The weighted average interest rate on CL&P's notes payable to banks
     outstanding on December 31, 2000 and 1999, was 8.41 percent and 7.69
     percent, respectively.  Maturities of short-term debt obligations were for
     periods of three months or less.

     This credit agreement provides that CL&P must comply with certain
     financial and nonfinancial covenants as are customarily included in such
     agreements, including, but not limited to, common equity ratios and
     interest coverage ratios.  CL&P currently is and expects to remain in
     compliance with these covenants.

     Money Pool:  Certain subsidiaries of NU, including CL&P, are members of
     the Northeast Utilities System Money Pool (Pool).  The Pool provides a
     more efficient use of the cash resources of the NU system and reduces
     outside short-term borrowings.  NUSCO administers the Pool as agent for
     the member companies.  Short-term borrowing needs of the member companies
     are first met with available funds of other member companies, including
     funds borrowed by NU parent.  NU parent may lend to the Pool but may not
     borrow.  Funds may be withdrawn from or repaid to the Pool at any
     time without prior notice.  Investing and borrowing subsidiaries receive
     or pay interest based on the average daily federal funds rate.  Borrowings
     based on loans from NU parent, however, bear interest at NU parent's cost
     and must be repaid based upon the terms of NU parent's original borrowing.
     At December 31, 2000 and 1999, CL&P had $38 million of lendings to and
     $11.7 million of borrowings from the Pool, respectively.  The interest
     rate on lendings to and borrowings from the Pool at December 31, 2000 and
     1999, was 5.4 percent and 4.9 percent, respectively.

3.   LEASES
     CL&P finances its respective shares of nuclear fuel for Millstone 2 and 3
     under the Niantic Bay Fuel Trust (NBFT) capital lease agreement.  This
     capital lease agreement has an expiration date of June 1, 2040.  At
     December 31, 2000 and 1999, the present value of CL&P's capital lease
     obligation to the NBFT was $112.6 million and $127.2 million,
     respectively.  In connection with the planned nuclear divestiture, the
     NBFT capital lease will be terminated, the nuclear fuel will be
     transferred to Dominion and the related $180 million Series G Intermediate
     Term Note Agreement will be extinguished with the divestiture proceeds.

     CL&P makes quarterly lease payments for the cost of nuclear fuel consumed
     in the reactors based on a units-of-production method at rates which
     reflect estimated kilowatt-hours of energy provided plus financing costs
     associated with the fuel in the reactors.  Upon permanent discharge from
     the reactors, CL&P's ownership interest in the nuclear fuel transfers to
     CL&P.

     CL&P also has entered into lease agreements, some of which are capital
     leases, for the use of data processing and office equipment, vehicles,
     nuclear control room simulators, and office space.  The provisions of
     these lease agreements generally provide for renewal options.

     Capital lease rental payments charged to operating expense were $36.3
     million in 2000, $10 million in 1999 and $20.5 million in 1998.  Interest
     included in capital lease rental payments was $7.9 million in 2000, $9.4
     million in 1999 and $14.1 million in 1998.  Operating lease rental
     payments charged to expense were $9.8 million in 2000, $14.3 million in
     1999 and $17.9 million in 1998.

     Future minimum rental payments, excluding annual nuclear fuel lease
     payments and executory costs such as property taxes, state use taxes,
     insurance, and maintenance, under long-term noncancelable leases, as of
     December 31, 2000, are as follows:

     -------------------------------------------------------------------------
     Year                                 Capital Leases     Operating Leases
     -------------------------------------------------------------------------
                                                 (Millions of Dollars)

     2001................................    $  2.4                $11.5
     2002................................       2.4                 10.0
     2003................................       2.4                  8.1
     2004................................       2.4                  6.6
     2005................................       2.4                  5.9
     After 2005..........................      27.0                 13.4
                                             ------                -----
     Future minimum lease payments.......      39.0                $55.5
                                                                   =====
     Less amount representing interest...      21.7
                                             ------
     Present value of future minimum
       lease payments for other than
       nuclear fuel......................      17.3

     Present value of future nuclear
       fuel lease payments...............     112.6
                                             ------
     Present value of future minimum
       lease payments....................    $129.9
                                             ======
     -------------------------------------------------------------------------

4.   PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
     Details of preferred stock not subject to mandatory redemption are as
     follows:

     --------------------------------------------------------------------------
                              December 31,     Shares
                                  2000       Outstanding        December 31,
                               Redemption    December 31,     ---------------
     Description                  Price         2000          2000       1999
     --------------------------------------------------------------------------
                                                      (Millions of Dollars)

     $1.90  Series of 1947      $52.50        163,912        $  8.2     $  8.2
     $2.00  Series of 1947       54.00        336,088          16.8       16.8
     $2.04  Series of 1949       52.00        100,000           5.0        5.0
     $2.20  Series of 1949       52.50        200,000          10.0       10.0
      3.90% Series of 1949       50.50        160,000           8.0        8.0
     $2.06  Series E of 1954     51.00        200,000          10.0       10.0
     $2.09  Series F of 1955     51.00        100,000           5.0        5.0
      4.50% Series of 1956       50.75        104,000           5.2        5.2
      4.96% Series of 1958       50.50        100,000           5.0        5.0
      4.50% Series of 1963       50.50        160,000           8.0        8.0
      5.28% Series of 1967       51.43        200,000          10.0       10.0
     $3.24  Series G of 1968     51.84        300,000          15.0       15.0
      6.56% Series of 1968       51.44        200,000          10.0       10.0
                                                             ------     ------
                                                             $116.2     $116.2
                                                             ======     ======
     --------------------------------------------------------------------------

5.   LONG-TERM DEBT
     Details of long-term debt outstanding are as follows:

     --------------------------------------------------------------------------
     At December 31,                                    2000       1999
     --------------------------------------------------------------------------
                                                      (Millions of Dollars)
     First Mortgage Bonds:
     5 3/4% Series XX due 2000...................     $     -     $  159.0
     7 7/8% Series A  due 2001...................        160.0       160.0
     7 3/4% Series C  due 2002...................        200.0       200.0
     7 3/8% Series TT due 2019...................           -         20.0
     8 1/2% Series C  due 2024...................        115.0       115.0
     7 7/8% Series D  due 2024...................        140.0       140.0
                                                      --------    --------
                                                         615.0       794.0
     Pollution Control Notes:
       Variable rate, due 2016-2022..............         46.4        46.4
       Variable rate, tax exempt,
         due 2028-2031...........................        377.5       377.5
     Fees and interest due for spent nuclear
       fuel disposal costs.......................        194.7       183.4
     Other.......................................           -          0.2
     Less amounts due within one year............        160.0       159.0
     Unamortized premium and discount, net.......         (0.9)       (1.4)
                                                      --------    --------
     Long-term debt, net.........................     $1,072.7    $1,241.1
                                                      ========    ========
     --------------------------------------------------------------------------

     Long-term debt maturities and cash sinking fund requirements, excluding
     fees and interest due for spent nuclear fuel disposal costs, on debt
     outstanding at December 31, 2000, for the years 2001 through 2005 are
     $160 million, $200 million, and no requirements for 2003, 2004 and 2005,
     respectively.

     Essentially all utility plant of CL&P is subject to the liens of the
     company's first mortgage bond indenture.

     CL&P has secured $315.5 million of pollution control notes with second
     mortgage liens on Millstone 1, junior to the liens of its first mortgage
     bond indenture.

     CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds with
     bond insurance secured by first mortgage bonds and a liquidity facility.

     The average effective interest rates on the variable-rate pollution
     control notes ranged from 3.2 percent to 4.9 percent for 2000 and from
     2.2 percent to 3.9 percent for 1999.

6.   INCOME TAX EXPENSE
     The components of the federal and state income tax provisions were
     charged/(credited) to operations as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)
     Current income taxes:
       Federal....................................  $ 77.2    $197.7    $ (9.2)
       State......................................    17.2      27.9      (3.9)
                                                    ------    ------    ------
         Total current............................    94.4     225.6     (13.1)
                                                    ------    ------    ------
     Deferred income taxes, net:
       Federal....................................    10.6    (113.0)    (34.9)
       State......................................     2.4     (20.1)    (17.5)
                                                    ------    ------    ------
         Total deferred...........................    13.0    (133.1)    (52.4)
                                                    ------    ------    ------
     Investment tax credits, net..................    (7.3)     (7.3)    (13.3)
                                                    ------    ------    ------
     Total income tax expense/(credit)............  $100.1    $ 85.2    $(78.8)
                                                    ======    ======    ======
     --------------------------------------------------------------------------

     The components of total income tax expense/(credit) are classified as
     follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)

     Income taxes charged to operating expenses...  $131.0    $122.1   $(11.7)
     Other income taxes...........................   (30.9)    (36.9)   (67.1)
                                                    ------    ------   ------
     Total income tax expense/(credit)............  $100.1    $ 85.2   $(78.8)
                                                    ======    ======   ======
     --------------------------------------------------------------------------

     Deferred income taxes are comprised of the tax effects of temporary
     differences as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)
     Depreciation, leased nuclear  fuel,
       settlement credits and disposal costs......  $13.8   $  (9.9)   $ (5.6)
     Regulatory deferral..........................  (14.1)      6.2     (36.7)
     State net operating loss carryforward........     -        7.8       1.1
     Regulatory disallowance......................     -      (24.2)    (18.1)
     Sale of fossil generation assets.............     -     (126.1)       -
     Pension accruals.............................   13.6       9.8       8.9
     Other........................................   (0.3)      3.3      (2.0)
                                                    -----   -------    ------
     Deferred income taxes, net...................  $13.0   $(133.1)   $(52.4)
                                                    =====   =======    ======
     --------------------------------------------------------------------------

     A reconciliation between income tax expense/(credit) and the expected tax
     expense/(credit) at 35 percent of pretax income/(loss) is as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)

     Expected federal income tax.................. $ 86.9      $25.0   $(96.1)
     Tax effect of differences:
       Depreciation...............................    5.8       27.1     20.9
       Amortization of regulatory assets..........    3.6       31.9     22.7
       Investment tax credit amortization.........   (7.3)      (7.3)   (13.3)
       State income taxes, net of
         federal benefit..........................   12.7        5.1    (13.9)
       Other, net.................................   (1.6)       3.4      0.9
                                                   ------      -----   ------
     Total income tax expense/(credit)............ $100.1      $85.2   $(78.8)
                                                   ======      =====   ======
     --------------------------------------------------------------------------

7.   PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
     The NU system companies, including CL&P, participate in a uniform
     noncontributory defined benefit retirement plan covering substantially all
     regular NU system employees.  Benefits are based on years of service and
     the employees' highest eligible compensation during 60 consecutive months
     of employment.  CL&P's portion of the NU system's total pension credit,
     part of which was credited to utility plant, was $57.2 million in 2000,
     $40.3 million in 1999 and $32.6 million in 1998.

     Currently, CL&P's policy is to annually fund an amount at least equal to
     that which will satisfy the requirements of the Employee Retirement Income
     Security Act and Internal Revenue Code.

     The NU system companies, including CL&P, also provide certain health care
     benefits, primarily medical and dental, and life insurance benefits
     through a benefit plan to retired employees.  These benefits are available
     for employees retiring from CL&P who have met specified service
     requirements.  For current employees and certain retirees, the total
     benefit is limited to two times the 1993 per retiree health care cost.
     These costs are charged to expense over the estimated work life of the
     employee.  CL&P annually funds postretirement costs through external
     trusts with amounts that have been rate-recovered and which also are tax
     deductible.

     Pension and trust assets are invested primarily in domestic and
     international equity securities and bonds.

     The following table represents information on the plans' benefit
     obligation, fair value of plan assets, and the respective plans' funded
     status:

<TABLE>
<CAPTION>
     -------------------------------------------------------------------------------
                                                     At December 31,
     -------------------------------------------------------------------------------
                                        Pension Benefits     Postretirement Benefits
     -------------------------------------------------------------------------------
     (Millions of Dollars)              2000       1999         2000         1999
     -------------------------------------------------------------------------------
     <S>                              <C>        <C>          <C>          <C>
     Benefit obligation
       at beginning of year.........  $ (551.9)  $ (562.7)    $(131.9)     $(133.8)
     Service cost...................      (9.7)     (11.0)       (1.9)        (2.3)
     Interest cost..................     (42.3)     (40.0)      (10.1)        (9.3)
     Plan amendment.................        -       (32.5)         -            -
     Transfers......................      (4.9)       1.8          -            -
     Actuarial (loss)/gain..........     (18.9)      58.8        (5.2)        (0.6)
     Benefits paid..................      40.4       35.5        12.8         14.1
     Settlements and other..........        -        (1.8)         -            -
     -------------------------------------------------------------------------------
     Benefit obligation
       at end of year...............  $ (587.3)  $ (551.9)    $(136.3)     $(131.9)
     -------------------------------------------------------------------------------
     Change in plan assets
     Fair value of plan assets
       at beginning of year.........  $1,037.8   $  935.7     $  59.7      $  53.8
     Actual return on plan assets...      (3.5)     135.8         3.0          6.6
     Employer contribution..........        -          -         12.5         13.4
     Benefits paid..................     (40.4)     (35.5)      (12.8)       (14.1)
     Transfers......................       4.9        1.8          -            -
     -------------------------------------------------------------------------------
     Fair value of plan assets
       at end of year...............  $  998.8   $1,037.8     $  62.4      $  59.7
     -------------------------------------------------------------------------------
     Funded status at December 31...  $  411.5   $  485.9     $ (73.9)     $ (72.2)
     Unrecognized transition
       (asset)/obligation...........      (3.7)      (4.6)       88.2         95.5
     Unrecognized prior
       service cost.................      30.4       33.1          -            -
     Unrecognized net gain..........    (267.5)    (400.9)      (14.3)       (23.3)
     -------------------------------------------------------------------------------
     Prepaid benefit cost...........  $  170.7   $  113.5      $   -       $   -
     -------------------------------------------------------------------------------
</TABLE>

     The following actuarial assumptions were used in calculating the plans'
     year end funded status:

     -------------------------------------------------------------------------
                                               At December 31,
     -------------------------------------------------------------------------
                                  Pension Benefits     Postretirement Benefits
     -------------------------------------------------------------------------
                                    2000    1999           2000      1999
     -------------------------------------------------------------------------
     Discount rate.............     7.50%   7.75%          7.50%     7.75%
     Compensation/progression
       rate....................     4.50    4.75           4.50      4.75
     Health care cost
       trend rate (a)..........      N/A     N/A           5.26      5.57
     -------------------------------------------------------------------------

     (a) The annual per capita cost of covered health care benefits was
         assumed to decrease to 4.91 percent by 2001.

     The components of net periodic benefit (credit)/cost are:

     --------------------------------------------------------------------------
                                     For the Years Ended December 31,
     --------------------------------------------------------------------------
                                                           Postretirement
                                 Pension Benefits              Benefits
     --------------------------------------------------------------------------
     (Millions of Dollars)   2000      1999      1998     2000   1999     1998
     --------------------------------------------------------------------------
     Service cost.........  $  9.7   $ 11.0    $  9.8    $ 1.9   $ 2.3   $ 2.0
     Interest cost........    42.3     40.0      37.5     10.1     9.3     9.2
     Expected return
       on plan assets.....   (88.4)   (78.1)    (68.4)    (4.9)   (4.2)   (3.6)
     Amortization of
       unrecognized net
       transition (asset)/
       obligation.........    (0.9)    (0.9)     (0.9)     7.3     7.3     7.4
     Amortization of prior
       service cost.......     2.7      2.7       0.3       -       -       -
     Amortization of
       actuarial gain.....   (22.6)   (15.0)    (10.9)      -       -       -
     Other
       amortization, net..      -        -         -      (1.9)   (1.3)   (1.7)
     --------------------------------------------------------------------------
     Net periodic benefit
      (credit)/cost.......  $(57.2)  $(40.3)   $(32.6)   $12.5   $13.4   $13.3
     --------------------------------------------------------------------------

     For calculating pension and postretirement benefit costs, the following
     assumptions were used:

     --------------------------------------------------------------------------
                                     For the Years Ended December 31,
     --------------------------------------------------------------------------
                                                           Postretirement
                                 Pension Benefits              Benefits
     --------------------------------------------------------------------------
                            2000      1999      1998     2000    1999     1998
     --------------------------------------------------------------------------
     Discount rate........  7.75%     7.00%     7.25%    7.75%   7.00%    7.25%
     Expected long-term
       rate of return.....  9.50      9.50      9.50      N/A     N/A      N/A
     Compensation/
      progression rate....  4.75      4.25      4.25     4.75    4.25     4.25
     Long-term rate
       of return -
       Health assets,
         net of tax.......   N/A       N/A       N/A     7.50    7.50     7.75
       Life assets........   N/A       N/A       N/A     9.50    9.50     9.50
     --------------------------------------------------------------------------

     Assumed health care cost trend rates have a significant effect on the
     amounts reported for the health care plans.  The effect of changing the
     assumed health care cost trend rate by one percentage point in each year
     would have the following effects:

     --------------------------------------------------------------------------
                                            One Percentage     One Percentage
     (Millions of Dollars)                  Point Increase     Point Decrease
     --------------------------------------------------------------------------
     Effect on total service and
       interest cost components                  $0.5              $(0.5)
     Effect on postretirement
       benefit obligation                        $6.2              $(5.9)
     --------------------------------------------------------------------------

     The trust holding the health plan assets is subject to federal income
     taxes.

8.   SALE OF CUSTOMER RECEIVABLES
     As of December 31, 2000 and 1999, CL&P had sold accounts receivable of
     $170 million to a third-party purchaser with limited recourse through the
     CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P.
     In addition, at December 31, 2000 and 1999, $18.9 million and $22.5
     million, respectively, of accounts receivable were designated as
     collateral under the agreement with the CRC.

     Concentrations of credit risk to the purchaser under the company's
     agreement with respect to the receivables are limited due to CL&P's
     diverse customer base within its service territory.

9.   COMMITMENTS AND CONTINGENCIES

     A.  Restructuring
         The 1999 restructuring orders allowed for securitization of CL&P's
         nonnuclear regulatory assets and the costs to buyout or buydown the
         various purchased-power contracts.  On November 8, 2000, the DPUC
         approved CL&P's request to securitize an amount not to exceed $1.55
         billion of approved, eligible stranded costs, primarily related to
         above-market purchased-power contracts and generation related
         regulatory assets.  However, the Office of Consumer Counsel (OCC)
         appealed the securitization order to the Connecticut Superior Court
         and it remains unclear when securitization financing can be
         undertaken.

     B.  Nuclear Generation Assets Divestiture
         On August 7, 2000, CL&P and certain other joint owners reached an
         agreement to sell substantially all of the Millstone units, located in
         Waterford, Connecticut, to Dominion, for approximately $1.3 billion,
         including approximately $105 million for nuclear fuel.  Dominion has
         also agreed to assume responsibility for decommissioning the three
         units and NU will transfer to Dominion all funds in the Millstone
         decommissioning trust.  Additionally, NU is obligated to top-off the
         decommissioning trust if its value does not equal a previously agreed
         upon level as defined.  NU expects to close on the sale of Millstone
         as early as the end of March 2001.

         If the transaction is consummated as proposed, CL&P would receive
         gross proceeds of approximately $843.2 million on a pretax basis for
         its respective ownership interest.  The proceeds from the sale of this
         interest will be used to reduce the company's stranded costs under
         restructuring and the cash proceeds will be used to repay subsidiary
         debt and capital lease obligations and to return equity capital to
         the parent company.  The DPUC approved the recovery of Millstone-
         related stranded costs not offset by asset divestiture proceeds.
         Pursuant to the DPUC order, CL&P will seek recovery of Millstone
         post-1997 capital additions totaling $50 million.  The OCC has
         appealed CL&P's ability to recover these costs.

     C.  Environmental Matters
         The NU system, including CL&P, is subject to environmental laws and
         regulations intended to mitigate or remove the effect of past
         operations and improve or maintain the quality of our environment.
         As such, the NU system, including CL&P, have active environmental
         auditing and training programs and believe they are substantially in
         compliance with the current laws and regulations.

         However, the normal course of operations may involve activities and
         substances that expose CL&P to potential liabilities of which
         management cannot determine the outcome.  Additionally, management
         cannot determine the outcome for liabilities that may be imposed for
         past acts, even though such past acts may have been lawful at the time
         they  occurred.  Management does not believe, however, that this
         will have a material impact on CL&P's consolidated financial
         statements.

         Based upon currently available information for the estimated
         remediation costs as of December 31, 2000 and 1999, the liability
         recorded by CL&P for its estimated environmental remediation costs
         amounted to $5.2 million and $6.9 million, respectively.

     D.  Spent Nuclear Fuel Disposal Costs
         Under the Nuclear Waste Policy Act of 1982, CL&P must pay the DOE
         for the disposal of spent nuclear fuel and high-level radioactive
         waste.  The DOE is responsible for the selection and development of
         repositories for, and the disposal of, spent nuclear fuel and high-
         level radioactive waste.  For nuclear fuel used to generate
         electricity prior to April 7, 1983 (Prior Period Fuel), an accrual
         has been recorded for the full liability and payment must be made
         prior to the first delivery of spent fuel to the DOE.  Until such
         payment is made, the outstanding balance will continue to accrue
         interest at the 3-month treasury bill yield rate.  As of December 31,
         2000 and 1999, fees due to the DOE for the disposal of Prior Period
         Fuel were $194.7 million and $183.4 million, respectively, including
         interest costs of $128.1 million and $116.9 million, respectively.

         Fees for nuclear fuel burned on or after April 7, 1983, are billed
         currently to customers and paid to the DOE on a quarterly basis.
         CL&P is responsible for fees to be paid for fuel burned until the
         divestiture of the Millstone and Seabrook nuclear units.

     E.  Nuclear Insurance Contingencies
         Insurance policies covering CL&P's ownership share of the NU system's
         nuclear facilities have been purchased for the primary cost of repair,
         replacement or decontamination of utility property, certain extra
         costs incurred in obtaining replacement power during prolonged
         accidental outages and the excess cost of repair, replacement or
         decontamination or premature decommissioning of utility property.

         CL&P is subject to retroactive assessments if losses under those
         policies exceed the accumulated funds available to the insurer.
         The maximum potential assessments with respect to losses arising
         during the current policy year for the primary property insurance
         program, the replacement power policies and the excess property damage
         policies are $5 million, $2.7 million and $6.1 million, respectively.
         In addition, insurance has been purchased by the NU system in the
         aggregate amount of $200 million on an industry basis for coverage
         of worker claims.

         Under certain circumstances, in the event of a nuclear incident at
         one of the nuclear facilities covered by the federal government's
         third-party liability indemnification program, the NU system,
         including CL&P, could be assessed liabilities in proportion to its
         ownership interest in each of its nuclear units up to $83.9 million.
         The NU system's payment of this assessment would be limited to, in
         proportion to its ownership interest in each of its nuclear units,
         $10 million in any one year per nuclear unit.  In addition, if
         the sum of all claims and costs from any one nuclear incident exceeds
         the maximum amount of financial protection, the NU system, including
         CL&P, would be subject to an additional 5 percent, or $4.2 million,
         liability, in proportion to its ownership interests in each of its
         nuclear units.  Based upon its ownership interests in the Millstone
         units and in Seabrook, CL&P's maximum liability, including any
         additional assessments, would be $192.9 million per incident, of which
         payments would be limited to $21.9 million per year.  In addition,
         through purchased-power contracts with VYNPC, CL&P would be
         responsible for up to an additional assessment of $8.4 million per
         incident, of which payments would be limited to $1 million per year.

         CL&P expects to terminate its nuclear insurance upon the divestiture
         of its nuclear units.

     F.  Long-Term Contractual Arrangements
         Yankee Companies:  Under the terms of its agreement, CL&P paid its
         ownership (or entitlement) shares of costs, which included
         depreciation, operation and maintenance (O&M) expenses, taxes, the
         estimated cost of decommissioning, and a return on invested capital.
         These costs were recorded as purchased-power expenses.  CL&P's cost
         of purchases under its contract with VYNPC amounted to $14.5 million
         in 2000, $17 million in 1999, and $15.9 million in 1998.  VYNPC is
         in the process of selling its nuclear unit.  Upon completion of the
         sale, this long-term contract will be terminated.

         Nonutility Generators (NUGs): CL&P has entered into various
         arrangements for the purchase of capacity and energy from NUGs.
         CL&P's total cost of purchases under these arrangements amounted to
         $308.6 million in 2000, $293.8 million in 1999 and $290.7 million in
         1998.  The company is in the process of renegotiating the terms of
         these contracts through either a contract buydown or buyout.  CL&P
         expects any payments to the NUGs as a result of these renegotiations
         to be recovered from the company's customers.

         Hydro-Quebec:  Along with other New England utilities, CL&P has
         entered into an agreement to support transmission and terminal
         facilities to import electricity from the Hydro-Quebec system in
         Canada.  CL&P is obligated to pay, over a 30-year period ending in
         2020, its proportionate share of the annual O&M expenses and capital
         costs of those facilities.

         Estimated Annual Costs:  The estimated annual costs of CL&P's
         significant long-term contractual arrangements, absent the effects of
         any contract terminations, buydowns or buyouts, are as follows:

         ---------------------------------------------------------------------
                                   2001     2002     2003     2004     2005
         ---------------------------------------------------------------------
                                             (Millions of Dollars)
         VYNPC.............      $ 16.6    $ 16.9   $ 17.0   $ 18.7   $ 17.6
         NUGs..............       292.5     296.2    301.7    283.3    289.2
         Hydro-Quebec......        15.9      15.4     14.8     14.2     13.7
         ---------------------------------------------------------------------

10.  NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
     Millstone and Seabrook:  CL&P's operating nuclear power plants,
     Millstone 2 and 3 and Seabrook, have service lives that are expected to
     end during the years 2015 through 2026, and upon retirement, must be
     decommissioned.  Millstone 1's expected service life was to end in 2010,
     however, in July 1998, restart activities were discontinued and
     decommissioning of the unit began.  In connection with the sale of the
     Millstone units, Dominion has agreed to assume responsibility for
     decommissioning.  Until the divestiture, CL&P recovers sufficient amounts
     through its allowed rates related to decommissioning costs.

     CL&P's ownership share of the estimated cost of decommissioning
     Millstone 2 and 3 and Seabrook, in year end 2000 dollars, is $348.8
     million, $343.1 million and $23.8 million, respectively.  Nuclear
     decommissioning costs are accrued over the expected service lives of
     the units and are included in depreciation expense and the accumulated
     provision for depreciation.  Nuclear decommissioning expenses for these
     units amounted to $24.4 million in 2000, $19.6 million in 1999 and $19.1
     million in 1998.  Nuclear decommissioning expenses for Millstone 1 were
     $20.6 million in 2000, $22.8 million in 1999 and $17.3 million in 1998.
     Through December 31, 2000 and 1999, total decommissioning expenses of
     $217.8 million and $185.1 million, respectively, have been collected from
     customers and are reflected in the accumulated provision for depreciation.

     External decommissioning trusts have been established for the costs of
     decommissioning the Millstone units.  Payments for CL&P's ownership share
     of the cost of decommissioning Seabrook are paid to an independent
     decommissioning financing fund managed by the state of New Hampshire.
     Funding of the estimated decommissioning costs assumes after-tax earnings
     on the Millstone and Seabrook decommissioning funds of 5.5 percent and
     6.5 percent, respectively.

     As of December 31, 2000 and 1999, $191.9 million and $164.2 million,
     respectively, have been transferred to external decommissioning trusts.
     Earnings on the decommissioning trusts increase the decommissioning trust
     balances and the accumulated provisions for depreciation.  Unrealized
     gains and losses associated with the decommissioning trusts also impact
     the balance of the trusts and the accumulated provisions for depreciation.
     The fair values of the amounts in the external decommissioning trusts
     were $310.1 million and $282.2 million at December 31, 2000 and 1999,
     respectively.  Upon divestiture, balances in the decommissioning trusts
     will be transferred to the buyer.  NU is obligated to top-off the
     Millstone decommissioning trust if its value does not equal an agreed upon
     amount at closing, pursuant to the conditions set forth in the purchase
     and sale agreement.

     Yankee Companies:  VYNPC owns and operates a nuclear generating unit with
     a service life that is expected to end in 2012.  CL&P's ownership share of
     estimated costs, in year end 2000 dollars, of decommissioning this unit is
     $42.9 million.  In 1999, VYNPC agreed to sell its nuclear generating unit
     for $22 million to an unaffiliated company.  Among other commitments, the
     acquiring company agreed to assume the obligation to decommission the unit
     after it is taken out of service, and the owners of VYNPC (including CL&P)
     agreed to fund their shares of the decommissioning costs up to a
     negotiated amount.  Subsequent to the time that agreement was executed,
     the original proposed acquiring company has increased the price it agreed
     to pay and three other unaffiliated companies have indicated their
     interest in buying VYNPC's generating unit on terms that have not been
     disclosed.  At present, CL&P expects that the unit will be sold, but the
     identity of the owner and the terms of sale, including price, future
     decommissioning obligations and future power purchase obligations, are
     not known.

     As of December 31, 2000 and 1999, CL&P's remaining estimated obligation,
     including decommissioning for the units owned by CYAPC, YAEC and MYAPC,
     which have been shut down was $160.6 million and $238.1 million,
     respectively.

11.  MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY
     CL&P Capital LP (CL&P LP), a subsidiary of CL&P, previously had issued
     $100 million of cumulative 9.3 percent Monthly Income Preferred Securities
     (MIPS), Series A.  CL&P has the sole ownership interest in CL&P LP, as a
     general partner, and is the guarantor of the MIPS securities.  Subsequent
     to the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance,
     along with CL&P's $3.1 million capital contribution, back to CL&P in the
     form of an unsecured debenture.  CL&P consolidates CL&P LP for financial
     reporting purposes.  Upon consolidation, the unsecured debenture is
     eliminated, and the MIPS securities are accounted for as a minority
     interest.

12.  FAIR VALUE OF FINANCIAL INSTRUMENTS
     The following methods and assumptions were used to estimate the fair value
     of each of the following financial instruments:

     Nuclear Decommissioning Trusts:  CL&P's portion of the investments held
     in the NU system companies' nuclear decommissioning trusts were marked-
     to-market by $83.2 million as of December 31, 2000, and $88.2 million as
     of December 31, 1999, with corresponding offsets to the accumulated
     provision for depreciation.  The amounts adjusted in 2000 and in 1999
     represent cumulative net unrealized gains.  Cumulative gross unrealized
     holding losses were immaterial for both 2000 and 1999.

     Preferred Stock and Long-Term Debt:  The fair value of CL&P's fixed-rate
     securities is based upon the quoted market price for those issues or
     similar issues.  Adjustable rate securities are assumed to have a fair
     value equal to their carrying value.  The carrying amounts of CL&P's
     financial instruments and the estimated fair values are as follows:

     --------------------------------------------------------------------------
                                                    At December 31, 2000
     --------------------------------------------------------------------------
                                                   Carrying         Fair
     (Millions of Dollars)                          Amount          Value
     --------------------------------------------------------------------------
     Preferred stock not subject
       to mandatory redemption...............       $116.2         $139.7

     Long-term debt -
        First mortgage bonds.................        615.0          621.6

        Other long-term debt.................        618.6          576.4

     MIPS....................................        100.0          100.5
     --------------------------------------------------------------------------

     --------------------------------------------------------------------------
                                                    At December 31, 1999
     --------------------------------------------------------------------------
                                                   Carrying         Fair
     (Millions of Dollars)                          Amount          Value
     --------------------------------------------------------------------------
     Preferred stock not subject
       to mandatory redemption...............       $116.2         $144.9

     Preferred stock subject to
       mandatory redemption..................         99.6           96.8

     Long-term debt -
        First mortgage bonds.................        794.0          805.4

        Other long-term debt.................        607.3          564.5

     MIPS....................................        100.0           97.3
     --------------------------------------------------------------------------

13.  OTHER COMPREHENSIVE INCOME
     The accumulated balance for each other comprehensive income item is as
     follows:

     --------------------------------------------------------------------------
                                                        Current
                                       December 31,     Period     December 31,
                                           1999         Change         2000
     --------------------------------------------------------------------------
     (Thousands of Dollars)
     --------------------------------------------------------------------------
     Unrealized gains
       on securities...................    $676          $ 90          $766
     Minimum pension
       liability adjustments...........    (260)            -          (260)
     --------------------------------------------------------------------------
     Accumulated other
       comprehensive income............    $416          $ 90          $506
     --------------------------------------------------------------------------

     --------------------------------------------------------------------------
                                                        Current
                                       December 31,     Period     December 31,
                                           1998         Change         1999
     --------------------------------------------------------------------------
     (Thousands of Dollars)
     --------------------------------------------------------------------------
     Unrealized gains
       on securities...................    $638          $ 38          $676
     Minimum pension
       liability adjustments...........    (260)            -          (260)
     --------------------------------------------------------------------------
     Accumulated other
       comprehensive income............    $378          $ 38          $416
     --------------------------------------------------------------------------

     The changes in the components of other comprehensive income are reported
     net of the following income tax effects:

     --------------------------------------------------------------------------
                                                  2000      1999      1998
     --------------------------------------------------------------------------
     (Thousands of Dollars)
     --------------------------------------------------------------------------
     Unrealized gains
       on securities........................      $(59)     $(26)    $(446)
     Minimum pension
       liability adjustments................         -         -       182
     --------------------------------------------------------------------------
     Other comprehensive income.............      $(59)     $(26)    $(264)
     --------------------------------------------------------------------------

14.  SEGMENT INFORMATION
     Effective January 1, 1999, the NU system companies, including CL&P,
     adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and
     Related Information."  The NU system is organized between regulated
     utilities and competitive energy subsidiaries.  CL&P is included in the
     regulated utilities segment of the NU system and has no other reportable
     segments.

15.  SUBSEQUENT EVENT
     Merger Agreement With Consolidated Edison, Inc.:  In 2000, NU and
     Consolidated Edison, Inc. (Con Edison) received most of the approvals
     needed to complete the merger announced in October 1999.  Shareholders
     from both companies approved the merger in April 2000, and all state
     regulatory approvals were granted by the end of the year.  Additionally,
     the FERC approved the merger in May 2000, the Nuclear Regulatory
     Commission approved the transaction in August 2000, and the United States
     Department of Justice approved the merger in February 2001.  Necessary
     approval from the SEC was expected to be received in mid-March 2001.

     On February 28, 2001, NU's Board of Trustees requested that Con Edison
     provide reasonable assurance, in writing, that it intended to comply with
     the terms of the definitive merger agreement between the two companies.
     This included assurances that Con Edison would consummate the pending
     merger at the price set forth in the agreement promptly following the
     receipt of SEC approval.  The original request for assurance was to be
     received by March 2, 2001, however that date was later extended to
     March 5, 2001.  On March 5, 2001, Con Edison advised NU that it was not
     willing to close the merger on the agreed terms.  NU notified Con Edison
     that it was treating its refusal to proceed on the terms set forth in the
     merger agreement as a repudiation and breach of the merger agreement, and
     that NU would file suit to obtain the benefits of the transaction as
     negotiated for NU shareholders.  On March 6, 2001, Con Edison filed suit
     in the U.S. District Court for the Southern District of  New York
     (Southern District), seeking declaratory judgment that NU failed to
     satisfy conditions precedent under the merger agreement.  On March 12,
     2001, NU filed suit against Con Edison in the Southern District seeking
     damages in excess of $1 billion arising from Con Edison's breach of the
     merger agreement.

<TABLE>
The Connecticut Light and Power Company and Subsidiaries
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
SELECTED CONSOLIDATED FINANCIAL DATA       2000         1999          1998          1997          1996
- ----------------------------------------------------------------------------------------------------------
                                                              (Thousands of Dollars)
<S>                                    <C>           <C>           <C>           <C>           <C>
Operating Revenues..................   $2,935,922    $2,452,855    $2,386,864    $2,465,587    $2,397,460

Operating Income/(Loss).............      238,285       174,749        28,254        (7,619)       59,142

Net Income/(Loss)...................      148,135       (13,568)     (195,725)     (139,597)      (50,868)

Cash Dividends on Common Stock......       72,014          -             -            5,989       138,608

Total Assets........................    4,764,198     5,298,284     6,050,198     6,081,223     6,244,036

Long-Term Debt (a)..................    1,232,688     1,400,056     2,007,957     2,043,327     2,038,521

Preferred Stock Not Subject
  to Mandatory Redemption...........      116,200       116,200       116,200       116,200       116,200

Preferred Stock Subject to
  Mandatory Redemption (a)..........         -           99,539       119,289       155,000       155,000

Obligations Under Capital
  Leases (a)........................      129,869       144,400       162,884       158,118       155,708


</TABLE>
<TABLE>
<CAPTION>

- ------------------------------------------------------------------------------------------------
CONSOLIDATED QUARTERLY FINANCIAL DATA (Unaudited)
- ------------------------------------------------------------------------------------------------
                                                      Quarter Ended
- ------------------------------------------------------------------------------------------------
2000                           March 31        June 30        September 30         December 31
- ------------------------------------------------------------------------------------------------
                                                  (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------
<S>                            <C>             <C>              <C>                  <C>
Operating Revenues             $747,976        $683,585         $748,143             $756,218
                               ========        ========         ========             ========

Operating Income               $ 76,021        $ 42,723         $ 51,944             $ 67,597
                               ========        ========         ========             ========

Net Income                     $ 49,643        $ 19,186         $ 27,908             $ 51,398
                               ========        ========         ========             ========
- ------------------------------------------------------------------------------------------------
1999
- ------------------------------------------------------------------------------------------------

Operating Revenues             $606,997        $565,069         $667,349             $613,440
                               ========        ========         ========             ========

Operating Income               $ 20,412        $ 24,370         $ 51,969             $ 77,998
                               ========        ========         ========             ========

Net(Loss)/Income               $(13,705)       $ (6,814)        $  9,873             $ (2,922)
                               ========        ========         ========             ========
</TABLE>
(a) Includes portion due within one year.



The Connecticut Light and Power Company and Subsidiaries

- -------------------------------------------------------------------------------
CONSOLIDATED STATISTICS (Unaudited)
- -------------------------------------------------------------------------------

                                       Average
        Gross Electric                  Annual
         Utility Plant                 Use Per
          December 31,     kWh        Residential    Electric
        (Thousands of     Sales        Customer      Customers      Employees
           Dollars)     (Millions)      (kWh)       (Average)      December 31,
- -------------------------------------------------------------------------------

2000    $5,964,605        42,179        8,976        1,121,551        2,057
1999     6,007,421        29,317        8,969        1,120,846        2,377
1998     6,345,215        27,356        8,476        1,111,370        2,379
1997     6,639,786        25,766        8,526        1,103,309        2,163
1996     6,512,659        26,043        8,639        1,099,340        2,194

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13.2
<SEQUENCE>16
<FILENAME>0016.txt
<DESCRIPTION>ANNUAL REPORT OF WMECO
<TEXT>


                                2000 Annual Report

             Western Massachusetts Electric Company and Subsidiary

                                     Index


Contents                                                               Page
- --------                                                               ----

Management's Discussion and Analysis of Financial
  Condition and Results of Operations.............................       1

Report of Independent Public Accountants..........................      10

Consolidated Statements of Income.................................      11

Consolidated Statements of Comprehensive Income...................      11

Consolidated Balance Sheets.......................................    12-13

Consolidated Statements of Common Stockholder's Equity............      14

Consolidated Statements of Cash Flows.............................      15

Notes to Consolidated Financial Statements........................      16

Selected Consolidated Financial Data..............................      38

Consolidated Quarterly Financial Data (Unaudited).................      38

Consolidated Statistics (Unaudited)...............................      39

Preferred Stockholder and Bondholder Information..................   Back Cover



Western Massachusetts Electric Company and Subsidiary

- -------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
- -------------------------------------------------------------------------------

FINANCIAL CONDITION
- -------------------

Overview
- --------

The Western Massachusetts Electric Company's (WMECO or the company) earnings
totaled $35.3 million in 2000, compared with $2.9 million in 1999 and a loss
of $9.6 million in 1998.  WMECO is an operating company in the Northeast
Utilities system (NU system) and is wholly owned by Northeast Utilities (NU).
WMECO benefited from the return to service of the Millstone 2 unit in May 1999,
the strong performance of the Millstone 2 and 3 units in 2000 and the absence
of restructuring charges in 2000.  Millstone 2 operated at a capacity factor
of 82 percent in 2000, while Millstone 3 operated at a capacity factor of
virtually 100 percent in 2000.  In 2000, WMECO's revenues increased to $513.7
million, up 24 percent from $414.2 million in 1999, primarily due to higher
wholesale and retail revenues.  Revenues were $393.3 million in 1998.

Consolidated Edison, Inc. Merger
- --------------------------------

In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the
approvals needed to complete the merger announced in October 1999.
Shareholders from both companies approved the merger in April 2000, and all
state regulatory approvals were granted by the end of the year.  Additionally,
the Federal Energy Regulatory Commission (FERC) approved the merger in May
2000, the Nuclear Regulatory Commission approved the transaction in August
2000, and the United States Department of Justice approved the merger in
February 2001.  Necessary approval from the Securities and Exchange Commission
(SEC) was expected to be received in mid-March 2001.

On February 28, 2001, NU's Board of Trustees requested that Con Edison provide
reasonable assurance, in writing, that it intended to comply with the terms of
the definitive merger agreement between the two companies.  This included
assurances that Con Edison would consummate the pending merger at the price set
forth in the agreement promptly following the receipt of SEC approval.  The
original request for assurance was to be received by March 2, 2001, however,
that date was later extended to March 5, 2001.  On March 5, 2001, Con Edison
advised NU that it was not willing to close the merger on the agreed terms.
NU notified Con Edison that it was treating its refusal to proceed on the terms
set forth in the merger agreement as a repudiation and breach of the merger
agreement, and that NU would file suit to obtain the benefits of the
transaction as negotiated for NU shareholders.  On March 6, 2001, Con Edison
filed suit in the U.S. District Court for the Southern District of New York
(Southern District), seeking declaratory judgment that NU failed to satisfy
conditions precedent under the merger agreement.  On March 12, 2001, NU filed
suit against Con Edison in the Southern District seeking damages in excess of
$1 billion arising from Con Edison's breach of the merger agreement.  NU cannot
predict the outcome of this matter nor its effect on NU.

Liquidity
- ---------

WMECO's net cash flows provided by operating activities from operations
increased to $71.5 million in 2000 compared to $2.1 million in 1999 and $27.6
million in 1998.  The increase in cash flows from operations is primarily
attributable to increased earnings and higher amortization of regulatory
assets, a noncash expense.  Cash flows from operations were more than adequate
to meet the payment of WMECO's common and preferred dividends ($14.8 million)
and investments in electric utility plant, nuclear fuel and nuclear
decommissioning trusts ($38.6 million).  The level of common dividends totaled
$12 million in 2000, as compared to no common dividends paid in 1999 and 1998.
WMECO currently forecasts construction expenditures of $26.6 million for the
year 2001.

The transfer of 1,289 megawatts (MW) of hydroelectric generation assets to
Northeast Generation Company, an affiliated company, from WMECO and The
Connecticut Light and Power Company (CL&P) in March 2000, produced a
significant source of cash for WMECO and CL&P.  WMECO used this cash primarily
to retire long-term debt and to return equity capital to the parent company.
During 2000, $94.2 million of long-term debt was retired compared to $100.9
million in 1999 and $9.8 million in 1998.

In November 2000, WMECO and CL&P reduced their revolving credit agreement to
$350 million from $500 million to reflect lower borrowing needs post-
restructuring.  This agreement was renewed with more favorable terms as a
result of the NU system's improving credit profile.  In January 2001, Moody's
Investors Service and Standard and Poor's upgraded their credit ratings for
WMECO primarily as a result of the anticipated sale of the Millstone units
and NU's general financial recovery.  In February 2001, Fitch IBCA upgraded
its credit ratings for WMECO.  These upgrades return WMECO's unsecured debt
to investment grade ratings for the first time in five years and will save
the NU system in excess of $4.7 million annually in financing costs.

For further information regarding the WMECO's borrowing facilities, see
Note 2, "Short-Term Debt," to the consolidated financial statements.

In 2001, NU expects to reduce the capitalization of its regulated electric
operating companies significantly as a result of continued asset sales and
securitization of stranded costs.  WMECO expects to receive gross proceeds
of $196.2 million as a result of the sale of its ownership interest in the
Millstone units to Dominion Resources, Inc. (Dominion).  This sale is expected
to close as early as the end of March 2001.  The cash proceeds are expected to
be used to repay subsidiary debt and capital lease obligations and to return
equity capital to the parent company.

During February 2001, the Massachusetts Department of Telecommunications and
Energy (DTE) approved the securitization of $155 million of stranded costs by
WMECO.   A significant portion of those proceeds will be used to buyout a
purchased-power contract with the remainder used to retire WMECO's debt and to
return equity capital to the parent company.  Securitization for WMECO is
expected to take place early in the second quarter of 2001.

Restructuring
- -------------

As a result of industry restructuring, WMECO stopped supplying power directly
to customers in 2000.  Instead, WMECO became an energy delivery company,
delivering electricity to customers that is produced by other companies and
sometimes bought by customers through intermediaries.  In 2000, customers in
Massachusetts had the option of choosing alternative power suppliers or relying
on WMECO to acquire the power for them through standard offer service.

WMECO continues to generate power through either direct ownership of generating
plants, such as Millstone 2 and 3, or through purchased-power contracts.  WMECO
sold its share of the capacity associated with Millstone 2 and 3 to Select
Energy, Inc. and five unaffiliated companies.  These contracts will expire on
December 31, 2001.  The revenues generated from these contracts are expected to
recover WMECO's share of the nuclear operating costs through the divestiture
of the Millstone units.

In 2000, WMECO supplied power to standard offer customers at a rate of slightly
more than $0.045 per kilowatt-hour.  As a result of new one-year standard offer
supply contracts signed in December 2000, that rate will increase significantly
in 2001 to approximately $0.073 per kilowatt-hour.  In January 2001, the DTE
approved an average overall rate increase of approximately 17.4 percent for
WMECO standard offer customers, allowing WMECO to fully recover these increased
power procurement costs.  A higher rate was also approved for customers who
take default service from WMECO.  Under the new standard offer contracts, three
unaffiliated companies provide up to 630 MW of power to WMECO's standard offer
customers and one unaffiliated company serves WMECO's default load of up to
70 MW through December 31, 2001.  WMECO renegotiates its standard offer supply
contracts on an annual basis.

For further information regarding commitments and contingencies related to
restructuring, see Note 9A, "Commitments and Contingencies - Restructuring,"
to the consolidated financial statements.

Regional Transmission Organization
- ----------------------------------

Pursuant to FERC Order 888 (issued in April 1996), the NU system companies,
including WMECO, operate their transmission system under an open access,
nondiscriminatory transmission tariff.

In December 1999, the FERC issued an order calling on all transmission owners
to voluntarily join Regional Transmission Organizations (RTOs) in order to
boost competition in electric markets.  In general, each of these organizations
would be an independent operator over all transmission facilities, and would
perform, among other functions, tariff administration, construction planning
and reliability management for the particular regional transmission system.
NU's active voting interest in such an organization would be limited to 5
percent under the proposal.

The NU system companies, including WMECO, and other parties have appealed this
order.  Of primary concern to NU is the ratemaking authority granted to RTOs
and its impact on the ability of transmission owners to earn appropriate
returns on their transmission investment under the organizational structure
and the minimum functions proposed in the order.  The NU system companies,
including WMECO, were required to participate in a collaborative process
established by the FERC beginning in March of 2000.  On January 16, 2001,
NU along with the Independent System Operator and five other New England
transmission owning utilities filed a proposal to establish a New England
RTO.

Nuclear Plant Performance And Divestiture
- -----------------------------------------

Millstone
The Millstone units completed one of their best years ever in 2000.
Millstone 2 operated at a capacity factor of 82 percent in 2000 and completed
a refueling outage in early June more than four days ahead of schedule.  The
40-day, 21-hour outage set a world record for a refueling that included a
full generator rewind.  Millstone 3 operated at virtually a 100 percent
capacity factor in 2000 and ran for 585 consecutive days before beginning a
scheduled refueling outage on February 3, 2001.  Millstone 3 is expected to
return to service by the end of the first quarter of 2001.

On August 7, 2000, WMECO and certain other joint owners reached an agreement
to sell substantially all of the Millstone units, located in Waterford,
Connecticut, to Dominion, for approximately $1.3 billion, including
approximately $105 million for nuclear fuel. Dominion has also agreed to assume
responsibility for decommissioning the three units and NU will transfer to
Dominion all funds in the Millstone decommissioning trust.  Additionally, NU is
obligated to top-off the decommissioning trust if its value does not equal an
agreed upon amount at closing.  That amount is pursuant to the purchase and
sale agreement (PSA) with Dominion, subject to adjustment for delays in the
closing of the sale and Millstone 1 not meeting the "cold and dark" condition
specified in the PSA.

If the transaction is consummated as proposed, WMECO would receive gross
proceeds of approximately $196.2 million on a pretax basis for its respective
ownership interest.  The proceeds from the sale of this interest will be used
to reduce the company's stranded costs under restructuring and the cash
proceeds will be used to repay subsidiary debt and capital lease obligations
and to return equity capital to the parent company.

In preparation for the divestiture of the Millstone units, it was discovered
that two full-length irradiated fuel rods are missing.  NU believes that the
two rods remain stored in the Millstone 1 spent fuel pool or were shipped in
a shielded cask to a facility licensed to accept radioactive material.  NU's
investigation into the location of the two rods is ongoing.  NU is responsible
for any potential liabilities, which are not determinable at this time, related
to these missing fuel rods.

NU currently expects to close on the sale of Millstone as early as the end
of March 2001.

Yankee Companies
In 1999, the Vermont Yankee Nuclear Power Corporation (VYNPC) agreed to sell
its nuclear generating unit for $22 million to an unaffiliated company.  Among
other commitments, the acquiring company agreed to assume the obligation to
decommission the unit after it is taken out of service, and the owners of VYNPC
(including WMECO) agreed to fund their shares of the decommissioning costs up
to a negotiated amount.  Subsequent to the time that agreement was executed,
the original proposed acquiring company increased its purchase price and three
other unaffiliated companies have indicated their interest in buying VYNPC's
generating unit on terms that have not been disclosed.  On February 14, 2001,
the Vermont Public Service Board dismissed the acquiring company's petition for
approval and VYNPC agreed to work with the Vermont regulators to develop an
auction process for the sale of the unit.  At present, WMECO expects that the
unit will be sold, but the identity of the owner and the terms of sale,
including price, future decommissioning obligations and future power purchase
obligations, are not known.

Nuclear Decommissioning
In connection with the aforementioned sale of the Millstone units, Dominion has
agreed to assume responsibility for decommissioning the Millstone units.

For further information regarding nuclear decommissioning, see Note 10,
"Nuclear Decommissioning and Plant Closure Costs," to the consolidated
financial statements.

Spent Nuclear Fuel Disposal Costs
The United States Department of Energy (DOE) originally was scheduled to begin
accepting delivery of spent nuclear fuel in 1998.  However, delays in
confirming the suitability of a permanent storage site continually have
postponed plans for the DOE's long-term storage and disposal site.  Extended
delays or a default by the DOE could lead to consideration of costly
alternatives.  WMECO has the primary responsibility for the interim storage of
its spent nuclear fuel prior to divestiture of its nuclear units.

For further information regarding spent nuclear fuel disposal costs, see
Note 9D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs,"
to the consolidated financial statements.

Other Matters
- -------------

Environmental Matters
WMECO is subject to environmental laws and regulations structured to mitigate
or remove the effect of past operations and to improve or maintain the quality
of the environment.  For further information regarding environmental matters,
see Note 9C, "Commitments and Contingencies - Environmental Matters," to the
consolidated financial statements.

Other Commitments and Contingencies
For further information regarding other commitments and contingencies, see
Note 9, "Commitments and Contingencies," to the consolidated financial
statements.

Forward Looking Statements
This discussion and analysis includes forward looking statements, which are
statements of future expectations and not facts including, but not limited to,
statements regarding future earnings, refinancings, the use of proceeds from
restructuring, and the recovery of operating costs.  Words such as estimates,
expects, anticipates, intends, plans, and similar expressions identify forward
looking statements.  Actual results or outcomes could differ materially as a
result of further actions by state and federal regulatory bodies, competition
and industry restructuring, changes in economic conditions, changes in
historical weather patterns, changes in laws, developments in legal or public
policy doctrines, technological developments, and other presently unknown or
unforeseen factors.

RESULTS OF OPERATIONS

The components of significant income statement variances for the past
two years are provided in the table below.


                                          Income Statement Variances
                                             (Millions of Dollars)

                               2000 over/(under) 1999   1999 over/(under) 1998
                               -----------------------------------------------
                                  Amount    Percent        Amount    Percent
                                  ------    -------        ------    -------

Operating Revenues                $ 99        24%           $ 21         5%

Operating Expenses:
Fuel, purchased and net
  interchange power                 95        62              21        16
Other operation                    (26)      (25)            (16)      (13)
Maintenance                        (14)      (30)             (9)      (16)
Depreciation                       (10)      (36)            (13)      (32)
Amortization of
  regulatory assets, net            21        80              20        (a)
Federal and state
  income taxes                       2        12              17        (a)
Taxes other than
  income taxes                      (3)      (14)              1         5
Gain on sale of
  utility plant                     22       100             (22)        -
                                  ----       ---            ----       ---
Total operating expenses            87        23              (1)        -
                                  ----       ---            ----       ---
Operating income                    12        30              22        (a)
                                  ----       ---            ----       ---

Other Income:
Equity in earnings of
  regional nuclear
  generating and
  transmission companies             2        (a)             (1)      (76)
Nuclear related costs               15        84             (18)        -
Other, net                           5        (a)             (2)      (90)
Other income taxes                  (4)      (39)              8        (a)
Net other income                    18        (a)            (13)       (a)
Interest charges, net               (2)       (7)             (4)      (12)
                                  ----       ---            ----       ---
Net income/(loss)                 $ 32        (a)           $ 13        (a)
                                  ====       ===            ====       ===

(a) Percent greater than 100.

Operating Revenues
Operating revenues increased by $99 million or 24 percent in 2000, primarily
due to higher wholesale and retail revenues.  Wholesale revenues increased
($82 million) as a result of the sale of output from Millstone 2 and 3, and
the amortization of the gain on the transfer of certain hydroelectric
generation assets ($6 million).  Retail revenues increased by $11 million due
to retail rate increases in late 1999 and early 2000.  Retail sales compared
to 1999 were flat.

Operating revenues increased by $21 million or 5 percent in 1999, primarily due
to higher wholesale and retail revenues.  Wholesale revenues increased ($17
million) due to higher energy sales and related capacity and transmission
revenues.  Retail revenues increased by $4 million due to the retail kilowatt-
hour sales increase of 3.6 percent which increased revenues by $16 million and
was partially offset by the retail rate decrease in 1998 ($12 million).

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased in 2000, primarily
due to the transition, under industry restructuring, of purchasing full
requirements for customers from standard offer suppliers, in addition to the
remaining fuel costs of the nuclear units and cogenerators.

Fuel, purchased and net interchange power expense increased in 1999, primarily
due to a reversal of fuel expense deferrals which were recorded in other
operation and maintenance (O&M) expenses as a result of the WMECO restructuring
order, partially offset by lower replacement power costs.

Other Operation and Maintenance
Other O&M expenses decreased in 2000, primarily due to lower spending at the
nuclear units ($17 million), the decommissioning status of Millstone 1 ($7
million), lower administrative and general expenses ($14 million), lower fossil
and hydroelectric expenses due to the sale of certain fossil generation assets
and transfer of certain hydroelectric generation assets ($6 million), partially
offset by higher transmission expenses ($4 million).

Other O&M expenses decreased in 1999, primarily due to lower costs at the
Millstone units ($17 million), deferrals associated with the restructuring
order ($5 million), and lower fossil and hydroelectric O&M costs ($4 million),
partially offset by higher transmission expenses ($4 million).

Depreciation
Depreciation decreased in 2000, primarily due to the effect of discontinuing
Statement of Financial Accounting Standards No. 71, "Accounting for the Effects
of Certain Types of Regulation," for the generation portion of the business and
the resulting reclassification of depreciable nuclear plant balances to
regulatory assets ($14 million), the sale of certain fossil generation assets
and the transfer of certain hydroelectric generation assets.

Depreciation decreased in 1999, primarily due to lower rates utilized in 1999
as a result of the 1999 restructuring orders and the retirement of Millstone 1.

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased in 2000, primarily due to
changes in amortization levels as a result of industry restructuring ($24
million) and higher amortization associated with the reclassified nuclear plant
balances ($14 million), partially offset by the amortization in 1999 of the
gain on the sale of the fossil plants ($12 million).

Amortization of regulatory assets, net increased in 1999, primarily due to
increased amortization associated with the gain on the sale of fossil and
hydroelectric generation assets ($13 million), the amortization of the
Millstone 1 investment ($5 million) and the reclassification of the
depreciation on the nuclear plants transferred to regulatory assets
($4 million).

Federal and State Income Taxes
Federal and state income taxes increased in 2000 and 1999, primarily due
to higher book taxable income.

Taxes Other Than Income Taxes
Taxes other than income taxes decreased in 2000, primarily due to a decrease
in local property taxes.

Gain on Sale of Utility Plant
WMECO recorded a gain on the sale of its fossil and hydroelectric generation
assets in 1999.  A corresponding amount of amortization expense was recorded.

Nuclear Related Costs
Nuclear related costs in 2000 are comprised of a settlement of Millstone 3
joint owner litigation, net of insurance proceeds ($2 million), and a
regulatory settlement ($1 million).

In comparison, costs in 1999 are comprised of one-time charges related to the
return disallowed on Millstone 1 unrecovered plant from March 1998 forward
($11 million), the settlement of Millstone 3 owner litigation, net of insurance
proceeds ($5 million) and the disallowed Millstone 1 plant per the
Massachusetts restructuring order ($2 million).

Other, Net
Other, net, increased in 2000, primarily due to an environmental reserve
recorded in 1999 ($3 million).

Interest Charges, Net
Interest charges, net, decreased in 2000 and 1999, primarily due to
reacquisitions and retirements of long-term debt, partially offset by an
increase in interest charges related to short-term borrowings.



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
- ----------------------------------------

To the Board of Directors
   of Western Massachusetts Electric Company:

We have audited the accompanying consolidated balance sheets of Western
Massachusetts Electric Company (a Massachusetts corporation and a wholly owned
subsidiary of Northeast Utilities) and subsidiary as of December 31, 2000 and
1999, and the related consolidated statements of income, comprehensive income,
common stockholder's equity and cash flows for each of the three years in the
period ended December 31, 2000.  These financial statements are the
responsibility of the company's management.  Our responsibility is to express
an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements.  An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Western Massachusetts
Electric Company and subsidiary as of December 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States.




                                                /s/ ARTHUR ANDERSEN LLP
                                                    ARTHUR ANDERSEN LLP


Hartford, Connecticut
January 23, 2001 (except with
respect to the matter discussed
in Note 14, as to which the
date is March 13, 2001)




WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31,                   2000       1999        1998
- ---------------------------------------------------------------------------------
                                                      (Thousands of Dollars)

<S>                                             <C>        <C>         <C>
Operating Revenues............................. $ 513,678  $ 414,231   $ 393,322
                                                ---------- ----------  ----------
Operating Expenses:
  Operation -
     Fuel, purchased and net interchange power.   246,130    151,714     130,401
     Other.....................................    75,940    101,842     117,663
  Maintenance..................................    33,111     47,586      56,622
  Depreciation.................................    17,693     27,771      40,901
  Amortization of regulatory assets............    47,775     26,488       6,016
  Federal and state income taxes...............    21,174     18,849       2,109
  Taxes other than income taxes................    17,759     20,677      19,756
  Gain on sale of utility plant................      -       (22,437)       -
                                                ---------- ----------  ----------
        Total operating expenses...............   459,582    372,490     373,468
                                                ---------- ----------  ----------
Operating Income...............................    54,096     41,741      19,854
                                                ---------- ----------  ----------

Other Income/(Loss):
  Equity in earnings of regional nuclear
    generating companies.......................     2,251        407       1,699
  Nuclear related costs........................    (2,808)   (18,035)       -
  Other, net...................................     1,242     (3,618)     (1,905)
  Income taxes.................................     6,029      9,906       2,198
                                                ---------- ----------  ----------
        Other income/(loss), net...............     6,714    (11,340)      1,992
                                                ---------- ----------  ----------
        Income before interest charges.........    60,810     30,401      21,846
                                                ---------- ----------  ----------
Interest Charges:
  Interest on long-term debt...................    14,051     24,255      28,027
  Other interest...............................    11,491      3,259       3,398
                                                ---------- ----------  ----------
        Interest charges, net..................    25,542     27,514      31,425
                                                ---------- ----------  ----------

Net Income/(Loss).............................. $  35,268  $   2,887   $  (9,579)
                                                ========== ==========  ==========

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Net Income/(Loss).............................. $  35,268  $   2,887   $  (9,579)
                                                ---------- ----------  ----------
Other comprehensive income, net of tax:
  Unrealized gains on securities...............        22         10         183
  Minimum pension liability adjustments........      -          -            (33)
                                                ---------- ----------  ----------
        Other comprehensive income, net of tax.        22         10         150
                                                ---------- ----------  ----------
Comprehensive Income/(Loss)                     $  35,290  $   2,897   $  (9,429)
                                                ========== ==========  ==========

</TABLE>
The accompanying notes are an integral part of these financial statements.



WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
AT DECEMBER 31,                                                  2000          1999
- ---------------------------------------------------------------------------------------
                                                               (Thousands of Dollars)
<S>                                                         <C>            <C>
ASSETS
- ------

Utility Plant, at original cost:
  Electric................................................  $  1,112,405   $ 1,175,954

     Less: Accumulated provision for depreciation.........       792,923       813,978
                                                            -------------  ------------
                                                                 319,482       361,976
  Construction work in progress...........................        22,813        21,181
  Nuclear fuel, net.......................................        18,296        18,880
                                                            -------------  ------------
     Total net utility plant..............................       360,591       402,037
                                                            -------------  ------------
Other Property and Investments:
  Nuclear decommissioning trusts, at market...............       144,921       144,567
  Investments in regional nuclear generating
   companies, at equity...................................        11,117        14,723
  Other, at cost..........................................         6,249         6,232
                                                            -------------  ------------
                                                                 162,287       165,522
                                                            -------------  ------------
Current Assets:
  Cash....................................................           985           950
  Receivables less the accumulated provision for
   uncollectible accounts of $1,886 in 2000 and
   $1,640 in 1999.........................................        36,364        31,692
  Accounts receivable from affiliated companies...........        16,146         3,918
  Taxes receivable........................................         -             1,912
  Accrued utility revenues................................        21,222        13,485
  Fuel, materials and supplies, at average cost...........         1,606         3,097
  Prepayments and other...................................         4,817         3,640
                                                            -------------  ------------
                                                                  81,140        58,694
                                                            -------------  ------------
Deferred Charges:
  Regulatory assets.......................................       392,247       594,800
  Unamortized debt expense................................         1,822         1,926
  Prepaid pension.........................................        45,473        26,479
  Other...................................................         4,258         4,146
                                                            -------------  ------------
                                                                 443,800       627,351
                                                            -------------  ------------

Total Assets..............................................  $  1,047,818   $ 1,253,604
                                                            =============  ============
</TABLE>
The accompanying notes are an integral part of these financial statements.



WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
AT DECEMBER 31,                                                  2000          1999
- ---------------------------------------------------------------------------------------
                                                               (Thousands of Dollars)
<S>                                                            <C>           <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------

Capitalization:
  Common stock, $25 par value - authorized
   1,072,471 shares; 590,093 shares outstanding in 2000
   and 1,072,471 shares outstanding in 1999...............  $     14,752   $    26,812
  Capital surplus, paid in................................        94,010       171,691
  Retained earnings.......................................        62,952        38,712
  Accumulated other comprehensive income..................           182           160
                                                            -------------  ------------
           Total common stockholder's equity..............       171,896       237,375
  Preferred stock not subject to mandatory redemption.....        20,000        20,000
  Preferred stock subject to mandatory redemption.........        15,000        16,500
  Long-term debt..........................................       139,425       290,279
                                                            -------------  ------------
           Total capitalization...........................       346,321       564,154
                                                            -------------  ------------
Obligations Under Capital Leases..........................         5,935         8,106
                                                            -------------  ------------
Current Liabilities:
  Notes payable to banks..................................       110,000       123,000
  Notes payable to affiliated company.....................           600         9,400
  Long-term debt and preferred stock - current portion....        61,500         1,500
  Obligations under capital leases - current portion......        20,986        21,866
  Accounts payable........................................        25,298        12,974
  Accounts payable to affiliated companies................         8,611         3,208
  Accrued taxes...........................................         8,471           589
  Accrued interest........................................         4,703         6,046
  Other...................................................         7,671        14,384
                                                            -------------  ------------
                                                                 247,840       192,967
                                                            -------------  ------------
Deferred Credits and Other Long-term Liabilities:
  Accumulated deferred income taxes.......................       224,711       242,942
  Accumulated deferred investment tax credits.............        17,580        19,765
  Decommissioning obligation - Millstone 1................       136,130       136,130
  Deferred contractual obligations........................        42,519        63,701
  Other...................................................        26,782        25,839
                                                            -------------  ------------
                                                                 447,722       488,377
                                                            -------------  ------------
Commitments and Contingencies (Note 9)

Total Capitalization and Liabilities......................  $  1,047,818   $ 1,253,604
                                                            =============  ============
</TABLE>
The accompanying notes are an integral part of these financial statements.



WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------
                                                                                 Accumulated
                                                        Capital     Retained        Other
                                             Common     Surplus,    Earnings    Comprehensive
                                             Stock      Paid In       (a)          Income         Total
- ---------------------------------------------------------------------------------------------------------
                                                               (Thousands of Dollars)
<S>                                        <C>         <C>         <C>                <C>       <C>
Balance at January 1, 1998...............  $ 26,812    $151,171    $ 58,608    $       -        $236,591

    Net loss for 1998....................                            (9,579)                      (9,579)
    Cash dividends on preferred stock....                            (3,026)                      (3,026)
    Capital stock expenses, net..........                   260                                      260
    Other comprehensive income...........                                                150         150
                                           ---------   ---------   ---------    -------------   ---------
Balance at December 31, 1998.............    26,812     151,431      46,003              150     224,396

    Net income for 1999..................                             2,887                        2,887
    Cash dividends on preferred stock....                            (3,298)                      (3,298)
    Capital stock expenses, net..........                   260                                      260
    Allocation of benefits - ESOP........                            (6,880)                      (6,880)
    Capital contribution from
      Northeast Utilities................                20,000                                   20,000
    Other comprehensive income...........                                                 10          10
                                           ---------   ---------   ---------    -------------   ---------
Balance at December 31, 1999.............    26,812     171,691      38,712              160     237,375

    Net income for 2000..................                            35,268                       35,268
    Cash dividends on preferred stock....                            (2,798)                      (2,798)
    Cash dividends on common stock.......                           (12,002)                     (12,002)
    Repurchase of common stock...........   (12,060)    (77,940)                                 (90,000)
    Capital stock expenses, net..........                   259                                      259
    Tax benefit for 1993-1999 from
      reduction of NU parent losses(b)...                             3,824                        3,824
    Allocation of benefits - ESOP........                               (52)                         (52)
    Other comprehensive income...........                                                 22          22
                                           ---------   ---------   ---------    -------------   ---------
Balance at December 31, 2000.............  $ 14,752    $ 94,010    $ 62,952    $         182    $171,896
                                           =========   =========   =========    =============   =========
</TABLE>
(a)  The company has no dividend restrictions.  However, the company has a
     30% common equity test to meet and therefore, at December 31, 2000, cannot
     pay out approximately $31.5 million in equity.

(b) In June 1999, WMECO paid NU parent $6.9 million for NU shares issued from
    1992 through 1998 on behalf of its employees in accordance with NU's 401(k)
    plan.  This transaction resulted in a reduction of the NU parent loss and
    a tax benefit to WMECO.  The amount in 2000 represents the remaining
    previously unallocated 1993 through 1999 NU parent losses.

The accompanying notes are an integral part of the financial statements.


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
                                                                For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)                                             2000        1999        1998
- --------------------------------------------------------------------------------------------------
<S>                                                            <C>         <C>         <C>
Operating Activities:
  Net income/(loss)........................................... $   35,268  $    2,887  $   (9,579)
  Adjustments to reconcile to net cash
   provided by operating activities:
    Depreciation..............................................     17,693      27,771      40,901
    Deferred income taxes and investment tax credits, net.....    (11,549)     (6,544)      7,405
    Amortization of recoverable energy costs, net.............      9,386         -           -
    Amortization of regulatory assets, net....................     47,775      26,488       6,016
    Tax benefit for 1993-1999 from
      reduction of NU parent losses...........................      3,824         -           -
    Nuclear related costs.....................................      2,808      18,035         -
    Allocation of ESOP benefits...............................        (52)     (6,880)        -
    Gain on sale of utility plant.............................        -       (22,437)        -
    Other uses of cash........................................    (28,834)    (24,096)     (6,553)
  Changes in working capital:
    Receivables and accrued utility revenues..................    (24,637)    (44,045)      1,622
    Fuel, materials and supplies..............................      1,491       1,956         807
    Accounts payable..........................................     17,727     (14,636)    (20,962)
    Investments in securitizable assets.......................        -        21,865       3,415
    Accrued taxes.............................................      7,882        (675)        742
    Other working capital (excludes cash).....................     (7,321)     22,368       3,748
                                                               ----------- ----------- -----------
Net cash flows provided by operating activities...............     71,461       2,057      27,562
                                                               ----------- ----------- -----------
Investing Activities:
  Investments in plant:
    Electric utility plant....................................    (27,267)    (30,192)    (19,895)
    Nuclear fuel..............................................     (7,848)     (5,817)     (1,801)
                                                               ----------- ----------- -----------
    Net cash flows used for investments in plant..............    (35,115)    (36,009)    (21,696)

  Investments in nuclear decommissioning trusts...............     (3,437)    (11,387)    (12,918)
  Other investment activities, net............................      3,589       1,807        (171)
  Net proceeds from the transfer/sale of utility plant........    185,787      48,524         -
  Capital contributions from Northeast Utilities..............        -        20,000         -
                                                               ----------- ----------- -----------
Net cash flows provided by/(used in) investing activities.....    150,824      22,935     (34,785)
                                                               ----------- ----------- -----------

Financing Activities:
  Net (decrease)/increase in short-term debt..................    (21,800)     81,500      21,550
  Reacquisitions and retirements of long-term debt............    (94,150)   (100,850)     (9,800)
  Reacquisitions and retirements of preferred stock...........     (1,500)     (1,500)     (1,500)
  Repurchase of common shares.................................    (90,000)        -           -
  Cash dividends on preferred stock...........................     (2,798)     (3,298)     (3,026)
  Cash dividends on common stock..............................    (12,002)        -           -
                                                               ----------- ----------- -----------
Net cash flows (used in)/provided by financing activities.....   (222,250)    (24,148)      7,224
                                                               ----------- ----------- -----------

Net increase in cash for the period...........................         35         844           1
Cash - beginning of period....................................        950         106         105
                                                               ----------- ----------- -----------
Cash - end of period.......................................... $      985  $      950  $      106
                                                               =========== =========== ===========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
  Interest, net of amounts capitalized........................ $   26,055  $   30,958  $   22,902
                                                               =========== =========== ===========
  Income taxes................................................ $   18,554  $   (6,296) $   (2,624)
                                                               =========== =========== ===========
Increase in obligations:
  Niantic Bay Fuel Trust...................................... $    1,532  $    1,112  $    2,375
                                                               =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ------------------------------------------

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     A.  About Western Massachusetts Electric Company
         Western Massachusetts Electric Company (WMECO or the company) along
         with The Connecticut Light and Power Company (CL&P), Public Service
         Company of New Hampshire (PSNH), North Atlantic Energy Corporation
         (NAEC), and Holyoke Water Power Company (HWP) are the operating
         companies comprising the Northeast Utilities system (NU system) and
         are wholly owned by Northeast Utilities (NU).  The NU system serves
         in excess of 30 percent of New England's electric needs and is one of
         the 25 largest electric utility systems in the country as measured by
         revenues.  The NU system furnishes franchised retail electric service
         in western Massachusetts, Connecticut and New Hampshire through WMECO,
         CL&P and PSNH.  NAEC sells all of its entitlement to the capacity and
         output of the Seabrook Station nuclear unit (Seabrook) to PSNH under
         the terms of two life-of-unit, full cost recovery contracts.  HWP,
         also is engaged in the production and distribution of electric power.

         On March 1, 2000, NU completed its acquisition of Yankee Energy
         System, Inc., the parent company of Yankee Gas Services Company,
         Connecticut's largest natural gas distribution system.

         NU is registered with the Securities and Exchange Commission (SEC)
         as a holding company under the Public Utility Holding Company Act of
         1935 (1935 Act) and the NU system, including WMECO, is subject to
         provisions of the 1935 Act.  Arrangements among the NU system
         companies, outside agencies and other utilities covering
         interconnections, interchange of electric power and sales of utility
         property are subject to regulation by the Federal Energy Regulatory
         Commission (FERC) and/or the SEC.  WMECO is subject to further
         regulation for rates, accounting and other matters by the FERC and
         the Massachusetts Department of Telecommunications and Energy (DTE).

         Several wholly owned subsidiaries of NU provide support services for
         the NU system companies, including WMECO, and, in some cases, for
         other New England utilities.  Northeast Utilities Service Company
         (NUSCO) provides centralized accounting, administrative, information
         resources, engineering, financial, legal, operational, planning,
         purchasing, and other services to the NU system companies, including
         WMECO.  Northeast Nuclear Energy Company acts as agent for the NU
         system companies and other New England utilities in operating the
         Millstone nuclear units.  North Atlantic Energy Service Corporation
         has operational responsibility for Seabrook.

     B.  Presentation
         The consolidated financial statements of WMECO include the accounts of
         its subsidiary.  Intercompany transactions have been eliminated in
         consolidation.

         The preparation of financial statements in conformity with accounting
         principles generally accepted in the United States requires management
         to make estimates and assumptions that affect the reported amounts of
         assets and liabilities and disclosure of contingent liabilities at the
         date of the financial statements and the reported amounts of revenues
         and expenses during the reporting period.  Actual results could differ
         from those estimates.

         Certain reclassifications of prior years' data have been made to
         conform with the current year's presentation.

         All transactions among affiliated companies are on a recovery of cost
         basis which may include amounts representing a return on equity and
         are subject to approval by various federal and state regulatory
         agencies and the DTE.

     C.  New Accounting Standards
         Derivative Instruments:  Effective January 1, 2001, WMECO adopted
         Statement of Financial Accounting Standards (SFAS) No. 133,
         "Accounting for Derivative Instruments and Hedging Activities," as
         amended.  SFAS No. 133 requires that derivative instruments be
         recorded as an asset or liability measured at its fair value and that
         changes in the fair value of derivative instruments be recognized
         currently in earnings unless specific hedge accounting criteria are
         met.

         In order to implement SFAS No. 133 by January 1, 2001, NU established
         a cross-functional project team to identify all derivative
         instruments, measure the fair value of those derivative instruments,
         designate and document various hedge relationships, and evaluate the
         effectiveness of those hedge relationships.  NU has completed the
         process of identifying all derivative instruments and has established
         appropriate fair value measurements of those derivative instruments in
         place at January 1, 2001.  In addition, for those derivative
         instruments which are hedging an identified risk, NU has designated
         and documented all hedging relationships anew.

         Management believes the adoption of this new standard will not have a
         material impact on WMECO's financial position or results of
         operations.

         Revenue Recognition:  In December 1999, the SEC issued Staff
         Accounting Bulletin (SAB) No. 101, "Revenue Recognition."  The
         adoption of SAB No. 101, as amended, did not have a material impact
         on WMECO's consolidated financial statements.

     D.  Investments and Jointly Owned Electric Utility Plant
         Regional Nuclear Generating Companies: WMECO owns common stock in four
         regional nuclear companies (Yankee Companies).  WMECO's ownership
         interests in the Yankee Companies at December 31, 2000 and 1999, which
         are accounted for on the equity method due to WMECO's ability to
         exercise significant influence over their operating and financial
         policies are 9.5 percent of the Connecticut Yankee Atomic Power
         Company (CYAPC), 7 percent of the Yankee Atomic Electric Company
         (YAEC), 3 percent of the Maine Yankee Atomic Power Company (MYAPC),
         and 2.5 percent of the Vermont Yankee Nuclear Power Corporation
         (VYNPC).  WMECO's total equity investment in the Yankee Companies at
         December 31, 2000 and 1999, is $11.1 million and $14.7 million,
         respectively.  Each Yankee Company owns a single nuclear generating
         unit.  However, VYNPC is the only unit still in operation at
         December 31, 2000.

         Millstone:  WMECO has a 19 percent joint ownership in both
         Millstone 1, a 660 megawatt (MW) nuclear unit, which is currently in
         decommissioning status, and Millstone 2, an 870 MW nuclear generating
         unit.  WMECO has a 12.24 percent joint ownership interest in
         Millstone 3, a 1,154 MW nuclear generating unit.  On August 7, 2000,
         WMECO and certain other joint owners reached an agreement to sell
         substantially all of the Millstone units to Dominion Resources, Inc.
         (Dominion) for approximately $1.3 billion, including approximately
         $105 million for nuclear fuel.  NU currently expects to close on the
         sale of Millstone as early as the end of March 2001.

         Plant-in-service and the accumulated provision for depreciation for
         WMECO's share of Millstone 2 and 3 are as follows:

         ----------------------------------------------------------------------
         At December 31,                                 2000        1999
         ----------------------------------------------------------------------
                                                       (Millions of Dollars)

         Plant-in-service
         Millstone 2.............................       $182.3       $180.4
         Millstone 3.............................        382.7        380.5
         Accumulated provision for depreciation
         Millstone 2.............................       $174.5       $166.7
         Millstone 3.............................        357.3        358.7
         ----------------------------------------------------------------------

     E.  Depreciation
         The provision for depreciation is calculated using the straight-line
         method based on estimated remaining useful lives of depreciable
         utility plant-in-service, adjusted for salvage value and removal
         costs, as approved by the appropriate regulatory agency where
         applicable.  Except for major facilities, depreciation rates are
         applied to the average plant-in-service during the period.  Major
         facilities are depreciated from the time they are placed in service.
         When plant is retired from service, the original cost of the plant,
         including costs of removal less salvage, is charged to the accumulated
         provision for depreciation.  The costs of closure and removal of
         nonnuclear facilities are accrued over the life of the plant as a
         component of depreciation.  The depreciation rates for the several
         classes of electric plant-in-service are equivalent to a composite
         rate of 2.2 percent in 2000, 2.3 percent in 1999 and 2.9 percent in
         1998.

         As a result of discontinuing the application of SFAS No. 71,
         "Accounting for the Effects of Certain Types of Regulation," for
         WMECO's generation business in 1999, the company recorded a charge
         to accumulated depreciation for the nuclear plant in excess of the
         estimated fair market value at the time in the amount of $330 million
         and a corresponding regulatory asset was created.

     F.  Revenues
         Revenues are based on authorized rates applied to each customer's use
         of electricity.  In general, rates can be changed only through a
         formal proceeding before the DTE.  Regulatory commissions also have
         authority over the terms and conditions of nontraditional rate-making
         arrangements.  At the end of each accounting period, WMECO accrues a
         revenue estimate for the amount of energy delivered but unbilled.

     G.  Regulatory Accounting and Assets
         The accounting policies of WMECO and the accompanying consolidated
         financial statements conform to accounting principles generally
         accepted in the United States applicable to rate-regulated enterprises
         and historically reflect the effects of the rate-making process in
         accordance with SFAS No. 71.  As a result of final restructuring
         orders issued in 1999, WMECO discontinued the application of SFAS
         No. 71 for the generation portion of its business.

         WMECO's transmission and distribution business will continue to be
         cost-based and management believes the application of SFAS No. 71
         continues to be appropriate.  Management continues to believe it is
         probable that WMECO will recover its investments in long-lived assets,
         including regulatory assets through charges to their transmission and
         distribution customers.  The majority for WMECO will be recovered
         through a transition charge over a 12-year period.  In addition, all
         material regulatory assets are earning a return.  The components of
         WMECO's regulatory assets are as follows:

         ----------------------------------------------------------------------
         At December 31,                                 2000        1999
         ----------------------------------------------------------------------
                                                       (Millions of Dollars)

         Recoverable nuclear costs...............       $257.7       $428.9
         Income taxes, net.......................         50.3         49.0
         Unrecovered contractual obligations.....         42.5         63.7
         Recoverable energy costs, net...........          6.9         16.3
         Other...................................         34.8         36.9
                                                        ------       ------
                                                        $392.2       $594.8
                                                        ======       ======
         ----------------------------------------------------------------------

         As a result of discontinuing the application of SFAS No. 71 in 1999
         for WMECO's generation business, the company reclassified nuclear
         plant in excess of its estimated fair market value from plant to
         regulatory assets.  As of December 31, 2000 and 1999, excluding the
         impact of the transfer of generation assets to Northeast Generation
         Company in 2000, the unamortized balance ($286.9 million and $316.1
         million, respectively) is classified as recoverable nuclear costs.
         Also included in that regulatory asset component for 2000 and 1999
         are $104.9 million and $112.8 million, respectively, which includes
         Millstone 1 recoverable nuclear costs relating to the recoverable
         portion of the undepreciated plant and related assets ($39.6 million
         and $43.8 million, respectively) and the decommissioning and closure
         obligation ($65.3 million and $69 million, respectively).

     H.  Income Taxes
         The tax effect of temporary differences (differences between the
         periods in which transactions affect income in the financial
         statements and the periods in which they affect the determination of
         taxable income) is accounted for in accordance with the rate-making
         treatment of the applicable regulatory commissions.

         The tax effect of temporary differences, including timing differences
         accrued under previously approved accounting standards, that give rise
         to the accumulated deferred tax obligation is as follows:

         ----------------------------------------------------------------------
         At December 31,                                 2000        1999
         ----------------------------------------------------------------------
                                                       (Millions of Dollars)

         Accelerated depreciation and
           other plant-related differences.......       $193.7      $213.4

         Regulatory assets -
           income tax gross up...................         19.5        19.0

         Other...................................         11.5        10.5
                                                        ------      ------
                                                        $224.7      $242.9
                                                        ======      ======
         ----------------------------------------------------------------------

     I.  Unrecovered Contractual Obligations
         Under the terms of contracts with the Yankee Companies, the
         shareholder-sponsored companies, including WMECO, are responsible for
         their proportionate share of the remaining costs of the units,
         including decommissioning.  As management expects that WMECO will be
         allowed to recover these costs from its customers, WMECO has recorded
         a regulatory asset, with a corresponding obligation, on its
         consolidated balance sheet.

     J.  Recoverable Energy Costs
         Under the Energy Policy Act of 1992 (Energy Act), WMECO is assessed
         for its proportionate share of the costs of decontaminating and
         decommissioning uranium enrichment plants owned by the United States
         Department of Energy (DOE) (D&D Assessment).  The Energy Act requires
         that regulators treat D&D Assessments as a reasonable and necessary
         current cost of fuel, to be fully recovered in rates like any other
         fuel cost.  WMECO is currently recovering these costs through rates.
         As of December 31, 2000 and 1999, WMECO's total D&D Assessment
         deferrals were $8.6 million and $9.6 million, respectively.

2.   SHORT-TERM DEBT
     Limits:  The amount of short-term borrowings that may be incurred by WMECO
     is subject to periodic approval by either the SEC under the 1935 Act or by
     state regulators.  Currently, SEC authorization allows WMECO to incur
     total short-term borrowings up to a maximum of $250 million.  In addition,
     the charter of WMECO contains preferred stock provisions restricting the
     amount of unsecured debt the company may incur.  As of December 31, 2000,
     WMECO's charter permits WMECO to incur $94 million of additional
     unsecured debt.

     Credit Agreement:  On November 17, 2000, WMECO and CL&P entered into a
     364-day revolving credit facility for $350 million, replacing the previous
     $500 million facility which was to expire on November 17, 2000.  WMECO may
     draw up to $150 million under the facility which, until the nuclear
     divestiture, is secured by second mortgages on Millstone 2 and 3.  Once
     WMECO and CL&P receive the proceeds from securitization, the $350 million
     revolving credit facility will be reduced to $250 million, with a $100
     million limit for WMECO.  Unless extended, the credit facility will expire
     on November 16, 2001.  At December 31, 2000 and 1999, there were $110
     million and $123 million, respectively, in borrowings under these
     facilities.

     Under the aforementioned credit agreement, WMECO may borrow at fixed or
     variable rates plus an applicable margin based upon certain debt ratings,
     as rated by the lower of Standard and Poor's or Moody's Investors Service.
     The weighted average interest rate on WMECO's notes payable to banks
     outstanding on December 31, 2000 and 1999, was 8.05 percent and 7.70
     percent, respectively.  Maturities of short-term debt obligations were for
     periods of three months or less.

     This credit agreement provides that WMECO must comply with certain
     financial and nonfinancial covenants as are customarily included in such
     agreements, including, but not limited to, common equity ratios and
     interest coverage ratios.  WMECO currently is and expects to remain in
     compliance with these covenants.

     Money Pool:  Certain subsidiaries of NU, including WMECO, are members of
     the Northeast Utilities System Money Pool (Pool).  The Pool provides a
     more efficient use of the cash resources of the NU system and reduces
     outside short-term borrowings.  NUSCO administers the Pool as agent for
     the member companies.  Short-term borrowing needs of the member companies
     are first met with available funds of other member companies, including
     funds borrowed by NU parent.  NU parent may lend to the Pool but may not
     borrow.  Funds may be withdrawn from or repaid to the Pool at any time
     without prior notice.  Investing and borrowing subsidiaries receive or
     pay interest based on the average daily federal funds rate.  Borrowings
     based on loans from NU parent, however, bear interest at NU parent's cost
     and must be repaid based upon the terms of NU parent's original borrowing.
     At December 31, 2000 and 1999, WMECO had $0.6 million and $9.4 million,
     respectively, of borrowings outstanding from the Pool.  The interest rate
     on borrowings from the Pool at December 31, 2000 and 1999, was 5.4 percent
     and 4.9 percent, respectively.

3.   LEASES
     WMECO finances its respective shares of the nuclear fuel for Millstone 2
     and 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement.
     This capital lease agreement has an expiration date of June 1, 2040.  At
     December 31, 2000 and 1999, the present value of WMECO's capital lease
     obligation to the NBFT was $26.6 million and $29.8 million, respectively.
     In connection with the planned nuclear divestiture, the NBFT capital lease
     will be terminated, the nuclear fuel will be transferred to Dominion and
     the related $180 million Series G Intermediate Term Note Agreement will be
     extinguished with the divestiture proceeds.

     WMECO makes quarterly lease payments for the cost of nuclear fuel consumed
     in the reactors based on a units-of-production method at rates which
     reflect estimated kilowatt-hours of energy provided plus financing costs
     associated with the fuel in the reactors.  Upon permanent discharge from
     the reactors, WMECO's ownership interest in the nuclear fuel transfers to
     WMECO.

     WMECO also has entered into lease agreements, some of which are capital
     leases, for the use of data processing and office equipment, vehicles,
     nuclear control room simulators, and office space.  The provisions of
     these lease agreements generally provide for renewal options.

     Capital lease rental payments charged to operating expense were $9.6
     million in 2000, $2.6 million in 1999 and $4.1 million in 1998.  Interest
     included in capital lease rental payments was $2.8 million in 2000, $3.1
     million in 1999 and $2.8 million in 1998.  Operating lease rental payments
     charged to expense were $3.2 million in 2000, $4.8 million in 1999 and
     $5.8 million in 1998.

     Future minimum rental payments, excluding annual nuclear fuel lease
     payments and executory costs such as property taxes, state use taxes,
     insurance, and maintenance, under long-term noncancelable leases, as
     of December 31, 2000, are as follows:

     --------------------------------------------------------------------------
     Year                                 Capital Leases     Operating Leases
     --------------------------------------------------------------------------
                                                 (Millions of Dollars)

     2001................................     $ 0.1                $ 3.5
     2002................................       0.1                  3.4
     2003................................       0.1                  3.1
     2004................................        -                   2.8
     2005................................        -                   2.6
     After 2005..........................        -                  13.1
                                              -----                -----
     Future minimum lease payments.......       0.3                $28.5
                                                                   =====
     Present value of future nuclear
       fuel lease payments...............      26.6
                                              -----
     Present value of future minimum
       lease payments....................     $26.9
                                              =====
     --------------------------------------------------------------------------

4.   PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
     Details of preferred stock not subject to mandatory redemption are as
     follows:

     --------------------------------------------------------------------------
                             December 31,      Shares
                                2000         Outstanding      December 31,
                             Redemption      December 31,    -------------
     Description               Price            2000         2000     1999
     --------------------------------------------------------------------------
                                                          (Millions of Dollars)

     7.72% Series B of 1971   $103.51          200,000       $20.0    $20.0
     --------------------------------------------------------------------------

5.   PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
     Details of preferred stock subject to mandatory redemption are as
     follows:

     --------------------------------------------------------------------------
                             December 31,       Shares
                                2000          Outstanding      December 31,
                             Redemption       December 31,    -------------
     Description               Price             2000         2000     1999
     --------------------------------------------------------------------------
                                                          (Millions of Dollars)

     7.60% Series of 1987      $25.26          660,000        $16.5   $18.0

     Less preferred stock
       to be redeemed
       within one year                          60,000          1.5     1.5
                                                              -----   -----
                                                              $15.0   $16.5
                                                              =====   =====
     --------------------------------------------------------------------------

     This series is subject to certain refunding limitations for the first five
     years after issuance.  The redemption price reduces in future years.

     The minimum sinking fund requirements of the series subject to mandatory
     redemption aggregate $1.5 million per year for each year for 2001 through
     2005.  In case of default on sinking fund payments, no payments may be
     made on any junior stock by way of dividends or otherwise (other than in
     shares of junior stock) so long as the default continues.  If WMECO is in
     arrears in the payment of dividends on any outstanding shares of preferred
     stock, WMECO is prohibited from redeeming or purchasing less than all of
     the outstanding preferred stock.

6.   LONG-TERM DEBT
     Details of long-term debt outstanding are as follows:

     --------------------------------------------------------------------------
      At December 31,                                    2000       1999
     --------------------------------------------------------------------------
                                                      (Millions of Dollars)
     First Mortgage Bonds:
     7 3/8% Series B, due 2001...................       $ 60.0     $ 60.0
     7 3/4% Series V, due 2002...................         40.0       84.2
     7 3/4% Series Y, due 2024...................           -        50.0
                                                        ------     ------
                                                         100.0      194.2
     Pollution Control Notes:
       Tax Exempt 1993 Series A, 5.85% due 2028..         53.8       53.8
     Fees and interest due for spent nuclear
       fuel disposal costs.......................         45.6       43.0
     Less amounts due within one year............         60.0         -
     Unamortized premium and discount, net.......           -        (0.7)
                                                        ------     ------
     Long-term debt, net.........................       $139.4     $290.3
                                                        ======     ======
     --------------------------------------------------------------------------

     Long-term debt maturities and cash sinking fund requirements, excluding
     fees and interest due for spent nuclear fuel disposal costs, on debt
     outstanding at December 31, 2000, for the years 2001 through 2005 are
     $60 million, $40 million, and no requirements for 2003, 2004 and 2005.

     Essentially all utility plant of WMECO is subject to the liens of the
     company's first mortgage bond indenture.

     WMECO has secured $53.8 million of pollution control notes with second
     mortgage liens on Millstone 1, junior to the liens of its first mortgage
     bond indenture.

7.   INCOME TAX EXPENSE
     The components of the federal and state income tax provisions were
     charged/(credited) to operations as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)
     Current income taxes:
     Federal......................................  $ 15.8    $ 13.5    $ (7.4)
     State........................................    10.9       2.0      (0.1)
                                                    ------    ------    ------
       Total current..............................    26.7      15.5      (7.5)
                                                    ------    ------    ------
     Deferred income taxes, net:
       Federal....................................    (0.8)     (3.5)      6.5
       State......................................    (8.6)     (0.9)      2.4
                                                    ------    ------    ------
         Total deferred...........................    (9.4)     (4.4)      8.9
                                                    ------    ------    ------
     Investment tax credits, net..................    (2.1)     (2.2)     (1.5)
                                                    ------    ------    ------
     Total income tax expense/(credit)............  $ 15.2    $  8.9    $ (0.1)
                                                    ======    ======    ======
     --------------------------------------------------------------------------

     The components of total income tax expense/(credit) are classified as
     follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)

     Income taxes charged to operating expenses...   $21.2    $18.8     $ 2.1
     Other income taxes...........................    (6.0)    (9.9)     (2.2)
                                                     -----    -----     -----
     Total income tax expense/(credit)............   $15.2    $ 8.9     $(0.1)
                                                     =====    =====     =====
     --------------------------------------------------------------------------

     Deferred income taxes are comprised of the tax effects of temporary
     differences as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)
     Depreciation, leased nuclear  fuel,
       settlement credits and disposal costs......  $ 0.9    $ (2.3)    $ 5.8
     Regulatory deferral..........................  (16.4)     (1.4)      1.3
     Regulatory disallowance......................     -       (4.2)       -
     Pension accruals.............................    5.9       4.2       1.0
     Other........................................    0.2      (0.7)      0.8
                                                    -----     -----     -----
     Deferred income taxes, net...................  $(9.4)    $(4.4)    $ 8.9
                                                    =====     =====     =====
     --------------------------------------------------------------------------

     A reconciliation between income tax expense/(credit) and the expected tax
     expense/(credit) at 35 percent of pretax income/(loss) is as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)
     Expected federal income tax..................  $17.6      $ 4.1   $(3.4)
     Tax effect of differences:
       Depreciation...............................   (1.2)       0.2     2.2
       Amortization of regulatory assets..........    1.3        6.2     0.9
       Investment tax credit amortization.........   (2.1)      (2.2)   (1.5)
       State income taxes, net of
         federal benefit..........................    1.5        0.7     1.5
       Dividends received deduction...............   (1.7)      (0.4)   (0.7)
       Other, net.................................   (0.2)       0.3     0.9
                                                    -----      -----   -----
     Total income tax expense/(credit)............  $15.2      $ 8.9   $(0.1)
                                                    =====      =====   =====
     --------------------------------------------------------------------------


8.   PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
     The NU system companies, including WMECO, participate in a uniform
     noncontributory defined benefit retirement plan covering substantially
     all regular NU system employees.  Benefits are based on years of service
     and the employees' highest eligible compensation during 60 consecutive
     months of employment.  WMECO's portion of the NU system's total pension
     credit, part of which was credited to utility plant, was $19 million in
     2000, $10.8 million in 1999 and $7.4 million in 1998.

     Currently, WMECO's policy is to annually fund an amount at least equal
     to that which will satisfy the requirements of the Employee Retirement
     Income Security Act and Internal Revenue Code.

     The NU system companies, including WMECO, also provide certain health
     care benefits, primarily medical and dental, and life insurance benefits
     through a benefit plan to retired employees.  These benefits are available
     for employees retiring from WMECO who have met specified service
     requirements.  For current employees and certain retirees, the total
     benefit is limited to two times the 1993 per retiree health care cost.
     These costs are charged to expense over the estimated work life of the
     employee.  WMECO annually funds postretirement costs through external
     trusts with amounts that have been rate-recovered and which also are
     tax deductible.

     Pension and trust assets are invested primarily in domestic and
     international equity securities and bonds.

     The following table represents information on the plans' benefit
     obligation, fair value of plan assets, and the respective plans' 7
     funded status:

- -------------------------------------------------------------------------------
                                                At December 31,
- -------------------------------------------------------------------------------
                                   Pension Benefits     Postretirement Benefits
- -------------------------------------------------------------------------------
(Millions of Dollars)              2000       1999         2000         1999
- -------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation
  at beginning of year.........   $(118.1)   $(118.7)     $(29.5)      $(30.1)
Service cost...................      (2.2)      (2.4)       (0.4)        (0.5)
Interest cost..................      (8.9)      (8.5)       (2.2)        (2.1)
Plan amendment.................        -        (7.3)         -            -
Transfers......................       0.5        0.2          -            -
Actuarial (loss)/gain..........      (3.0)      10.2        (0.5)         0.4
Benefits paid..................       8.2        7.8         2.6          2.6
Settlements and other..........       2.4        0.6         0.7          0.2
- -------------------------------------------------------------------------------
Benefit obligation
  at end of year...............   $(121.1)   $(118.1)     $(29.3)      $(29.5)
- -------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets
  at beginning of year.........   $ 223.9    $ 201.6      $ 16.6       $ 14.6
Actual return on plan assets...      (0.9)      29.9         0.8          1.7
Employer contribution..........        -          -          2.5          2.9
Benefits paid..................      (8.2)      (7.8)       (2.6)        (2.6)
Transfers......................      (0.5)       0.2          -            -
- -------------------------------------------------------------------------------
Fair value of plan assets
  at end of year...............   $ 214.3    $ 223.9      $ 17.3       $ 16.6
- -------------------------------------------------------------------------------
Funded status at December 31...   $  93.2    $ 105.8      $(12.0)      $(12.9)
Unrecognized transition
  (asset)/obligation...........      (0.9)      (1.2)       19.1         21.2
Unrecognized prior
  service cost.................       6.6        7.6          -            -
Unrecognized net gain..........     (53.4)     (85.7)       (6.6)        (8.2)
- -------------------------------------------------------------------------------
Prepaid benefit cost...........   $  45.5    $  26.5      $  0.5       $  0.1
- -------------------------------------------------------------------------------

     The following actuarial assumptions were used in calculating the plans'
     year end funded status:

      -------------------------------------------------------------------------
                                                At December 31,
      -------------------------------------------------------------------------
                                   Pension Benefits     Postretirement Benefits
      -------------------------------------------------------------------------
                                     2000    1999           2000      1999
      -------------------------------------------------------------------------
      Discount rate.............     7.50%   7.75%          7.50%     7.75%
      Compensation/progression
        rate....................     4.50    4.75           4.50      4.75
      Health care cost
        trend rate (a)..........      N/A     N/A           5.26      5.57
      -------------------------------------------------------------------------

      (a) The annual per capita cost of covered health care benefits was
          assumed to decrease to 4.91 percent by 2001.

     The components of net periodic benefit (credit)/cost are:

     --------------------------------------------------------------------------
                                     For the Years Ended December 31,
     --------------------------------------------------------------------------
                                                           Postretirement
                                 Pension Benefits              Benefits
     --------------------------------------------------------------------------
     (Millions of Dollars)   2000      1999      1998     2000   1999     1998
     --------------------------------------------------------------------------
     Service cost.........  $  2.2   $  2.4    $  2.2    $ 0.4   $ 0.5   $ 0.5
     Interest cost........     8.9      8.5       7.9      2.2     2.1     2.1
     Expected return
       on plan assets.....   (19.0)   (16.9)    (14.8)    (1.3)   (1.0)   (0.9)
     Amortization of
       unrecognized net
       transition (asset)/
       obligation.........    (0.2)    (0.2)     (0.2)     1.6     1.6     1.6
     Amortization of prior
       service cost.......     0.6      0.6       0.1       -       -       -
     Amortization of
       actuarial gain.....    (4.9)    (3.4)     (2.6)      -       -       -
     Other
       amortization, net..      -        -         -      (0.4)   (0.3)   (0.4)
     Settlements and
       other..............    (6.6)    (1.8)       -        -       -       -
     --------------------------------------------------------------------------
     Net periodic benefit
      (credit)/cost.......  $(19.0)  $(10.8)   $ (7.4)   $ 2.5   $ 2.9   $ 2.9
     --------------------------------------------------------------------------

     For calculating pension and postretirement benefit costs, the following
     assumptions were used:

     --------------------------------------------------------------------------
                                     For the Years Ended December 31,
     --------------------------------------------------------------------------
                                                           Postretirement
                                 Pension Benefits              Benefits
     --------------------------------------------------------------------------
                            2000      1999      1998     2000    1999     1998
     --------------------------------------------------------------------------
     Discount rate........  7.75%     7.00%     7.25%    7.75%   7.00%    7.25%
     Expected long-term
       rate of return.....  9.50      9.50      9.50      N/A     N/A      N/A
     Compensation/
      progression rate....  4.75      4.25      4.25     4.75    4.25     4.25
     Long-term rate
       of return -
       Health assets,
         net of tax.......   N/A       N/A       N/A     7.50    7.50     7.75
       Life assets........   N/A       N/A       N/A     9.50    9.50     9.50
     --------------------------------------------------------------------------

     Assumed health care cost trend rates have a significant effect on the
     amounts reported for the health care plans.  The effect of changing the
     assumed health care cost trend rate by one percentage point in each year
     would have the following effects:

     --------------------------------------------------------------------------
                                            One Percentage     One Percentage
     (Millions of Dollars)                  Point Increase     Point Decrease
     --------------------------------------------------------------------------
     Effect on total service and
       interest cost components                  $0.1              $(0.1)
     Effect on postretirement
       benefit obligation                        $1.4              $(1.3)
     --------------------------------------------------------------------------

     The trust holding the health plan assets is subject to federal income
     taxes.

9.   COMMITMENTS AND CONTINGENCIES

     A.  Restructuring
         A settlement has been reached with the Massachusetts Attorney General
         finalizing a $155 million securitization plan.  WMECO expects to
         receive approval of its securitization plan in February 2001.

     B.  Nuclear Generation Assets Divestiture
         On August 7, 2000, WMECO and certain other joint owners reached an
         agreement to sell substantially all of the Millstone units, located
         in Waterford, Connecticut, to Dominion, for approximately $1.3
         billion, including approximately $105 million for nuclear fuel.
         Dominion has also agreed to assume responsibility for decommissioning
         the three units and NU will transfer to Dominion all funds in the
         Millstone decommissioning trust.  Additionally, NU is obligated to
         top-off the decommissioning trust if its value does not equal a
         previously agreed upon level as defined.  NU expects to close on the
         sale of Millstone as early as the end of March 2001.

         If the transaction is consummated as proposed, WMECO would receive
         gross proceeds of approximately $196.2 million on a pretax basis for
         its respective ownership interest.  The proceeds from the sale of
         this interest will be used to reduce the company's stranded costs
         under restructuring and the cash proceeds will be used to repay
         subsidiary debt and capital lease obligations and to return equity
         capital to the parent company.

     C.  Environmental Matters
         The NU system, including WMECO, is subject to environmental laws and
         regulations intended to mitigate or remove the effect of past
         operations and improve or maintain the quality of our environment.
         As such, the NU system, including WMECO, have active environmental
         auditing and training programs and believe they are substantially in
         compliance with the current laws and regulations.

         However, the normal course of operations may involve activities and
         substances that expose WMECO to potential liabilities of which
         management cannot determine the outcome.  Additionally, management
         cannot determine the outcome for liabilities that may be imposed for
         past acts, even though such past acts may have been lawful at the
         time they occurred.  Management does not believe, however, that this
         will have a material impact on WMECO's consolidated financial
         statements.

         Based upon currently available information for the estimated
         remediation costs as of December 31, 2000 and 1999, the liability
         recorded by WMECO for its estimated environmental remediation costs
         amounted to $4.6 million and $4.2 million, respectively.

     D.  Spent Nuclear Fuel Disposal Costs
         Under the Nuclear Waste Policy Act of 1982, WMECO must pay the DOE for
         the disposal of spent nuclear fuel and high-level radioactive waste.
         The DOE is responsible for the selection and development of
         repositories for, and the disposal of, spent nuclear fuel and high-
         level radioactive waste.  For nuclear fuel used to generate
         electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has
         been recorded for the full liability and payment must be made prior to
         the first delivery of spent fuel to the DOE.  Until such payment is
         made, the outstanding balance will continue to accrue interest at the
         3-month treasury bill yield rate.  As of December 31, 2000 and 1999,
         fees due to the DOE for the disposal of Prior Period Fuel were $45.6
         million and $43 million, respectively, including interest costs of
         $30 million and $27.4 million, respectively.

         Fees for nuclear fuel burned on or after April 7, 1983, are billed
         currently to customers and paid to the DOE on a quarterly basis.
         WMECO is responsible for fees to be paid for fuel burned until the
         divestiture of the Millstone nuclear units.

     E.  Nuclear Insurance Contingencies
         Insurance policies covering WMECO's ownership share of the NU system's
         nuclear facilities have been purchased for the primary cost of repair,
         replacement or decontamination of utility property, certain extra
         costs incurred in obtaining replacement power during prolonged
         accidental outages and the excess cost of repair, replacement or
         decontamination or premature decommissioning of utility property.

         WMECO is subject to retroactive assessments if losses under those
         policies exceed the accumulated funds available to the insurer.  The
         maximum potential assessments with respect to losses arising during
         the current policy year for the primary property insurance program,
         the replacement power policies and the excess property damage policies
         are $1.1 million, $0.6 million and $1.4 million, respectively.  In
         addition, insurance has been purchased by the NU system in the
         aggregate amount of $200 million on an industry basis for coverage
         of worker claims.

         Under certain circumstances, in the event of a nuclear incident at
         one of the nuclear facilities covered by the federal government's
         third-party liability indemnification program, the NU system,
         including WMECO, could be assessed liabilities in proportion to its
         ownership interest in each of its nuclear units up to $83.9 million.
         The NU system's payment of this assessment would be limited to, in
         proportion to its ownership interest in each of its nuclear units,
         $10 million in any one year per nuclear unit.  In addition, if the
         sum of all claims and costs from any one nuclear incident exceeds the
         maximum amount of financial protection, the NU system, including
         WMECO, would be subject to an additional 5 percent, or $4.2 million,
         liability, in proportion to its ownership interests in each of its
         nuclear units.  Based upon its ownership interests in the Millstone
         units, WMECO's maximum liability, including any additional
         assessments, would be $44.3 million per incident, of which payments
         would be limited to $5 million per year.  In addition, through
         purchased-power contracts with VYNPC, WMECO would be responsible for
         up to an additional assessment of $2.2 million per incident, of which
         payments would be limited to $0.3 million per year.

         WMECO expects to terminate its nuclear insurance upon the divestiture
         of its nuclear units.

     F.  Long-Term Contractual Arrangements
         Yankee Companies:  Under the terms of its agreement, WMECO paid its
         ownership (or entitlement) shares of costs, which included
         depreciation, operation and maintenance (O&M) expenses, taxes, the
         estimated cost of decommissioning, and a return on invested capital.
         These costs were recorded as purchased-power expenses.  WMECO's cost
         of purchases under its contract with VYNPC amounted to $4 million in
         2000, $4.7 million in 1999 and $4.4 million in 1998.  VYNPC is in the
         process of selling its nuclear unit.  Upon completion of the sale,
         this long-term contract will be terminated.

         Nonutility Generators (NUGs): WMECO has entered into various
         arrangements for the purchase of capacity and energy from NUGs.
         WMECO's total cost of purchases under these arrangements amounted to
         $28.5 million in 2000, $28.2 million in 1999 and $29.9 million in
         1998.  The company is in the process of renegotiating the terms of
         these contracts through either a contract buydown or buyout.  WMECO
         expects any payments to the NUGs as a result of these renegotiations
         to be recovered from the company's customers.

         Hydro-Quebec:  Along with other New England utilities, WMECO has
         entered into an agreement to support transmission and terminal
         facilities to import electricity from the Hydro-Quebec system in
         Canada.  WMECO is obligated to pay, over a 30-year period ending in
         2020, its proportionate share of the annual O&M expenses and capital
         costs of those facilities.

         Estimated Annual Costs:  The estimated annual costs of WMECO's
         significant long-term contractual arrangements, absent the effects
         of any contract terminations, buydowns or buyouts are as follows:

         ---------------------------------------------------------------------
                                   2001     2002     2003     2004     2005
         ---------------------------------------------------------------------
                                             (Millions of Dollars)

         VYNPC.............       $ 4.8     $ 4.9    $ 5.0    $ 5.4    $ 5.1
         NUGs..............        29.5      30.4     31.2     31.9     32.6
         Hydro-Quebec......         3.2       3.1      3.0      2.9      2.8
         ---------------------------------------------------------------------

10.  NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
     Millstone:  WMECO's operating nuclear power plants, Millstone 2 and 3,
     have service lives that are expected to end in 2015 and 2025,
     respectively, and upon retirement, must be decommissioned.  Millstone 1's
     expected service life was to end in 2010, however, in July 1998, restart
     activities were discontinued and decommissioning of the unit began.
     In connection with the sale of the Millstone units, Dominion has agreed to
     assume responsibility for decommissioning.  Until the divestiture, WMECO
     recovers sufficient amounts through its allowed rates related to
     decommissioning costs.

     WMECO's ownership share of the estimated cost of decommissioning
     Millstone 2 and 3, in year end 2000 dollars, is $81.8 million and $79.3
     million, respectively.  Nuclear decommissioning costs are accrued over the
     expected service lives of the units and are included in depreciation
     expense and the accumulated provision for depreciation.  Nuclear
     decommissioning expenses for these units amounted to $3.7 million in 2000,
     1999 and 1998.  Nuclear decommissioning expenses for Millstone 1 were
     $2.5 million in 2000, $2.9 million in 1999 and $2.5 million in 1998.
     Through December 31, 2000 and 1999, total decommissioning expenses of $43
     million and $39.3 million, respectively, have been collected from
     customers and are reflected in the accumulated provision for depreciation.

     External decommissioning trusts have been established for the costs of
     decommissioning the Millstone units.  Funding of the estimated
     decommissioning costs assumes after-tax earnings on the Millstone
     decommissioning funds of 5.5 percent.

     As of December 31, 2000 and 1999, $43 million and $39.3 million,
     respectively, have been transferred to external decommissioning trusts.
     Earnings on the decommissioning trusts increase the decommissioning trust
     balances and the accumulated provisions for depreciation.  Unrealized
     gains and losses associated with the decommissioning trusts also impact
     the balance of the trusts and the accumulated provisions for depreciation.
     The fair values of the amounts in the external decommissioning trusts
     were $82.4 million and $77.4 million at December 31, 2000 and 1999,
     respectively.  Upon divestiture, balances in the decommissioning trusts
     will be transferred to the buyer.  NU is obligated to top-off the
     Millstone decommissioning trust if its value does not equal an agreed upon
     amount at closing, pursuant to the conditions set forth in the purchase
     and sale agreement.

     Yankee Companies:  VYNPC owns and operates a nuclear generating unit with
     a service life that is expected to end in 2012.  WMECO's ownership share
     of estimated costs, in year end 2000 dollars, of decommissioning this unit
     is $11.3 million.  In 1999, VYNPC agreed to sell its nuclear generating
     unit for $22 million to an unaffiliated company.  Among other commitments,
     the acquiring company agreed to assume the obligation to decommission the
     unit after it is taken out of service, and the owners of VYNPC (including
     WMECO) agreed to fund their shares of the decommissioning costs up to a
     negotiated amount.  Subsequent to the time that agreement was executed,
     the original proposed acquiring company has increased the price it agreed
     to pay and three other unaffiliated companies have indicated their
     interest in buying VYNPC's generating unit on terms that have not been
     disclosed.  At present, WMECO expects that the unit will be sold, but the
     identity of the owner and the terms of sale, including price, future
     decommissioning obligations and future power purchase obligations, are not
     known.

     As of December 31, 2000 and 1999, WMECO's remaining estimated obligation,
     including decommissioning for the units owned by CYAPC, YAEC and MYAPC,
     which have been shut down was $42.5 million and $63.7 million,
     respectively.

11.  FAIR VALUE OF FINANCIAL INSTRUMENTS
     The following methods and assumptions were used to estimate the fair
     value of each of the following financial instruments:

     Nuclear Decommissioning Trusts:  WMECO's portion of the investments held
     in the NU system companies' nuclear decommissioning trusts were marked-
     to-market by $32.3 million as of December 31, 2000, and $35.4 million as
     of December 31, 1999, with corresponding offsets to the accumulated
     provision for depreciation.  The amounts adjusted in 2000 and in 1999
     represent cumulative net unrealized gains.  Cumulative gross unrealized
     holding losses were immaterial for both 2000 and 1999.

     Preferred stock and long-term debt:  The fair value of WMECO's fixed-rate
     securities is based upon the quoted market price for those issues or
     similar issues.  Adjustable rate securities are assumed to have a fair
     value equal to their carrying value.  The carrying amounts of WMECO's
     financial instruments and the estimated fair values are as follows:

     --------------------------------------------------------------------------
                                                    At December 31, 2000
     --------------------------------------------------------------------------
                                                   Carrying         Fair
     (Millions of Dollars)                          Amount          Value
     --------------------------------------------------------------------------
     Preferred stock not subject
       to mandatory redemption...............       $ 20.0         $ 20.2

     Preferred stock subject to
       mandatory redemption..................         16.5           16.5

     Long-term debt -
       First mortgage bonds..................        100.0          100.3

       Other long-term debt..................         99.4           93.7
     --------------------------------------------------------------------------

     --------------------------------------------------------------------------
                                                    At December 31, 1999
     --------------------------------------------------------------------------
                                                   Carrying         Fair
     (Millions of Dollars)                          Amount          Value
     --------------------------------------------------------------------------
     Preferred stock not subject
       to mandatory redemption...............       $ 20.0         $ 19.1

     Preferred stock subject to
       mandatory redemption..................         18.0           18.0

     Long-term debt -
       First mortgage bonds..................        194.2          196.3

       Other long-term debt..................         96.8           89.9
     --------------------------------------------------------------------------

12.  OTHER COMPREHENSIVE INCOME
     The accumulated balance for each other comprehensive income item is as
     follows:

     --------------------------------------------------------------------------
                                                        Current
                                       December 31,     Period     December 31,
                                           1999         Change         2000
     --------------------------------------------------------------------------
     (Thousands of Dollars)
     --------------------------------------------------------------------------
     Unrealized gains
       on securities................       $193          $22           $215
     Minimum pension
       liability adjustments...........     (33)          -             (33)
     --------------------------------------------------------------------------
     Accumulated other
       comprehensive income............    $160          $22           $182
     --------------------------------------------------------------------------

     --------------------------------------------------------------------------
                                                        Current
                                       December 31,     Period     December 31,
                                           1998         Change         1999
     --------------------------------------------------------------------------
     (Thousands of Dollars)
     --------------------------------------------------------------------------
     Unrealized gains
       on securities...................    $183           $10          $193
     Minimum pension
       liability adjustments...........     (33)           -            (33)
     --------------------------------------------------------------------------
     Accumulated other
       comprehensive income............    $150           $10          $160
     --------------------------------------------------------------------------

     The changes in the components of other comprehensive income are reported
     net of the following income tax effects:

     --------------------------------------------------------------------------
                                                  2000      1999      1998
     --------------------------------------------------------------------------
     (Thousands of Dollars)
     --------------------------------------------------------------------------
     Unrealized gains on securities.........      $(14)     $(7)     $(117)
     Minimum pension liability adjustments..         -        -         21
     Other comprehensive income.............      $(14)     $(7)     $ (96)
     --------------------------------------------------------------------------

13.  SEGMENT INFORMATION
     Effective January 1, 1999, the NU system companies, including WMECO,
     adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and
     Related Information."  The NU system is organized between regulated
     utilities and competitive energy subsidiaries.  WMECO is included in the
     regulated utilities segment of the NU system and has no other reportable
     segments.

14.  SUBSEQUENT EVENT
     Merger Agreement With Consolidated Edison, Inc.:  In 2000, NU and
     Consolidated Edison, Inc. (Con Edison) received most of the approvals
     needed to complete the merger announced in October 1999.  Shareholders
     from both companies approved the merger in April 2000, and all state
     regulatory approvals were granted by the end of the year.  Additionally,
     the FERC approved the merger in May 2000, the Nuclear Regulatory
     Commission approved the transaction in August 2000, and the United States
     Department of Justice approved the merger in February 2001.  Necessary
     approval from the SEC was expected to be received in mid-March 2001.

     On February 28, 2001, NU's Board of Trustees requested that Con Edison
     provide reasonable assurance, in writing, that it intended to comply with
     the terms of the definitive merger agreement between the two companies.
     This included assurances that Con Edison would consummate the pending
     merger at the price set forth in the agreement promptly following the
     receipt of SEC approval.  The original request for assurance was to be
     received by March 2, 2001, however that date was later extended to
     March 5, 2001.  On March 5, 2001, Con Edison advised NU that it was not
     willing to close the merger on the agreed terms.  NU notified Con Edison
     that it was treating its refusal to proceed on the terms set forth in the
     merger agreement as a repudiation and breach of the merger agreement, and
     that NU would file suit to obtain the benefits of the transaction as
     negotiated for NU shareholders.  On March 6, 2001, Con Edison filed suit
     in the U.S. District Court for the Southern District of New York (Southern
     District), seeking declaratory judgment that NU failed to satisfy
     conditions precedent under the merger agreement.  On March 12, 2001,
     NU filed suit against Con Edison in the Southern District seeking damages
     in excess of $1 billion arising from Con Edison's breach of the merger
     agreement.


<TABLE>
Western Massachusetts Electric Company and Subsidiary
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
SELECTED CONSOLIDATED FINANCIAL DATA       2000         1999          1998          1997          1996
- ----------------------------------------------------------------------------------------------------------
                                                              (Thousands of Dollars)
<S>                                   <C>           <C>            <C>           <C>           <C>
Operating Revenues..................  $   513,678   $  414,231     $  393,322    $  426,447    $  421,337

Operating Income....................       54,096        41,741        19,854           251        33,190

Net Income/(Loss)...................       35,268         2,887        (9,579)      (27,460)       11,089

Cash Dividends on Common Stock......       12,002          -             -           15,004        16,494

Total Assets........................    1,047,818     1,253,604     1,287,682     1,179,128     1,191,915

Long-Term Debt (a)..................      199,425       290,279       389,314       396,649       349,442

Preferred Stock Not Subject
  to Mandatory Redemption)..........       20,000        20,000        20,000        20,000        20,000

Preferred Stock Subject to
  Mandatory Redemption (a)..........       16,500        18,000        19,500        21,000        21,000

Obligations Under Capital
  Leases (a)........................       26,921        29,972        34,093        32,887        32,234

- ----------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
CONSOLIDATED QUARTERLY FINANCIAL DATA (Unaudited)
- ------------------------------------------------------------------------------------------------
                                                      Quarter Ended
- ------------------------------------------------------------------------------------------------
2000                           March 31        June 30        September 30         December 31
- ------------------------------------------------------------------------------------------------
                                                  (Thousands of Dollars)
<S>                            <C>             <C>              <C>                  <C>
Operating Revenues             $129,410        $120,090         $130,400             $133,778
                               ========        ========         ========             ========

Operating Income               $ 14,782        $  9,974         $ 13,940             $ 15,400
                               ========        ========         ========             ========

Net Income                     $ 11,053        $  2,956         $  9,638             $ 11,621
                               ========        ========         ========             ========
- ------------------------------------------------------------------------------------------------
1999
- ------------------------------------------------------------------------------------------------

Operating Revenues             $ 97,686        $108,829         $107,776             $ 99,940
                               ========        ========         ========             ========

Operating Income/(Loss)        $ 12,205        $  8,812         $ 22,821             $ (2,097)
                               ========        ========         ========             ========

Net Income/(Loss)              $  4,852        $  4,183         $ 11,368             $(17,516)
                               ========        ========         ========             ========
</TABLE>
(a) Includes portion due within one year.



Western Massachusets Electric Company and Subsidiary

- -------------------------------------------------------------------------------
CONSOLIDATED STATISTICS (Unaudited)
- -------------------------------------------------------------------------------

                                       Average
        Gross Electric                  Annual
         Utility Plant                 Use Per
          December 31,     kWh        Residential    Electric
        (Thousands of     Sales        Customer      Customers      Employees
           Dollars)     (Millions)      (kWh)       (Average)      December 31,
- -------------------------------------------------------------------------------

2000    $1,535,514         7,278        7,371        198,372           406
1999     1,216,015         4,654        7,423        198,012           482
1998     1,256,046         4,091        6,979        196,339           533
1997     1,334,233         4,300        7,121        195,324           507
1996     1,303,361         4,626        7,335        194,705           497

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13.3
<SEQUENCE>17
<FILENAME>0017.txt
<DESCRIPTION>ANNUAL REPORT OF PSNH
<TEXT>

                               2000 Annual Report

                     Public Service Company of New Hampshire

                                     Index


Contents                                                                Page
- --------                                                                ----

Management's Discussion and Analysis of Financial
  Condition and Results of Operations.............................        1

Report of Independent Public Accountants..........................       10

Statements of Income..............................................       11

Statements of Comprehensive Income................................       11

Balance Sheets....................................................     12-13

Statements of Common Stockholder's Equity.........................       14

Statements of Cash Flows..........................................       15

Notes to Financial Statements.....................................     16-38

Selected Financial Data...........................................       39

Quarterly Financial Data (Unaudited)..............................       39

Statistics (Unaudited)............................................       40

Preferred Stockholder and Bondholder Information..................   Back Cover


Public Service Company of New Hampshire

- -------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
- -------------------------------------------------------------------------------

Financial Condition
- -------------------

Overview
- --------

Public Service Company of New Hampshire (PSNH or the company) is a wholly owned
operating subsidiary of Northeast Utilities (NU) and is part of the Northeast
Utilities system (NU system).  PSNH earned $67.6 million before extraordinary
charges in 2000.  Earnings before extraordinary charges declined $16.6 million
from 1999, primarily as a result of a rate decrease on October 1, 2000, and
lower wholesale revenues.  Because of extraordinary charges totaling $214.2
million, PSNH had a net loss of $146.7 million in 2000, compared with $84.2
million in 1999 and $91.7 million in 1998.  These extraordinary charges are a
result of the "Agreement to Settle PSNH Restructuring" (Settlement Agreement)
with the State of New Hampshire and the discontinuation of Statement of
Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation."

During 2000, PSNH and the State of New Hampshire were able to reach a
settlement regarding restructuring in the state.  This agreement ended several
years of uncertainty related to restructuring for PSNH and the State of New
Hampshire.  PSNH expects to implement the settlement agreement in 2001.

Increases in sales pushed total PSNH revenues to $1.29 billion in 2000, up
11.2 percent from $1.16 billion in 1999.  The growth in competitive energy
revenues more than offset a 5 percent rate reduction on October 1, 2000 for
PSNH retail customers.  Revenues were $1.09 billion in 1998.  Operating
earnings at PSNH are expected to decline significantly after the first quarter
of 2001, as a result of the retail rate reductions that will accompany the
introduction of industry restructuring in New Hampshire.

Consolidated Edison, Inc. Merger
In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the
approvals needed to complete the merger announced in October 1999.
Shareholders from both companies approved the merger in April 2000, and all
state regulatory approvals were granted by the end of the year.  Additionally,
the Federal Energy Regulatory Commission (FERC) approved the merger in May
2000, the Nuclear Regulatory Commission approved the transaction in August
2000, and the United States Department of Justice approved the merger in
February 2001.  Necessary approval from the Securities and Exchange Commission
(SEC) was expected to be received in mid-March 2001.

On February 28, 2001, NU's Board of Trustees requested that Con Edison provide
reasonable assurance, in writing, that it intended to comply with the terms of
the definitive merger agreement between the two companies.  This included
assurances that Con Edison would consummate the pending merger at the price
set forth in the agreement promptly following the receipt of SEC approval.
The original request for assurance was to be received by March 2, 2001, however
that date was later extended to March 5, 2001.  On March 5, 2001, Con Edison
advised NU that it was not willing to close the merger on the agreed terms.
NU notified Con Edison that it was treating its refusal to proceed on the
terms set forth in the merger agreement as a repudiation and breach of the
merger agreement, and that NU would file suit to obtain the benefits of the
transaction as negotiated for NU shareholders.  On March 6, 2001, Con Edison
filed suit in the U.S. District Court for the Southern District of New York
(Southern District), seeking a declaratory judgment that NU failed to satisfy
conditions precedent under the merger agreement.  On March 12, 2001, NU filed
suit against Con Edison in the Southern District seeking damages in excess of
$1 billion arising from Con Edison's breach of the merger agreement.  NU
cannot predict the outcome of this matter nor its effect on NU.

Liquidity
- ---------

During 2000, net cash flows provided by PSNH's operations were $190.3 million,
compared to $199.1 million in 1999 and $217.6 million in 1998.  The decrease
in 2000 is primarily related to a decrease in net income and an increase in
amortization of recoverable energy costs.

Net cash flows used in financing activities were $188.9 million in 2000,
compared to $31.6 million in 1999 and $204.3 million in 1998.  This included
approximately $135 million paid in 2000 to retire long-term debt and
preferred stock, compared to $25 million in 1999 and $195 million in 1998.
Payments made for preferred stock dividends were $4 million, $6.6 million
and $9.3 million for 2000, 1999 and 1998, respectively.  For the first time
since March 1997, PSNH paid a cash dividend on common shares.  In October
2000, a cash dividend of $50 million was paid in 2000.

Including construction expenditures and investments in nuclear decommissioning
trusts, net cash flows used in investing activities were $68.9 million in
2000, compared to $45.8 million in 1999 and $46.9 million in 1998.  PSNH
currently forecasts construction expenditures of $78.7 million for the
year 2001.

In April 2000, Moody's Investors Service (Moody's) upgraded its credit ratings
for PSNH, and in October 2000, Fitch IBCA (Fitch) upgraded its credit ratings
for PSNH.  In January 2001, Moody's and Standard and Poor's upgraded their
credit ratings for PSNH, primarily as a result of the New Hampshire Supreme
Court's decision to uphold the state's restructuring plan, the anticipated
sale of Millstone and NU's general financial recovery.  These upgrades return
NU and PSNH to investment grade ratings for the first time in five years and
will save the NU system in excess of $4.7 million annually in financing costs.

PSNH terminated its $75 million revolving credit agreement in April 1999 and
continues to fund its operations and capital program with cash on hand and
operating cash flows.  In August and September 2000, PSNH repaid $109.2
million of variable-rate taxable pollution control bonds from cash on hand.
PSNH also paid a $50 million common dividend to NU on October 2, 2000, PSNH's
first common dividend to NU since February 1997.  Despite those cash outflows,
PSNH maintained $115.1 million of cash on hand as of December 31, 2000.

PSNH expects to receive gross proceeds of  $26 million as a result of the
sale of their ownership interest in the Millstone units to Dominion Resources,
Inc. (Dominion).  This sale is expected to close as early as the end of March
2001.  The cash proceeds, in addition to those anticipated from securitization
and the future sale of the Seabrook Station nuclear unit (Seabrook), are
expected to be used to repay subsidiary debt and capital lease obligations
and to return equity capital to the parent company.

By the end of 2002, PSNH expects to complete the auction of approximately 1,200
MW of fossil and hydroelectric generation assets, as well as CL&P's and NAEC's
share of Seabrook.  PSNH's restructuring settlement was predicated upon
receiving approximately $400 million of net proceeds from those sales.  Cash
proceeds will be used to retire debt and to return equity capital to the
parent company.

In September 2000, the New Hampshire Public Utilities Commission (NHPUC)
approved a comprehensive restructuring settlement that allows PSNH to
securitize up to $670 million of stranded costs.  In January 2001, the New
Hampshire Supreme Court upheld this restructuring order on appeal.  However,
one of the appellants indicated publicly it would request a review of the
New Hampshire Supreme Court decision by the United States Supreme Court.
Such a request must be filed by May 1, 2001.  Management believes that such
an appeal would have a low probability of success, but cannot determine what
effect it might have on the timing of the issuance of securitization bonds
and the implementation of customer choice in New Hampshire.  PSNH currently
expects to work with the State of New Hampshire to issue securitization bonds
early in the second quarter of 2001.  Cash proceeds would be combined with
cash on hand and used primarily to buydown the power contract between PSNH
and NAEC, retire debt at the two companies of approximately $300 million and
to return equity capital to the parent company from PSNH and NAEC of
another $375 million.

Restructuring
- -------------

Because of delays in implementing restructuring, PSNH remained a vertically
integrated utility in 2000 with a fuel and purchased-power adjustment charge.
For the first nine months following restructuring, PSNH will meet the load
requirements of those customers who do not choose an alternative supplier
(transition service or standard offer service) through its own generation
assets and purchased-power obligations.  Because PSNH's generation assets
are heavily weighted toward coal and nuclear generation, PSNH is somewhat
insulated from rising oil and natural gas prices.  Following that initial
nine-month period, PSNH expects to sell its generation assets and acquire power
for up to two years from third-party suppliers for customers who remain on
transition service.  Under the restructuring statute and the conforming
Settlement Agreement, PSNH will utilize its own generation capability to
provide Transition Service and Default Service for the Initial Transition
Service Period (ITSP, the first nine months after competition day) as defined
in the agreement.  At the conclusion of the ITSP, PSNH will be required to
contract for Transition Service for the remaining 24-month Transition Service
period with third-party suppliers through a competitive bidding process
administered by the NHPUC.  As part of its negotiation with the state
legislature, PSNH has agreed to absorb the first $7 million of costs for
the first 12-month period following the ITSP, if the cost of acquiring
Transition Service exceeds the rate charged to customers.  PSNH will be
permitted to defer and recover, as unsecuritized stranded costs, all
Transition Service costs in excess of the initial $7 million.

Provisions for Transition Service are but one element of the Settlement
Agreement which during 2000 was approved by the New Hampshire House and Senate,
signed into law by the Governor of New Hampshire and approved by the NHPUC.
Other provisions allow for issuing rate reduction bonds to securitize stranded
costs; implementing a rate decrease of approximately 15.5 percent, 5 percent
of which was implemented on a temporary basis on October 1, 2000; an after-tax
write-off of stranded costs in excess of $200 million, which was recorded in
the fourth quarter; selling NAEC's share of Seabrook no later than December 31,
2003, and; fixing PSNH's delivery rates at $0.028 per kilowatt-hour for the
first 33 months after the Settlement Agreement takes effect.  PSNH and NAEC
will also terminate the Seabrook Power Contracts upon the sale of Seabrook.
Restructuring is expected to take effect the first day of the month after
PSNH issues rate reduction bonds, which is anticipated to be May 1, 2001.

For further information regarding commitments and contingencies related to
restructuring, see Note 9A, "Commitments and Contingencies - Restructuring,"
to the financial statements.

Regional Transmission Organization
- ----------------------------------

Pursuant to FERC Order 888 (issued in April 1996), the NU system companies,
including PSNH, operate their transmission system under an open access,
nondiscriminatory transmission tariff.

In December 1999, the FERC issued an order calling on all transmission owners
to voluntarily join Regional Transmission Organizations (RTOs) in order to
boost competition in electric markets.  In general, each of these organizations
would be an independent operator over all transmission facilities, and would
perform, among other functions, tariff administration, construction planning
and reliability management for the particular regional transmission system.
NU's active voting interest in such an organization would be limited to 5
percent under the proposal.

The NU system companies, including PSNH, and other parties have appealed this
order.  Of primary concern to NU is the ratemaking authority granted to RTOs
and its impact on the ability of transmission owners to earn appropriate
returns on their transmission investment under the organizational structure
and the minimum functions proposed in the order.  The NU system companies
were required to participate in a collaborative process established by the
FERC beginning in March of 2000.  On January 16, 2001, NU along with the
Independent System Operator and five other New England transmission owning
utilities filed a proposal to establish a New England RTO.

Nuclear Plant Performance and Divestiture
- -----------------------------------------

Seabrook
North Atlantic Energy Corporation (NAEC) is another wholly owned subsidiary of
NU.  PSNH is obligated to purchase the capacity and output from NAEC's 35.98
percent joint ownership interest in the Seabrook Station nuclear unit
(Seabrook) under the terms of two life-of-unit, full cost recovery contracts
(Seabrook Power Contracts).  Seabrook operated at a capacity factor of 78
percent in 2000.  The unit began a scheduled refueling outage on October 21,
2000.  The outage was extended by approximately two months as a result of the
need to repair extensive problems with a back-up diesel generator.  Seabrook
returned to service on January 29, 2001.

On December 15, 2000, PSNH filed its divestiture plan for Seabrook with the
NHPUC and DPUC.  PSNH hopes to complete the sale in 2002.

Millstone 3
PSNH has a 2.85 percent ownership of the Millstone 3 unit. Millstone 3 operated
at virtually a 100 percent capacity factor in 2000 and ran for 585 consecutive
days before beginning a scheduled refueling outage on February 3, 2001.
Millstone 3 is expected to return to service by the end of the first quarter
2001.

On August 7, 2000, CL&P, WMECO and certain other joint owners including PSNH
reached an agreement to sell substantially all of the Millstone units, located
in Waterford, Connecticut, to Dominion, for approximately $1.3 billion,
including approximately $105 million for nuclear fuel.  Dominion has also
agreed to assume responsibility for decommissioning the three units and NU will
transfer to Dominion all funds in the Millstone decommissioning trust.
Additionally, NU is obligated to top-off the decommissioning trust if its
value does not equal an agreed upon amount at closing.  That amount is pursuant
to the purchase and sale agreement (PSA) with Dominion, subject to adjustment
for delays in the closing of the sale and Millstone 1 not meeting the "cold
and dark" condition specified in the PSA.

If the transaction is consummated as proposed, PSNH will receive $26 million on
a pretax basis, which will be reflected as a gain in accordance with the
Settlement Agreement.

NU currently expects to close on the sale of Millstone as early as the end
of March 2001.

Yankee Companies
PSNH is a 4 percent shareholder and sponsor company of the Vermont Yankee
Nuclear Power Corporation (VYNPC).  In 1999, VYNPC agreed to sell its nuclear
generating unit for $22 million to an unaffiliated company.  Among other
commitments, the acquiring company agreed to assume the obligation to
decommission the unit after it is taken out of service, and the owners of VYNPC
(including PSNH) agreed to fund their shares of the decommissioning costs up to
a negotiated amount.  Subsequent to the time that the agreement was executed,
the original proposed acquiring company increased its purchase price and three
other unaffiliated companies have indicated their interest in buying VYNPC's
generating unit on terms that have not been disclosed.  On February 14, 2001,
the Vermont Public Service Board dismissed the acquiring company's petition
for approval and VYNPC agreed to work with the Vermont regulators to develop
an auction process for the sale of the unit.  At present, PSNH expects that
the unit will be sold, but the identity of the owner and the terms of sale,
including price, future decommissioning obligations and future power purchase
obligations, are not known.

Nuclear Decommissioning
In connection with the aforementioned sale of the Millstone units, Dominion has
agreed to assume responsibility for decommissioning the Millstone units.

For further information regarding nuclear decommissioning, see Note 10,
"Nuclear Decommissioning and Plant Closure Costs," to the financial statements.

Spent Nuclear Fuel Disposal Costs
The United States Department of Energy (DOE) originally was scheduled to begin
accepting delivery of spent fuel in 1998.  However, delays in confirming the
suitability of a permanent storage site continually have postponed plans for
the DOE's long-term storage and disposal site.  Extended delays or a default by
the DOE could lead to consideration of costly alternatives.  PSNH has the
primary responsibility for the interim storage of its share of spent nuclear
fuel prior to the divestiture of Millstone 3.

For further information regarding spent nuclear fuel disposal costs, see
Note 9D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs,"
to the financial statements.

Other Matters
- -------------

Environmental Matters
PSNH is subject to environmental laws and regulations structured to mitigate
or remove the effect of past operations and to improve or maintain the quality
of the environment.  For further information regarding environmental matters,
see Note 9C, "Commitments and Contingencies - Environmental Matters," to the
financial statements.

Other Commitments and Contingencies
For further information regarding other commitments and contingencies, see
Note 9, "Commitments and Contingencies," to the financial statements.

Forward Looking Statements
This discussion and analysis includes forward looking statements, which are
statements of future expectations and not facts including, but not limited to,
statements regarding future earnings, refinancing, the use of proceeds from
restructuring, and the recovery of operating costs.  Words such as estimates,
expects, anticipates, intends, plans, and similar expressions identify forward
looking statements.  Actual results or outcomes could differ materially as a
result of further actions by state and federal regulatory bodies, competition
and industry restructuring, changes in economic conditions, changes in
historical weather patterns, changes in laws, developments in legal or public
policy doctrines, technological developments, and other presently unknown or
unforeseen factors.

RESULTS OF OPERATIONS

The components of significant income statement variances for the past two
years are provided in the table below.

                                          Income Statement Variances
                                             (Millions of Dollars)

                               2000 over/(under) 1999   1999 over/(under) 1998
                               -----------------------------------------------
                                  Amount    Percent        Amount    Percent
                                  ------    -------        ------    -------

Operating Revenues                $ 131        11%          $  73        7%

Operating Expenses:
Fuel, purchased and net
  interchange power                 162        23              86       14
Other operation and
  maintenance                       (11)       (6)             11        7
Depreciation                         (4)       (8)              2        5
Amortization of regulatory
  assets, net                        11        31               8       30
Federal and state income taxes        8        22             (28)     (43)
Taxes other than income taxes        (1)       (3)              -        1
                                  -----       ---           -----      ---
Total operating expenses            165        16              80        8
                                  -----       ---           -----      ---
Operating Income:                   (35)      (28)             (7)      (5)
                                  -----       ---           -----      ---
Equity in earnings of
  regional nuclear
  generating companies                1        71              (2)     (58)
Other, net                            8        (a)             (4)     (38)
Other income taxes                    4        (a)              4       (a)
                                  -----       ---           -----      ---
Net other income                     12        (a)             (2)     (35)
Interest charges                     (6)      (13)             (1)      (1)
                                  -----       ---           -----      ---
Income before
  extraordinary items               (17)      (20)             (7)      (8)
                                  -----       ---           -----      ---
Extraordinary loss                 (214)       (a)              -        -
                                  -----       ---           -----      ---
Net Income/(Loss)                 $(231)       (a)          $ (7)      (8)

(a)  Percent greater than 100.


Operating Revenues
Operating revenues increased by $131 million or 11 percent in 2000, primarily
due to higher wholesale and retail revenues.  Wholesale revenues increased by
$128 million primarily due to higher wholesale energy and capacity sales.
Retail revenues were higher primarily due to higher retail sales ($12 million),
partially offset by a rate decrease as part of PSNH restructuring ($8 million).
Retail kilowatt-hour sales increased by 2.1 percent.

Operating revenues increased by $73 million or 7 percent in 1999, primarily due
to higher retail revenues ($43 million), higher wholesale energy and capacity
sales and transmission revenues ($30 million).  Retail kilowatt-hour sales
increased by 5.3 percent.

Fuel, Purchased and Interchange Power, Net
Fuel, purchased and net interchange power expense increased in 2000, primarily
due to higher wholesale energy sales.

Fuel, purchased and net interchange power expense increased in 1999, primarily
due to higher purchased-power expenses ($48 million)and higher deferred
expenses ($25 million) associated with the company's fuel clause and higher
capacity costs for Seabrook ($8 million).  Seabrook's capacity costs are higher
due to costs associated with the refueling outage in 1999 and the amortization
of the deferred return that was deferred by PSNH through November 1998.

Other Operation and Maintenance Expense
Other operation and maintenance (O&M) expense increased in 2000, primarily due
to lower transmission and distribution expense ($6 million) and lower fossil
maintenance expenses($5 million).

Other O&M expense increased in 1999, primarily due to the recognition of
environmental insurance proceeds which reduced O&M expense in 1998 ($12
million), higher fossil maintenance expenses ($3 million) and higher
transmission expense ($2 million), partially offset by lower storm cost
in 1999 ($6 million).

Amortization of Regulatory Assets
Amortization of regulatory assets net increased in 2000, primarily due to the
completion of, in 1999, the amortization of regulatory obligations related to
net operating loss carryforwards as a result of the Global Settlement.

Amortization of regulatory assets, net increased in 1999, primarily due to
an increase in the amortization of the Seabrook deferred return which began
in June 1998.  The reduction of the acquisition premium amortization ($21
million) was offset by the completion in 1999, of the amortization of a
regulatory obligation related to net operating loss carryforwards ($21 million)
as a result of the Global Settlement.

Federal and State Income Taxes
Federal and state income taxes increased in 2000, primarily due to the 1999
utilization of net operating loss carryforwards.

Federal and state income taxes decreased in 1999, primarily due to the
utilization of net operating loss carryforwards.

Equity Earnings of Regional Nuclear Generating Companies
Equity in earnings of regional nuclear generating and transmission companies
was relatively unchanged in 2000.

Equity in earnings of regional nuclear generating and transmission companies
decreased in 1999, primarily due to lower earnings from Connecticut Yankee.

Other, Net
Other, net increased in 2000, primarily due to the 1999 settlement with the
New Hampshire Electric Cooperative (NHEC) which was recognized in a $6.2
million write-off in 1999.

Other, net decreased in 1999, primarily due to the settlement with the NHEC
which required a $6.2 million write-off.

Interest Charges, Net
Interest charges, net decreased in 2000, primarily due to the redemption of
long-term debt bonds in 2000.

The change in interest charges, net in 1999, was not significant compared
to 1998.

Extraordinary Loss
The extraordinary loss is due to an after-tax write-off by PSNH of
approximately $225 million of stranded costs under an industry restructuring
settlement with the state of New Hampshire, combined with other positive
effects relating to the discontinuation of SFAS 71 ($11 million).



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
- ----------------------------------------

To the Board of Directors
   of Public Service Company of New Hampshire:

We have audited the accompanying balance sheets of Public Service Company of
New Hampshire (a New Hampshire corporation and a wholly owned subsidiary of
Northeast Utilities) as of December 31, 2000 and 1999, and the related
statements of income, comprehensive income, common stockholder's equity and
cash flows for each of the three years in the period ended December 31, 2000.
These financial statements are the responsibility of the company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.  We believe that
our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Public Service Company of
New Hampshire as of December 31, 2000 and 1999, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.




                                                    /s/ ARTHUR ANDERSEN LLP
                                                        ARTHUR ANDERSEN LLP



Hartford, Connecticut
January 23, 2001 (except with
respect to the matter discussed
in Note 14, as to which the
date is March 13, 2001)



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

STATEMENTS OF INCOME

<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31,                        2000        1999        1998
- ---------------------------------------------------------------------------------------
                                                           (Thousands of Dollars)

<S>                                                 <C>         <C>         <C>
Operating Revenues................................. $1,291,280  $1,160,572  $1,087,247
                                                    ----------- ----------- -----------
Operating Expenses:
  Operation -
    Fuel, purchased and net interchange power......    853,563     691,743     605,518
    Other..........................................    123,337     129,041     118,565
  Maintenance......................................     47,429      52,481      51,734
  Depreciation.....................................     43,873      47,695      45,342
  Amortization of regulatory assets, net...........     45,874      34,915      26,758
  Federal and state income taxes...................     45,080      36,810      65,079
  Taxes other than income taxes....................     42,194      43,282      43,052
                                                    ----------- ----------- -----------
        Total operating expenses...................  1,201,350   1,035,967     956,048
                                                    ----------- ----------- -----------
Operating Income...................................     89,930     124,605     131,199
                                                    ----------- ----------- -----------

Other Income/(Loss):
  Equity in earnings of regional nuclear
    generating companies and subsidiary company....      1,896       1,112       2,649
  Other, net.......................................     13,214       5,681       9,222
  Income taxes.....................................         68      (3,914)     (7,473)
                                                    ----------- ----------- -----------
        Other income, net..........................     15,178       2,879       4,398
                                                    ----------- ----------- -----------
        Income before interest charges.............    105,108     127,484     135,597
                                                    ----------- ----------- -----------

Interest Charges:
  Interest on long-term debt.......................     37,510      42,728      43,317
  Other interest...................................         47         547         594
                                                    ----------- ----------- -----------
        Interest charges, net......................     37,557      43,275      43,911
                                                    ----------- ----------- -----------
Income before extraordinary loss,
  net of tax benefit...............................     67,551      84,209      91,686

Extraordinary loss, net of tax benefit
  of $155,783......................................   (214,217)       -           -
                                                    ----------- ----------- -----------
Net (Loss)/Income.................................. $ (146,666) $   84,209  $   91,686
                                                    =========== =========== ===========

STATEMENTS OF COMPREHENSIVE INCOME

Net (Loss)/Income.................................. $ (146,666) $   84,209  $   91,686
                                                    ----------- ----------- -----------
Other comprehensive income, net of tax:
Unrealized gains on securities.....................        133          70       1,198
Minimum pension liability adjustments..............       -           -           (194)
                                                    ----------- ----------- -----------
  Other comprehensive income, net of tax...........        133          70       1,004
                                                    ----------- ----------- -----------
Comprehensive (Loss)/Income........................ $ (146,533) $   84,279  $   92,690
                                                    =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

BALANCE SHEETS

<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
AT DECEMBER 31,                                                   2000           1999
- -----------------------------------------------------------------------------------------
                                                                 (Thousands of Dollars)
<S>                                                          <C>            <C>
ASSETS
- ------

Utility Plant, at cost:
  Electric................................................   $  1,505,967   $  1,939,856

     Less: Accumulated provision for depreciation.........        711,340        674,155
                                                             -------------  -------------
                                                                  794,627      1,265,701
  Unamortized acquisition costs...........................           -           324,437
  Construction work in progress...........................         27,251         17,160
  Nuclear fuel, net.......................................          1,924          1,734
                                                             -------------  -------------
     Total net utility plant..............................        823,802      1,609,032
                                                             -------------  -------------
Other Property and Investments:
  Nuclear decommissioning trusts, at market...............          7,362          6,880
  Investments in regional nuclear generating
   companies and subsidiary company, at equity............         16,293         18,855
  Other, at cost..........................................          3,225          3,149
                                                             -------------  -------------
                                                                   26,880         28,884
                                                             -------------  -------------
Current Assets:
  Cash and cash equivalents...............................        115,135        182,588
  Receivables, less the accumulated provision for
   uncollectible accounts of $1,869 in 2000 and
   $1,359 in 1999.........................................         71,992         79,290
  Accounts receivable from affiliated companies...........          2,798          9,091
  Taxes receivable from affiliated companies..............          9,983         11,661
  Accrued utility revenues................................         41,844         48,822
  Fuel, materials and supplies, at average cost...........         28,760         38,076
  Recoverable energy costs - current portion..............           -            73,721
  Prepayments and other...................................         14,750         18,121
                                                             -------------  -------------
                                                                  285,262        461,370
                                                             -------------  -------------
Deferred Charges:

  Regulatory assets.......................................        924,847        490,921
  Deferred receivable from affiliated company.............          3,240         12,984
  Unamortized debt expense................................          9,067         11,896
  Other...................................................          9,096          7,346
                                                             -------------  -------------
                                                                  946,250        523,147
                                                             -------------  -------------


Total Assets..............................................   $  2,082,194   $  2,622,433
                                                             =============  =============
</TABLE>
The accompanying notes are an integral part of these financial statements.



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

BALANCE SHEETS

<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
AT DECEMBER 31,                                                   2000           1999
- -----------------------------------------------------------------------------------------
                                                                 (Thousands of Dollars)
<S>                                                          <C>            <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------

Capitalization:
  Common stock, $1 par value - authorized
   100,000,000 shares; 1,000 shares outstanding
   in 2000 and 1999.......................................   $          1   $          1
  Capital surplus, paid in................................        424,909        424,654
  Retained earnings.......................................        123,177        319,938
  Accumulated other comprehensive income..................          1,207          1,074
                                                             -------------  -------------
           Total common stockholder's equity..............        549,294        745,667
  Preferred stock subject to mandatory redemption.........           -            25,000
  Long-term debt..........................................        407,285        516,485
                                                             -------------  -------------
           Total capitalization...........................        956,579      1,287,152
                                                             -------------  -------------
Obligations Under Seabrook Power Contracts
 and Other Capital Leases.................................         91,702        624,477
                                                             -------------  -------------
Current Liabilities:
  Preferred stock - current portion.......................         24,268         25,000
  Obligations under Seabrook Power Contracts and other
   capital leases - current portion.......................        537,528        101,676
  Accounts payable........................................         45,847         38,685
  Accounts payable to affiliated companies................         54,157         38,229
  Accrued taxes...........................................            656         33,443
  Accrued interest........................................          4,962          6,294
  Other...................................................         13,112         10,184
                                                             -------------  -------------
                                                                  680,530        253,511
                                                             -------------  -------------

Deferred Credits and Other Long-term Liabilities:
  Accumulated deferred income taxes.......................        179,723        266,644
  Accumulated deferred investment tax credits.............         27,348         12,532
  Deferred contractual obligations........................         41,499         56,544
  Deferred revenue from affiliated company................          3,240         12,984
  Deferred pension costs..................................         41,216         45,504
  Other...................................................         60,357         63,085
                                                             -------------  -------------
                                                                  353,383        457,293
                                                             -------------  -------------
Commitments and Contingencies (Note 9)

Total Capitalization and Liabilities......................   $  2,082,194   $  2,622,433
                                                             =============  =============

</TABLE>
The accompanying notes are an integral part of these financial statements.



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
                                                                                 Accumulated
                                                       Capital                      Other
                                            Common     Surplus,    Retained     Comprehensive
                                             Stock     Paid In      Earnings       Income          Total
- ----------------------------------------------------------------------------------------------------------
                                                               (Thousands of Dollars)
<S>                                        <C>        <C>         <C>          <C>              <C>
Balance at January 1, 1998...............  $     1    $423,713    $ 170,501    $        -       $ 594,215

    Net income for 1998..................                            91,686                        91,686
    Cash dividends on preferred stock....                            (9,275)                       (9,275)
    Capital stock expenses, net..........                  537                                        537
    Other comprehensive income...........                                              1,004        1,004
                                           --------   ---------   ----------    -------------   ----------
Balance at December 31, 1998.............        1     424,250      252,912            1,004      678,167

    Net income for 1999..................                            84,209                        84,209
    Cash dividends on preferred stock....                            (6,625)                       (6,625)
    Capital stock expenses, net..........                  404                                        404
    Allocation of benefits - ESOP........                           (10,558)                      (10,558)
    Other comprehensive income...........                                                 70           70
                                           --------   ---------   ----------    -------------   ----------
Balance at December 31, 1999.............        1     424,654      319,938            1,074      745,667

    Net loss for 2000....................                          (146,666)                     (146,666)
    Cash dividends on preferred stock....                            (3,962)                       (3,962)
    Cash dividends on common stock.......                           (50,000)                      (50,000)
    Capital stock expenses, net..........                  255                                        255
    Tax benefit for 1993-1999 from
      reduction of NU parent losses (a)..                             3,952                         3,952
    Allocation of benefits - ESOP........                               (85)                          (85)
    Other comprehensive income...........                                                133          133
                                           --------   ---------   ----------    -------------   ----------
Balance at December 31, 2000.............  $     1    $424,909    $ 123,177    $       1,207    $ 549,294
                                           ========   =========   ==========    =============   ==========

</TABLE>
(a) In June 1999, PSNH paid NU parent $10.6 million for NU shares issued from
    1992 through 1998 on behalf of its employees in accordance with NU's 401(k)
    plan.  This transaction resulted in a reduction of the NU parent loss and
    a tax benefit to PSNH.  The amount in 2000 represents the remaining
    previously allocated 1993 through 1999 NU parent losses.

The accompanying notes are an integral part of these financial statements.



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
                                                                For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)                                             2000        1999        1998
- --------------------------------------------------------------------------------------------------
<S>                                                            <C>         <C>         <C>
Operating Activities:
  Net income before extraordinary loss........................ $   67,551  $   84,209  $   91,686
  Adjustments to reconcile to net cash
  provided by operating activities:
    Depreciation..............................................     43,873      47,695      45,342
    Deferred income taxes and investment tax credits, net.....       (512)     (5,297)     78,366
    Net (deferral)/amortization of recoverable energy costs...    (35,886)     27,065       2,065
    Amortization of regulatory assets, net....................     45,874      34,915      26,758
    Tax benefit for 1993-1999 from
      reduction of NU parent losses...........................      3,952        -           -
    Allocation of ESOP benefits...............................        (85)    (10,558)       -
    Net other sources/(uses) of cash..........................     38,694      48,537     (52,004)
  Changes in working capital:
    Receivables and accrued utility revenues..................     20,569       6,004      21,536
    Fuel, materials and supplies..............................      9,316      (1,434)      3,519
    Accounts payable..........................................     23,090      22,277         729
    Accrued taxes.............................................    (32,787)    (49,300)     13,298
    Other working capital (excludes cash).....................      6,645      (4,994)    (13,653)
                                                               ----------- ----------- -----------
Net cash flows provided by operating activities...............    190,294     199,119     217,642
                                                               ----------- ----------- -----------
Investing Activities:
  Investments in plant:
    Electric utility plant....................................    (69,500)    (46,096)    (43,780)
    Nuclear fuel..............................................     (1,153)     (1,168)       (307)
                                                               ----------- ----------- -----------
    Net cash flows used for investments in plant..............    (70,653)    (47,264)    (44,087)

  Investment in nuclear decommissioning trusts................       (686)       (678)       (641)
  Other investment activities, net............................      2,486       2,151      (2,213)
                                                               ----------- ----------- -----------
Net cash flows used in investing activities...................    (68,853)    (45,791)    (46,941)
                                                               ----------- ----------- -----------

Financing Activities:
  Reacquisitions and retirements of long-term debt............   (109,200)       -       (170,000)
  Reacquisitions and retirements of preferred stock...........    (25,732)    (25,000)    (25,000)
  Cash dividends on preferred stock...........................     (3,962)     (6,625)     (9,275)
  Cash dividends on common stock..............................    (50,000)       -           -
                                                               ----------- ----------- -----------
Net cash flows used in financing activities...................   (188,894)    (31,625)   (204,275)
                                                               ----------- ----------- -----------

Net (decrease)/increase in cash for the period................    (67,453)    121,703     (33,574)
Cash and cash equivalents - beginning of period...............    182,588      60,885      94,459
                                                               ----------- ----------- -----------
Cash and cash equivalents - end of period..................... $  115,135  $  182,588  $   60,885
                                                               =========== =========== ===========
Supplemental Cash Flow Information:
Cash paid during the year for:
  Interest, net of amounts capitalized........................ $   38,819  $   39,895  $   42,677
                                                               =========== =========== ===========
  Income taxes................................................ $   22,070  $   38,511  $   18,948
                                                               =========== =========== ===========
(Decrease)/increase in obligations:
  Seabrook Power Contracts.................................... $  (96,208) $ (115,065) $  (78,939)
                                                               =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.


NOTES TO FINANCIAL STATEMENTS
- -----------------------------

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     A.  About Public Service Company of New Hampshire Public Service Company
         of New Hampshire (PSNH or the company) along with The Connecticut
         Light and Power Company (CL&P), Western Massachusetts Electric Company
         (WMECO), North Atlantic Energy Corporation (NAEC), and Holyoke Water
         Power Company (HWP) are the operating companies comprising the
         Northeast Utilities system (NU system) and are wholly owned by
         Northeast Utilities (NU).  The NU system serves in excess of 30
         percent of New England's electric needs and is one of the 25 largest
         electric utility systems in the country as measured by revenues.  The
         NU system furnishes franchised retail electric service in New
         Hampshire, Connecticut, and western Massachusetts through PSNH, CL&P
         and WMECO.  NAEC sells all of its entitlement to the capacity and
         output of Seabrook Station nuclear unit (Seabrook) to PSNH under the
         terms of two life-of-unit, full cost recovery contracts (Seabrook
         Power Contacts).  HWP, also is engaged in the production and
         distribution of electric power.

         NU is registered with the Securities and Exchange Commission (SEC) as
         a holding company under the Public Utility Holding Company Act of 1935
         (1935 Act) and the NU system, including PSNH, is subject to provisions
         of the 1935 Act.  Arrangements among the NU system companies, outside
         agencies and other utilities covering interconnections, interchange of
         electric power and sales of utility property are subject to regulation
         by the Federal Energy Regulatory Commission (FERC) and/or the SEC.
         PSNH is subject to further regulation for rates, accounting and other
         matters by the FERC and/or applicable state regulatory commissions.

         Several wholly owned subsidiaries of NU provide support services for
         the NU system companies including PSNH, and, in some cases, for other
         New England utilities.  Northeast Utilities Service Company (NUSCO)
         provides centralized accounting, administrative, information
         resources, engineering, financial, legal, operational, planning,
         purchasing, and other services to the NU system companies, including
         PSNH.  Northeast Nuclear Energy Company acts as agent for the NU
         system companies and other New England utilities in operating the
         Millstone nuclear units.  North Atlantic Energy Service Corporation
         has operational responsibility for Seabrook.

     B.  Presentation
         The preparation of financial statements in conformity with accounting
         principles generally accepted in the United States requires management
         to make estimates and assumptions that affect the reported amounts of
         assets and liabilities and disclosure of contingent liabilities at the
         date of the financial statements and the reported amounts of revenues
         and expenses during the reporting period.  Actual results could differ
         from those estimates.

         Certain reclassifications of prior years' data have been made to
         conform with the current year's presentation.

         All transactions among affiliated companies are on a recovery of cost
         basis which may include amounts representing a return on equity and
         are subject to approval by various federal and state regulatory
         agencies.

     C.  New Accounting Standards
         Derivative Instruments:  Effective January 1, 2001, PSNH adopted
         Statement of Financial Accounting Standards (SFAS) No. 133,
         "Accounting for Derivative Instruments and Hedging Activities,"
         as amended.  SFAS No. 133 requires that derivative instruments be
         recorded as an asset or liability measured at its fair value and
         that changes in the fair value of derivative instruments be recognized
         currently in earnings unless specific hedge accounting criteria be
         met.

         In order to implement SFAS No. 133 by January 1, 2001, NU established
         a cross-functional project team to identify all derivative
         instruments, measure the fair value of those derivative instruments,
         designate and document various hedge relationships, and evaluate the
         effectiveness of those hedge relationships.  NU has completed the
         process of identifying all derivative instruments and has established
         appropriate fair value measurements of those derivative instruments
         in place at January 1, 2001.  In addition, for those derivative
         instruments which are hedging an identified risk, NU has designated
         and documented all hedging relationships anew.

         Management believes the adoption of this new standard will not have a
         material impact on PSNH's financial position or results of operations.

         Revenue Recognition:  In December 1999, the SEC issued Staff
         Accounting Bulletin (SAB) No. 101, "Revenue Recognition."  The
         adoption of SAB No. 101, as amended, did not have a material impact
         on PSNH's financial statements.

     D.  Investments and Jointly Owned Electric Utility Plant
         Regional Nuclear Generating Companies:  PSNH owns common stock in four
         regional nuclear companies (Yankee Companies).  PSNH's ownership
         interests in the Yankee Companies at December 31, 2000 and 1999, which
         are accounted for on the equity method due to PSNH's ability to
         exercise significant influence over their operating and financial
         policies are 5 percent of the Connecticut Yankee Atomic Power Company
         (CYAPC), 7 percent of the Yankee Atomic Electric Company (YAEC), 5
         percent of Maine Yankee Atomic Power Company (MYAPC), and 4 percent of
         Vermont Yankee Nuclear Power Corporation (VYNPC).  PSNH's total equity
         investment in the Yankee Companies at December 31, 2000 and 1999 is
         $10 million and $12.3 million, respectively.  Each Yankee Company owns
         a single nuclear generating unit.  However, VYNPC is the only unit
         still in operation at December 31, 2000.

         Millstone:  PSNH has a 2.85 percent joint ownership interest in
         Millstone 3, a 1,154 megawatt (MW) nuclear generating unit.  At
         December 31, 2000 and 1999, plant-in-service included $119.8 million
         and $119.3 million, respectively, and the accumulated provision for
         depreciation included $42 million and $39 million, respectively,
         related to PSNH's share of Millstone 3.

         Wyman Unit 4:  PSNH has a 3.14 percent ownership interest in Wyman
         Unit 4, a 632 MW oil-fired generating unit.  At December 31, 2000 and
         1999, plant-in-service included $6.1 million in each year and the
         accumulated provision for depreciation included $4.3 million and
         $4.2 million, respectively.

     E.  Depreciation
         The provision for depreciation is calculated using the straight-line
         method based on estimated remaining useful lives of depreciable
         utility plant-in-service, adjusted for salvage value and removal
         costs, as approved by the appropriate regulatory agency where
         applicable.  Except for major facilities, depreciation rates are
         applied to the average plant-in-service during the period.  Major
         facilities are depreciated from the time they are placed in service.
         When plant is retired from service, the original cost of plant,
         including costs of removal less salvage, is charged to the
         accumulated provision for depreciation.  The costs of closure and
         removal of nonnuclear facilities are accrued over the life of the
         plant as a component of depreciation.  The depreciation rates for the
         several classes of electric plant-in-service are equivalent to a
         composite rate of 3.2 percent in 2000, 3.7 percent in 1999 and 3.6
         percent in 1998.

     F.  Revenues
         Revenues are based on authorized rates applied to each customer's use
         of electricity.  In general, rates can be changed only through a
         formal proceeding before the New Hampshire Public Utility Commission
         (NHPUC).  Regulatory commissions also have authority over the terms
         and conditions of nontraditional rate-making arrangements.  At the end
         of each accounting period, PSNH accrues a revenue estimate for the
         amount of energy delivered but unbilled.

     G.  PSNH Acquisition Costs
         PSNH acquisition costs represent the aggregate value placed by the
         1989 rate agreement with the state of New Hampshire (Rate Agreement)
         on PSNH's assets in excess of the net book value of PSNH's non-
         Seabrook assets, plus the $700 million value assigned to Seabrook by
         the Rate Agreement as part of the bankruptcy resolution on June 5,
         1992.  The Rate Agreement provided for the recovery through rates,
         with a return, of the PSNH acquisition costs.  In connection with
         the Settlement Agreement approximately $219.4 million was written off
         and the balance of $76.6 million has been reclassified as a regulatory
         asset.

     H.  Regulatory Accounting and Assets
         The accounting policies of PSNH and the accompanying financial
         statements conform to accounting principles generally accepted in the
         United States applicable to rate-regulated enterprises and
         historically reflect the effects of the rate-making process in
         accordance with SFAS No. 71, "Accounting for the Effects of Certain
         Types of regulation."  During the fourth quarter of 2000, the
         "Agreement to Settle PSNH Restructuring," (Settlement Agreement)
         became probable of implementation, therefore, PSNH discontinued the
         application of SFAS No. 71 for the generation portion of its business.

         PSNH's transmission and distribution business will continue to be
         cost-based and management believes the application of SFAS No. 71
         continues to be appropriate.  Management continues to believe it is
         probable that PSNH will recover their investments in long-lived
         assets, including regulatory assets through charges to their
         transmission and distribution customers.  PSNH will recover
         securitized assets over a 12-year period.  Nuclear decommissioning and
         IPP costs will be recovered over the period PSNH is responsible for
         these costs.  The third type of PSNH stranded costs are non-
         securitized regulatory assets (type three regulatory assets).  Any
         type three regulatory assets not collected by the recovery end date
         will be written off.  Based on current projections, PSNH expects to
         fully recover all of its type three regulatory assets by the recovery
         end date stipulated in the Settlement Agreement.  In addition, all
         material regulatory assets are earning a return.  The components of
         PSNH's regulatory assets are as follows:

         ----------------------------------------------------------------------
         At December 31,                                 2000        1999
         ----------------------------------------------------------------------
                                                       (Millions of Dollars)

         Recoverable nuclear costs...............       $484.7       $   -
         Income taxes, net.......................         68.1        166.2
         Unrecovered contractual obligations.....         41.5         56.5
         Recoverable energy costs, net...........        230.3        120.7
         Other...................................        100.2        147.5
                                                        ------       ------
                                                        $924.8       $490.9
                                                        ======       ======
         ----------------------------------------------------------------------

         As a result of discontinuing the application of SFAS No. 71 in 2000
         for PSNH's generation business, PSNH recorded an after-tax charge of
         $214.2 million in the fourth quarter of 2000.  In addition, a
         regulatory asset was created for the Seabrook over market generation
         in the amount of $484.7 million, which is classified as recoverable
         nuclear costs.  It is anticipated this regulatory asset will be
         securitized.

     I.  Income Taxes
         The tax effect of temporary differences (differences between the
         periods in which transactions affect income in the financial
         statements and the periods in which they affect the determination of
         taxable income) is accounted for in accordance with the rate-making
         treatment of the applicable regulatory commissions.

         The tax effect of temporary differences, including timing differences
         accrued under previously approved accounting standards, that give rise
         to the accumulated deferred tax obligation is as follows:

         ----------------------------------------------------------------------
         At December 31,                                 2000        1999
         ----------------------------------------------------------------------
                                                       (Millions of Dollars)

         Accelerated depreciation and
           other plant-related differences.......       $ 93.8      $102.4

         Regulatory assets -
           income tax gross up...................         25.1        62.0

         Other...................................         60.8       102.2
                                                        ------      ------
                                                        $179.7      $266.6
                                                        ======      ======
         ----------------------------------------------------------------------

         PSNH had an Investment Tax Credit (ITC) carryforward of $23 million
         which expires in 2004.  It is anticipated that this carryforward will
         be fully utilized when filing the 2000 income tax return.

     J.  Recoverable Energy Costs
         Under the Energy Policy Act of 1992 (Energy Act), PSNH is assessed for
         its proportionate share of the costs of decontaminating and
         decommissioning uranium enrichment plants owned by the United States
         Department of Energy (DOE) (D&D Assessment).  The Energy Act requires
         that regulators treat D&D Assessments as a reasonable and necessary
         current cost of fuel, to be fully recovered in rates like any other
         fuel cost.  PSNH is currently recovering these costs through rates.
         As of December 31, 2000 and 1999, PSNH's total D&D deferrals were
         approximately $.2 million in each year.

         The Rate Agreement includes a fuel and purchased-power adjustment
         clause (FPPAC) permitting PSNH to pass through to retail customers,
         for a 10-year period that began in May 1991, the retail portion of
         differences between the fuel and purchased-power costs assumed in
         the Rate Agreement and PSNH's actual costs, which include the costs
         related to the Seabrook Power Contracts and the Clean Air Act
         Amendment.  The cost components of the FPPAC are subject to a prudence
         review by the NHPUC.  At December 31, 2000 and 1999, PSNH had $230.1
         million and $120.5 million, respectively, of recoverable energy costs
         deferred under the FPPAC.  Under the Settlement Agreement, the FPPAC
         will be recovered as a type three regulatory asset through a
         transition charge.

         In addition, under the Rate Agreement, charges made by NAEC through
         the Seabrook Power Contracts, including the deferred Seabrook capital
         expenses, are to be collected by PSNH through the FPPAC.  Beginning on
         June 1, 1998, the Seabrook deferred capital expenses began to be
         recovered over a 36-month period.  Included within the restructuring
         settlement write-off is the write-off of any deferred capital
         expenses.

     K.  Unrecovered Contractual Obligations
         Under the terms of contracts with the Yankee companies, the
         shareholder-sponsor companies, including PSNH, are each responsible
         for their proportionate share of the remaining costs of the units,
         including decommissioning.  The Settlement Agreement allows for
         recovery of these costs, therefore, PSNH has recorded a regulatory
         asset, with a corresponding obligation on its balance sheet.

     L.  Cash and Cash Equivalents
         Cash and cash equivalents includes cash on hand and short-term cash
         investments which are highly liquid in nature and have original
         maturities of three months or less.

2.   SEABROOK POWER CONTRACTS
     PSNH and NAEC have entered into two power contracts that obligate PSNH
     to purchase NAEC's 35.98 percent ownership of the capacity and output
     of Seabrook for the term of Seabrook's operating license.  Under these
     power contracts, PSNH is obligated to pay NAEC's cost of service during
     this period, regardless of whether Seabrook is operating.  NAEC's cost
     of service includes all of its Seabrook-related costs, including operation
     and maintenance (O&M) expenses, fuel expense, income and property tax
     expense, depreciation expense, certain overhead and other costs, and a
     return on its allowed investment.

     With the implementation of the Settlement Agreement, PSNH and NAEC will
     restructure the power contracts to provide for the buydown of the value
     of the Seabrook asset to $100 million.  The Settlement Agreement also
     requires NAEC to sell via public auction its share of Seabrook, with
     the sale to occur no later than December 31, 2003.  Upon a successful
     sale of NAEC's share of Seabrook, the existing Seabrook Power Contracts
     between PSNH and NAEC will be terminated.

     PSNH has included its right to buy power from NAEC on its balance sheet
     as part of utility plant and regulatory assets with a corresponding
     obligation.  At December 31, 2000, this right to buy power was valued
     at $626.9 million.

     Under the current Seabrook Power Contracts, if Seabrook is shut down
     prior to the expiration of its operating license, PSNH will be
     unconditionally required to pay NAEC termination costs for 39 years,
     less the period during which Seabrook has operated.  These termination
     costs will reimburse NAEC for its share of Seabrook shut-down and
     decommissioning costs, and will pay NAEC a return of and on any
     undepreciated balance of its initial investment over the remaining term
     of the power contracts, and the return of and on any capital additions
     to the plant made after the Acquisition Date over a period of five years
     after shut down (net of any tax benefits to NAEC attributable to the
     cancellation).

     Contract payments charged to operating expenses in 2000, 1999 and 1998
     were $268 million, $280 million and $272 million, respectively.  Interest
     included in the contract payments in 2000, 1999 and 1998 was $44 million,
     $49 million and $54 million, respectively.

     Future minimum payments, excluding executory costs, such as property
     taxes, state use taxes, insurance and maintenance, under the terms of the
     contracts, as of December 31, 2000, were approximately:

     Year                              Seabrook Power Contracts
     ----                              ------------------------
                                         (Millions of Dollars)

     2001...........................          $  116.8
     2002...........................              77.5
     2003...........................              75.2
     2004...........................              72.9
     2005...........................              70.5
     After 2005.....................             936.2
                                              --------

     Future minimum payments........           1,349.1

     Less amount representing
       interest.....................             722.2
                                              --------
     Present value of Seabrook
       Power Contracts payments.....          $  626.9
                                              ========
     --------------------------------------------------------------------------

3.   SHORT-TERM DEBT
     Limits:  The amount of short-term borrowings that may be incurred by NU
     and the NU system operating companies, including PSNH, is subject to
     periodic approval by either the SEC under the 1935 Act or by the
     respective state regulators.  PSNH is authorized by the NHPUC to incur
     short-term borrowings up to a maximum of $71.3 million.

     Money Pool:  Certain subsidiaries of NU, including PSNH, are members
     of the Northeast Utilities System Money Pool (Pool).  The Pool provides
     a more efficient use of the cash resources of the NU system and reduces
     outside short-term borrowings.  NUSCO administers the Pool as agent for
     the member companies.  Short-term borrowing needs of the member companies
     are first met with available funds of other member companies, including
     funds borrowed by NU parent.  NU parent may lend to the Pool but may
     not borrow.  Funds may be withdrawn from or repaid to the Pool at any
     time without prior notice.  Investing and borrowing subsidiaries receive
     or pay interest based on the average daily federal funds rate.  Borrowings
     based on loans from NU parent, however, bear interest at NU parent's cost
     and must be repaid based upon the terms of NU parent's original borrowing.
     At December 31, 2000 and 1999, PSNH had no outstanding borrowings from
     the Pool in 2000.  Due to the conditions placed on PSNH by the NHPUC
     during March 2000, PSNH was restricted from lending money to the Pool
     until the restructuring write-off was recorded.  Maturities of short-
     term debt obligations were for periods of three months or less.

4.   LEASES
     PSNH has entered into lease agreements, some of which are capital leases,
     for the use of data processing and office equipment, vehicles and office
     space.  The provisions of these lease agreements generally provide for
     renewal options.

     Capital lease rental payments charged to operating expense were $1 million
     in 2000, $1.5 million in 1999 and $1.6 million in 1998.  Interest included
     in capital lease rental payments was $0.3 million in 2000, $0.4 million in
     1999 and $0.2 million in 1998.  Operating lease rental payments charged to
     expense were $3.5 million in 2000, $3.1 million in 1999 and $5.4 million
     in 1998.

     Future minimum rental payments, excluding executory costs such as property
     taxes, state use taxes, insurance and maintenance, under long-term
     noncancelable leases, as of December 31, 2000, are:

     -------------------------------------------------------------------------
     Year                                 Capital Leases     Operating Leases
     -------------------------------------------------------------------------
                                                 (Millions of Dollars)

     2001................................     $ 1.2                $ 8.3
     2002................................       0.4                  5.4
     2003................................       0.4                  3.7
     2004................................       0.4                  2.9
     2005................................       0.4                  2.3
     After 2005..........................       0.7                  5.1
                                              -----                -----
     Future minimum lease payments.......       3.5                $27.7
                                                                   =====
     Less amount representing interest...       1.2
                                              -----
     Present value of future minimum
       lease payments....................     $ 2.3
                                              =====
     -------------------------------------------------------------------------

5.   EMPLOYEE BENEFITS

     Pension Benefits and Postretirement Benefits Other Than Pensions
     The NU system's subsidiaries, including PSNH, participate in a uniform
     noncontributory defined benefit retirement plan covering substantially all
     regular NU system employees.  Benefits are based on years of service and
     employees' highest eligible compensation during 60 consecutive months of
     employment.  PSNH's portion of the NU system's pension credit, part of
     which was credited to utility plant, was $4.3 million in 2000, $0.5
     million in 1999 and $0.1 million in 1998.

     Currently, PSNH annually funds an amount at least equal to that which will
     satisfy the requirements of the Employee Retirement Income Security Act
     and Internal Revenue Code.

     The NU system companies, including PSNH, also provide certain health care
     benefits, primarily medical and dental, and life insurance benefits
     through a benefit plan to retired employees.  These benefits are available
     for employees retiring from PSNH who have met specified service
     requirements.  For current employees and certain retirees, the total
     benefit is limited to two times the 1993 per retiree health care cost.
     These costs are charged to expense over the estimated work life of the
     employee.  PSNH annually funds postretirement costs through external
     trusts with amounts that have been rate-recovered and which also are tax
     deductible.

     Pension and trust assets are invested primarily in domestic and
     international equity securities and bonds.

     The following table represents information on the plans' benefit
     obligation, fair value of plan assets, and the respective plans' funded
     status:
<TABLE>
<CAPTION>

     -------------------------------------------------------------------------------
                                                     At December 31,
     -------------------------------------------------------------------------------
                                        Pension Benefits     Postretirement Benefits
     -------------------------------------------------------------------------------
     (Millions of Dollars)              2000       1999         2000         1999
     -------------------------------------------------------------------------------
     <S>                              <C>        <C>           <C>          <C>
     Change in benefit obligation
     Benefit obligation
       at beginning of year.........  $ (201.5)  $ (201.0)     $(51.2)      $(50.1)
     Service cost...................      (4.8)      (4.9)       (0.9)        (1.0)
     Interest cost..................     (15.0)     (14.3)       (3.9)        (3.6)
     Plan amendment.................        -       (11.2)         -            -
     Transfers......................       0.1        0.5          -            -
     Actuarial gain/(loss)..........      (1.0)      19.1        (1.1)        (1.5)
     Benefits paid..................      11.1       10.3         4.2          5.0
     -------------------------------------------------------------------------------
     Benefit obligation
       at end of year...............  $ (211.1)  $ (201.5)     $(52.9)      $(51.2)
     -------------------------------------------------------------------------------
     Change in plan assets
     Fair value of plan assets
       at beginning of year.........  $  233.8   $  213.2      $ 30.6       $ 27.3
     Actual return on plan assets...      (0.8)      30.4         1.5          3.4
     Employer contribution..........        -          -          4.5          4.9
     Benefits paid..................     (11.1)     (10.3)       (4.2)        (5.0)
     Transfers......................      (0.1)       0.5          -            -
     -------------------------------------------------------------------------------
     Fair value of plan assets
       at end of year...............  $  221.8   $  233.8      $ 32.4       $ 30.6
     -------------------------------------------------------------------------------
     Funded status at December 31...  $   10.7   $   32.3      $(20.5)      $(20.6)
     Unrecognized transition
       obligation...................       3.0        3.3        35.3         38.2
     Unrecognized prior
       service cost.................      15.5       16.9          -            -
     Unrecognized net gain..........     (70.4)     (98.0)      (14.8)       (17.6)
     -------------------------------------------------------------------------------
     Deferred benefit cost..........  $  (41.2)  $  (45.5)     $   -        $  -
     -------------------------------------------------------------------------------
</TABLE>

     The following actuarial assumptions were used in calculating the plans'
     year end funded status:

      -------------------------------------------------------------------------
                                                At December 31,
      -------------------------------------------------------------------------
                                   Pension Benefits     Postretirement Benefits
      -------------------------------------------------------------------------
                                     2000    1999           2000      1999
      -------------------------------------------------------------------------
      Discount rate.............     7.50%   7.75%          7.50%     7.75%
      Compensation/progression
        rate....................     4.50    4.75           4.50      4.75
      Health care cost
        trend rate (a)..........      N/A     N/A           5.26      5.57
      -------------------------------------------------------------------------

     (a) The annual per capita cost of covered health care benefits was assumed
         to decrease to 4.91 percent by 2001.

     The components of net periodic benefit (credit)/cost are:

     --------------------------------------------------------------------------
                                     For the Years Ended December 31,
     --------------------------------------------------------------------------
                                                           Postretirement
                                 Pension Benefits              Benefits
     --------------------------------------------------------------------------
     (Millions of Dollars)    2000     1999     1998     2000    1999     1998
     --------------------------------------------------------------------------
     Service cost........    $  4.8   $ 4.9    $ 4.3    $ 0.9   $ 1.0    $ 0.9
     Interest cost........     15.0    14.3     13.2      3.9     3.6      3.4
     Expected return
       on plan assets.....    (19.7)  (17.7)   (15.6)    (2.6)   (2.1)    (1.8)
     Amortization of
       unrecognized net
       transition (asset)/
       obligation.........      0.3     0.3      0.3      2.9     2.9      2.9
     Amortization of prior
       service cost.......      1.3     1.3      0.5       -       -        -
     Amortization of
       actuarial gain.....     (6.0)   (3.6)    (2.8)      -       -        -
     Other
       amortization, net..       -       -        -      (0.6)   (0.5)   (0.5)
     --------------------------------------------------------------------------
     Net periodic benefit
      (credit)/cost.......    $(4.3)  $(0.5)   $(0.1)   $ 4.5   $ 4.9   $ 4.9
     --------------------------------------------------------------------------

     For calculating pension and postretirement benefit costs, the following
     assumptions were used:

     --------------------------------------------------------------------------
                                     For the Years Ended December 31,
     --------------------------------------------------------------------------
                                                           Postretirement
                                 Pension Benefits              Benefits
     --------------------------------------------------------------------------
                            2000      1999      1998     2000    1999     1998
     --------------------------------------------------------------------------
     Discount rate........  7.75%     7.00%     7.25%    7.75%   7.00%    7.25%
     Expected long-term
       rate of return.....  9.50      9.50      9.50      N/A     N/A      N/A
     Compensation/
      progression rate....  4.75      4.25      4.25     4.75    4.25     4.25
     Long-term rate
       of return -
       Health assets,
         net of tax.......   N/A       N/A       N/A     7.50    7.50     7.75
       Life assets........   N/A       N/A       N/A     9.50    9.50     9.50
     --------------------------------------------------------------------------

     Assumed health care cost trend rates have a significant effect on the
     amounts reported for the health care plans.  The effect of changing the
     assumed health care cost trend rate by one percentage point in each year
     would have the following effects:

     --------------------------------------------------------------------------
                                            One Percentage     One Percentage
     (Millions of Dollars)                  Point Increase     Point Decrease
     --------------------------------------------------------------------------
     Effect on total service and
       interest cost components ......           $0.2              $(0.2)
     Effect on postretirement
       benefit obligation.............           $2.9              $(2.6)
     --------------------------------------------------------------------------

     The trust holding the health plan assets is subject to federal income
     taxes.

6.   PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
     Details of preferred stock subject to mandatory redemption are:

     --------------------------------------------------------------------------
                                          Shares
                                       Outstanding           December 31,
     Description                    December 31, 2000      2000        1999
     --------------------------------------------------------------------------
                                                          (Millions of Dollars)

     10.60%  Series A of 1991             970,722         $24.3        $50.0

     Less preferred stock to be
       redeemed within one year           970,722          24.3         25.0
                                                          -----        -----
                                                          $  -         $25.0
                                                          =====        =====

     The Series A preferred stock is not subject to optional redemption by
     PSNH.  It is subject to an annual sinking fund requirement of $25 million
     each year, which began on June 30, 1997, sufficient to retire annually
     1,000,000 shares at $25 per share.  In case of default on dividends or
     sinking fund payments, no payments may be made on any junior stock by way
     of dividends or otherwise (other than in shares of junior stock) so long
     as the default continues.  If PSNH is in arrears in the payment of
     dividends on any outstanding shares of preferred stock, PSNH would be
     prohibited from redeeming or purchasing less than all of the outstanding
     preferred stock.

7.   LONG-TERM DEBT
     Details of long-term debt outstanding are:

     -------------------------------------------------------------------------
      At December 31,                                    2000       1999
     -------------------------------------------------------------------------
                                                      (Millions of Dollars)
     Pollution Control Revenue Bonds:
     7.65% Tax-Exempt  Series A, due 2021........       $ 66.0     $ 66.0
     7.50% Tax-Exempt  Series B, due 2021........        109.0      109.0
     7.65% Tax-Exempt  Series C, due 2021........        112.5      112.5
     6.00% Tax-Exempt  Series D, due 2021........         75.0       75.0
     6.00% Tax-Exempt  Series E, due 2021........         44.8       44.8
     Adjustable Rate,  Series D, due 2021........           -        39.5
     Adjustable Rate,  Series E, due 2021........           -        69.7
                                                        ------     ------
     Long-term debt..............................       $407.3     $516.5
                                                        ======     ======
     -------------------------------------------------------------------------

     There are no cash sinking fund requirements or debt maturities for the
     years 2001 through 2005.  There are annual renewal and replacement fund
     requirements equal to 2.25 percent of the average of net depreciable
     utility property owned by PSNH at the reorganization date, plus cumulative
     gross property additions thereafter.  PSNH expects to meet these future
     fund requirements by certifying property additions.  Any deficiency would
     need to be satisfied by the deposit of cash or bonds.

     Concurrent with the issuance of PSNH's Series A and B first mortgage
     bonds, PSNH entered into financing arrangements with the Business Finance
     Authority (BFA) of the State of New Hampshire.  Pursuant to these
     arrangements, the BFA issued five series of Pollution Control Revenue
     Bonds (PCRBs) and loaned the proceeds to PSNH.  PSNH's obligation to repay
     each series of PCRBs is secured by the first mortgage bonds.  Each such
     series of first mortgage bonds contains similar terms and provisions as
     the applicable series of PCRBs.  For financial reporting purposes, these
     bonds would not be considered outstanding unless PSNH failed to meet its
     obligations under the PCRBs.

     The average effective interest rates on the variable-rate pollution
     control notes ranged from 5.9 percent to 6.8 percent in 2000 and from 4.9
     percent to 6.1 percent in 1999.

8.   INCOME TAX EXPENSE
     The components of the federal and state income tax provisions were
     charged/(credited) to operations as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)
     Current income taxes:
       Federal....................................  $ 41.8    $ 41.4    $ (6.6)
       State......................................     3.7       4.6       0.8
                                                    ------    ------    ------
         Total current............................    45.5      46.0      (5.8)
                                                    ------    ------    ------
     Deferred income taxes, net:
       Federal....................................     6.7       4.6      78.0
       State......................................     0.8      (2.2)      0.9
                                                    ------    ------    ------
         Total deferred...........................     7.5       2.4      78.9
                                                    ------    ------    ------
     Investment tax credits, net..................    (8.0)     (7.7)     (0.5)
                                                    ------    ------    ------
     Total income tax expense.....................  $ 45.0    $ 40.7    $ 72.6
                                                    ======    ======    ======
     --------------------------------------------------------------------------

     The components of total income tax expense/(credit) are classified as
     follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)

     Income taxes charged to operating expenses...  $ 45.1    $ 36.8   $ 65.1
     Other income taxes...........................    (0.1)      3.9      7.5
                                                    ------    ------   ------
     Total income tax expense.....................  $ 45.0    $ 40.7   $ 72.6
                                                    ======    ======   ======
     --------------------------------------------------------------------------

     Deferred income taxes are comprised of the tax effects of temporary
     differences as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)

     Depreciation.................................  $(1.0)   $ (6.5)   $(12.1)
     Regulatory deferral..........................    6.9     (12.6)     22.6
     State net operating loss carryforward........     -       29.5      69.2
     Regulatory disallowance......................     -       (2.3)       -
     Contractual settlements......................     -       (6.7)       -
     Other........................................    1.6       1.0      (0.8)
                                                    -----    ------    ------
     Deferred income taxes, net...................  $ 7.5    $  2.4      78.9
                                                    =====    ======    ======
     --------------------------------------------------------------------------

     A reconciliation between income tax expense and the expected tax expense
     at 35 percent of pretax income/(loss) is as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)

     Expected federal income tax                    $39.4     $43.7     $57.5
     Tax effect of differences:
       Depreciation...............................    0.3       0.9      (2.2)
       Amortization of regulatory assets..........    9.9       9.9      17.3
       Investment tax credit amortization.........   (8.0)     (7.7)     (0.5)
       State income taxes, net of
         federal benefit..........................    2.9       1.6       1.0
       Adjustment to tax asset
         valuation allowance......................     -       (7.4)       -
       Seabrook intercompany gains and losses.....    5.0       0.8       0.6
       Allocation of parent company loss..........   (4.2)       -         -
       Other, net.................................   (0.3)     (1.1)     (1.1)
                                                    -----      -----    -----
     Total income tax expense.....................  $45.0      $40.7    $72.6
                                                    =====      =====    =====
     --------------------------------------------------------------------------

9.   COMMITMENTS AND CONTINGENCIES

     A.  Restructuring
         In September 2000, the New Hampshire Public Utilities Commission
         (NHPUC) approved a comprehensive restructuring order that would allow
         PSNH to securitize up to $670 million of stranded costs.  In January
         2001, the New Hampshire Supreme Court upheld this restructuring order
         on appeal.  However, one of the appellants indicated publicly it would
         request a review of the New Hampshire Supreme Court decision by the
         United States Supreme Court.  Such a request must be filed by May 1,
         2001.  Management believes that such an appeal would have a low
         probability of success, but cannot determine what effect it might have
         on the timing of the issuance of securitization bonds and the
         implementation of customer choice in New Hampshire.  PSNH currently
         expects to work with the State of New Hampshire to issue
         securitization bonds early in the second quarter of 2001.

     B.  Nuclear Generation Assets Divestiture
         On August 7, 2000, PSNH, CL&P, and WMECO and certain other joint
         owners, including PSNH, reached an agreement to sell substantially all
         of the Millstone units, located in Waterford, Connecticut, to Dominion
         Resources, Inc. (Dominion), for approximately $1.3 billion, including
         approximately $105 million for nuclear fuel.  NU expects to close on
         the sale of Millstone as early as the end of March 2001.

         If the transaction is consummated as proposed, PSNH will receive $26
         million on a pretax basis, which will be reflected as a gain in
         accordance with the Settlement Agreement.

         By the end of 2002, PSNH expects to complete the sale of its fossil
         and hydroelectric generation assets, as well as NAEC's ownership share
         of Seabrook.

     C.  Environmental Matters
         The NU system, including PSNH, is subject to environmental laws and
         regulations intended to mitigate or remove the effect of past
         operations and improve or maintain the quality of our environment.
         As such, the NU system and PSNH have active environmental auditing
         and training programs and believe they are substantially in compliance
         with the current laws and regulations.

         However, the normal course of operations may necessarily involve
         activities and substances that expose PSNH to potential liabilities of
         which management cannot determine the outcome.  Additionally,
         management cannot determine the outcome for liabilities that may be
         imposed for past acts, even though such past acts may have been lawful
         at the time they occurred.  Management does not believe, however, that
         this will have a material impact on PSNH's financial statements.

         Based upon currently available information for the estimated
         remediation costs as of December 31, 2000 and 1999, the liability
         recorded by PSNH for its estimated environmental remediation costs
         amounted to $9.7 million and $9.5 million, respectively.

     D.  Spent Nuclear Fuel Disposal Costs
         Under the Nuclear Waste Policy Act of 1982, PSNH must pay the DOE for
         the disposal of spent nuclear fuel and high-level radioactive waste.
         The DOE is responsible for the selection and development of
         repositories for, and the disposal of, spent nuclear fuel and high-
         level radioactive waste.  Fees for nuclear fuel burned are billed
         currently to customers and paid to the DOE on a quarterly basis.

     E.  Nuclear Insurance Contingencies
         Insurance policies covering PSNH's ownership share of the NU system's
         nuclear facilities have been purchased for the primary cost of repair,
         replacement or decontamination of utility property, certain extra
         costs incurred in obtaining replacement power during prolonged
         accidental outages and the excess cost of repair, replacement or
         decontamination or premature decommissioning of utility property.

         PSNH is subject to retroactive assessments if losses under those
         policies exceed the accumulated funds available to the insurer.  The
         maximum potential assessments, including costs resulting from PSNH's
         contracts with NAEC, with respect to losses arising during the current
         policy year for the primary property insurance program, the
         replacement power policies and the excess property damage policies
         are $2.1 million, $0.8 million and $2.7 million, respectively.  In
         addition, insurance has been purchased in the aggregate amount of
         $200 million on an industry basis by the NU system for coverage of
         worker claims.

         Under certain circumstances, in the event of a nuclear incident at one
         of the nuclear facilities covered by the federal government's third-
         party liability indemnification program, the NU system, including
         PSNH, could be assessed liabilities in proportion to its ownership
         interest in each of its nuclear units up to $83.9 million.  The NU
         system's payment of this assessment would be limited to, in proportion
         to its ownership interest in each of its nuclear units, $10 million in
         any one year per nuclear unit.  In addition, if the sum of all claims
         and costs from any one nuclear incident exceeds the maximum amount of
         financial protection, the NU system would be subject to an additional
         5 percent or $4.2 million liability, in proportion to its ownership
         interests in each of its nuclear units.  Under the terms of the
         Seabrook Power Contracts, PSNH could be obligated to pay for any
         assessment charged to NAEC as a cost of service.  Based upon its
         ownership interest in Millstone 3 and NAEC's ownership interest in
         Seabrook, PSNH's maximum liability, including any additional
         assessments, would be $33.8 million per incident, of which payments
         would be limited to $3.9 million per year.  In addition, through
         purchased-power contracts with VYNPC, PSNH would be responsible for
         up to an additional assessment of $3.5 million per incident, of which
         payments would be limited to $0.3 million per year.

     F.  Long-Term Contractual Arrangements
         Yankee Companies:  Under the terms of its agreement, PSNH paid its
         ownership (or entitlement) shares of costs, which included
         depreciation, operation and maintenance (O&M) expenses, taxes, the
         estimated cost of decommissioning, and a return on invested capital.
         These costs were recorded as purchased-power expenses and recovered
         through PSNH's rates.  PSNH's cost of purchases under contracts with
         VYNPC amounted to $6.4 million in 2000, $7.5 million in 1999 and $7
         million in 1998.  VYNPC is in the process of selling its nuclear unit.
         Upon completion of the sale, this long-term contract will be
         terminated.

         Nonutility Generators (NUGs):  PSNH has entered into various
         arrangements for the purchase of capacity and energy from NUGs.
         PSNH's total cost of purchases under these arrangements amounted to
         $144.9 million in 2000, $139.8 million in 1999 and $139.1 million in
         1998.  The company is attempting to renegotiate the terms of the
         largest of these contracts through either a contract buydown or
         buyout.  The company expects any payments to the NUGs as a result of
         these successful renegotiations to be recovered from the company's
         customers.

         Hydro-Quebec:  Along with other New England utilities, PSNH has
         entered into an agreement to support transmission and terminal
         facilities to import electricity from the Hydro-Quebec system in
         Canada.  PSNH is obligated to pay, over a 30-year period ending in
         2020, its proportionate share of the annual O&M expenses and capital
         costs of those facilities.

         Estimated Annual Costs:  The estimated annual costs of PSNH's
         significant long-term contractual arrangements, absent the effects of
         any contract terminations, buydowns or buyouts are as follows:

         ---------------------------------------------------------------------
                                   2001     2002     2003     2004     2005
         ---------------------------------------------------------------------
                                            (Millions of Dollars)

         VYNPC.............      $  7.1    $  7.1   $  7.1   $  7.9   $  7.4
         NUGs..............       150.0     154.6    159.4    163.7    166.4
         Hydro-Quebec......         8.7       8.4      8.1      7.8      7.5
         ---------------------------------------------------------------------

     G.  Deferred Receivable from Affiliated Company
         At the time PSNH emerged from bankruptcy on May 16, 1991, in
         accordance with the phase-in under the Rate Agreement, it began to
         accrue a deferred return on a portion of its Seabrook investment.
         From May 16, 1991, to the Acquisition Date, PSNH accrued a deferred
         return of $50.9 million.  On the Acquisition Date, PSNH sold the
         $50.9 million deferred return to NAEC as part of the Seabrook-
         related assets.

         At the time PSNH transferred the deferred return to NAEC, it realized,
         for income tax purposes, a gain that was deferred under the
         consolidated income tax rules.  Beginning December 1, 1997, the gain
         is being amortized into income for income tax purposes, as the
         deferred return of $50.9 million, and the associated income taxes of
         $32.9 million, are being collected by NAEC through the Seabrook Power
         Contracts.  As NAEC recovers the $32.9 million in years eight through
         ten of the Rate Agreement, corresponding payments are being made to
         PSNH.  The balance of the deferred receivable from NAEC at
         December 31, 2000 and 1999, was $3.2 million and $13 million,
         respectively.

10.  NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
     Millstone and Seabrook:  PSNH is obligated to pay NAEC's share of
     Seabrook's decommissioning costs, even if the unit is shut down prior
     to the expiration of its operating license.  Accordingly, NAEC bills PSNH
     directly for its share of the costs of decommissioning Seabrook.  PSNH
     records its Seabrook decommissioning costs as a component of purchased-
     power expense.  These costs are recovered through base rates.  The
     Seabrook decommissioning costs will continue to be increased annually by
     its respective escalation rates until the unit is sold.  Under New
     Hampshire law, Seabrook's decommissioning funding requirements are set
     by the New Hampshire Nuclear Decommissioning Financing Committee (NDFC).
     During April 1999, the NDFC issued an order that adjusted the
     decommissioning collection period and funding levels assuming that
     Seabrook's anticipated energy producing life was 25 years from the date
     it went into commercial operation.  Decommissioning collections are now
     expected to be completed by October 2015, as opposed to 2026, for the
     decommissioning collection period only.  The cost of funding
     decommissioning Seabrook is now accrued over the estimated remaining
     accelerated funding period that was ordered by the NDFC.  This is
     eleven years earlier than the service life established by Seabrook's
     Nuclear Regulatory Commission's (NRC) operating license.

     Millstone 3 and Seabrook's service lives are expected to end during the
     years 2025 through 2026, and upon retirement, must be decommissioned.
     In connection with the sale of the Millstone nuclear units, Dominion has
     agreed to assume responsibility for decommissioning.  Until the
     divestiture, PSNH recovers sufficient amounts through their allowed rates
     related to decommissioning costs.

     PSNH's ownership share of the estimated cost of decommissioning
     Millstone 3 and NAEC's ownership share of Seabrook, in year end 2000
     dollars, is $18.4 million and $210.8 million, respectively.  Nuclear
     decommissioning costs are accrued over the expected service lives of
     Millstone 3 and are included in depreciation expense and the accumulated
     provision for depreciation.  Nuclear decommissioning expenses for PSNH's
     ownership share of Millstone 3 amounted to $.5 million in 2000 and 1999
     and $0.4 million in 1998.  Through December 31, 2000 and 1999, total
     decommissioning expenses of $4 million and $3.5 million, respectively,
     have been collected from customers and are reflected in the accumulated
     provision for depreciation.

     External decommissioning trusts have been established for the costs of
     decommissioning the Millstone units.  PSNH payments for NAEC's ownership
     share of the cost of decommissioning Seabrook are paid by NAEC to an
     independent decommissioning financing fund managed by the state of New
     Hampshire.  Funding of the estimated decommissioning costs assumes
     after-tax earnings on the Millstone and Seabrook decommissioning funds
     of 5.5 percent and 6.5 percent, respectively.

     As of December 31, 2000 and 1999, NAEC has paid approximately $39.6
     million and $32.7 million, respectively, (including payments made prior
     to the Acquisition Date by PSNH) into Seabrook's decommissioning fund.
     Earnings on the decommissioning trusts increase the decommissioning trust
     balances and the accumulated provisions for depreciation.  Unrealized
     gains and losses associated with the decommissioning trusts also impact
     the balance of the trusts and the accumulated provisions for depreciation.
     The fair values of the amounts in the external decommissioning trusts for
     Millstone 3 were $7.4 million and $6.9 million at December 31, 2000
     and 1999, respectively.  Upon divestiture of Millstone 3, balances in
     the decommissioning trusts for Millstone 3 will be transferred to the
     buyer.  NU is obligated to top off the decommissioning trust if its value
     does not equal an agreed upon amount at closing, pursuant to the
     conditions set forth in the purchase and sale agreement.

     Yankee Companies:  VYNPC owns and operates a nuclear generating unit with
     a service life that is expected to end in 2012.  PSNH's ownership share of
     estimated costs, in year end 2000 dollars, of decommissioning this unit is
     $18.1 million.  In 1999, VYNPC agreed to sell its nuclear generating unit
     for $22 million to an unaffiliated company.  Among other commitments, the
     acquiring company agreed to assume the obligation to decommission the unit
     after it is taken out of service, and the owners of VYNPC (including PSNH)
     agreed to fund their shares of the decommissioning costs up to a
     negotiated amount.  Subsequent to the time that agreement was executed,
     the original proposed acquiring company has increased the price it agreed
     to pay and three other unaffiliated companies have indicated their
     interest in buying VYNPC's generating unit on terms that have not been
     disclosed.  At present, PSNH expects that the unit will be sold, but the
     identity of the owner and the terms of sale, including price, future
     decommissioning obligations and future power purchase obligations, are
     not known.

     As of December 31, 2000 and 1999, PSNH's remaining estimated obligation,
     including decommissioning for the units owned by CYAPC, YAEC and MYAPC,
     which have been shut down was $41.5 million and $56.5 million,
     respectively.

11.  FAIR VALUE OF FINANCIAL INSTRUMENTS
     The following methods and assumptions were used to estimate the fair value
     of each of the following financial instruments:

     Cash and cash equivalents:  The carrying amounts approximate fair value
     due to the short-term nature of cash and cash equivalents.

     Nuclear decommissioning trusts: PSNH's portion of the investments held
     in the NU system companies' nuclear decommissioning trusts were marked-
     to-market by $2 million as of December 31, 2000, and $2.2 million as of
     December 31, 1999, with corresponding offsets to the accumulated provision
     for depreciation.  The amounts adjusted in 2000 and 1999 represent
     cumulative net unrealized gains.  Cumulative gross unrealized holding
     losses were immaterial for both 2000 and 1999.

     Preferred stock and long-term debt:  The fair value of PSNH's fixed-rate
     securities is based upon the quoted market price for those issues or
     similar issues.  Adjustable rate securities are assumed to have a fair
     value equal to their carrying value.  The carrying amounts of PSNH's
     financial instruments and the estimated fair values are as follows:

     --------------------------------------------------------------------------
                                                    At December 31, 2000
     --------------------------------------------------------------------------
                                                   Carrying         Fair
     (Millions of Dollars)                          Amount          Value
     --------------------------------------------------------------------------
     Preferred stock subject
       to mandatory redemption...............       $ 24.3         $ 25.5

     Other long-term debt....................        407.3          401.9
     --------------------------------------------------------------------------

     --------------------------------------------------------------------------
                                                    At December 31, 1999
     --------------------------------------------------------------------------
                                                   Carrying         Fair
     (Millions of Dollars)                          Amount          Value
     --------------------------------------------------------------------------
     Preferred stock subject
       to mandatory redemption...............       $ 50.0         $ 52.0

     Other long-term debt....................        516.5          517.4
     --------------------------------------------------------------------------

12.  OTHER COMPREHENSIVE INCOME
     The accumulated balance for each other comprehensive income item is as
     follows:

     --------------------------------------------------------------------------
                                                        Current
                                       December 31,     Period     December 31,
                                           1999         Change         2000
     --------------------------------------------------------------------------
     (Thousands of Dollars)
     --------------------------------------------------------------------------
     Unrealized gains
       on securities................      $1,268         $133         $1,401
     Minimum pension
       liability adjustments...........     (194)          -            (194)
     --------------------------------------------------------------------------
     Accumulated other
       comprehensive income............   $1,074         $133         $1,207
     --------------------------------------------------------------------------

     --------------------------------------------------------------------------
                                                        Current
                                       December 31,     Period     December 31,
                                           1998         Change         1999
     --------------------------------------------------------------------------
     (Thousands of Dollars)
     --------------------------------------------------------------------------
     Unrealized gains
       on securities...................   $1,198          $ 70        $1,268
     Minimum pension
       liability adjustments...........     (194)           -           (194)
     --------------------------------------------------------------------------
     Accumulated other
       comprehensive income............   $1,004          $ 70        $1,074
     --------------------------------------------------------------------------

     The changes in the components of other comprehensive income are reported
     net of the following income tax effects:

     --------------------------------------------------------------------------
                                                  2000      1999      1998
     --------------------------------------------------------------------------
     (Thousands of Dollars)
     --------------------------------------------------------------------------
     Unrealized gains on securities.........      $(74)     $(39)    $(660)
     Minimum pension
       liability adjustments................         -         -       107
     --------------------------------------------------------------------------
     Other comprehensive income.............      $(74)     $(39)    $(553)
     --------------------------------------------------------------------------

13.  SEGMENT INFORMATION
     Effective January 1, 1999, the NU system companies, including PSNH, adopted
     SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
     Information."  The NU system is organized between regulated utilities and
     competitive energy subsidiaries.  PSNH is included in the regulated
     utilities segment of the NU system and has no other reportable segments.

14.  SUBSEQUENT EVENT
     Merger Agreement With Consolidated Edison, Inc.:  In 2000, NU and
     Consolidated Edison, Inc. (Con Edison) received most of the approvals
     needed to complete the merger announced in October 1999.  Shareholders
     from both companies approved the merger in April 2000, and all state
     regulatory approvals were granted by the end of the year.  Additionally,
     the FERC approved the merger in May 2000, the NRC approved the transaction
     in August 2000, and the United States Department of Justice approved the
     merger in February 2001.  Necessary approval from the SEC was expected
     to be received in mid-March 2001.

     On February 28, 2001, NU's Board of Trustees requested that Con Edison
     provide reasonable assurance, in writing, that it intended to comply with
     the terms of the definitive merger agreement between the two companies.
     This included assurances that Con Edison would consummate the pending
     merger at the price set forth in the agreement promptly following the
     receipt of SEC approval.  The original request for assurance was to be
     received by March 2, 2001, however that date was later extended to
     March 5, 2001.  On March 5, 2001, Con Edison advised NU that it was not
     willing to close the merger on the agreed terms.  NU notified Con Edison
     that it was treating its refusal to proceed on the terms set forth in the
     merger agreement as a repudiation and breach of the merger agreement, and
     that NU would file suit to obtain the benefits of the transaction as
     negotiated for NU shareholders.  On March 6, 2001, Con Edison filed suit
     in the U.S. District Court for the Southern District of New York (Southern
     District), seeking a declaratory judgment that NU failed to satisfy
     conditions precedent under the merger agreement.  On March 12, 2001,
     NU filed suit against Con Edison in the Southern District seeking damages
     in excess of $1 billion arising from Con Edison's breach of the merger
     agreement.


<TABLE>
Public Service Company of New Hampshire
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
SELECTED FINANCIAL DATA                    2000         1999          1998          1997          1996
- ----------------------------------------------------------------------------------------------------------
                                                              (Thousands of Dollars)
<S>                                    <C>           <C>           <C>           <C>           <C>
Operating Revenues..................   $1,291,280    $1,160,572    $1,087,247    $1,108,459    $1,110,169

Operating Income....................       89,930       124,605       131,199       144,024       155,758

Net Income..........................     (146,666)       84,209        91,686        92,172        97,465

Cash Dividends on Common Stock......       50,000          -             -           85,000        52,000

Total Assets........................    2,082,194     2,622,433     2,681,595     2,837,159     2,851,212

Long-Term Debt (a)..................      407,285       516,485       516,485       686,485       686,485

Preferred Stock Subject
  to Mandatory Redemption (a).......       24,268        50,000        75,000       100,000       125,000

Obligations Under Seabrook Power
  Contracts and Other Capital
  Leases (a)........................      629,230       726,153       842,223       921,813       914,617

- ----------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
QUARTERLY FINANCIAL DATA (Unaudited)
- ------------------------------------------------------------------------------------------------
                                                      Quarter Ended
- ------------------------------------------------------------------------------------------------
2000                           March 31        June 30        September 30         December 31
- ------------------------------------------------------------------------------------------------
                                                  (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------
<S>                            <C>             <C>              <C>                 <C>
Operating Revenues             $328,694        $326,458         $337,865            $ 298,263
                               ========        ========         ========            =========

Operating Income               $ 25,242        $ 24,434         $ 28,180            $  12,074
                               ========        ========         ========            =========

Net Income                     $ 17,431        $ 14,252         $ 28,733            $(207,082)
                               ========        ========         ========            =========
- ------------------------------------------------------------------------------------------------
1999
- ------------------------------------------------------------------------------------------------

Operating Revenues             $286,799        $286,824         $310,739            $ 276,210
                               ========        ========         ========            =========

Operating Income               $ 35,449        $ 29,419         $ 34,666            $  25,071
                               ========        ========         ========            =========

Net Income                     $ 25,281        $ 20,695         $ 25,584            $  12,649
                               ========        ========         ========            =========
</TABLE>
(a) Includes portion due within one year.



Public Service Company of New Hampshire

- -------------------------------------------------------------------------------
STATISTICS (Unaudited)
- -------------------------------------------------------------------------------

                                       Average
        Gross Electric                  Annual
         Utility Plant                 Use Per
          December 31,     kWh        Residential    Electric
        (Thousands of     Sales        Customer      Customers      Employees
         Dollars) (a)   (Millions)      (kWh)       (Average)      December 31,
- -------------------------------------------------------------------------------

2000    $1,535,142        17,143        6,644        433,937          1,227
1999     2,283,187        12,832        6,665        427,694          1,258
1998     2,302,254        12,579        6,347        421,602          1,265
1997     2,312,628        13,340        6,528        407,642          1,254
1996     2,382,009        13,601        6,567        407,082          1,279

(a) Includes unamortized acquisition costs.

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13.4
<SEQUENCE>18
<FILENAME>0018.txt
<DESCRIPTION>ANNUAL REPORT OF NAEC
<TEXT>

                               2000 Annual Report

                       North Atlantic Energy Corporation

                                     Index


Contents                                                               Page
- --------                                                               ----

Management's Discussion and Analysis of Financial
  Condition and Results of Operations.............................       1

Report of Independent Public Accountants..........................       8

Statements of Income..............................................       9

Balance Sheets....................................................     10-11

Statements of Common Stockholder's Equity.........................       12

Statements of Cash Flows..........................................       13

Notes to Financial Statements.....................................     14-26

Selected Financial Data...........................................       27

Quarterly Financial Data (Unaudited)..............................       27

Statistics (Unaudited)............................................       27

Preferred Stockholder and Bondholder Information..................   Back Cover


                       North Atlantic Energy Corporation

- -------------------------------------------------------------------------------
Management's Discussion and Analysis of Financial
Condition and Results of Operations
- -------------------------------------------------------------------------------

Financial Condition
- -------------------

Overview
North Atlantic Energy Corporation, (NAEC or the company), is a wholly owned
operating subsidiary of Northeast Utilities (NU) and is part of the Northeast
Utilities system (NU system). Public Service Company of New Hampshire (PSNH),
is another wholly owned subsidiary of NU.  PSNH is obligated to purchase the
capacity and output from NAEC's 35.98 percent joint ownership interest in the
Seabrook Station nuclear unit (Seabrook) under the terms of two life-of-unit,
full cost recovery contracts (Seabrook Power Contracts).

The company's only assets are Seabrook and other Seabrook-related assets and
its only source of revenues are the Seabrook Power Contracts.  PSNH's
obligations under the Seabrook Power Contracts are solely its own and have
not been guaranteed by NU.  The Seabrook Power Contracts contain no provisions
entitling PSNH to terminate its obligations.  If, however, PSNH were to fail
to perform its obligations under the Seabrook Power Contracts, the company
would be required to find other purchasers for Seabrook's power.

With the implementation of the "Agreement to Settle PSNH Restructuring"
(Settlement Agreement), PSNH and NAEC will restructure the power contracts
to provide for the buydown of the value of the Seabrook asset to $100 million.
NAEC will use a portion of these cash proceeds to retire its existing long-term
debt obligation.  NAEC will also return to NU parent another portion of these
cash proceeds in the form of a dividend.  The Settlement Agreement also
requires NAEC to sell via public auction its share of Seabrook, with the
sale to occur no later than December 31, 2003. Upon a successful sale of
NAEC's share of Seabrook, the existing Seabrook Power Contracts between PSNH
and NAEC will be terminated.  However, PSNH will continue to be responsible
for funding NAEC's ownership share of Seabrook's decommissioning liability.

In 2000, NAEC's revenues decreased to $274.3 million, down 4.5 percent from
revenues of $287.4 million in 1999. Revenues were $276.7 million in 1998.
In 2000, NAEC had net income of $32.5 million, compared to $29.6 million in
1999 and $29.5 million in 1998.

Consolidated Edison, Inc. Merger
- --------------------------------

In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the
approvals needed to complete the merger announced in October 1999.
Shareholders from both companies approved the merger in April 2000, and all
state regulatory approvals were granted by the end of the year.  Additionally,
the Federal Energy Regulatory Commission (FERC) approved the merger in May
2000, the Nuclear Regulatory Commission approved the transaction in August
2000, and the United States Department of Justice approved the merger in
February 2001.  Necessary approval from the Securities and Exchange Commission
(SEC) was expected to be received in mid-March 2001.

On February 28, 2001, NU's Board of Trustees requested that Con Edison provide
reasonable assurance, in writing, that it intended to comply with the terms of
the definitive merger agreement between the two companies.  This included
assurances that Con Edison would consummate the pending merger at the price set
forth in the agreement promptly following the receipt of SEC approval.  The
original request for assurance was to be received by March 2, 2001, however
that date was later extended to March 5, 2001.  On March 5, 2001, Con Edison
advised NU that it was not willing to close the merger on the agreed terms.
NU notified Con Edison that it was treating its refusal to proceed on the terms
set forth in the merger agreement as a repudiation and breach of the merger
agreement, and that NU would file suit to obtain the benefits of the
transaction as negotiated for NU shareholders.  On March 6, 2001, Con Edison
filed suit in the U.S. District Court for the Southern District of New York
(Southern District), seeking a declaratory judgment that NU failed to satisfy
conditions precedent under the merger agreement. On March 12, 2001, NU filed
suit against Con Edison in the Southern District seeking damages in excess of
$1 billion arising from Con Edison's breach of the merger agreement.
NU cannot predict the outcome of this matter nor its effect on NU.

Liquidity
- ---------

During 2000, net cash flows provided by operations were $117.6 million,
compared to $181.4 million in 1999 and $128.7 million in 1998.  The decrease
in 2000 was primarily due to an increase in receivables and an increase in
deferred income tax benefit due to lower tax depreciation.

Net cash flows used in financing activities were $112 million in 2000, compared
to $130 million in 1999 and $75 million in 1998.  This included $270 million to
retire long-term debt, compared to $70 million and $20 million in 1999 and
1998, respectively.  Cash dividends on common shares paid in 2000 were $42
million, compared to $60 million in 1999 and $45 million in 1998.

Including investments made in the NU System Money Pool, construction
expenditures and investments in nuclear decommissioning trusts, net cash flows
used in investing activities were $5.5 million in 2000, compared to $51.5
million in 1999 and $53.7 million in 1998.  NAEC currently forecasts
construction expenditures of $6.6 million for the year 2001.

In 2000, NAEC renewed its $200 million term credit agreement for 364 days.
In April 2000, Moody's Investors Service (Moody's) upgraded its credit ratings
for NAEC, and in October 2000, Fitch IBCA (Fitch) upgraded its credit ratings
for NAEC.  In January 2001, Moody's and Standard and Poor's upgraded their
credit ratings for NAEC, primarily as a result of the New Hampshire Supreme
Court's decision to uphold that state's restructuring plan and NU's general
financial recovery.

By the end of 2002, PSNH expects to complete the auction of approximately
1,200 MW of fossil and hydroelectric generation assets, as well NAEC's
share of Seabrook.  PSNH's restructuring settlement was predicated upon
receiving approximately $400 million of net proceeds from those sales.
Cash proceeds will be used to retire debt and to return equity capital to
the parent company.

In September 2000, the New Hampshire Public Utilities Commission (NHPUC)
approved a comprehensive restructuring settlement that allows PSNH to
securitize up to $670 million of stranded costs.  In January 2001, the New
Hampshire Supreme Court upheld this restructuring order on appeal.  However,
one of the appellants indicated publicly it would request a review of the
New Hampshire Supreme Court decision by the United States Supreme Court.
Such a request must be filed by May 1, 2001.  Management believes that such
an appeal would have a low probability of success, but cannot determine what
effect it might have on the timing of the issuance of securitization bonds and
the implementation of customer choice in New Hampshire.  PSNH currently
expects to work with the State of New Hampshire to issue securitization bonds
early in the second quarter of 2001.  Cash proceeds would be combined with
cash on hand and used primarily to buydown the power contract between PSNH
and NAEC, retire debt at the two companies of approximately $300 million and
return equity capital to the parent company from PSNH and NAEC of another
$375 million.

Restructuring
- -------------

On September 8, 2000, the NHPUC issued two orders.  The first order approved
an Amended Settlement Agreement.  The Amended Settlement Agreement, as approved
by the NHPUC, will resolve 11 NHPUC dockets and PSNH's federal lawsuit which
had enjoined the state of New Hampshire from implementing its restructuring
legislation, will require PSNH to write off in excess of $200 million after-tax
of its stranded costs and allow for the recovery of the remaining amount.

The second order issued by the NHPUC was an order addressing financing issues,
primarily securitization. The order, among other things, authorizes PSNH to
issue up to $670 million of rate reduction bonds (RRB), permits PSNH to
establish a RRB charge, and establishes the terms of the RRB charge, including
the requirement that it be non-bypassable.  The New Hampshire legislature had
previously passed legislation, that permitted PSNH to issue up to $670 million
in RRBs to securitize certain regulatory assets.

The Settlement Agreement also requires NAEC to sell its share of the Seabrook
power plant, including Seabrook 2.  NAEC will use the proceeds of such a sale
to pay off any outstanding obligations.  Net proceeds in excess of book value
will be transferred to PSNH and applied against PSNH's stranded costs.  The
sales would be accomplished through an auction process subject to NHPUC
administration.

Nuclear Plant Performance and Divestiture
- -----------------------------------------

Seabrook
Seabrook operated at a capacity factor of 78 percent in 2000.  The unit began
a scheduled refueling outage on October 21, 2000.  The outage was extended by
approximately two months as a result of the need to repair extensive problems
with a back-up diesel generator.  Seabrook returned to service on January 29,
2001.

On December 15, 2000, NU filed its divestiture plan for Seabrook with the
NHPUC and the Connecticut Department of Public Utility Control.  NU hopes
to complete the sale in 2002.

Nuclear Decommissioning
For further information regarding nuclear decommissioning, see Note 2, "Nuclear
Decommissioning and Plant Closure Costs," to the financial statements.

Spent Nuclear Fuel Disposal Costs
The United States Department of Energy (DOE) originally was scheduled to begin
accepting delivery of spent nuclear fuel in 1998.  However, delays in
confirming the suitability of a permanent storage site continually have
postponed plans for the DOE's long-term storage and disposal site.  Extended
delays or a default by the DOE could lead to consideration of costly
alternatives.  NU has the primary responsibility for the interim storage of
its spent nuclear fuel prior to divestiture of its nuclear units.

For further information regarding spent nuclear fuel disposal costs, see
Note 7C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs,"
to the financial statements.

Other Matters
- -------------

Environmental Matters
NAEC is subject to environmental laws and regulations structured to mitigate or
remove the effect of past operations and to improve or maintain the quality of
the environment.  For further information regarding environmental matters, see
Note 7B, "Commitments and Contingencies - Environmental Matters," to the
financial statements.

Other Commitments and Contingencies
For further information regarding these other commitments and contingencies,
see Note 7, "Commitments and Contingencies," to the financial statements.

Forward Looking Statements
This discussion and analysis includes forward looking statements, which are
statements of future expectations and not facts including, but not limited to,
statements regarding future earnings, refinancing, the use of proceeds from
restructuring, and the recovery of operating costs.  Words such as estimates,
expects, anticipates, intends, plans, and similar expressions identify forward
looking statements.  Actual results or outcomes could differ materially as a
result of further actions by state and federal regulatory bodies, competition
and industry restructuring, changes in economic conditions, changes in
historical weather patterns, changes in laws, developments in legal or public
policy doctrines, technological developments, and other presently unknown or
unforeseen factors.

RESULTS OF OPERATIONS

The components of significant income statement variances for the past two years
are provided in the table below.

                                          Income Statement Variances
                                             (Millions of Dollars)

                               2000 over/(under) 1999   1999 over/(under) 1998
                               -----------------------------------------------
                                  Amount    Percent        Amount    Percent
                                  ------    -------        ------    -------

Operating Revenues                $(13)       (5)%          $ 11        4%

Operating Expenses:
Fuel, purchased and
  interchange power, net            (3)      (17)              2       17
Other operation and
  maintenance expense                -         -              10       19
Depreciation                         -         -               2        9
Amortization of
  regulatory assets                  -         -               -        -
Federal and state
  income taxes                       1         2              (1)      (4)
Taxes other than
  income taxes                      (6)      (42)              2       17
                                  ----       ---            ----      ---
Total operating expenses            (7)       (3)             15        7
                                  ----       ---            ----      ---
Operating Income                    (6)      (11)             (4)      (8)
                                  ----       ---            ----      ---
Other Income:
Deferred Seabrook return
  - other funds                     (2)      (52)             (2)     (34)
Other, net                           1        12               1       12
Other income tax                     4        19               5       33
                                  ----       ---            ----      ---
Net other income                     2        14               3       27
Interest charges                    (6)      (17)             (1)      (3)
                                  ----       ---            ----      ---
Net Income/(Loss)                 $  3        10            $ -         -
                                  ====       ===            ====      ===

Operating Revenues
Total operating revenues decreased by $13 million or 5 percent for 2000, as
compared to 1999, primarily due to lower operating costs billed to PSNH through
the Seabrook Power Contracts.

Operating revenues increased in 1999, primarily due to the higher operating
expenses related to the Seabrook refueling and maintenance outage in 1999.

Fuel, Purchased and Interchange Power, Net
Fuel expense decreased in 2000, as compared to 1999, primarily due to the
extended nuclear refueling outage in 2000.

Fuel expense increased in 1999, primarily due to a higher fuel amortization
rate since the Seabrook refueling outage.

Other Operation and Maintenance Expense
Other operation and maintenance (O&M) expenses were relatively unchanged in
2000, as compared to 1999.

Other O&M expenses increased in 1999, primarily due to higher costs relating
to the Seabrook refueling outage.

Depreciation
Depreciation expense was unchanged in 2000.

Depreciation increased in 1999 due to shorter useful lives for 1999 plant
asset additions.

Federal and State Income Taxes
Federal and state income taxes decreased during 2000, due to lower book
taxable income.

Federal and state income taxes decreased during 1999, due to lower book
taxable income.

Taxes Other Than Income Taxes
Taxes other than income taxes decreased in 2000, primarily due to the tax
true-up in the third quarter of 1999 as a result of a change to the statewide
utility property tax.

Taxes other than income taxes increased in 1999, as the result of the New
Hampshire change to a statewide utility property tax in place of the nuclear
station tax.

Deferred Seabrook Return - Other Funds
The deferred Seabrook return income decreased in 2000, as compared to 1999, as
NAEC continues to recover the Seabrook deferred return, reducing the
outstanding balance.

The deferred Seabrook return income decreased in 1999, as compared to 1998,
as NAEC continues to recover the Seabrook deferred return, reducing the
outstanding balance.

Other, Net
Other income, net increased in 2000, primarily due to higher interest income on
investments in the NU System Money Pool.

Other income, net increased in 1999, primarily due to higher interest income on
investments in the NU System Money Pool.

Interest Charges
Interest charges decreased in 2000, primarily due to lower long-term debt
outstanding.

Interest charges decreased in 1999, primarily due to lower long-term debt
outstanding.



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To the Board of Directors
  of North Atlantic Energy Corporation:

We have audited the accompanying balance sheets of North Atlantic Energy
Corporation (a New Hampshire corporation and a wholly owned subsidiary of
Northeast Utilities) as of December 31, 2000 and 1999, and the related
statements of income, common stockholder's equity and cash flows for each
of the three years in the period ended December  31, 2000.  These financial
statements are the responsibility of the company's management.  Our
responsibility is to express an opinion on these financial statements based
on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.  We believe that
our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of North Atlantic Energy
Corporation as of December 31, 2000 and 1999, and the results of its operations
and its cash flows for each of the three years in the period ended December 31,
2000, in conformity with accounting principles generally accepted in the
United States.




                                  /s/ ARTHUR ANDERSEN LLP
                                      ARTHUR ANDERSEN LLP


Hartford, Connecticut
January 23, 2001 (except with
respect to the matter discussed
in Note 11, as to which the
date is March 13, 2001)



NORTH ATLANTIC ENERGY CORPORATION

STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------
FOR THE YEAR ENDED DECEMBER 31,                        2000       1999       1998
- -------------------------------------------------------------------------------------
                                                          (Thousands of Dollars)

<S>                                                  <C>       <C>        <C>
Operating Revenues................................. $ 274,319  $ 287,369  $ 276,685
                                                    ---------- ---------- ----------
Operating Expenses:
  Operation -
     Fuel..........................................    12,923     15,596     13,305
     Other.........................................    40,650     41,727     36,763
  Maintenance......................................    20,268     19,030     14,120
  Depreciation.....................................    27,823     27,576     25,381
  Amortization of regulatory assets, net...........    85,176     85,488     85,464
  Federal and state income taxes...................    35,675     34,854     36,194
  Taxes other than income taxes....................     7,727     13,370     11,401
                                                    ---------- ---------- ----------
        Total operating expenses...................   230,242    237,641    222,628
                                                    ---------- ---------- ----------
Operating Income...................................    44,077     49,728     54,057
                                                    ---------- ---------- ----------
Other Income/(Loss):
  Deferred Seabrook return - other funds...........     2,112      4,417      6,731
  Other, net.......................................    (6,544)    (7,432)    (8,435)
  Income taxes.....................................    22,792     19,131     14,378
                                                    ---------- ---------- ----------
        Other income, net..........................    18,360     16,116     12,674
                                                    ---------- ---------- ----------
        Income before interest charges.............    62,437     65,844     66,731
                                                    ---------- ---------- ----------
Interest Charges:
  Interest on long-term debt.......................    32,247     45,297     50,082
  Other interest...................................     1,423       (542)      (676)
  Deferred Seabrook return - borrowed funds........    (3,726)    (8,467)   (12,169)
                                                    ---------- ---------- ----------
        Interest charges, net......................    29,944     36,288     37,237
                                                    ---------- ---------- ----------

Net Income......................................... $  32,493  $  29,556  $  29,494
                                                    ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.



NORTH ATLANTIC ENERGY CORPORATION

BALANCE SHEETS

<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
AT DECEMBER 31,                                                   2000           1999
- -----------------------------------------------------------------------------------------
                                                                 (Thousands of Dollars)
<S>                                                           <C>           <C>
ASSETS
- ------

Utility Plant, at original cost:
  Electric................................................   $    719,353   $    736,472

     Less: Accumulated provision for depreciation.........        223,465        196,694
                                                             -------------  -------------
                                                                  495,888        539,778
  Construction work in progress...........................          8,710         10,274
  Nuclear fuel, net.......................................         28,369         21,149
                                                             -------------  -------------
     Total net utility plant..............................        532,967        571,201
                                                             -------------  -------------

Other Property and Investments:
  Nuclear decommissioning trusts, at market...............         50,863         43,667
                                                             -------------  -------------
                                                                   50,863         43,667
                                                             -------------  -------------
Current Assets:
  Cash....................................................            118           -
  Notes receivable from affiliated companies..............         27,800         56,400
  Accounts receivable from affiliated companies...........         50,796         22,840
  Taxes receivable........................................            722         11,717
  Materials and supplies, at average cost.................         14,003         13,088
  Prepayments and other...................................          2,000          1,773
                                                             -------------  -------------
                                                                   95,439        105,818
                                                             -------------  -------------
Deferred Charges:
  Regulatory assets.......................................         48,068        129,641
  Unamortized debt expense................................            847          1,780
  Prepaid property tax....................................            630           -
  Other...................................................            150           -
                                                             -------------  -------------
                                                                   49,695        131,421
                                                             -------------  -------------

Total Assets..............................................   $    728,964   $    852,107
                                                             =============  =============
</TABLE>
The accompanying notes are an integral part of these financial statements.



NORTH ATLANTIC ENERGY CORPORATION

BALANCE SHEETS

<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
AT DECEMBER 31,                                                   2000           1999
- -----------------------------------------------------------------------------------------
                                                                 (Thousands of Dollars)
<S>                                                          <C>            <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------

Capitalization:
  Common stock, $1 par value - authorized 1,000 shares;
   1,000 shares outstanding in 2000 and 1999..............   $          1   $          1
  Capital surplus, paid in................................        160,999        160,999
  Retained earnings.......................................            (41)        12,752
                                                             -------------  -------------
           Total common stockholder's equity..............        160,959        173,752
  Long-term debt..........................................         65,000        135,000
                                                             -------------  -------------
           Total capitalization...........................        225,959        308,752
                                                             -------------  -------------

Current Liabilities:
  Notes payable to banks..................................        200,000           -
  Long-term debt - current portion........................         70,000        270,000
  Accounts payable........................................         16,543         11,694
  Accounts payable to affiliated companies................          1,389            806
  Accrued interest........................................          2,716          2,340
  Other...................................................            276            272
                                                             -------------  -------------
                                                                  290,924        285,112
                                                             -------------  -------------

Deferred Credits and Other Long-term Liabilities:
  Accumulated deferred income taxes.......................        184,763        222,601
  Deferred obligation to affiliated company...............          3,240         12,984
  Other...................................................         24,078         22,658
                                                             -------------  -------------
                                                                  212,081        258,243
                                                             -------------  -------------

Commitments and Contingencies (Note 7)

Total Capitalization and Liabilities......................   $    728,964   $    852,107
                                                             =============  =============
</TABLE>
The accompanying notes are an integral part of these financial statements.



NORTH ATLANTIC ENERGY CORPORATION

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------
                                                     Capital    Retained
                                           Common    Surplus,   Earnings
                                           Stock     Paid In      (a)      Total
- -----------------------------------------------------------------------------------
                                                   (Thousands of Dollars)

<S>                                             <C>   <C>        <C>       <C>
Balance at January 1, 1998.............. $       1  $ 160,999  $ 58,702  $ 219,702

    Net income for 1998.................                         29,494     29,494
    Cash dividends on common stock......                        (45,000)   (45,000)
                                         ---------- ---------- --------- ----------
Balance at December 31, 1998............         1    160,999    43,196    204,196

    Net income for 1999.................                         29,556     29,556
    Cash dividends on common stock......                        (60,000)   (60,000)
                                         ---------- ---------- --------- ----------
Balance at December 31, 1999............         1    160,999    12,752    173,752

    Net income for 2000.................                         32,493     32,493
    Cash dividends on common stock......                        (42,000)   (42,000)
    Tax expense for 1993-1999 from
     reduction on NU parent company
     losses (b).........................                         (3,286)    (3,286)
                                         ---------- ---------- --------- ----------
Balance at December 31, 2000............ $       1  $ 160,999  $    (41) $ 160,959
                                         ========== ========== ========= ==========

</TABLE>
(a) The dividend restriction allows all the retained earnings plus an allowance
    of $10,000,000 to be available.  However the company has a 25% common
    equity ratio test to meet.  Since the company's retained earnings are
    negative, only $9,959,000 of the allowance can be paid.

(b) The amount in 2000 represents the tax expense related to the previously
    unallocated 1993 through 1999 NU parent losses.

The accompanying notes are an integral part of these financial statements.



NORTH ATLANTIC ENERGY CORPORATION

STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
                                                                For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)                                             2000        1999        1998
- --------------------------------------------------------------------------------------------------
<S>                                                            <C>         <C>         <C>
Operating Activities:
  Net income.................................................. $   32,493  $   29,556  $   29,494
  Adjustments to reconcile to net cash
   provided by operating activities:
    Depreciation..............................................     27,823      27,576      25,381
    Amortization of nuclear fuel..............................     10,221      12,642      10,453
    Deferred income taxes and investment tax credits, net.....    (25,579)        452       6,010
    Deferred return - Seabrook................................     (5,838)    (12,884)    (18,900)
    Amortization of regulatory assets, net....................     85,176      85,488      85,464
    Tax expense for 1993-1999 from
       reduction of NU parent losses..........................     (3,286)       -           -
    Deferred obligation to affiliated company.................     (9,744)     (9,744)     (9,744)
    Net other sources of cash.................................     18,645      35,486      18,214
  Changes in working capital:
    Receivables...............................................    (27,956)        964       1,891
    Materials and supplies....................................       (915)       (276)        191
    Accounts payable..........................................      5,432       5,709      (7,161)
    Accrued taxes.............................................       -           (710)        710
    Other working capital (excludes cash).....................     11,148       7,133     (13,258)
                                                               ----------- ----------- -----------
Net cash flows provided by operating activities...............    117,620     181,392     128,745
                                                               ----------- ----------- -----------
Investing Activities:
  Investments in plant:
    Electric utility plant....................................     (6,586)     (7,895)     (9,028)
    Nuclear fuel..............................................    (17,222)     (9,934)     (6,474)
                                                               ----------- ----------- -----------
    Net cash flows used for investments in plant..............    (23,808)    (17,829)    (15,502)

  Investment in NU system Money Pool..........................     28,600     (26,050)    (30,350)
  Investments in nuclear decommissioning trusts...............    (10,294)     (7,584)     (7,885)
                                                               ----------- ----------- -----------
Net cash flows used in investing activities...................     (5,502)    (51,463)    (53,737)
                                                               ----------- ----------- -----------

Financing Activities:
  Net increase/(decrease) in short-term debt..................    200,000        -         (9,950)
  Reacquisitions and retirements of long-term debt............   (270,000)    (70,000)    (20,000)
  Cash dividends on common stock..............................    (42,000)    (60,000)    (45,000)
                                                               ----------- ----------- -----------
Net cash flows used in financing activities...................   (112,000)   (130,000)    (74,950)
                                                               ----------- ----------- -----------

Net increase/(decrease) in cash for the period................        118         (71)         58
Cash - beginning of period....................................       -             71          13
                                                               ----------- ----------- -----------
Cash - end of period.......................................... $      118  $     -     $       71
                                                               =========== =========== ===========

Supplemental Cash Flow Information:
Cash paid during the year for:
  Interest, net of amounts capitalized........................ $   28,349  $   38,042  $   42,498
                                                               =========== =========== ===========
  Income taxes................................................ $   28,053  $    3,000  $   22,136
                                                               =========== =========== ===========

</TABLE>
The accompanying notes are an integral part of these financial statements.



NOTES TO THE FINANCIAL STATEMENTS
- ---------------------------------

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     A.  About North Atlantic Energy Corporation
         North Atlantic Energy Corporation (NAEC or the company) along with The
         Connecticut Light and Power Company (CL&P), Public Service Company of
         New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO),
         and Holyoke Water Power Company (HWP) are the operating companies
         comprising the Northeast Utilities system (NU system) and are wholly
         owned by Northeast Utilities (NU).  The NU system serves in excess of
         30 percent of New England's electric needs and is one of the 25
         largest electric utility systems in the country as measured by
         revenues.  The NU system furnishes franchised retail electric service
         in New Hampshire, Connecticut and western Massachusetts through PSNH,
         CL&P and WMECO.  NAEC owns 35.98 percent of the Seabrook Station
         nuclear unit (Seabrook) and sells all of its entitlement to the
         capacity and output of Seabrook to PSNH under the terms of two life-
         of-unit, full cost recovery contracts (Seabrook Power Contracts).
         HWP, also is engaged in the production and distribution of electric
         power.

         NU is registered with the Securities and Exchange Commission (SEC)
         as a holding company under the Public Utility Holding Company Act
         of 1935 (1935 Act) and the NU system, including NAEC, is subject to
         provisions of the 1935 Act.  Arrangements among the NU system
         companies, outside agencies and other utilities covering
         interconnections, interchange of electric power and sales of utility
         property are subject to regulation by the Federal Energy Regulatory
         Commission (FERC) and/or the SEC.  NAEC is subject to further
         regulation for rates, accounting and other matters by the FERC and/or
         the New Hampshire Public Utilities Commission (NHPUC).

         Several wholly owned subsidiaries of NU provide support services for
         the NU system companies and, in some cases, for other New England
         utilities.  Northeast Utilities Service Company (NUSCO) provides
         centralized accounting, administrative, information resources,
         engineering, financial, legal, operational, planning, purchasing, and
         other services to the NU system companies.  Northeast Nuclear Energy
         Company acts as agent for the NU system companies and other New
         England utilities in operating the Millstone nuclear units.  North
         Atlantic Energy Service Corporation (NAESCO) has operational
         responsibility for Seabrook.

     B.  Presentation
         The preparation of financial statements in conformity with accounting
         principles generally accepted in the United States requires management
         to make estimates and assumptions that affect the reported amounts of
         assets and liabilities and disclosure of contingent liabilities at the
         date of the financial statements and the reported amounts of revenues
         and expenses during the reporting period.  Actual results could differ
         from those estimates.

         Certain reclassifications of prior years' data have been made to
         conform with the current year's presentation.

         All transactions among affiliated companies are on a recovery of cost
         basis which may include amounts representing a return on equity and
         are subject to approval by various federal and state regulatory
         agencies.

     C.  New Accounting Standards
         Derivative Instruments:  Effective January 1, 2001, NAEC adopted
         Statement of Financial Accounting Standards (SFAS) No. 133,
         "Accounting for Derivative Instruments and Hedging Activities," as
         amended.  SFAS No. 133 requires that derivative instruments be
         recorded as an asset or liability measured at its fair value and that
         changes in the fair value of derivative instruments be recognized
         currently in earnings unless specific hedge accounting criteria
         are met.

         In order to implement SFAS No. 133 by January 1, 2001, NU established
         a cross-functional project team to identify all derivative
         instruments, measure the fair value of those derivative instruments,
         designate and document various hedge relationships, and evaluate the
         effectiveness of those hedge relationships.  NU has completed the
         process of identifying all derivative instruments and has established
         appropriate fair value measurements of those derivative instruments in
         place at January 1, 2001.  In addition, for those derivative
         instruments which are hedging an identified risk, NU has designated
         and documented all hedging relationships anew.

         Management believes the adoption of this new standard will not have a
         material impact on NAEC's financial position or results of operations.

     D.  Jointly Owned Electric Utility Plant
         Seabrook:  NAEC has a 35.98 percent ownership interest in Seabrook,
         a 1,148 megawatt nuclear generating unit.  NAEC sells all of its share
         of the power generated by Seabrook to PSNH under the Seabrook Power
         Contracts.  NAEC expects to auction its investment in Seabrook in 2001
         with a closing on the sale expected in 2002.

         NAEC's share of Seabrook's plant-in-service as of December 31, 2000
         and 1999, was $734.6 million and $728 million, respectively, and the
         accumulated provision for depreciation was $172.6 million and $153
         million, respectively.

     E.  Depreciation
         The provision for depreciation is calculated using the straight-line
         method based on estimated remaining useful lives of depreciable
         utility plant-in-service, adjusted for salvage value and removal
         costs, as approved by the appropriate regulatory agency, where
         applicable.  Except for major facilities, depreciation rates are
         applied to the average plant-in-service during the period.  Major
         facilities are depreciated from the time they are placed in service.
         When plant is retired from service, the original cost of the plant,
         including costs of removal less salvage, is charged to the accumulated
         provision for depreciation.  The costs of closure and removal of
         nonnuclear facilities are accrued over the life of the plant as a
         component of depreciation.  The depreciation rates for the several
         classes of electric plant-in-service are equivalent to a composite
         rate of 2.9 percent in 2000, 3.8 percent in 1999 and 3.5 percent
         in 1998.

     F.  Seabrook Power Contracts
         NAEC and PSNH have entered into two power contracts that obligate
         PSNH to purchase NAEC's 35.98 percent ownership of the capacity and
         output of Seabrook for the term of Seabrook's operating license.
         Under these power contracts, PSNH is obligated to pay NAEC's cost
         of service during this period, regardless of whether Seabrook is
         operating.  NAEC's cost of service includes all of its Seabrook-
         related costs, including operation and maintenance (O&M) expenses,
         fuel expense, income and property tax expense, depreciation expense,
         certain overhead and other costs, and a return on its allowed
         investment.

         The Seabrook Power Contracts established the value of the initial
         investment in Seabrook at $700 million.  As prescribed by the 1989
         rate agreement between NU, PSNH, and the state of New Hampshire
         (Rate Agreement), as of May 1, 1996, NAEC phased into rates 100
         percent of the recoverable portion of its investment in Seabrook.
         From June 5, 1992 (the date NU acquired PSNH and NAEC acquired
         Seabrook from PSNH - the Acquisition Date) through November 1997,
         NAEC recorded a $203.9 million deferred return on its investment
         in Seabrook.  At November 30, 1997, NAEC's utility plant included
         $84.1 million of the deferred return that was transferred as part
         of the Seabrook plant assets to NAEC on the Acquisition Date.

         With the implementation of the "Agreement to Settle PSNH
         Restructuring" (Settlement Agreement), NAEC and PSNH will restructure
         the power contracts to provide for the buydown of the value of the
         Seabrook asset to $100 million.  The Settlement Agreement also
         requires NAEC to sell via public auction its share of Seabrook, with
         the sale to occur no later than December 31, 2003.  Upon a successful
         sale of NAEC's share of Seabrook, the existing Seabrook Power
         Contracts between NAEC and PSNH will be terminated.

         Under the current Seabrook Power Contracts, if Seabrook is shut
         down prior to the expiration of its operating license, PSNH will
         be unconditionally required to pay NAEC termination costs for 39
         years, less the period during which Seabrook has operated.  These
         termination costs will reimburse NAEC for its share of Seabrook
         shut-down and decommissioning costs, and will pay NAEC a return of
         and on any undepreciated balance of its initial investment over the
         remaining term of the power contracts, and the return of and on any
         capital additions to the plant made after the Acquisition Date over
         a period of five years after shut down (net of any tax benefits to
         NAEC attributable to the cancellation).

     G.  Regulatory Accounting and Assets
         The accounting policies of NAEC and the accompanying financial
         statements conform to accounting principles generally accepted in the
         United States applicable to rate-regulated enterprises and
         historically reflect the effects of the rate-making process in
         accordance with SFAS No. 71.  During the fourth quarter of 2000,
         the Settlement Agreement became probable of implementation, therefore,
         PSNH discontinued the application of SFAS No. 71 for the generation
         portion of its business.  In accordance with the power contracts,
         NAEC will be paid for the cost of Seabrook, therefore, PSNH's
         discontinuation of SFAS No. 71 did not impact NAEC.

         Management continues to believe it is probable that NAEC will
         recover their investments in long-lived assets, including regulatory
         assets.  In addition, all material regulatory assets are earning a
         return.  The components of NAEC's regulatory assets are as follows:

         ----------------------------------------------------------------------
         At December 31,                                 2000        1999
         ----------------------------------------------------------------------
                                                       (Millions of Dollars)

         Deferred costs - Seabrook...............       $23.2       $ 88.5
         Income taxes, net.......................        23.4         35.6
         Recoverable energy costs................         1.5          1.7
         Unamortized loss on reacquired debt.....          -           3.8
                                                        -----       ------
                                                        $48.1       $129.6
                                                        =====       ======
         ----------------------------------------------------------------------

         Upon the implementation of the Settlement Agreement, as filed, PSNH
         will make a payment to NAEC to buydown the Seabrook Power Contracts
         to $100 million.  NAEC will reduce the Seabrook assets to $100
         million.  Upon the final sale of Seabrook, the Seabrook Power Contract
         will be terminated and any difference between the net proceeds and the
         Seabrook book value at the time will be transferred to PSNH and
         applied against PSNH's stranded costs.

     H.  Income Taxes
         The tax effect of temporary differences (differences between the
         periods in which transactions affect income in the financial
         statements and the periods in which they affect the determination of
         taxable income) is accounted for in accordance with the rate-making
         treatment of the applicable regulatory commissions.

         The tax effect of temporary differences, including timing differences
         accrued under previously approved accounting standards, which give
         rise to the accumulated deferred tax obligation is as follows:

         ----------------------------------------------------------------------
         At December 31,                                 2000        1999
         ----------------------------------------------------------------------
                                                       (Millions of Dollars)

         Accelerated depreciation and
           other plant-related differences.......       $197.8      $205.1
         Regulatory assets -
           income tax gross up...................          7.6        12.2
         Other...................................        (20.6)        5.3
                                                        ------      ------
                                                        $184.8      $222.6
                                                        ======      ======
         ----------------------------------------------------------------------

     I.  Recoverable Energy Costs
         Under the Energy Policy Act of 1992 (Energy Act), NAEC is assessed for
         its proportionate shares of the costs of decontaminating and
         decommissioning uranium enrichment plants owned by the United States
         Department of Energy (DOE) (D&D Assessment).  The Energy Act requires
         that regulators treat D&D Assessments as a reasonable and necessary
         current cost of fuel, to be fully recovered in rates like any other
         fuel cost.  NAEC is currently recovering these costs through the
         Seabrook Power Contracts.  As of December 31, 2000 and 1999, NAEC's
         total D&D Assessment deferral was $1.5 million and $1.7 million,
         respectively.

2.   NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
     Seabrook: Under the terms of the Rate Agreement, PSNH is obligated to pay
     NAEC's share of Seabrook's decommissioning costs, even if the unit is shut
     down prior to the expiration of its operating license.  Accordingly, NAEC
     bills PSNH directly for its share of the costs of decommissioning
     Seabrook.  PSNH records its Seabrook decommissioning costs as a component
     of purchased-power expense.  Under the Rate Agreement, these costs are
     recovered through base rates.  The Seabrook decommissioning costs will
     continue to be increased annually by its respective escalation rates until
     the unit is sold.

     NAEC's existing decommissioning trusts will be increased at the time of
     the plant sale, however, PSNH will continue to be responsible for funding
     NAEC's ownership share of the remainder of Seabrook's decommissioning
     liability after its share of the unit is sold.  PSNH's obligation will
     be limited to the future funding of the decommissioning cost level in
     effect at the time of sale.  The Settlement Agreement provides PSNH for
     the recovery of these costs through a stranded cost recovery charge within
     rates.

     Under New Hampshire law, Seabrook decommissioning funding requirements
     are set by the New Hampshire Nuclear Decommissioning Financing Committee
     (NDFC).  During January 2000, the NDFC issued an order that adjusted the
     decommissioning collection period and funding levels assuming that
     Seabrook's anticipated energy producing life was 25 years from the date
     it went into commercial operation.  Decommissioning collections are now
     expected to be completed by October 2015, as opposed to 2026, for the
     decommissioning collection period only.  The cost of funding
     decommissioning Seabrook is now accrued over the estimated remaining
     accelerated funding period that was ordered by the NDFC.  This is eleven
     years earlier than the service life established by Seabrook's Nuclear
     Regulatory Commission's (NRC) operating license.

     Upon retirement, Seabrook must be decommissioned.  Current decommissioning
     studies conclude that complete and immediate dismantlement as soon as
     practical after retirement continues to be the most viable and economic
     method of decommissioning a unit.  These studies are reviewed and updated
     periodically to reflect changes in decommissioning requirements, costs,
     technology, and inflation.  Changes in requirements or technology, the
     timing of funding or dismantling or adoption of a decommissioning method
     other than immediate dismantlement would change decommissioning cost
     estimates and the amounts required to be recovered.

     The estimated cost of decommissioning NAEC's share of Seabrook, in year
     end 2000 dollars is $210.8 million. Nuclear decommissioning costs are
     accrued over the expected service life of the unit and are included in
     depreciation expense.  Nuclear decommissioning expenses for the unit
     amounted to $6.9 million in 2000, $6.8 million in 1999 and $4.7 million
     in 1998.  Nuclear decommissioning, as a cost of removal, is included in
     the accumulated provision for depreciation.

     Payments for NAEC's ownership share of the cost of decommissioning
     Seabrook are paid to an independent decommissioning financing fund managed
     by the state of New Hampshire.  Funding of the estimated decommissioning
     costs assumes escalated collections and after-tax earnings on the Seabrook
     decommissioning fund of 6.5 percent.

     As of December 31, 2000 and 1999, NAEC has paid $39.6 million and $32.7
     million (including payments made prior to the Acquisition Date by PSNH),
     into Seabrook's decommissioning financing fund.  Earnings on the
     decommissioning financing fund increase the decommissioning trust balance
     and the accumulated reserve for depreciation.  Unrealized gains and losses
     associated with the decommissioning financing fund also impact the balance
     of the trust and the accumulated reserve for depreciation.  The fair
     values of the amounts in the external decommissioning trust for NAEC were
     $50.9 million and $43.7 million at December 31, 2000 and 1999,
     respectively.

3.   SHORT-TERM DEBT
     Limits:  The amount of short-term borrowings that may be incurred by NAEC
     is subject to periodic approval by either the SEC under the 1935 Act or
     by the NHPUC.  As of December 31, 2000, NAEC is authorized by the NHPUC
     and the SEC to incur short-term borrowings up to a maximum of
     $260 million.

     Credit Agreements:  On November 9, 2000, NAEC entered into an unsecured
     364-day term credit agreement for $200 million, replacing a $225 million
     term loan which was to expire on November 9, 2000.  The proceeds from the
     term credit agreement were used to repay the $200 million outstanding
     under the previous term loan.  Additionally, the interest rate swaps and
     collar related to the previous term loan expired and were not replaced.
     The term credit agreement also contains two mandatory prepayment
     provisions; the first is a 50 percent mandatory principal repayment of
     amounts outstanding to $100 million within two days of the buydown of the
     Seabrook Power Contracts and the second is 100 percent prepayment within
     two days of the sale of Seabrook.  Any amounts prepaid can not be
     reborrowed.  Unless extended, the term credit agreement will expire on
     November 8, 2001.  At December 31, 2000 and 1999, there were $200 million
     in borrowings under the credit agreement and previous term loan.

     Under the aforementioned credit agreements, the respective borrowers
     may borrow at fixed or variable rates plus an applicable margin based
     upon certain debt ratings, as rated by the lower of Standard and Poor's
     or Moody's Investors Service.  The weighted average interest rate on
     NAEC's notes payable to banks outstanding on December 31, 2000, was
     8.3 percent.  Maturities of short-term debt obligations were for periods
     of three months or less.

     These credit agreements provide that NAEC must comply with certain
     financial and nonfinancial covenants as are customarily included in
     such agreements, including, but not limited to, common equity ratios and
     interest coverage ratios.  NAEC currently is and expects to remain in
     compliance with these covenants.

     Money Pool:  Certain subsidiaries of NU, including NAEC, are members
     of the Northeast Utilities System Money Pool (Pool).  The Pool provides
     a more efficient use of the cash resources of the NU system, and reduces
     outside short-term borrowings.  NUSCO administers the Pool as agent for
     the member companies.  Short-term borrowing needs of the member companies
     are first met with available funds of other member companies, including
     funds borrowed by NU parent.  NU parent may lend to the Pool but may not
     borrow.   Funds may be withdrawn from or repaid to the Pool at any time
     without prior notice.  Investing and borrowing subsidiaries receive
     or pay interest based on the average daily federal funds rate.  Borrowings
     based on loans from NU parent, however, bear interest at NU parent's cost
     and must be repaid based upon the terms of NU parent's original borrowing.
     At December 31, 2000 and 1999, NAEC had no borrowings outstanding from
     the Pool.

4.   LONG-TERM DEBT
     Details of long-term debt outstanding are:

     --------------------------------------------------------------------------
     At December 31,                                    2000          1999
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)
     First Mortgage Bonds:
       9.05% Series A, due 2002...................      $135          $205
     Notes:
       Variable - Rate Facility, due 2000.........        -            200

     Less amounts due within one year                     70           270
                                                        ----          ----
     Long-term debt, net                                $ 65          $135
                                                        ====          ====
     --------------------------------------------------------------------------

     Long-term debt maturities and cash sinking fund requirements on debt
     outstanding at December 31, 2000, for the years 2001 and 2002 are $70
     million and $65 million, respectively.

     Essentially all utility plant of NAEC is subject to the liens of the
     company's first mortgage bond indenture.  NAEC's first mortgage bonds
     are also secured by payments made to NAEC by PSNH under the terms of the
     Seabrook Power Contracts.

     In 1999, interest rate swaps effectively fix the interest rate of NAEC's
     $200 million variable-rate bank note at interest rates ranging from 5.81
     percent to 6.07 percent.

5.   INCOME TAX EXPENSE
     The components of the federal and state income tax provisions were
     charged/(credited) to operations as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)
     Current income taxes:
       Federal....................................   $37.5     $15.1    $15.2
       State......................................     1.0       0.2      0.6
                                                     -----     -----    -----
         Total current............................    38.5      15.3     15.8
                                                     -----     -----    -----
     Deferred income taxes, net:
       Federal....................................   (23.6)      0.4      4.0
       State......................................    (2.0)       -       2.0
                                                     -----     -----    -----
         Total deferred...........................   (25.6)      0.4      6.0
                                                     -----     -----    -----

     Total income tax expense.....................   $12.9     $15.7    $21.8
                                                     =====     =====    =====
     --------------------------------------------------------------------------

     The components of total income tax expense/(credit) are classified as
     follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)

     Income taxes charged to operating expenses...  $ 35.7    $ 34.8   $ 36.2
     Other income taxes...........................   (22.8)    (19.1)   (14.4)
                                                    ------    ------   ------
     Total income tax expense.....................  $ 12.9    $ 15.7   $ 21.8
                                                    ======    ======   ======
     --------------------------------------------------------------------------

     Deferred income taxes are comprised of the tax effects of temporary
     differences as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)

     Depreciation.................................  $ (6.5)  $ 19.5    $ 21.8
     Bond redemptions.............................    (1.4)    (2.8)     (2.8)
     Seabrook deferred return.....................   (17.3)   (15.7)    (14.2)
     Other........................................    (0.4)    (0.6)      1.2
                                                    ------   -------   ------
     Deferred income taxes, net...................  $(25.6)  $  0.4    $  6.0
                                                    ======   =======   ======
     --------------------------------------------------------------------------

     A reconciliation between income tax expense and the expected tax expense
     at 35 percent of pretax income is as follows:

     --------------------------------------------------------------------------
     For the Years Ended December 31,                2000      1999      1998
     --------------------------------------------------------------------------
                                                       (Millions of Dollars)

     Expected federal income tax..................  $15.9     $15.8     $18.0
     Tax effect of differences:
       Amortization of regulatory assets..........    7.1       7.0       7.1
       Depreciation...............................   (1.5)     (3.2)      1.6
       Deferred Seabrook return...................   (0.7)     (1.5)     (2.4)
       State income taxes, net of
         federal benefit..........................   (0.7)      0.1       1.7
       Allocation of Parent Company's loss........   (6.3)     (2.1)     (3.9)
       Other, net.................................   (0.9)     (0.4)     (0.3)
                                                    -----     -----     -----
     Total income tax expense.....................  $12.9     $15.7     $21.8
                                                    =====     =====     =====
     --------------------------------------------------------------------------

6.   DEFERRED OBLIGATION TO AFFILIATED COMPANY
     At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance
     with the phase-in under the Rate Agreement, it began to accrue a deferred
     return on a portion of its Seabrook investment.  From May 16, 1991, to the
     Acquisition Date, PSNH accrued a deferred return of $50.9 million.  On the
     Acquisition Date, PSNH sold the $50.9 million deferred return to NAEC as
     part of the Seabrook-related assets.

     At the time PSNH transferred the deferred return to NAEC, it realized, for
     income tax purposes, a gain that was deferred under the consolidated
     income tax rules.  Beginning December 1, 1997, the gain is being amortized
     into income for income tax purposes, as the deferred return of $50.9
     million, and the associated income taxes of $32.9 million, are being
     collected by NAEC through the Seabrook Power Contracts.  As NAEC recovers
     the $32.9 million in years eight through ten of the Rate Agreement,
     corresponding payments are being made to PSNH.  The balance of the
     deferred obligation to PSNH at December 31, 2000 and 1999, was $3.2
     million and $13 million, respectively.

7.   COMMITMENTS AND CONTINGENCIES
     A.  Restructuring
         In September 2000, the NHPUC approved a comprehensive restructuring
         order that would allow PSNH to securitize up to $670 million of
         stranded costs.  In January 2001, the New Hampshire Supreme Court
         upheld this restructuring order on appeal.  However, one of the
         appellants indicated publicly it would request a review of the New
         Hampshire Supreme Court decision by the United States Supreme Court.
         Such a request must be filed by May 1, 2001.  Management believes
         that such an appeal would have a low probability of success, but
         cannot determine what effect it might have on the timing of the
         issuance of securitization bonds and the implementation of customer
         choice in New Hampshire.  PSNH currently expects to work with the
         State of New Hampshire to issue securitization bonds early in the
         second quarter of 2001.

     B.  Environmental Matters
         The NU system, including NAESCO on behalf of NAEC, is subject to
         environmental laws and regulations intended to mitigate or remove the
         effect of past operations and improve or maintain the quality of our
         environment.  As such, the NU system and NAESCO, have an active
         environmental auditing and training program and believe they are
         substantially in compliance with the current laws and regulations.

         However, the normal course of operations may involve activities and
         substances that expose NAEC to potential liabilities of which
         management cannot determine the outcome.  Additionally, management
         cannot determine the outcome for liabilities that may be imposed for
         past acts, even though such past acts may have been lawful at the
         time they occurred.  Management does not believe, however, that this
         will have a material impact on NAEC's financial statements.

     C.  Spent Nuclear Fuel Disposal Costs
         Under the Nuclear Waste Policy Act of 1982, NAEC must pay the DOE
         for the disposal of spent nuclear fuel and high-level radioactive
         waste.  The DOE is responsible for the selection and development of
         repositories for, and the disposal of, spent nuclear fuel and high-
         level radioactive waste.  Fees for nuclear fuel burned are billed
         currently to customers and paid to the DOE on a quarterly basis.

     D.  Nuclear Insurance Contingencies
         Insurance policies covering NAEC's ownership share of Seabrook have
         been purchased for the primary cost of repair, replacement or
         decontamination of utility property and certain extra costs for
         repair, replacement or decontamination or premature decommissioning
         of utility property.

         NAEC is subject to retroactive assessments if losses under those
         policies exceed the accumulated funds available to the insurer.  The
         maximum potential assessments against NAEC, including costs resulting
         from PSNH's contracts with NAEC, with respect to losses arising during
         the current policy year for the primary property insurance program and
         the excess property damage policies are $2 million and $2.4 million,
         respectively.  In addition, insurance has been purchased by the NU
         system in the aggregate amount of $200 million on an industry basis
         for coverage of worker claims.

         Under certain circumstances, in the event of a nuclear incident at one
         of the nuclear facilities covered by the federal government's third-
         party liability indemnification program, the NU system, including
         NAEC, could be assessed liabilities in proportion to its ownership
         interest in each of its nuclear units up to $83.9 million.  The NU
         system's payment of this assessment would be limited to, in proportion
         to its ownership interest in each of its nuclear units, $10 million
         in any one year per nuclear unit.  In addition, if the sum of all
         claims and costs from any one nuclear incident exceeds the maximum
         amount of financial protection, the NU system would be subject to an
         additional 5 percent, or $4.2 million, liability, in proportion to its
         ownership interest in each of its nuclear units.  Under the terms of
         the Seabrook Power Contracts with NAEC, PSNH could be obligated to pay
         for any assessment charged to NAEC as a cost of service.  Based upon
         NAEC's ownership interest in Seabrook, PSNH's maximum liability,
         including any additional assessments, would be $31.3 million per
         incident, of which payments would be limited to $3.6 million per year.

8.   MARKET RISK AND MANAGEMENT INSTRUMENTS
     Interest Rate Risk Management:  In 2000 and 1999, NAEC used interest rate
     collar and swap instruments with financial institutions to hedge against
     interest rate risk associated with its $200 million variable-rate bank
     note.  On November 9, 2000, this facility was replaced with a fixed-rate
     bank note.  The collar and swap instruments expired and were not replaced.

     Credit Risk:  These agreements have been made with various financial
     institutions, each of which is rated "A3" or better by Moody's Investors
     Service rating group.  NAEC is exposed to credit risk on its respective
     market risk management instruments if the counterparties fail to perform
     their obligations.  Management anticipates that the counterparties will
     fully satisfy their obligations under the agreements.

9.   FAIR VALUE OF FINANCIAL INSTRUMENTS
     The following methods and assumptions were used to estimate the fair
     value of each of the following financial instruments:

     Cash and Cash Equivalents:  The carrying amounts approximate fair value
     due to the short-term nature of cash and cash equivalents.

     Nuclear Decommissioning Trust: The investments held in NAEC's nuclear
     decommissioning trust were marked-to-market by $0.1 million as of
     December 31, 2000, and by $3.2 million as of December 31, 1999, with
     corresponding offsets to the accumulated provision for depreciation.
     The amounts adjusted in 2000 and in 1999 represent cumulative net
     unrealized gains.  Cumulative gross unrealized holding losses were
     immaterial for both 2000 and 1999.

     Long-Term Debt:  The fair value of NAEC's fixed-rate security is based
     upon the quoted market price for that issue or similar issues.  The
     adjustable rate security is assumed to have a fair value equal to
     its carrying value.

     The carrying amounts of NAEC's financial instruments and the estimated
     fair values are as follows:

     --------------------------------------------------------------------------
                                                   At December 31, 2000
     --------------------------------------------------------------------------
                                                  Carrying        Fair
     (Million of Dollars)                           Amount        Value
     --------------------------------------------------------------------------
     First mortgage bonds.................         $135.0        $136.8
     --------------------------------------------------------------------------

     --------------------------------------------------------------------------
                                                   At December 31, 1999
     --------------------------------------------------------------------------
                                                  Carrying        Fair
     (Million of Dollars)                           Amount        Value
     --------------------------------------------------------------------------
     First mortgage bonds.................         $205.0        $207.8
     Other long-term debt.................         $200.0        $200.0
     --------------------------------------------------------------------------

10.  SEGMENT INFORMATION
     Effective January 1, 1999, the NU system companies, including NAEC,
     adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and
     Related Information."  The NU system is organized between regulated
     utilities and competitive energy subsidiaries.  NAEC is included in the
     regulated utilities segment of the NU system and has no other reportable
     segments.

11.  SUBSEQUENT EVENT
     Merger Agreement with Consolidated Edison, Inc.:  In 2000, NU and
     Consolidated Edison, Inc. (Con Edison) received most of the approvals
     needed to complete the merger announced in October 1999.   Shareholders
     from both companies approved the merger in April 2000, and all state
     regulatory approvals were granted by the end of the year.  Additionally,
     the FERC approved the merger in May 2000, the NRC approved the transaction
     in August 2000, and the United States Department of Justice approved the
     merger in February 2001.  Necessary approval from the SEC was expected to
     be received in mid-March 2001.

     On February 28, 2001, NU's Board of Trustees requested that Con Edison
     provide reasonable assurance, in writing, that it intended to comply with
     the terms of the definitive merger agreement between the two companies.
     This included assurances that Con Edison would consummate the pending
     merger at the price set forth in the agreement promptly following the
     receipt of SEC approval.  The original request for assurance was to be
     received by March 2, 2001, however that date was later extended to
     March 5, 2001.  On March 5, 2001, Con Edison advised NU that it was not
     willing to close the merger on the agreed terms.  NU notified Con Edison
     that it was treating its refusal to proceed on the terms set forth in the
     merger agreement as a repudiation and breach of the merger agreement, and
     that NU would file suit to obtain the benefits of the transaction as
     negotiated for NU shareholders.  On March 6, 2001, Con Edison filed suit
     in the U.S. District Court for the Southern District of New York (Southern
     District), seeking a declaratory judgment that NU failed to satisfy
     conditions precedent under the merger agreement.  On March 12, 2001, NU
     filed suit against Con Edison in the Southern District seeking damages in
     excess of $1 billion arising from Con Edison's breach of the merger
     agreement.


<TABLE>
North Atlantic Energy Corporation
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
SELECTED FINANCIAL DATA                    2000         1999          1998          1997          1996
- ----------------------------------------------------------------------------------------------------------
                                                              (Thousands of Dollars)
<S>                                      <C>          <C>           <C>          <C>           <C>
Operating Revenues..................     $274,319     $287,369      $276,685     $  192,381    $  162,152

Operating Income....................       44,077       49,728        54,057         57,061        54,889

Net Income..........................       32,493       29,556        29,494         29,953        32,072

Cash Dividends on Common Stock......       42,000       60,000        45,000         25,000        38,000

Total Assets........................      728,964      852,107       945,153      1,014,639     1,017,388

Long-Term Debt (a)..................      135,000      405,000       475,000        495,000       515,000
- ----------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
QUARTERLY FINANCIAL DATA (Unaudited)
- ------------------------------------------------------------------------------------------------
                                                      Quarter Ended
- ------------------------------------------------------------------------------------------------
2000                           March 31        June 30        September 30         December 31
- ------------------------------------------------------------------------------------------------
                                                  (Thousands of Dollars)
<S>                            <C>             <C>               <C>                 <C>
Operating Revenues             $66,276         $66,106           $66,921             $75,016
                               =======         =======           =======             =======

Operating Income               $11,657         $11,185           $10,470             $10,765
                               =======         =======           =======             =======

Net Income                     $ 7,753         $ 8,272           $ 8,063             $ 8,405
                               =======         =======           =======             =======
- ------------------------------------------------------------------------------------------------
1999
- ------------------------------------------------------------------------------------------------

Operating Revenues             $70,289         $77,203           $69,779             $70,098
                               =======         =======           =======             =======

Operating Income               $12,475         $12,303           $12,122             $12,828
                               =======         =======           =======             =======

Net Income                     $ 6,461         $ 6,243           $ 6,442             $10,410
                               =======         =======           =======             =======
</TABLE>

<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
STATISTICS (Unaudited)          2000         1999        1998         1997         1996
- -----------------------------------------------------------------------------------------
<S>                          <C>          <C>          <C>          <C>          <C>
Gross Electric Utility
  Plant at December 31,
  (Thousands of Dollars)     $756,432     $767,895     $784,113     $811,140     $816,446
                             ========     ========     ========     ========     ========
kWh Sales (Millions) for
  the year ended
  December 31,                  2,850        3,125        3,018        2,859        3,542
                             ========     ========     ========     ========     ========

(a) Includes portion due within one year.

</TABLE>

</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
-----END PRIVACY-ENHANCED MESSAGE-----
