<SUBMISSION>
<ACCESSION-NUMBER>0000929624-01-500037
<TYPE>10-K
<PUBLIC-DOCUMENT-COUNT>37
<PERIOD>20001231
<FILING-DATE>20010417
<FILER>
<COMPANY-DATA>
<CONFORMED-NAME>PG&E CORP
<CIK>0001004980
<ASSIGNED-SIC>4931
<IRS-NUMBER>943234914
<STATE-OF-INCORPORATION>CA
<FISCAL-YEAR-END>1231
</COMPANY-DATA>
<FILING-VALUES>
<FORM-TYPE>10-K
<ACT>34
<FILE-NUMBER>001-12609
<FILM-NUMBER>1603808
</FILING-VALUES>
<BUSINESS-ADDRESS>
<STREET1>ONE MARKET SPEAR TOWER
<STREET2>SUITE 2400
<CITY>SAN FRANCISCO
<STATE>CA
<ZIP>94105
<PHONE>4152677000
</BUSINESS-ADDRESS>
<MAIL-ADDRESS>
<STREET1>ONE MARKET SPEAR TOWER
<STREET2>SUITE 2400
<CITY>SAN FRANCISCO
<STATE>CA
<ZIP>94105
</MAIL-ADDRESS>
<FORMER-COMPANY>
<FORMER-CONFORMED-NAME>PG&E PARENT CO INC
<DATE-CHANGED>19951214
</FORMER-COMPANY>
</FILER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>d10k.txt
<DESCRIPTION>FORM 10-K FOR THE PERIOD ENDED 12/31/2000
<TEXT>

<PAGE>

                      SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C. 20549
                                   FORM 10-K
(Mark One)
  [X]          ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                      THE SECURITIES EXCHANGE ACT OF 1934
                  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
                   For the transition period from     to

<TABLE>
<CAPTION>
                                                                      IRS Employer
    Commission         Exact Name of Registrant          State of    Identification
    File Number      as specified in its charter       Incorporation     Number
    -----------      ---------------------------       ------------- --------------
    <C>         <S>                                    <C>           <C>
    1-12609     PG&E CORPORATION                        California     94-3234914
    1-2348      PACIFIC GAS AND ELECTRIC COMPANY        California     94-0742640
</TABLE>

   Pacific Gas and Electric Company               PG&E Corporation
            77 Beale Street                    One Market, Spear Tower
            P.O. Box 770000                          Suite 2400
       San Francisco, California              San Francisco, California
    (Address of principal executive        (Address of principal executive
               offices)                               offices)


                 94177                                  94105
              (Zip Code)                             (Zip Code)


            (415) 973-7000                         (415) 267-7000
    (Registrant's telephone number,        (Registrant's telephone number,
         including area code)                   including area code)

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

<TABLE>
<CAPTION>
                                                        Name of Each Exchange on
    Title of Each Class                                     Which Registered
    -------------------                                ---------------------------
    <S>                                                <C>
    PG&E Corporation
    Common Stock, no par value                         New York Stock Exchange and
    Preferred Stock Purchase Rights                    Pacific Exchange

    Pacific Gas and Electric Company
    First Preferred Stock, cumulative,                 American Stock Exchange and
     par value $25 per share:                          Pacific Exchange
      Redeemable: 7.04%, 5% Series A, 5%, 4.80%,
       4.50%, 4.36%
      Mandatorily Redeemable: 6.57%, 6.30%
      Nonredeemable: 6%, 5.50%, 5%
    7.90% Cumulative Quarterly Income Preferred        American Stock Exchange and
     Securities, Series A (liquidation preference      Pacific Exchange
     $25), issued by PG&E Capital I and guaranteed by
     Pacific Gas and Electric Company
</TABLE>

       Securities registered pursuant to Section 12(g) of the Act: None

  Indicate by check mark whether the registrant (1) has 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
registrant was required to file such reports), and (2) has 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 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. [_]

Aggregate market value of the voting common equity held by non-affiliates of
the registrant as of April 9, 2001:
   PG&E Corporation Common Stock                          $2,505 million

Common Stock outstanding as of April 9, 2001:
   PG&E Corporation:                                    387,137,690 (inc
   Pacific Gas and Electric Company:                    shares held by sub)
                                              Wholly owned by PG&E Corporation

  The market values of certain series of First Preferred Stock, for which
market prices as of a date within 60 days prior to the date of filing were not
available, were derived by dividing the annual dividend rate of each such
series of stock by the average yield of all of Pacific Gas and Electric
Company's Preferred Stock outstanding for which market prices were available.

                      DOCUMENTS INCORPORATED BY REFERENCE
  Portions of the documents listed below have been incorporated by reference
into the indicated parts of this report, as specified in the responses to the
item numbers involved.

<TABLE>
<S>                                                         <C>
(1) Designated portions of the combined Annual Report to
    Shareholders for the year ended December 31, 2000.....  Part I (Item 1), Part II (Items 5, 6, 7, 7A, and 8),
                                                            Part IV (Item 14)
(2) Designated portions of the Joint Proxy Statement
    relating to the 2001 Annual Meetings of Shareholders..  Part III (Items 10, 11, 12, and 13)
</TABLE>
<PAGE>

                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                        Page
                                                                        ----
 <C>     <S>                                                            <C>
         Glossary of Terms...........................................    iv

                                    PART I

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

         GENERAL.....................................................     1
         Corporate Structure and Business............................     1
         Competition and the Changing Regulatory Environment.........     3
          The Electric Industry......................................     3
          The Natural Gas Industry...................................     4
         Regulation of PG&E Corporation..............................     5
         Regulation of Pacific Gas and Electric Company..............     6
          Federal Regulation.........................................     6
          State Regulation...........................................     6
          Licenses and Permits.......................................     6
         Regulation of PG&E National Energy Group, Inc. Businesses...     7
          Federal Regulation.........................................     7
          State and Other Regulation.................................     7

         UTILITY OPERATIONS..........................................     9
         Ratemaking Mechanisms.......................................     9
            General Rate Case........................................     9
            Cost of Capital..........................................     9
            Electric and Gas Distribution Performance-Based
            Ratemaking (PBR).........................................     9
          Electric Ratemaking........................................    10
            Rate Stabilization Plan Proceeding.......................    10
            General Rate Case........................................    11
            2001 Attrition Rate Adjustment Request...................    12
            Revenue Adjustment Proceeding............................    12
            Annual Transition Cost Proceeding........................    12
            Electric Industry Restructuring Implementation Costs.....    13
            Electric Restructuring Costs Account (ERCA)..............    13
            Revenues from Must-Run Contracts.........................    13
            FERC Transmission Owner Rate Case........................    13
            AB 1890 Electric Base Revenue Increase...................    14
            Electric Transmission Rates..............................    14
            Post-Transition Period Ratemaking Proceeding.............    14
          Gas Ratemaking.............................................    15
            Gas Accord...............................................    15
            General Rate Case........................................    15
            Gas Procurement Costs....................................    15
            The Biennial Cost Allocation Proceeding (BCAP)...........    15
         Public Purpose Programs.....................................    16
         Electric Utility Operations.................................    16
          Electric Industry Restructuring............................    16
            California Power Crisis..................................    17
            FERC Order...............................................    17
            The California Independent System Operator and the
            California Power Exchange................................    18
            New California Legislation...............................    19
</TABLE>

                                       i
<PAGE>

<TABLE>
<CAPTION>
                                                                        Page
                                                                        ----
 <C>     <S>                                                            <C>
            Recovery of Transition Costs, Wholesale Power Purchase
            Costs, and End of Rate Freeze............................    20
            Retail Direct Access.....................................    21
         Electric Operating Statistics...............................    23
         Electric Resources..........................................    24
         Generating Capacity.........................................    24
          Hydroelectric Generation Assets............................    25
          Diablo Canyon Nuclear Power Plant..........................    25
            Diablo Canyon Ratemaking.................................    26
            Nuclear Fuel Supply and Disposal.........................    26
            Insurance................................................    27
            Decommissioning..........................................    27
         Other Electric Resources....................................    28
            QF Generation and Other Power Purchase Contracts.........    28
            Bilateral Agreements.....................................    30
          Electric Transmission and Distribution.....................    30
         Gas Utility Operations......................................    32
          Gas Operating Statistics...................................    33
         Natural Gas Supplies........................................    34
         Gas Regulatory Framework....................................    35
         Transportation Commitments..................................    36

         PG&E NATIONAL ENERGY GROUP, INC. ...........................    36
         Integrated Power Generation, and Energy Trading and
         Marketing Business..........................................    37
          Ownership and Operation of Generating Facilities...........    37
          New Power Plant Development and Construction...............    37
          Contractual Control of Generating Capacity.................    38
          Energy Marketing and Trading...............................    38
          Description of Generating Facilities.......................    41
          Competition................................................    42
         Natural Gas Transmission Business...........................    42
            PG&E GT-Northwest (PG&E GTN).............................    42
            North Baja Pipeline......................................    43
            Competition..............................................    43

         ENVIRONMENTAL MATTERS.......................................    45
         Environmental Matters.......................................    45
          Environmental Protection Measures..........................    45
          Air Quality................................................    45
          Water Quality..............................................    47
          Hazardous Waste Compliance and Remediation.................    48
          Potential Recovery of Hazardous Waste Compliance and
          Remediation Costs..........................................    49
          Compressor Station Litigation..............................    50
          Electric and Magnetic Fields...............................    50
          Low Emission Vehicle Programs..............................    51
 Item 2. Properties..................................................    52
 Item 3. Legal Proceedings...........................................    52
         Pacific Gas and Electric Company Bankruptcy.................    52
         Pacific Gas and Electric Company vs. California Public
         Utilities Commissioners.....................................    52
         Wilson vs. PG&E Corporation and Pacific Gas and Electric
         Company.....................................................    52
         Moss Landing Power Plant....................................    53
</TABLE>


                                       ii
<PAGE>

<TABLE>
<CAPTION>
                                                                          Page
                                                                          ----
 <C>      <S>                                                             <C>
          Compressor Station Chromium Litigation........................   54
          Texas Franchise Fee Litigation................................   55
 Item 4.  Submission of Matters to a Vote of Security Holders...........   55

          EXECUTIVE OFFICERS OF THE REGISTRANTS.........................   56

                                      PART II

 Item 5.  Market for the Registrant's Common Equity and Related
          Stockholder Matters...........................................   59
 Item 6.  Selected Financial Data.......................................   59
 Item 7.  Management's Discussion and Analysis of Financial Condition
          and Results of Operations.....................................   59
 Item 7A. Quantitative and Qualitative Disclosures About Market Risk....   59
 Item 8.  Financial Statements and Supplementary Data...................   59
          Changes in and Disagreements with Accountants on Accounting
 Item 9.  and Financial Disclosure......................................   60

                                     PART III

 Item 10. Directors and Executive Officers of the Registrant............   60
 Item 11. Executive Compensation........................................   60
 Item 12. Security Ownership of Certain Beneficial Owners and
          Management....................................................   60
 Item 13. Certain Relationships and Related Transactions................   60

                                      PART IV

 Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
          8-K...........................................................   61
          Signatures....................................................   68
          Independent Auditors' Report (Deloitte & Touche LLP)..........   69
          Report of Independent Public Accountants (Arthur Andersen
          LLP)..........................................................   70
          Report of Independent Public Accountants (Arthur Andersen
          LLP)..........................................................   71
</TABLE>

                                      iii
<PAGE>

                               GLOSSARY OF TERMS

<TABLE>
 <C>                             <S>
 AB 1890........................ Assembly Bill 1890, the California electric
                                  industry restructuring legislation
 AEAP........................... Annual Earnings Assessment Proceeding
 Alstom......................... Alstom Power, Inc.
 ATCP........................... Annual Transition Cost Proceeding
 BCAP........................... Biennial Cost Allocation Proceeding
 bcf............................ billion cubic feet
 Betz........................... Betz Chemical Company
 BFM............................ block forward market
 BRPU........................... Biennial Resource Plan Update
 BTA............................ best technology available
 Btu............................ British thermal unit
 CARE........................... California Alternate Rates for Energy
 CCAA........................... California Clean Air Act
 CEC............................ California Energy Commission
 CEMA........................... Catastrophic Event Memorandum Account
 Central Coast Board............ Central Coast Regional Water Quality Control
                                  Board
 CEQA........................... California Environmental Quality Act
 CERCLA......................... Comprehensive Environmental Response,
                                  Compensation, and Liability Act
 CFCA........................... Core Fixed Cost Account
 CLF............................ Conservation Law Foundation
 core customers................. residential and smaller commercial gas
                                  customers
 core subscription customers.... noncore customers who choose bundled service
 CPA............................ California Procurement Adjustment
 CPIM........................... core procurement incentive mechanism
 CPUC........................... California Public Utilities Commission
 CTC............................ competition transition charge
 Diablo Canyon.................. Diablo Canyon Nuclear Power Plant
 DOE............................ United States Department of Energy
 DSM............................ demand side management
 DWR............................ California Department of Water Resources
 EDRA........................... Electric Deferred Refund Account
 EIR............................ environmental impact report
 EMF............................ electric and magnetic fields
 EPA............................ United States Environmental Protection Agency
 ERCA........................... Electric Restructuring Costs Account
 ESP............................ energy service provider
 EWG............................ exempt wholesale generator
 FERC........................... Federal Energy Regulatory Commission
 GABA........................... Generation Asset Balancing Account
 Gas Accord..................... Gas Accord Settlement
 GRC............................ General Rate Case
 PG&E GTN....................... PG&E Gas Transmission, Northwest Corporation,
                                  formerly known as Pacific Gas Transmission
                                  Company
 PG&E GTN Expansion............. PG&E Gas Transmission, Northwest
                                  Corporation's portion of the Pipeline
                                  Expansion
 Holding Company Act............ Public Utility Holding Company Act of 1935
 Humboldt....................... Humboldt Bay Power Plant
 HWRC........................... hazardous waste remediation costs
</TABLE>

                                       iv
<PAGE>

                         GLOSSARY OF TERMS--(Continued)

<TABLE>
 <C>                             <S>
 ICIP........................... Incremental Cost Incentive Price
 IPP............................ independent power producer
 ISO............................ Independent System Operator
 kV............................. kilovolts
 kVa............................ kilovolt-amperes
 kW............................. kilowatts
 LEV............................ low emission vehicle
 LIEE........................... Low-Income Energy Efficiency
 Mcf............................ thousand cubic feet
 MDt............................ thousand decatherms
 MMcf........................... million cubic feet
 MMcf/d......................... million cubic feet per day
 MW............................. megawatts
 MWh............................ megawatt-hour
 NEES........................... New England Electric System
 NEIL........................... Nuclear Electric Insurance Limited
 NGL............................ natural gas liquids
 NOI............................ Notice of Intent
 noncore customers.............. industrial and larger commercial gas
                                  customers
 NOx............................ oxides of nitrogen
 NPDES.......................... National Pollutant Discharge Elimination
                                  System
 NRC............................ Nuclear Regulatory Commission
 NTP&S.......................... non-tariffed products and services
 Nuclear Waste Act.............. Nuclear Waste Policy Act of 1982
 ORA............................ Office of Ratepayer Advocates, a division of
                                  the California Public Utilities Commission
 PBR............................ performance-based ratemaking
 PECA........................... Purchased Electric Commodity Account
 PGA............................ Purchased Gas Account
 PG&E Expansion................. the Pacific Gas and Electric Company portion
                                  of the Pipeline Expansion
 PG&E ET........................ PG&E Corporation's energy commodities
                                  activities, PG&E Energy Trading or PG&E ET
 PG&E ES........................ PG&E Corporation's energy services
                                  operations, PG&E Energy Services or PG&E ES
 PG&E Gen....................... PG&E Generating Company, LLC and its
                                  affiliates
 PG&E GT........................ PG&E Corporation's gas transmission
                                  operations, PG&E Gas Transmission or PG&E GT
 PG&E GTT....................... PG&E Gas Transmission, Texas Corporation
 PG&E OSC....................... PG&E Operating Services Company
 Pipeline Expansion............. PG&E GT NW/PG&E Pipeline Expansion
 PPPs........................... public purpose programs
 Price Act...................... Price Anderson Act
 PRP............................ potentially responsible party
 PTO............................ Participating Transmission Owner
 PURPA.......................... Public Utility Regulatory Policies Act of
                                  1978
 PVC............................ Pacific Venture Capital, LLC
 PX............................. California Power Exchange
 PY............................. Program Year
 QF............................. qualifying facility
</TABLE>

                                       v
<PAGE>

                         GLOSSARY OF TERMS--(Continued)

<TABLE>
<S>                             <C>
RAP............................ Revenue Adjustment Proceeding
RCRA........................... Resource Conservation and Resource Act
RMR............................ reliability must-run
ROE............................ return on common equity
ROR............................ rate of return
RSP............................ Rate Stabilization Plan
RTO............................ regional transmission organization
SEC............................ Securities and Exchange Commission
SCS............................ Scheduled Coordinator Services
SO2............................ sulfur dioxide
SoCal Gas...................... Southern California Gas Company
SPE............................ special purpose entity
SRAC........................... short-run avoided costs
TAC............................ Transmission Access Charge
TCBA........................... Transition Cost Balancing Account
throughput..................... the amount of natural gas transported through a pipeline system
TRA............................ Transition Revenue Account
TRBA........................... Transition Revenue Balancing Account
Transwestern................... Transwestern Pipeline Company
TURN........................... The Utility Reform Network
USGenNE........................ USGen New England, Inc.
</TABLE>

                                       vi
<PAGE>

                                    PART I

ITEM 1. Business.

                                    GENERAL

Corporate Structure and Business

   PG&E Corporation is an energy-based holding company headquartered in San
Francisco, California. Effective January 1, 1997, Pacific Gas and Electric
Company (sometimes referred to herein as the "Utility") and its subsidiaries
became subsidiaries of PG&E Corporation, which was incorporated in 1995.
Pacific Gas and Electric Company, incorporated in California in 1905, is an
operating public utility engaged principally in the business of providing
electricity and natural gas distribution and transmission services throughout
most of Northern and Central California. The Utility is primarily regulated by
the California Public Utilities Commission (CPUC) and the Federal Energy
Regulatory Commission (FERC). In the holding company reorganization, Pacific
Gas and Electric Company's outstanding common stock was converted on a share-
for-share basis into PG&E Corporation common stock. Pacific Gas and Electric
Company's debt securities and preferred stock were unaffected and remain
securities of Pacific Gas and Electric Company.

   On April 6, 2001, Pacific Gas and Electric Company filed a voluntary
petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy
Code in the U.S. Bankruptcy Court for the Northern District of California.
Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains
control of its assets and is authorized to operate its business as a debtor in
possession while being subject to the jurisdiction of the bankruptcy court.
The factors causing the Utility to take this action are discussed in
"Management's Discussion and Analysis" and in Notes 2 and 3 of the "Notes to
the Consolidated Financial Statements," appearing in the PG&E Corporation and
Pacific Gas and Electric Company combined 2000 Annual Report to Shareholders,
which information is incorporated by reference into this report.

   The consolidated financial statements of PG&E Corporation incorporated
herein include the accounts of PG&E Corporation and its wholly owned and
controlled subsidiaries (collectively, PG&E Corporation). The consolidated
financial statements of Pacific Gas and Electric Company incorporated herein
include the accounts of Pacific Gas and Electric Company and its wholly owned
and controlled subsidiaries.

   The principal executive offices of PG&E Corporation are located at One
Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its
telephone number is (415) 267-7000. The principal executive offices of Pacific
Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San
Francisco, California 94177, and its telephone number is (415) 973-7000.

   PG&E Corporation's subsidiary, PG&E National Energy Group, Inc. (NEG), is
an integrated energy company with a strategic focus on power generation, new
power plant development, natural gas transmission, and wholesale energy
marketing and trading in North America. NEG businesses include its power plant
development and generation unit, PG&E Generating Company, LLC and its
affiliates (collectively, PG&E Gen); its natural gas transmission unit, PG&E
Gas Transmission Corporation (PG&E GT); and its wholesale energy and marketing
trading unit, PG&E Energy Trading Holdings Corporation, which owns PG&E Energy
Trading--Gas Corporation, and PG&E Energy Trading--Power, L.P. (collectively,
PG&E Energy Trading or PG&E ET). During 2000, NEG sold its energy services
unit, PG&E Energy Services Corporation. Also, during 2000, NEG sold its Texas
natural gas and natural gas liquids business carried on through PG&E Gas
Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their
subsidiaries (PG&E GTT). For more information about NEG's businesses, see
"PG&E National Energy Group, Inc." below.

   In December 2000, and in January and February 2001, PG&E Corporation and
NEG undertook a corporate restructuring of NEG, known as a "ringfencing"
transaction. The ringfencing complied with credit rating agency criteria
enabling NEG, PG&E Gas Transmission, Northwest Corporation (PG&E GTN), and
PG&E ET to receive

                                       1
<PAGE>

or retain their own credit ratings based on their own creditworthiness. The
ringfencing involved the creation or use of special purpose entities (SPEs) as
intermediate owners between PG&E Corporation and its non-CPUC regulated
subsidiaries. These SPEs are: PG&E National Energy Group, LLC which owns 100%
of the stock of NEG, PG&E GTN Holdings LLC which owns 100% of the stock of PG&E
GTN, and PG&E Energy Trading Holdings LLC which owns 100% of the stock of PG&E
Energy Trading Holdings Corporation. In addition, in March 2001, NEG's
organizational documents were modified to include the same structural elements
as the SPEs to meet credit rating agency criteria. Ringfencing is intended to
reduce further the likelihood that the assets of the ringfenced companies would
be substantively consolidated in a bankruptcy proceeding involving such
companies' ultimate parent, and to thereby preserve the value of the
"protected" entities as a whole. The SPEs require unanimous approval of their
respective boards of directors, including at least one independent director,
before they can (a) consolidate or merge with any entity, (b) transfer
substantially all of their assets to any entity, or (c) institute or consent to
bankruptcy, insolvency, or similar proceedings or actions. The SPEs may not
declare or pay dividends unless unanimously approved by the SPE's board of
directors and the company meets specified financial requirements.

   PG&E Corporation has identified four reportable operating segments. The
Utility is one reportable operating segment and the other three are part of NEG
(PG&E Gen, PG&E GT, and PG&E ET). Financial information about each reportable
operating segment is provided in "Management's Discussion and Analysis" in the
2000 Annual Report to Shareholders and in Note 16 of the "Notes to Consolidated
Financial Statements" beginning on page 86 of the 2000 Annual Report to
Shareholders, which information is incorporated by reference into this report.

   As of December 31, 2000, PG&E Corporation had $35.3 billion in assets. Of
this amount, Pacific Gas and Electric Company had $22 billion in assets. PG&E
Corporation generated $26.2 billion in operating revenues for 2000. Of this
amount, the Utility generated $9.6 billion in operating revenues for 2000. As
of December 31, 2000, PG&E Corporation and its subsidiaries and affiliates had
20,850 employees (including 18,393 employees of the Utility).

   The following report includes forward-looking statements about the future
that are necessarily subject to various risks and uncertainties. These
statements are based on current expectations and assumptions which management
believes are reasonable and on information currently available to management.
These forward-looking statements are identified by words such as "estimates,"
"expects," "anticipates," "plans," "believes," and other similar expressions.
Actual results could differ materially from those contemplated by the forward-
looking statements. Although PG&E Corporation and the Utility are not able to
predict all the factors that may affect future results, some of the factors
that could cause future results to differ materially from those expressed or
implied by the forward-looking statements include:

  . the reorganization plan that is ultimately adopted by the bankruptcy
    court;

  . the regulatory, judicial, or legislative actions (including future ballot
    initiatives) that may be taken to meet future power needs, mitigate the
    higher wholesale power prices, provide refunds for prior power costs, or
    address the Utility's financial condition;

  . the extent to which the Utility's undercollected wholesale power purchase
    costs may be collected from customers;

  . any changes in the amount of transition costs the Utility is allowed to
    collect from its customers, and the timing of the completion of the
    Utility's transition cost recovery;

  . future market prices for electricity and future fuel prices which, in
    part, are influenced by future weather conditions, the availability of
    hydroelectric power, and the development of competitive markets;

  . the method and timing of valuation of the Utility's hydroelectric
    generation assets;

  . future operating performance at the Diablo Canyon Nuclear Power Plant
    (Diablo Canyon) and the future ratemaking applicable to Diablo Canyon;

                                       2
<PAGE>

  . legislative or regulatory changes, including the pace and extent of the
    ongoing restructuring of the electric and natural gas industries across
    the United States;

  . future sales levels and economic conditions;

  . the extent to which NEG's current or planned generation development
    projects are completed and the pace and cost of such completion;

  . generating capacity expansion and retirements by others;

  . the outcome of the Utility's various regulatory proceedings;

  . fluctuations in commodity gas, natural gas liquids, and electric prices
    and the ability to successfully manage such price fluctuations;

  . the effect of compliance with existing and future environmental laws,
    regulations, and policies, the cost of which could be significant; and

  . the outcome of pending litigation.

   As the ultimate impact of these and other factors is uncertain, these and
other factors may cause future earnings to differ materially from results or
outcomes currently sought or expected.

Competition and the Changing Regulatory Environment

   Historically, energy utilities operated as regulated monopolies within
specific service territories where they were essentially the sole suppliers of
natural gas and electricity services. Under this model, the energy utilities
owned and operated all of the businesses necessary to procure, generate,
transport, and distribute energy. These services were priced on a combined
(bundled) basis, with rates charged by the energy companies designed to
include all of the costs of providing these services. Under traditional
regulation, utilities were provided the opportunity to earn a fair return on
their invested capital in exchange for a commitment to serve all customers
within a designated service territory. The objective of this regulatory policy
was to provide universal access to safe and reliable utility services.
Regulation was designed in part to take the place of competition and ensure
that these services were provided at fair prices. In recent years, energy
utilities faced intensifying pressures to "unbundle," or price separately,
those activities that are no longer considered natural monopoly services. The
most significant of these services are electricity generation and natural gas
supply.

   The driving forces behind these competitive pressures have been customers
who believe they can obtain energy at lower unit prices and competitors who
want access to those customers. Regulators and legislators responded to those
customers and competitors by providing for more competition in the energy
industry. Regulators and legislators required utilities to "unbundle" rates
(separate their various energy services and the prices of those services) and
to sell their electric generation facilities to outside parties. This was
intended to allow customers to compare unit prices of the utilities and other
providers when selecting their energy service provider.

   The Electric Industry. In 1998, California became one of the first states
in the country to implement electric industry restructuring with the goal of
establishing a competitive market framework for electric generation. The
framework for electric industry restructuring was established in Assembly Bill
1890 (AB 1890) passed by the California Legislature and signed by the Governor
in 1996 which turned over operation of the state's transmission system to the
California Independent System Operator (ISO) and the pricing of unregulated
generation to the California Power Exchange (PX). Californians were given the
choice to purchase electricity from generation providers other than the
traditional utilities (such as unregulated power generators and unregulated
retail electricity suppliers such as marketers, brokers, and aggregators). For
those customers who have not chosen an alternative generation provider,
investor-owned utilities, such as Pacific Gas and Electric Company, were to
continue to purchase electric power on their behalf. Investor-owned utilities
continue to provide distribution services to substantially all customers
within their service territories, including those customers who choose an
alternative generation provider.

                                       3
<PAGE>

   Beginning in June 2000, the wholesale price of electric power in California
has steadily increased, reflecting a dysfunctional wholesale power market.
Under AB 1890, the Utility's electric rates were frozen at levels insufficient
to recover the Utility's cost of purchasing power for its customers. Further,
the Utility was required to buy all the power it needed to serve its customers
from the PX. The combination of these factors created a financial crisis for
the Utility and its parent, PG&E Corporation. The Utility's undercollected
power purchase costs grew to $6.6 billion at December 31, 2000. As the
Utility's creditworthiness deteriorated, the Utility was unable to continue
financing these purchases. Federal and state legislators and regulators have
recognized that the wholesale power market is seriously flawed and have been
seeking solutions to the California electricity crisis. On January 19, 2001,
the California Legislature passed and the Governor signed Senate Bill 7X which
authorized the California Department of Water Resources (DWR) to purchase
electric power for the retail end use customers of California's investor-owned
utilities through January 31, 2001. On February 1, 2001, the California
Governor signed Assembly Bill 1 (AB 1X) which was passed by the California
Legislature during a special session to take effect immediately as an urgency
statute. AB 1X authorizes the DWR to purchase power and sell that power
directly to the utilities' retail end use customers. For more information
about California electric industry restructuring, see "Utility Operations--
Electric Utility Operations--California Electric Industry Restructuring"
below.

   As of December 31, 2000, 24 other states had enacted electric industry
restructuring legislation or issued comprehensive regulatory orders, including
Texas, Illinois, Pennsylvania, New Jersey, Massachusetts, Rhode Island, New
York, and Connecticut.

   In October 1999, the CPUC issued a decision outlining how the CPUC, in
cooperation with other regulatory agencies and the California Legislature,
plans to address the issues surrounding distributed generation, electric
distribution competition, and the role of the utility distribution companies
(such as Pacific Gas and Electric Company) in the competitive retail
electricity market. Distributed generation enables siting of electric
generation technologies in proximity to electric load (load is a measure of
electric power consumed over time). The CPUC decision opened a new rulemaking
proceeding to examine various issues concerning distributed generation,
including interconnection issues, who can own and operate distributed
generation, environmental impacts, the role of utility distribution companies,
and the rate design and cost allocation issues associated with the deployment
of distributed generation facilities. In July 2000, the CPUC's Division of
Strategic Planning and the CPUC's Energy Division issued a report on electric
retail markets and distribution services as required by the October 1999
decision. The report proposed that if the CPUC chooses to consider expanding
or consolidating competition in the electric industry, the CPUC should (a)
separately identify utility services and establish cost-based rates for these
services, (b) consider allowing providers of billing and metering services to
market directly to customers, (c) consider allowing multiple providers of
default service, and (d) investigate whether to allow competition in certain
aspects of distribution services that utilities currently perform. There is
currently no active proceeding on electric distribution and the role of
utility distribution companies.

   The Natural Gas Industry. Restructuring of the natural gas industry on both
the national and the state level has given choices to California utility
customers to meet their gas supply needs. FERC Order 636 issued in 1992
required interstate pipeline companies to divide their services into separate
gas commodity sales, transportation, and storage services. Under Order 636,
interstate gas pipelines must provide transportation service regardless of
whether the customer (often a local gas distribution company) buys the gas
commodity from the pipeline.

   In August 1997, the CPUC approved the Gas Accord settlement agreement (Gas
Accord) which restructured the Utility's gas services and its role in the gas
market. Among other matters, the Gas Accord separated, or "unbundled," the
rates for the Utility's gas transmission services from its distribution
services. As a result, the Utility's customers may buy gas directly from
competing suppliers and purchase transmission-only and distribution-only
services from the Utility. Most of the Utility's industrial and larger
commercial customers (noncore customers) now purchase their gas from marketers
and brokers. Substantially all residential and smaller

                                       4
<PAGE>

commercial customers (core customers) buy gas as well as transmission and
distribution services from the Utility as a bundled service. For more
information about the Gas Accord and regulatory changes affecting the
California natural gas industry, see "Utility Operations--Gas Utility
Operations--Gas Regulatory Framework" below.

Regulation of PG&E Corporation

   PG&E Corporation and its subsidiaries are exempt from all provisions,
except Section 9(a)(2), of the Public Utility Holding Company Act of 1935
(Holding Company Act). At present, PG&E Corporation has no expectation of
becoming a registered holding company under the Holding Company Act.

   PG&E Corporation is not a public utility under the laws of California and
is not subject to regulation as such by the CPUC. However, the CPUC approval
authorizing Pacific Gas and Electric Company to form a holding company was
granted subject to various conditions related to finance, human resources,
records and bookkeeping, and the transfer of customer information. The
financial conditions provide that the Utility is precluded from guaranteeing
any obligations of PG&E Corporation without prior written consent from the
CPUC, the Utility's dividend policy shall continue to be established by the
Utility's Board of Directors as though Pacific Gas and Electric Company were a
stand-alone utility company, and the capital requirements of the Utility, as
determined to be necessary to meet the Utility's service obligations, shall be
given first priority by the Boards of Directors of PG&E Corporation and
Pacific Gas and Electric Company. The conditions also provide that the Utility
shall maintain on average its CPUC-authorized utility capital structure,
although it shall have an opportunity to request a waiver of this condition if
an adverse financial event reduces the Utility's equity ratio by 1% or more.

   The CPUC also has adopted complex and detailed rules governing transactions
between California's natural gas local distribution and electric utility
companies and their non-regulated affiliates. The rules permit non-regulated
affiliates of regulated utilities to compete in the affiliated utility's
service territory, and also to use the name and logo of their affiliated
utility, provided that in California the affiliate includes certain designated
disclaimer language which emphasizes the separateness of the entities and that
the affiliate is not regulated by the CPUC. The rules also address the
separation of regulated utilities and their non-regulated affiliates and
information exchange among the affiliates. The rules prohibit the utilities
from engaging in certain practices that would discriminate against energy
service providers that compete with the utility's non-regulated affiliates.
The CPUC has also established specific penalties and enforcement procedures
for affiliate rules violations. Utilities are required to self-report
affiliate rules violations.

   In connection with the Utility's November 2000 request for an emergency
rate increase, the CPUC ordered that an audit be performed. On January 31,
2001, the CPUC released the report of its consultant of the overall financial
position of the Utility, PG&E Corporation, its other affiliates, and the flow
of funds between these entities and the Utility. The report covers credit and
default relationships, power purchases and cash flows, cash conservation
activities, accounting mechanisms to track stranded cost recovery, inter-
company cash flows, affiliate earnings in the California energy market, and
other matters.

   On April 3, 2001, the CPUC issued an order instituting an investigation
into whether the California investor-owned utilities, including the Utility,
have complied with past CPUC decisions, rules, or orders authorizing their
holding company formations and/or governing affiliate transactions, as well as
applicable statutes. The order states that the CPUC will investigate (1) the
utilities' transfer of money to their holding companies since deregulation of
the electric industry commenced, including times when their utility
subsidiaries were experiencing financial difficulties, (2) the failure of the
holding companies to financially assist the utilities when needed; (3) the
transfer by the holding companies of assets to unregulated subsidiaries; and
(4) the holding companies' actions to "ringfence" their unregulated
subsidiaries. The CPUC will also determine whether additional rules,
conditions, or changes are needed to adequately protect ratepayers and the
public from dangers of abuse stemming from the holding company structure. The
CPUC will investigate whether it should modify, change, or add conditions to
the holding company decisions, make further changes to the holding company
structure, alter the standards under which the CPUC determines whether to
authorize the formation of holding

                                       5
<PAGE>

companies, otherwise modify the decisions, or recommend statutory changes to
the California Legislature. As a result of the investigation, the CPUC may
impose remedies (including penalties), prospective rules, or conditions, as
appropriate. PG&E Corporation and the Utility believe that they have complied
with applicable statutes, CPUC decisions, rules, and orders. As described
above, on April 6, 2001, the Utility filed a voluntary petition for relief
under Chapter 11 of the U.S. Bankruptcy Code. PG&E Corporation and the Utility
believe that to the extent the CPUC seeks to investigate past conduct for
compliance purposes, the investigation is automatically stayed by the
bankruptcy filing. Neither the Utility nor PG&E Corporation can predict what
the outcome of the investigation will be or whether the outcome will have a
material adverse effect on their results of operation or financial condition.

Regulation of Pacific Gas and Electric Company

   Federal Regulation

   The FERC regulates electric transmission rates and access, operation of the
California ISO and the California PX, uniform systems of accounts, and
contracts involving the wholesale sale of power. The ISO has responsibility
for meeting applicable reliability criteria and assuring the maintenance of
adequate reserves. The PX, which has now suspended operations, had the
responsibility of conducting an open, efficient auction for matching energy
bids to supply with demand bids to purchase energy. Both these entities were
subject to FERC regulation of tariffs and conditions of service. In addition,
the FERC has jurisdiction over the Utility's electric transmission revenue
requirements and rates. The FERC also regulates the interstate transportation
of natural gas. Further, most of the Utility's hydroelectric facilities are
subject to licenses issued by the FERC.

   On December 20, 1999, the FERC issued its final rule (Order No. 2000) on
Regional Transmission Organizations (RTOs). The order encourages utilities
owning transmission systems to form RTOs on a voluntary basis. Typically, the
establishment of these entities results in the consolidation of transmission
charges imposed by successive transmission systems into a single tariff. The
Utility is a participant in the ISO, however the FERC has not yet approved the
ISO's status as an RTO under Order No. 2000.

   The Nuclear Regulatory Commission (NRC) oversees the licensing,
construction, operation, and decommissioning of nuclear facilities, including
Diablo Canyon and the nuclear generating unit at Humboldt Bay Power Plant
(Unit 3). NRC regulations require extensive monitoring and review of the
safety, radiological, and environmental aspects of these facilities.

   State Regulation

   The CPUC has jurisdiction to regulate the following utility functions
within California: electric distribution service, gas distribution service,
and gas transmission service. The CPUC regulates Pacific Gas and Electric
Company's rates and conditions of service, sales of securities, dispositions
of utility property, rates of return, rates of depreciation, and long-term
resource procurement. The CPUC also conducts various reviews of utility
performance and conducts investigations into various matters, such as
deregulation, competition, and the environment, in order to determine its
future policies. The CPUC consists of five members appointed by the Governor
and confirmed by the State Senate for six-year terms.

   The California Energy Commission (CEC) has the responsibility to make
electric-demand forecasts for the state and for specific service territories.
Based upon these forecasts, the CEC determines the need for additional energy
sources and for conservation programs. The CEC sponsors alternative-energy
research and development projects, promotes energy conservation programs, and
maintains a statewide plan of action in case of energy shortages. In addition,
the CEC certifies power plant sites and related facilities within California.
The CEC also administers funding for public purpose research and development,
and renewable technologies programs.

   Licenses and Permits

   Pacific Gas and Electric Company obtains a number of permits,
authorizations, and licenses in connection with the construction and operation
of its generating plants, transmission lines, and gas compressor station

                                       6
<PAGE>

facilities. Discharge permits, various Air Pollution Control District permits,
United States Department of Agriculture--Forest Service permits, FERC
hydroelectric facility and transmission line licenses, and NRC licenses are
the most significant examples. Some licenses and permits may be revoked or
modified by the granting agency if facts develop or events occur that differ
significantly from the facts and projections assumed in granting the approval.
Furthermore, discharge permits and other approvals and licenses are granted
for a term less than the expected life of the associated facility. Licenses
and permits may require periodic renewal, which may result in additional
requirements being imposed by the granting agency. The Utility currently has
10 hydroelectric projects and one transmission line project undergoing FERC
license renewal.

Regulation of PG&E National Energy Group, Inc. Businesses

   Federal Regulation

   The rates, terms, and conditions of the wholesale sale of power by the
generating facilities owned or leased by NEG through PG&E Gen, its
subsidiaries, and affiliates, and of power contractually controlled by them is
subject to FERC jurisdiction under the Federal Power Act. Various NEG
subsidiaries and affiliates have FERC-approved market-based rate schedules and
accordingly have been granted waivers of many of the accounting, record-
keeping, and reporting requirements imposed on entities with cost-based rate
schedules. This market-based rate authority may be revoked or limited were the
FERC to conclude that the rates charged are no longer just and reasonable.
Such a conclusion could be reached were the FERC to conclude, for example,
that a NEG subsidiary or affiliate has excess market power. The FERC also
regulates the rates, terms, and conditions for electric transmission in
interstate commerce. Tariffs established under FERC regulation provide NEG
with the necessary access to transmission lines.

   The FERC also licenses all of NEG's hydroelectric and pumped storage
projects. These licenses, which are issued for 30 to 50 years, will expire at
different times between 2001 and 2020. The relicensing process often involves
complex administrative processes that may take as long as 10 years. The FERC
may issue a new license to the existing licensee, issue a license to a new
licensee, order that the project be taken over by the federal government (with
compensation to the licensee), or order the decommissioning of the project at
the owner's expense.

   NEG-affiliated projects are also subject to other differing federal
regulatory regimes. Those qualifying as qualifying facilities (QFs) under the
Public Utility Regulatory Policies Act of 1978 (PURPA), are exempt from the
Holding Company Act, certain rate filings, and accounting, record-keeping, and
reporting requirements that the FERC otherwise imposes and from certain state
laws. Others qualify as Exempt Wholesale Generators (EWGs) under the National
Energy Policy Act of 1992. EWGs are not regulated under the Holding Company
Act, but are subject to FERC and state regulation, including rate approval.

   NEG's natural gas transmission business is also subject to FERC
jurisdiction. Certificates of public convenience and necessity have been
obtained from the FERC for construction and operation of the existing
pipelines and related facilities and properties, and application has been made
to construct the U.S. segment of the North Baja Pipeline. The rates, terms,
and conditions of the transportation and sale (for resale) of natural gas in
interstate commerce is subject to FERC jurisdiction. As necessary, NEG
subsidiaries and affiliates file applications with the FERC for changes in
rates and charges that allow recovery of costs of providing services to
transportation customers. An October 1999 order permits individually
negotiated rates in certain circumstances.

   The Department of Energy also regulates the importation of natural gas from
Canada and exportation of power to Canada.

   State and Other Regulations

   In addition to federal laws and regulation, NEG businesses are also subject
to various state regulations. First, public utility regulatory commissions at
the state level are responsible for approving rates and other terms and

                                       7
<PAGE>

conditions under which public utilities purchase electric power from
independent power producers. As a result, power sales agreements, which NEG
affiliates enter into with such utilities, are potentially subject to review
by the public utility commissions, through the commissions' power to review,
for example, the process by which the utilities have entered into these
agreements. Second, state public utility commissions also have the authority
to promulgate regulations for implementing some federal laws, including
certain aspects of PURPA. Third, some public utility commissions have asserted
limited jurisdiction over independent power producers. For example, in New
York the state public utility commissions have imposed limited requirements
involving safety, reliability, construction, and the issuance of securities by
subsidiaries operating assets located in that state. Fourth, state regulators
have jurisdiction over the restructuring of retail electric markets and
related deregulation of their electric markets. Finally, states may also
assert jurisdiction over the siting, construction, and operation of NEG's
generation facilities.

   In addition, the National Energy Board of Canada and the Canadian gas-
exporting provinces issue licenses and permits for removal of natural gas from
Canada which can impact customers' ability to import gas for transport over
NEG pipelines.

   Other regulatory matters are described throughout this report. For a
discussion of environmental regulations to which PG&E Corporation and it
subsidiaries are subject, see the section entitled "Environmental Matters"
below.

                                       8
<PAGE>

                              UTILITY OPERATIONS

   Pacific Gas and Electric Company provides regulated electric and gas
distribution and transmission services in Northern and Central California. The
Utility's service territory covers 70,000 square miles with an estimated
population of approximately 13 million and includes all or portions of 48 of
California's 58 counties. The area's diverse economy includes aerospace,
electronics, computer technology, financial services, food processing,
petroleum refining, agriculture, and tourism.

Ratemaking Mechanisms

   Customer rates are determined by the FERC or the CPUC and are designed to
recover the Utility's anticipated reasonable costs and a fair rate of return.
Some rates incorporate a performance incentive mechanism by providing rewards
and penalties for meeting certain performance criteria. Some of the ratemaking
mechanisms affecting both electricity and gas distribution operations are
discussed below.

   General Rate Case. The CPUC authorizes an amount, known as "base revenues,"
to be collected from ratepayers to recover the Utility's basic business and
operational costs for its gas and electric distribution operations. Base
revenues, which include non-fuel-related operating and maintenance costs,
depreciation, taxes, and a return on invested capital, currently are
authorized by the CPUC in General Rate Case (GRC) proceedings. During the GRC,
which occurs every three years, the CPUC examines the Utility's costs and
operations to determine the amount of base revenue requirement the Utility is
authorized to collect from customers through base revenues. The revenue
requirement is forecasted on the basis of a specified test year. (The return
component of the Utility's revenue requirement is computed using the overall
cost of capital authorized in other proceedings.) Following the revenue
requirement phase of a GRC, the CPUC conducts a rate design phase, which
allocates revenue requirements and establishes rate levels for the different
classes of customers. Since base revenues are determined for a three-year
period by GRCs, the Utility may apply for a yearly increase in base revenues
(known as an attrition rate adjustment) to reflect inflation and the growth in
capital investments necessary to serve customers. The 1999 and 2002 GRCs are
discussed below.

   Cost of Capital. Each year, the Utility files an application with the CPUC
to determine the authorized rate of return that the Utility may earn on its
electric and gas distribution assets and recover from ratepayers. Since
February 17, 2000, the Utility's adopted return on common equity (ROE) has
been 11.22% on electric and gas distribution operations, resulting in an
authorized 9.12% overall rate of return (ROR). The Utility's earlier adopted
ROR was 10.6%. The adopted ROR for 2000 resulted in an increase of
approximately $49 million in electric and gas distribution revenues. In May
2000, the Utility filed an application with the CPUC to establish its
authorized ROR for electric and gas distribution operations for 2001. The
application requests a ROE of 12.4%, and an overall ROR of 9.75%. If granted,
the requested ROR would increase electric distribution revenues by
approximately $72 million and gas distribution revenues by approximately $23
million. The application also requests authority to implement an Annual Cost
of Capital Adjustment Mechanism for 2002 through 2006 that would replace the
annual cost of capital proceedings. The proposed adjustment mechanism would
modify the Utility's cost of capital based on changes in an interest rate
index. The Utility also proposes to maintain its currently authorized capital
structure of 46.2% long-term debt, 5.8% preferred stock, and 48% common
equity. In March 2001, the CPUC issued a proposed decision recommending no
change to the current 11.22% ROE for 2001. A final decision is expected in the
second quarter of 2001.

   The return on the Utility's electric transmission-related assets is
determined by the FERC. See "Electric Transmission Rates" below. The return on
the Utility's natural gas transmission and storage business was incorporated
in rates established in the Gas Accord settlement. See "Gas Ratemaking--Gas
Accord" below.

   Electric and Gas Distribution Performance-Based Ratemaking (PBR). In June
2000, the CPUC granted the Utility's request to withdraw its PBR application
filed in November 1998. The Utility had requested the withdrawal in accordance
with the 1999 GRC decision issued in February 2000, which required a 2002 GRC
before a PBR revenue/rate indexing mechanism could be implemented. In closing
the PBR proceeding, the CPUC ordered the Utility to file a new PBR application
by September 2000.

                                       9
<PAGE>

   In September 2000, the Utility filed an application with the CPUC to
establish (1) performance standards and associated financial rewards and
penalties for electric and gas distribution service, (2) a revenue-sharing
mechanism for new categories of non-tariffed products and services (NTP&S)
offered by the Utility and (3) ratemaking for proceeds from sales or transfers
of certain non-generation related land. The performance standards would cover
a period of five years beginning January 1, 2001. The total maximum annual
reward or penalty is $54 million per year, consisting of $52 million for
electric distribution and $2 million for gas distribution. The revenue-sharing
mechanism proposes to share net positive after-tax revenues from new
categories of NTP&S equally between ratepayers and shareholders. Finally, the
Utility requested that the CPUC establish basic rules about the allocation of
gains and losses from the Utility's non-generation-related land sales. In
November 2000, the CPUC suspended the schedule in the PBR proceeding until
further order.

Electric Ratemaking

   As required by AB 1890, electric rates for all customers were frozen at the
level in effect on June 10, 1996, and, beginning January 1, 1998, rates for
residential and small commercial customers were reduced by 10% from 1996
levels. The rate freeze ends the earlier of March 31, 2002, or when the
Utility has recovered its eligible transition costs (uneconomic generation-
related costs). Most transition costs must be recovered during a transition
period that ends the earlier of December 31, 2001, or when the Utility has
recovered its eligible transition costs. In 1997, the Utility, through a
special purpose entity, refinanced the expected 10% rate reduction with $2.9
billion of rate reduction bonds. At December 31, 2000, $2 billion of bonds
remained outstanding. If the transition period ends before December 31, 2001,
the Utility may be obligated to return a portion of the economic benefits of
the transaction to customers. The timing of any such return and the exact
amount of such portion, if any, have not yet been determined.

   The Utility has advised the CPUC that it had recovered all of its
transition costs during August 2000 (and possibly as early as May 2000,
depending on the final valuation of the Utility's hydroelectric generating
assets and when the rate freeze is determined to have ended). The Utility has
asked the CPUC to recognize that the rate freeze already has ended for the
Utility's customers. After the rate freeze, changes in the Utility's electric
revenue requirements in general will be reflected in rates. The Utility
believes that after the rate freeze is determined to have ended, the Utility
is entitled to recover from ratepayers the costs it incurred to purchase power
on behalf of retail customers. At December 31, 2000, the balance of the
Utility's undercollected power purchase costs was $6.6 billion. PG&E
Corporation and the Utility recognized a fourth quarter charge to earnings of
$6.9 billion ($4.1 billion after tax) to reflect the fact that the Utility
could no longer conclude that its generation-related regulatory assets and
undercollected purchased power costs were probable of recovery from
ratepayers.

   Rate Stabilization Plan Proceeding. Consistent with the Utility's position
that it had recovered its transition costs thus requiring an end to the rate
freeze, in November 2000, the Utility filed an application with the CPUC
seeking approval of a five-year rate stabilization plan (RSP) designed to
protect the Utility's customers from the high and volatile wholesale power
prices, while increasing rates effective January 1, 2001, to allow the Utility
to begin recovery of the Utility's past and ongoing wholesale power purchase
costs. The Utility requested that its proposed RSP rates and tariffs be
adopted by January 1, 2001, on an interim basis, subject to refund, and that
the CPUC approve the application by no later than March 31, 2001.

   The Utility also proposed to defer receiving a portion of its share of
profits from its retained generation facilities, primarily from the Diablo
Canyon nuclear power plant and its hydroelectric plants, until a later time
during the five-year period and allow those funds instead to be used to offset
uncollected power purchase costs. The Utility proposed that for the next two
years (after which the Utility expects the current supply shortage will be
less critical), the Utility retain its generation facilities and sell the
output of these facilities directly to its retail distribution customers on an
incentive ratemaking basis to lower the costs of procured power for such
customers.

   On January 4, 2001, the CPUC issued an emergency interim decision denying
the Utility's emergency request for a rate increase. Instead of the requested
relief, the CPUC approved a 90-day temporary rate increase of 1 cent per
kilowatt hour (kWh), subject to refund and adjustment. This rate increase,
which raises

                                      10
<PAGE>

approximately $70 million per month, is grossly insufficient for the Utility
to pay its ongoing procurement bills or to make further financing of these
costs possible.

   On March 27, 2001, the CPUC issued a decision making the 1 cent per kWh
surcharge permanent and authorizing the Utility to add an average 3 cent per
kWh surcharge to current rates. Although the increase is authorized
immediately, the 3 cent per kWh surcharge will not be collected in rates until
the CPUC establishes an appropriate rate design for the surcharge, which is
not expected to be adopted until May 2001, at the earliest. The revenue
generated by the rate increase is to be used only for electric power
procurement costs that are incurred after March 27, 2001. The rate increase is
subject to refund (1) if not used to pay for such power purchases, (2) to the
extent that generators and sellers of power make refunds for overcollections,
or (3) to the extent any administrative body or court denies the refunds of
overcollections in a proceeding where recovery has been hampered by a lack of
cooperation from the Utility. In addition, the CPUC ordered that the 3 cent
per kWh surcharge be added to the rate paid to the DWR as adopted by the CPUC
in a companion decision discussed below.

   Also on March 27, 2001, the CPUC issued a decision ordering the Utility and
the other California investor-owned utilities to pay the DWR a per-kWh price
equal to the applicable generation-related retail rate per kWh established for
each utility as in effect on January 5, 2001, for each kWh the DWR sells to
the customers of each utility. The CPUC determined that the generation-related
component of retail rates should be equal to the total bundled electric rate
(including the 1 cent per kWh interim surcharge adopted by the CPUC on January
5, 2001) less the following non-generation-related rates or charges:
transmission, distribution, public purpose programs, nuclear decommissioning,
and the fixed transition amount. The CPUC determined that the Utility's
company-wide average generation-related rate component is 6.471 cents per kWh
and that this is the amount that should be paid to the DWR for each kWh
delivered by the DWR to the Utility's retail customers after February 1, 2001,
until specific rates are calculated. The CPUC ordered the utilities to pay the
DWR within 45 days after the DWR supplies power to their retail customers,
subject to penalties for each day that payment is late. The amount of power
supplied to retail end-use customers after March 27, 2001, for which the DWR
is entitled to be paid would be based on the product of the number of kWh that
the DWR provided 45 days earlier and the Utility's company-wide average
generation-related rate of 6.471 cents per kWh, and the additional 3 cent per
kWh surcharge described above.

   The CPUC also ordered that the utilities immediately pay the sums owed to
the DWR for power sold by the DWR from January 18, 2001 through January 31,
2001, under California Senate Bill 7X. Based on an estimated number of kWh
sold by the DWR, the Utility paid approximately $30 million to the DWR at the
rate of 5.471 cents per kWh as adopted by the CPUC.

   As the DWR has not advised the CPUC of its revenue requirement for the
DWR's power purchases, it is unclear how much of the 3 cent surcharge will be
needed by the DWR and how much, if any, may be used by the Utility to recover
its procurement costs incurred after March 27, 2001.

   General Rate Case. In February 2000, the CPUC issued a decision in the
Utility's 1999 GRC for the period 1999-2001. The decision was retroactive to
January 1, 1999. The CPUC authorized base revenues for the Utility's electric
distribution function of approximately $2.3 billion, reflecting an increase of
$377 million over base revenues authorized in 1996. In March 2000, two
intervenors filed applications for rehearing of the decision, alleging that
the CPUC committed legal errors by approving funding in certain areas that
were not adequately supported by record evidence. In April 2000, the Utility
filed its response to these applications for rehearing, defending the GRC
decision against the allegations of error. A CPUC decision on the applications
for rehearing is pending.

   The 1999 GRC decision also ordered that the Utility file a 2002 GRC. In
July 2000, the CPUC issued a decision requiring the Utility to file a Notice
of Intent (NOI) with the CPUC by May 1, 2001. The CPUC decision affirms that
rates would still become effective on January 1, 2002, although the CPUC
decision may not be rendered until late 2002. In January 2001, the Utility
filed a petition with the CPUC requesting that the May 1,

                                      11
<PAGE>

2001 deadline for filing the NOI be suspended, asserting that many assumptions
that would have to be made in order to forecast year 2002 costs would very
likely need to be changed based on how the wholesale electricity price and
natural gas supply crises are resolved. The Utility requested that it be
allowed to file an alternative to the schedule, or to the GRC itself, by May
1, 2001. The CPUC has not acted on the Utility's January 2001 petition. On
March 27, 2001, the CPUC extended the NOI filing date by the number of days
from March 5, 2001 to 30 days after the CPUC renders a decision on the
petition. The extension will become effective only if the CPUC denies the
petition. If the CPUC grants the petition, the Utility would be allowed to
file an alternative schedule or an alternative to the GRC and the CPUC would
subsequently decide how to proceed with the case.

   2001 Attrition Rate Adjustment Request. In July 2000, the Utility filed an
attrition rate adjustment application with the CPUC to increase its 2001
electric distribution revenues by $189 million, effective January 1, 2001, to
reflect inflation and the growth in capital investments necessary to serve
customers. The Utility did not request an increase in gas distribution
revenues. On December 21, 2000, the CPUC issued an interim order finding that
a decision on the merits of this application cannot be rendered by January 1,
2001, and determining that if attrition relief is eventually granted, that
relief will be effective as of January 1, 2001. Hearings are scheduled to
begin in June 2001, and a CPUC decision is expected by January 2002.

   Revenue Adjustment Proceeding. The CPUC established a separate annual
proceeding, the Revenue Adjustment Proceeding (RAP), to review and verify the
amounts recorded in the Utility's Transition Revenue Account (TRA), and to
verify each electric utility's authorized revenue requirements, including any
necessary adjustments to reflect the revenue requirements which are approved
in other proceedings. The RAP also establishes revenue allocation and rate
design, and identifies all electric balancing and memorandum accounts for
continued retention or elimination. The TRA is a regulatory balancing account
that is credited with total revenue collected from ratepayers through frozen
rates. From this total revenue, the following items are subtracted: (1)
revenues collected for transmission services and for the payment of rate
reduction bond debt service, (2) the authorized revenue requirement for
distribution services, public purpose programs, and nuclear decommissioning
costs, and (3) electric industry restructuring implementation costs, energy
procurement costs, and other costs. Remaining revenues, if any, are
transferred to the Transition Cost Balancing Account (TCBA), a regulatory
balancing account that tracks recovery of transition costs, to offset
transition costs. Due to the high wholesale power costs at which the Utility
has been required to purchase power for its distribution customers since June
2000, revenues from frozen rates have been grossly insufficient to recover the
Utility's operating costs, resulting in a TRA under-collection of $6.6 billion
at December 31, 2000. On January 4, 2001, the CPUC issued a decision in the
Utility's 1999 RAP approving the transfer of $967 million of residual revenue
in the TRA to the TCBA for the period from June 1, 1998 through June 30, 1999,
and adopted a PX credit adder of .007 cents per kWh for utility customers that
elect direct access to offset the energy costs included in the bundled rate.
The Utility will file its application for its next RAP to address revenues and
costs recorded in the TRA from July 1, 1999 through at least April 30, 2001,
on or before June 1, 2001. One of the CPUC's March 27, 2001, decisions
retroactively changes the TRA and TCBA accounting mechanisms. (See "Electric
Utility Operations--Electric Industry Restructuring--New California
Legislation," below.)

   Annual Transition Cost Proceeding. The Annual Transition Cost Proceeding
(ATCP), applicable to all California investor-owned electric utilities, was
established to verify the accounting and recording of costs and revenues in
the TCBA and ensure that only eligible transition costs have been entered. The
TCBA tracks the revenues available to offset transition costs, including the
accelerated recovery of plant balances, and other generation-related assets
and obligations. Transition costs will receive a limited "reasonableness"
review. On January 4, 2001, the CPUC issued a decision in the Utility's 1999
ATCP finding that $2.6 billion recorded in the TCBA from July 1, 1998 through
June 30, 1999 are eligible for recovery as transition costs. In February 2000,
the Utility's request for approval of the Hunters Point power plant
decommissioning cost was bifurcated into a separate phase and will be
addressed in a separate decision expected to be issued in the second quarter
of 2001. In September 2000, the Utility filed its 2000 ATCP application
seeking approval of amounts recorded in the TCBA and generation-related
memorandum accounts for the period July 1, 1999 through June 30, 2000.


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<PAGE>

   As required by the CPUC, in August 2000, the Utility made a filing with the
CPUC that estimated the market value of the Utility's remaining hydroelectric
generating assets at $2.8 billion (based on a negotiated value used in a
proposed settlement discussed below under "Electric Resources--Hydroelectric
Generation Assets.") The Utility credited its TCBA by $2.1 billion, the amount
of the estimated value over the assets' book value. At the same time, the
Utility made a corresponding debit entry of the same amount in the newly
established Generation Asset Balancing Account (GABA) to prevent an immediate
charge to earnings that would have otherwise resulted from the credit to the
TCBA. The filing will become effective after appropriate review by the CPUC's
Energy Division and the TCBA entries are subject to review in the 2001 ATCP to
be filed September 1, 2001. The Utility believes that with the credit to the
TCBA, the Utility has recovered all of its transition costs as of early August
2000. If the final value of the hydroelectric assets is higher than the
estimate, the Utility believes its transition costs would have been recovered
as of an earlier date, possibly as early as May 2000. However, in a decision
issued on March 27, 2001, the CPUC has stated that with the retroactive
accounting changes adopted in the decision, the conditions for meeting the
rate freeze have not been met. See "Electric Utility Operations--Electric
Industry Restructuring--New California Legislation," below.

   Electric Industry Restructuring Implementation Costs. Under AB 1890,
certain electric industry restructuring implementation costs found reasonable
by the CPUC may be recovered from electric customers. In May 1999, the CPUC
approved a multi-party settlement agreement that, among other things, permits
the Utility to recover 1997 and 1998 restructuring implementation costs of
$41.3 million (reflecting a reduction of $10 million from the Utility's
requested revenue requirement). In addition, the Utility is authorized to
recover in its TRA costs related to the Consumer Education Program and the
Electric Education Trust funded by the Utility and FERC-approved ISO and PX
development and start-up costs. At the end of the transition period, if
recovery of these restructuring implementation costs recorded in the TRA
displaces recovery of transition costs recorded in the TCBA, the Utility may
recover up to $95 million of such displaced transition costs after the
transition period.

   Electric Restructuring Costs Account (ERCA). The CPUC authorized the
Utility to establish the Electric Restructuring Costs Account (ERCA) to record
the restructuring implementation costs that were removed from its 1999 GRC
revenue requirement request, any unanticipated restructuring costs incurred as
a result of directives from the CPUC or the FERC, and certain other costs. In
July 2000, the Utility filed an application seeking approval of $142.5 million
of costs recorded in the ERCA. In August 2000, protests were filed by Enron
Corporation, the CPUC's Officer of Ratepayer Advocates (ORA), and The Utility
Reform Network (TURN), challenging the evidentiary support for the costs,
among other concerns. This matter is pending.

   Revenues from Must-Run Contracts. The ISO has designated certain units at
electric generation facilities as necessary to remain available to maintain
the reliability of the electric transmission system. These units are called
"must-run" units. In general, the ISO dispatches these units under cost-based
contracts regulated by the FERC that allow the owners to recover a portion of
fixed and operating costs of the must-run units. The owners of must-run units
choose among two different forms of must-run contract, both of which cover
operating costs. One form provides payments of a percentage of the unit's
fixed cost revenue requirement and does not limit market participation. The
other form provides 100% fixed cost recovery but allows only very restricted
market participation. The Utility's two remaining fossil-fueled power plants
(Hunters Point and Humboldt Bay), three of its hydroelectric generation
facilities, and a combustion turbine located at a substation in San Jose,
California, are under must-run contracts. The form of must-run contract chosen
for all of these facilities (except Hunters Point and the combustion turbine)
is the one that does not limit market participation. The Utility currently
receives approximately $91 million per year as payments under these must-run
contracts, plus fuel costs. In addition, the Utility has the opportunity to
earn market revenues for all of these plants except Hunters Point and the
combustion turbine, when the ISO has not dispatched the plant.

   FERC Transmission Owner Rate Case. The ISO controls most of the state's
electric transmission facilities. The Utility serves as the scheduling
coordinator to schedule transmission with the ISO to facilitate continuing
service under wholesale transmission contracts that the Utility entered into
before the ISO was established. The ISO bills the Utility for providing
certain services associated with these contracts. These ISO charges are
referred

                                      13
<PAGE>

to as the "scheduling coordinator costs." As part of the Utility's
Transmission Owner rate case filed at the FERC, the Utility established a
balancing account, the Transmission Revenue Balancing Account (TRBA), to
record these scheduling coordinator costs in order to recover these costs
through transmission rates. Certain transmission-related revenues collected by
the ISO and paid to the Utility are also recorded in the TRBA. Through
December 31, 2000, the Utility has recorded approximately $33 million of these
scheduling coordinator costs in the TRBA. (The Utility has also disputed
approximately $26 million of these costs as incorrectly billed by the ISO. Any
refunds that ultimately may be made by the ISO would be credited to the TRBA.)
In September 1999, a proposed decision was issued denying recovery of these
scheduling coordinator costs. The proposed decision is subject to change by
the FERC in its final decision. The FERC is expected to issue a final decision
sometime in 2001. On January 11, 2000, the FERC accepted a proposal by the
Utility to establish the Scheduling Coordinator Services (SCS) Tariff that
would act as a back-up mechanism for recovery of the scheduling coordinator
costs if the FERC ultimately decides that these costs may not be recovered in
the TRBA. The FERC also conditionally granted the Utility's request that the
SCS Tariff be effective retroactive to March 31, 1998, but the FERC suspended
the procedural schedule until the final decision is issued regarding the
inclusion of scheduling coordinator costs in the TRBA.

   AB 1890 Electric Base Revenue Increase. AB 1890 provided for an increase in
the Utility's electric base revenues for 1997 and 1998, for enhancement of
transmission and distribution system safety and reliability. The CPUC
authorized a 1997 base revenue increase of $164 million. For 1998, the CPUC
authorized an additional base revenue increase of $77 million. The CPUC will
determine how much of the authorized increases were actually spent on system
safety and reliability during 1997 and 1998, and adjust the amounts downward
if necessary. The Utility claims that it overspent the 1997 authorized revenue
requirement by approximately $11.8 million and that the Utility underspent
1998 incremental revenues by approximately $6.5 million. The Utility has
proposed that the underspent amount be credited to TRA revenues. In July 1999,
the ORA recommended that $88.4 million in expenditures for 1997 and 1998 be
disallowed. In August 1999, TURN recommended an additional $14 million
disallowance for a total recommended disallowance for 1997 and 1998
expenditures of $102.4 million. The Utility opposed the recommended
disallowances and hearings were held in October 1999. It is uncertain when a
proposed decision will be issued by the CPUC. Any proposed decision would be
subject to comment by the parties and change by the CPUC before a final
decision is issued.

   Electric Transmission Rates. Since April 1998, electric transmission
revenues have been authorized by the FERC, including various rates to recover
transmission costs from the Utility's former bundled retail transmission
customers. The FERC has not yet acted upon a settlement filed by the Utility
that, if approved, would allow the Utility to recover $345 million in electric
transmission rates for the 14-month period of April 1, 1998 through May 31,
1999. During that period, somewhat higher rates were collected, subject to
refund. A FERC order approving this settlement is expected by the end of 2001.
The Utility has accrued $24 million for potential refunds related to the
period ended May 31, 1999. In April 2000, the FERC approved a settlement that
permits the Utility to recover $264 million in electric transmission rates
retroactively for the 10-month period from May 31, 1999 to March 31, 2000. In
September 2000, the FERC approved another settlement that permits the Utility
to recover $340 million annually in electric transmission rates and made this
retroactive to April 1, 2000. Further, in November 2000, the FERC accepted,
subject to refund, the Utility's proposal to collect $397 million in electric
transmission rates beginning on May 6, 2001.

   Post-Transition Period Ratemaking Proceeding. In October 1999, the CPUC
issued a decision in the Utility's post-transition period ratemaking
proceeding. Among other matters, the CPUC decision prohibits the Utility from
collecting after the rate freeze any costs incurred during the rate freeze but
not recovered during the rate freeze, including costs that are not transition
costs and not related to generation assets such as undercollected wholesale
power purchase costs incurred on behalf of retail distribution customers. In
November 2000, the California Supreme Court denied the Utility's petition for
review of an appellate decision that had denied the Utility's petition for
review of the CPUC's decision. The Utility has filed a complaint against the
CPUC in federal court requesting the court to declare that the Utility is
permitted as a matter of federal law to recover from distribution customers
the wholesale power purchase costs it has incurred to purchase power on their
behalf. For more information, see "Item 3--Legal Proceedings," below.

                                      14
<PAGE>

   In the October 1999 decision, the CPUC also established the Purchased
Electric Commodity Account (PECA) for the Utility to track energy costs after
the rate freeze and transition period end. In June 2000, the CPUC issued a
decision in which the CPUC determined that the PECA would reflect a pass-
through of energy costs, possibly subject to after-the-fact reasonableness
reviews. The decision states that after the rate freeze ends, there will be
rate proceedings that will, among other matters, address electric energy
procurement practices and rates.

Gas Ratemaking

   Gas Accord. The Gas Accord separated or "unbundled" the Utility's gas
transmission services from its distribution services, changed the terms of
service and rate structure for gas transportation, increased the opportunity
for core customers to purchase gas from competing suppliers, established a
form of incentive mechanism to measure the reasonableness of core procurement
costs, and established gas transmission and storage rates through 2002. In
November 2000, the Utility filed an advice letter requesting authorized
increases in the rates established for 2001 by the Gas Accord. Additional
information about the Gas Accord is provided below in "Utility Operations-Gas
Utility Operations."

   General Rate Case. In February 2000, the CPUC issued a decision in the
Utility's GRC for the period 1999-2001. The decision is retroactive to January
1, 1999. The CPUC authorized base revenues for the Utility's gas distribution
function, including public purpose programs, of approximately $892 million,
reflecting an increase of approximately $93 million over base revenues
authorized in 1996. Revised gas transportation rates reflecting the revenue
changes resulting from the GRC and other regulatory proceedings were effective
March 1, 2000. (For a discussion of the 2002 GRC, see above under "Electric
Ratemaking.")

   The Core Fixed Cost Account (CFCA) is the regulatory balancing account that
matches gas distribution and storage authorized revenue to the actual revenue
collected from core customers. During May 2000, the Utility refunded
approximately $320 million to core gas customers to reduce an over-collection
in the CFCA. Since the volumes of gas delivered to core customers during the
1998 and 1999 winter seasons were higher than the forecasted volumes used to
set the rates, an over-collection resulted. Beginning in December 2000,
storage activity is recorded in a new procurement balancing account, Core Firm
Storage Account, instead of in the CFCA, and are included in monthly core
procurement rates.

   Gas Procurement Costs. The Utility procures gas for more than 90 percent of
its core customers. The Utility passes on the natural gas costs it incurs on
behalf of customers to ratepayers. The core procurement rate is set monthly
based on the forecasted cost of gas. Gas procurement activity is recorded in
the Purchased Gas Account (PGA). The PGA matches the actual gas commodity
costs to the revenue collected from customers. Over- or under-collections in
the PGA are collected or returned to customers through an adjustment to the
gas procurement rate in subsequent months.

   The Biennial Cost Allocation Proceeding (BCAP). The BCAP remains the
proceeding in which distribution costs and balancing account balances are
allocated to customers. The BCAP normally occurs every two years and is
updated in the interim year for purposes of amortizing any accumulation in the
balancing accounts. Balancing accounts for gas distribution and public purpose
program revenue requirements accumulate differences between authorized revenue
requirements and actual base revenues. In April 2000, the Utility filed its
2000 BCAP application to cover the period of January 1, 2000 through December
31, 2002, requesting a decrease in the annual base revenue requirement of $132
million compared to the authorized revenue requirement of $941 million at the
time the application was filed. On October 27, 2000, the Utility filed with
the CPUC a settlement agreement between the Utility and various parties and
groups representing noncore industrial, electric generation, and co-generation
customers. The settlement agreement resolved all issues relating the 2000 BCAP
application raised by parties regarding customer throughput, marginal costs,
the allocation of balancing account balances, and core and noncore rate
design. If the settlement is adopted, there would be a decrease in the base
revenue requirement of approximately $113 million, subject to adjustment for
the most recent balancing account balances and CPUC decisions in place when
the CPUC acts on the proposed settlement. A decision is expected in the third
quarter of 2001.

                                      15
<PAGE>

Public Purpose Programs

   Under state law, the Utility is authorized to collect not less than $198
million in a separate nonbypassable charge included in frozen electric rates
to fund Utility and other entities' investments in four public purpose
programs: (1) cost-effective energy efficiency and energy conservation
programs, (2) research, development and demonstration programs, (3) renewable
energy resources programs, and (4) low-income electricity programs including
targeted energy efficiency services and rate discounts. Low-income energy
efficiency programs are funded at the level of need, but are not to be funded
at less than the 1996 level of expenditures. The Utility is obligated to fund
through electric rates energy efficiency and conservation programs in an
amount not less than $106 million per year, public interest research and
development programs at not less than $30 million per year, renewable energy
technologies at not less than $48 million per year, and low-income energy
efficiency programs at not less than $14 million per year. The Utility also
collects funds for the California Alternate Rates for Energy (CARE) low-income
discount rate, a rate subsidy paid for by the Utility's other customers, which
is currently about $31 million per year.

   Under the oversight of the CPUC, the Utility administers both the cost-
effective energy efficiency and low-income energy efficiency programs. These
two programs are reviewed annually in the Annual Earnings Assessment
Proceeding (AEAP). In March 1999, the CPUC determined that these programs
should continue to be administered by investor-owned utilities, subject to
CPUC oversight, through 2001. Effective January 1, 2000, Section 327 of the
California Public Utilities Code requires utilities to continue to administer
low-income energy efficiency programs. The California Energy Resources
Conservation and Development Commission (also called the California Energy
Commission (CEC)) administers both the public interest research and
development program and the renewable energy program on a statewide basis. The
Utility transfers $78 million per year to the CEC for these two programs.

   In October 2000, the California Legislature passed and the Governor signed
legislation extending the existing surcharge on electricity to fund public
purpose energy efficiency, renewable energy, and research development and
demonstration programs for another 10 years, beginning January 1, 2002.

   The AEAP determines shareholder incentives to be earned for the Utility's
demand side management (DSM) programs. The 1999 AEAP determines shareholder
incentives to be earned for the Utility's pre-1998 DSM activities and 1998 and
later energy efficiency programs. The Utility was authorized in 2000 to
collect $15.67 million for pre-1998 DSM earnings, $0.11 million for Program
Year (PY) 1998 Low-Income Energy Efficiency (LIEE) earnings, and $10.45
million for PY 1998 non-LIEE earnings. After consolidating the adjusted
incentive payment installments from prior years, the net revenue change in
2000 from shareholder incentives should be an electric increase of
approximately $3.4 million and a gas decrease of approximately $1.5 million.
In May 2000, the Utility filed its 2000 AEAP application seeking to recover
approximately $53 million of shareholder incentives for attainment of
milestones for PY 1999 energy efficiency programs, and for achieving savings
for PY 1998 and 1999 LIEE programs and for DSM accomplishments related to pre-
1998 program commitments. In October 2000, the CPUC postponed the proceedings
until further notice.

Electric Utility Operations

   Electric Industry Restructuring

   The goal of California electric industry restructuring (AB 1890) was to
open up the electric generation function of traditional utilities to
competition to give electric customers of investor-owned utilities (such as
Pacific Gas and Electric Company) the choice of continuing to purchase
electric power from investor-owned utilities or purchasing electric power from
alternative providers (including independent power generators and retail
electricity providers such as marketers, brokers, and aggregators). Purchasing
electric power from an alternative generation provider is called "direct
access." Beginning March 31, 1998, customers were permitted to choose direct
access. For those customers who did not choose direct access, investor-owned
utilities were to continue to purchase electric power on their behalf.
Investor-owned utilities continue to provide distribution services to
substantially all customers within their service territories, including those
customers who choose direct access. During the transition period, the
California investor-owned utilities were required to sell into the

                                      16
<PAGE>

PX all of their generated electric power. "Must-take" generation resources,
such as nuclear generation from Diablo Canyon, electric power generated by QFs
and electricity that the Utility is required to purchase under existing
contractual commitments, were also required to be scheduled through the PX.
These "must take" resources were bid into the PX at $0 per megawatt-hour (MWh)
to ensure that these resources are used to meet demand. During the transition
period, the California investor-owned utilities also were required to buy
power on behalf of their retail customers through the PX. Following the
divestiture of much of their power generation facilities in connection with
electric industry restructuring, the majority of the power purchased through
the PX was supplied by third party generators. The CPUC did not permit the
utilities to buy power directly from third parties through bilateral
agreements until August 2000.

   California Power Crisis. California has endured a power crisis as demand
for power far outstripped supply. Since June 2000, wholesale power prices in
California have steadily increased to an average cost of 18.16 cents per kWh
for the seven month period of June 2000 through December 2000, as compared to
an average cost of 4.23 cents per kWh for the same period in 1999. During
2000, the Utility collected only approximately 5.4 cents per kWh through
frozen rates for the recovery of its wholesale power costs. Many factors have
contributed to the high wholesale power prices, including:

  . Economic and population growth in California.

  . A lack of new power supplies to meet the growing demand.

  . A substantial increase in natural gas prices. Since many power plants
    serving California are natural gas fired, the natural gas prices paid by
    generators in producing electricity are reflected in the price of power
    charged by the generators.

  . Limited availability of hydroelectric power due to dryer than usual
    conditions.

  . Uncoordinated power plant outages due to scheduled maintenance or
    unplanned outages.

  . Dysfunctional power markets that produced unjust and unreasonable price
    levels.

  . The tendency of frozen retail rates to eliminate the incentive for
    customers to conserve energy and reduce demand.

  . Delays in regulatory approvals to permit the California investor-owned
    utilities to enter into long-term power purchase contracts as a hedge
    against price fluctuations. After permission was given in August 2000,
    there have been further delays in regulatory approvals of reasonableness
    standards for entering into bilateral contracts.

   FERC Order. On December 15, 2000, the FERC issued an order adopting
remedies for what the FERC characterized as the seriously flawed electric
power markets in California. Among other matters, the FERC:

  . Eliminated, effective December 15, 2000, the requirement that the
    California investor-owned utilities sell all of their generation into and
    buy all of their energy needs from the PX, which results in over reliance
    on spot market (i.e., real-time) purchases. The order encourages the
    utilities to meet their purchase power needs through bilateral long-term
    contracts of two years or more and to adopt a balanced portfolio of
    contracts to mitigate cost exposure. To encourage the execution of
    bilateral contracts, the order requires the PX's rate schedules to
    terminate effective at the close of business on April 30, 2001.

  . Adopted a price benchmark at $74 per MWh for assessing prices of five-
    year energy supply contracts to be used by the FERC in assessing any
    complaints regarding justness and reasonableness of pricing long-term
    contracts.

  . Permitted penalties to be imposed on market participants who do not
    schedule at least 95% of their load in advance of the ISO's real-time
    market (through self-scheduling, bilateral contracts, or the PX markets),
    to reduce the reliance on the ISO's real-time market to meet supply. A
    penalty charge will be assessed when more than 5% of a market
    participant's load is scheduled into the ISO's real-time market.
    Penalties are to be disbursed to other market participants who schedule
    their load properly. The FERC order does not contain provisions for
    penalties to be imposed on generators who do not schedule in advance.

                                      17
<PAGE>

  . Established an interim $150 per MWh "soft cap" modification of the single
    price auction so that bids above $150 MWh will not set the market
    clearing prices paid to all bidders at or below $150 per MWh. Bids above
    the $150 MWh level will trigger certain weekly reporting requirements and
    FERC monitoring. These price provisions will be in effect until April 30,
    2001.

  . Deferred the consideration of retroactive refund issues linked to
    protective orders associated with the volatile prices experienced in
    California this past summer. Although the period for potential refund
    liability continues until December 31, 2002, with respect to specific
    transactions, refund potential on a transaction will close after 60 days
    unless the FERC has issued written notification to the seller that its
    transaction is still under review.

   PG&E Corporation and the Utility believe the actions outlined in the order
will not provide a complete solution that ensures reliability of the state's
electric supply and relief from future price increases, particularly since the
FERC order fails to require sellers to enter into forward contracts at
reasonable prices, and fails to provide an effective price cap. In addition,
the FERC order does not address issues associated with retroactive refund and
retroactive remedial authority issues. The Utility has filed a request for
rehearing of the FERC's order to the extent that it does not provide effective
mitigation of prices. In March 2001, the FERC ordered refunds of $68.7 million
for January 2001 and subsequently ordered refunds of $55 million for February
2001 and indicated it would continue to review December 2000 wholesale prices.
The generators have appealed the decision, and will supply cost justification.
Any refunds will be offset against amounts owed the generators.

   The California Independent System Operator and the California Power
Exchange. The PX and the ISO, both California public benefit non-profit
corporations, began operating on March 31, 1998, as provided for under AB
1890. The FERC has jurisdiction over both the ISO and the PX. Pursuant to the
FERC order of December 15, 2000, the ISO Board of Governors, which included
representatives of market participants, was replaced with a non-stakeholder
board who are independent of market participants.

   The ISO operates and controls most of the state's electric transmission
facilities (which continue to be owned and maintained by the California
utilities) and provides comparable open access to electric transmission
service. The ISO accepts balanced schedules for supply and load from
scheduling coordinators, including the PX and the Utility, and market
participants and manages the availability of electric transmission on a
statewide basis for these transactions. The ISO also purchases necessary
generation and ancillary services on a real-time basis to maintain grid
reliability. The ISO is required to ensure reliable transmission services
consistent with planning and operating reserve criteria no less stringent than
those established by the Western Systems Coordinating Council and the North
American Electric Reliability Council. Oversight of utility distribution
systems remains with the CPUC.

   Until January 31, 2001, the PX provided an auction process, intended to be
competitive, to establish hourly transparent market clearing prices for
electricity in the markets operated by the PX. The PX operated two markets:
the day-ahead market where market participants purchase power for their
customers' needs on the following day and the day-of-or hour-ahead market
where market participants purchase power needed to serve their customers on
the same day. The PX set a market-clearing price for electricity by matching
all demand bids (the amount of energy that an eligible customer is willing to
purchase and the maximum price that the customer is willing to pay) with
supply bids (the price at which a seller is prepared to sell energy) ranked
from lowest to highest. The highest-accepted generation supply bid used to
serve load set the PX market-clearing price for electricity. The market-
clearing price then became the single cost for electricity throughout
California for that energy delivery hour. Due to downgrades in the Utility's
credit ratings and the Utility's alleged failure to post collateral for all
market transactions, the PX suspended the Utility's market trading privileges
as of January 19, 2001. On January 31, 2001, the PX suspended its day-of and
day-ahead markets in response to the FERC's order directing the PX to comply
with the terms of its December 15, 2000 order and implement a $150 per MWh
"soft" price cap. The FERC ordered the PX to recalculate all PX transactions
since December 15, 2000. The PX subsequently filed for bankruptcy protection.

                                      18
<PAGE>

   In May 1999, the PX obtained FERC approval to operate the block forward
market (BFM), an exchange that matches bids to buy power with offers to sell
power more than one day in advance of the contracted delivery date. In July
1999, the Utility obtained CPUC authority to participate in the BFM for
contracts that called for delivery by October 31, 2000 and subject to a volume
limit. In March 2000, the CPUC raised the volume limit to permit the Utility
to cover its "net open position" (the amount of power to meet the Utility's
customers' needs that can not be met with Utility-owned generation or power
under contract to the Utility) and affirmed that all PX purchases made during
the transition period are deemed reasonable. The CPUC also expanded the
Utility's authority to participate in the BFM through the end of the
transition period. Participation in the BFM lessened after the FERC's December
15, 2000 order, discussed above. The PX sought to liquidate the Utility's BFM
contracts for the purchase of power. On January 25, 2001, a California
Superior Court judge granted the Utility's application for a temporary
restraining order, which thereby restrained and enjoined the PX from
liquidating the Utility's contracts, pending a hearing on a preliminary
injunction on February 5, 2001. Immediately before the hearing, California
Governor Gray Davis, acting under California's Emergency Services Act,
commandeered the contracts for the benefit of the State. Under the Act, the
State must pay the Utility the reasonable value of the contracts, although the
PX may seek to recover the monies that the Utility owes to the PX from any
proceeds realized from those contracts. The Utility has filed a claim with the
California Victim Compensation and Government Claims Board which will be heard
with other claims filed by the PX.

   New California Legislation. Some generation providers refused to sell power
into the California markets based on their concern as to the credit quality of
the California investor-owned utilities whose rates were still frozen. The
Secretary of the U.S. Department of Energy (DOE) ordered such providers to
continue selling into the California markets on request by the ISO. On January
18, 2001, the California Assembly passed Senate Bill 7X that appropriated $400
million and authorized the DWR to use such funds to purchase power at no more
than 5.5 cents per kWh (far less than the current wholesale market rates in
early 2001) and then resell it to the Utility at cost to enable the Utility to
continue to serve its customers. The DWR was authorized to purchase power
through January 31, 2001. On February 1, 2001, the California Governor signed
Assembly Bill No. 1 (AB 1X) which was passed by the California Legislature
during a special session to take effect immediately as an urgency statute. AB
1X authorizes the DWR to enter into contracts for the purchase of electric
power for such periods and at such prices as the DWR deems appropriate
consistent with the objectives of AB 1X to have an overall portfolio of
contracts resulting in reliable service at the least cost. AB 1X prohibits the
DWR from entering into any contract after January 1, 2003. AB 1X requires the
DWR to sell power that it purchases directly to retail end use customers,
except as may be necessary to maintain system integrity.

   AB 1X provides that the DWR will retain title to the power it purchases and
that payment for any sale of power by the DWR is a direct obligation of retail
end use customers to the DWR. The DWR may contract with the electric utilities
for the electric utilities to transmit and distribute the power purchased and
sold by the DWR and to provide billing, collection, and other related
services, as agent of the DWR, on terms that reasonably compensate the
utilities. AB 1X does not authorize the DWR to take ownership of transmission,
generation, or distribution assets of any electric utility. AB 1X states it
shall not be construed (1) to reduce or modify any electrical corporation's
obligation to serve, or (2) to obligate the DWR for any procurement cost
obligations of the utilities that existed before January 31, 2001.

   AB 1X authorizes the CPUC to set rates to cover revenue requirements of
DWR's power purchasing program, but prohibits the CPUC from increasing
electric rates for residential customers who use less power than 130% of their
existing baseline quantities, until the DWR has recovered the costs of power
it has purchased for retail customers.

   On March 27, 2001, the CPUC issued a decision in which it noted that
although the DWR has assumed responsibility to purchase some of the utilities'
power requirements, it has not committed to purchase all of the utilities' net
open position, i.e., the power needs of the retail electric customers that
cannot be met by utility-owned generation or power under contract to the
utilities. To the extent the DWR does not buy enough power to cover the
Utility's net open position, the ISO purchases emergency power on the high-
priced spot market to meet system reliability requirements and the net open
position. The ISO may attempt to charge the

                                      19
<PAGE>

Utility a proportionate share of the ISO's purchases. The Utility believes
that under the current circumstances and applicable tariffs it is not
responsible for such ISO charges.

   In addition, on April 3, 2001, the CPUC adopted a method to calculate the
California Procurement Adjustment, as described in Public Utilities Code
Section 360.5 (added by Assembly Bill 1X). Section 360.5 requires the CPUC to
determine (1) the portion of each electric utility's electric retail rate
effective on January 5, 2001, the "California Procurement Adjustment" or CPA,
that is equal to the difference between the generation-related component of
the utility's retail rate in effect on January 5, 2001, and the sum of the
costs of the utility's own generation, QF contracts, existing bilateral
contracts (i.e., entered into before February 1, 2001), and ancillary
services, and (2) the amount of the CPA that is allocable to the power sold by
the DWR. The CPUC decided that the CPA should be a set rate calculated by
determining each utility's generation-related revenues (for the Utility the
CPUC has proposed that this be equal to 6.471 cents per kWh multiplied by
total kWh sales by the Utility to the Utility's retail customers), then
subtracting each utility's statutorily authorized generation-related costs,
and dividing the result by each utility's total kWh sales. Each utility's CPA
rate will be used to determine the amount of bonds the DWR may issue.

   Using the CPUC's methodology, but substituting the CPUC's cost assumptions
with actual expected costs and including costs the CPUC has refused to
recognize, the Utility's calculations show that the CPA for the 11-month
period February through December 2001 would be negative by $2.2 billion,
(i.e., there would be no CPA available to the DWR) assuming the DWR purchases
84 percent of the Utility's net open position. If AB 1X were amended to also
include in the CPA all the incremental revenue from the 3 cent per kWh
increase discussed above (approximately $2.3 billion for 11 months), then the
amount available to the DWR for the CPA for the comparable 11-month period,
assuming the Utility were allowed to recover its costs first, would be
approximately $100 million. The Utility believes the method adopted by the
CPUC is unlawful and inconsistent with Section 360.5 because, among other
reasons, it establishes a set rate that does not reflect actual residual
revenues, overstates the CPA by excluding and/or understating authorized
costs, and to the extent it is dedicated to the DWR does not allow the Utility
to recover its own revenue requirements and costs of service. The Utility has
filed an application for rehearing of the decision.

   Recovery of Transition Costs, Wholesale Power Purchase Costs, and End of
Rate Freeze. Based on the premise that market-based revenues would not be
sufficient to recover the utilities' uneconomic generation costs, AB 1890
provides the investor-owned utilities the opportunity to recover their
transition costs during a transition period ending the earlier of December 31,
2001, or when the particular utility has recovered its transition costs. Some
transition costs may be recovered after the transition period. Costs eligible
for recovery as transition costs, as determined by the CPUC, include (1)
above-market sunk costs (i.e., costs associated with utility generating
facilities that are fixed and unavoidable and that were included in customer
rates on December 20, 1995) and future sunk costs, such as costs related to
plant removal, (2) costs associated with long-term contracts to purchase power
at above-market prices from QFs and other power suppliers, and (3) generation-
related regulatory assets and obligations. (In general, regulatory assets are
expenses deferred in the current or prior periods to be included in rates in
subsequent periods.) The Utility tracks the recovery of its transition costs
in its TCBA.

   Transition costs may be recovered only through the competition transition
charge (CTC) (the amount of revenues remaining after paying authorized
operating costs), the excess of market value of generating assets over book
value, and retained generation revenues. Due to the high wholesale power
prices the Utility has been required to pay to purchase power for its
customers, revenues from frozen rates since June 2000 have been insufficient
to provide any CTC revenues.

   Under current CPUC decisions, if undercollected power purchase costs
recorded in the TRA are not recovered through frozen rates by the end of the
transition period, they cannot be recovered or offset against over-collections
of transition costs. The Utility has filed a lawsuit in federal district court
against the CPUC challenging these decisions. See "Item 3--Legal Proceedings,"
below.

   Under AB 1890, when the Utility has recovered its eligible transition
costs, the conditions for terminating the rate freeze and ending the
transition period will have been satisfied. At August 31, 2000, consistent
with

                                      20
<PAGE>

transition period accounting mechanisms adopted by the CPUC, the Utility
credited its TCBA by $2.1 billion, the amount by which a negotiated $2.8
billion hydroelectric generation asset valuation exceeded the aggregate book
value of such assets. Based on this credit, the Utility believes it recovered
its eligible transition costs during August 2000. At August 31, 2000, there
was a balance of approximately $2.2 billion of undercollected wholesale power
costs recorded in the TRA. If the final valuation for the hydroelectric assets
is greater than $2.8 billion, as the Utility expects, the Utility believes it
will have recovered its transition costs possibly as early as May 2000. The
undercollected TRA balance as of the end of the earlier determined transition
period will be less than the $2.2 billion August 31, 2000 balance and could be
zero depending on the ultimate valuation of the hydroelectric assets and when
the transition period actually ends. Under current CPUC decisions and AB 1890,
the Utility's customers are responsible for wholesale power purchase costs
after the Utility has recovered its transition costs.

   In one of its March 27, 2001 decisions, the CPUC adopted TURN's proposal to
transfer on a monthly basis the balance in each utility's TRA to the utility's
TCBA. The accounting changes are retroactive to January 1, 1998. The Utility
believes the CPUC is retroactively transforming the undercollected power
purchase costs in the TRA into transition costs in the TCBA. However, the CPUC
characterized the accounting changes as merely reducing the prior revenues
recorded in the TCBA, thereby affecting only the amount of transition cost
recovery achieved to date. The CPUC also ordered that the utilities restate
and record their generation memorandum accounts balances to the TRA on a
monthly basis before any transfer of generation revenues to the TCBA. The CPUC
found that based on the accounting changes, the conditions for meeting the end
of the rate freeze have not been met.

   The Utility believes the adoption of TURN's proposed accounting changes
results in illegal retroactive ratemaking and constitutes an unconstitutional
taking of the Utility's property, and violates the federal filed rate
doctrine. The Utility also believes the other CPUC decisions are similarly
illegal to the extent they would compel the Utility to make payments to the
DWR and QFs without providing adequate revenues for such payments. The Utility
plans to challenge the decisions in appropriate legal forums.

   PG&E Corporation and the Utility recognized a fourth quarter charge to
earnings of $6.9 billion ($4.1 billion after tax) to reflect the fact that the
Utility could no longer conclude that its generation-related regulatory assets
and undercollected purchased power costs were probable of recovery from
ratepayers. Further, absent a regulatory judicial, or legislative solution,
the Utility cannot conclude that any power purchase costs it incurs during
2001 in excess of revenues from retail rates are probable of recovery through
future rates.

   Retail Direct Access. Customers participating in direct access may purchase
their electric power directly either through (1) competing non-utility retail
electric providers such as brokers, marketers, aggregators, or other
retailers, or (2) direct negotiated contracts with electric generators. Energy
service providers (ESPs) supplying the direct access market had three billing
options: (1) consolidated energy supplier billing, under which the utility
bills the energy supplier for the services provided directly by the utility to
the customer, and the supplier, in turn, provides a consolidated bill to the
customer, (2) consolidated distribution company billing, under which the
utility places the supplier's energy charge on a distribution bill, or (3)
dual billing, under which the energy supplier and the utility bill separately
for their own services. All customers (with limited exceptions), whether they
choose direct access or not, were required to pay the nonbypassable CTC to be
collected by their distribution utility in connection with recovery of the
utilities' transition costs. The majority of direct access customers have been
small commercial and large industrial customers. In light of the California
electricity crisis, many ESPs have returned their direct access customers to
Utility service. As of March 30, 2001, the Utility only had 36,641 direct
access customers. AB 1X provides that, at a time to be determined by the CPUC,
the right of retail customers to procure service from other ESPs will be
suspended until the DWR no longer supplies power for retail end use customers.
There may be further legislation to address direct access.

   Pursuant to CPUC regulations, the Utility has provided a PX energy credit
to direct access customers. As wholesale power prices began to increase
beginning in June 2000, the level of PX credits increased correspondingly to
the point where the credits exceeded the Utility's distribution and
transmission charges to direct access customers. Although the Utility paid
approximately $39 million in PX credits, the Utility has ceased

                                      21
<PAGE>

paying these credits. The Utility believes whether these credits are owed, and
if so in what amount, may be affected by the resolution of when the rate
freeze ended (the Utility believes its rate freeze ended as early as May 2000
depending on the final valuation of the Utility's hydroelectric generating
assets) and by whether the FERC ultimately orders refunds of wholesale prices
which have been found by the FERC to be unjust and unreasonable. As of March
29, 2001, the estimated total of accumulated credits potentially owing to
direct access customers that have not been paid by the Utility may be as high
as $503 million. Three ESPs have filed complaints against the Utility at the
CPUC arguing that the Utility violated CPUC orders and demanding payment for
credits accumulated for their customers. The large PX credits have reduced
revenues which, along with high PX costs, have contributed to the under-
collection in the Utility's TRA.

                                      22
<PAGE>

Electric Operating Statistics

   At December 31, 2000, the Utility served approximately 4.6 million electric
distribution customers.

   The following table shows the Utility's operating statistics (excluding
subsidiaries) for electric energy sold, including the classification of sales
and revenues by type of service. Before August 2000, the Utility was required
to buy from the PX all electricity needed to provide service to retail
customers that continue to choose the Utility as their electricity supplier.

<TABLE>
<CAPTION>
                             2000        1999        1998        1997        1996
                          ----------  ----------  ----------  ----------  ----------
<S>                       <C>         <C>         <C>         <C>         <C>
Customers (average for
 the year):
 Residential............   4,071,794   4,017,428   3,962,318   3,915,370   3,874,223
 Commercial.............     471,080     474,710     469,136     465,461     459,001
 Industrial.............       1,300       1,151       1,093       1,121       1,248
 Agricultural...........      78,439      85,131      85,429      86,359      87,250
 Public street and
  highway lighting......      23,339      20,806      18,351      17,955      17,583
 Other electric
  utilities.............           8           0          14          47          28
                          ----------  ----------  ----------  ----------  ----------
  Total.................   4,645,960   4,599,226   4,536,341   4,486,313   4,439,333
                          ==========  ==========  ==========  ==========  ==========
Sales-kWh (in millions):
 Residential............      28,753      27,739      26,846      25,946      25,458
 Commercial.............      31,761      30,426      28,839      28,887      27,868
 Industrial(1)..........      16,899      16,722      16,327      16,876      15,786
 Agricultural(1)........       3,818       3,739       3,069       3,932       3,631
 Public street and
  highway lighting......         426         437         445         446         438
 Other electric
  utilities.............         266         167       2,358       3,291       1,213
                          ----------  ----------  ----------  ----------  ----------
  Total energy
   delivered............      81,923      79,230      77,884      79,378      74,394
                          ==========  ==========  ==========  ==========  ==========
Revenues (in thousands):
 Residential............  $3,007,675  $2,961,788  $2,891,424  $3,082,013  $3,033,613
 Commercial.............   2,693,316   2,837,111   2,793,336   2,932,560   2,840,101
 Industrial.............     509,486     863,951     933,316   1,028,378   1,005,694
 Agricultural...........     385,961     391,876     350,445     413,711     396,469
 Public street and
  highway lighting......      43,403      49,209      51,195      53,183      55,372
 Other electric
  utilities.............      26,269      16,501      50,166     118,781      81,855
  Revenues from energy
   deliveries...........   6,666,110   7,120,436   7,069,882   7,628,626   7,413,104
 Miscellaneous..........     194,947     162,105     161,156      (9,439)    112,303
 Regulatory balancing
  accounts..............      (6,765)    (50,780)    (40,408)     71,441    (365,192)
                          ----------  ----------  ----------  ----------  ----------
  Operating revenues....  $6,854,292  $7,231,761  $7,190,630  $7,690,628  $7,160,215
                          ==========  ==========  ==========  ==========  ==========

   The following table shows certain customer information:

<CAPTION>
                             2000        1999        1998        1997        1996
Selected Statistics:      ----------  ----------  ----------  ----------  ----------
<S>                       <C>         <C>         <C>         <C>         <C>
 Average annual
  residential usage
  (kWh).................       7,062       6,905       6,776       6,627       6,571
 Average billed revenues
  per kWh (cents per
  kWh):
  Residential...........       10.46       10.68       10.77       11.88       11.92
  Commercial............        8.48        9.32        9.69       10.15       10.19
  Industrial(1).........        3.02        5.17        5.72        6.09        6.37
  Agricultural(1).......       10.11       10.48       11.42       10.52       10.92
 Net plant investment
  per customer ($)......       1,969       2,388       2,705       3,027       3,198
</TABLE>
--------
(1) Beginning April 1998, the sales-kWh and average billed revenues per kWh
    include electricity provided to direct access customers where the Utility
    does not earn commodity charges.

                                      23
<PAGE>

Electric Resources

   The Utility's sources of generation during 2000 were as follows: 15% from
the Utility's hydroelectric assets, 21% from the Utility's nuclear facilities
at Diablo Canyon, 1% from the Utility's fossil-fueled plants, and 63% from QFs
and other power suppliers. In 1995, the CPUC issued a decision which required
the Utility to "file a plan to voluntarily divest [itself] of at least 50% of
[its] fossil generating assets." As an incentive to divest, the CPUC reduced
the rate of return on the Utility's generating assets, including its
hydroelectric generation assets and Diablo Canyon, to 6.77%. The Utility has
sold all but two of its fossil-fueled electric generating plants and has sold
all of its geothermal generating facilities. The Utility's own generation
resources and contracted for generation resources serve approximately 36% of
the Utility's retail electric customers.

   Until December 15, 2000, the Utility was required to sell all of its owned
generation, and generation purchased by the Utility under long-term contracts
with QFs and other power providers, to the PX. The December 15, 2000 FERC
order eliminated the requirement that the California investor-owned utilities
sell all of their generation into (and buy all of their energy needs from) the
PX. The PX suspended the Utility's trading privileges on January 19, 2001 and
the PX markets were suspended as of January 31, 2001. Since January 31, 2001,
the Utility has been scheduling its own generation through the ISO for use by
the Utility's customers. The remainder of the power needed to serve the
Utility's customers has been purchased by the DWR or the ISO.

Generating Capacity

   Except as otherwise noted below, as of December 31, 2000, Pacific Gas and
Electric Company owned and operated the following generating plants, all
located in California, listed by energy source:

<TABLE>
<CAPTION>
                                                        Number     Net
                                                          of    Operating
      Generation Type             County Location       Units  Capacity kW
      ---------------             ---------------       ------ -----------
<S>                         <C>                         <C>    <C>
Hydroelectric:
 Conventional Plants....... 16 counties in Northern and  107    2,684,100
                            Central California
 Helms Pumped Storage
  Plant.................... Fresno                         3    1,212,000
                                                         ---    ---------
   Hydroelectric Subtotal..                              110    3,896,100
                                                         ---    ---------
Steam Plants:
 Humboldt Bay.............. Humboldt                       2      105,000
 Hunters Point(1).......... San Francisco                  3      377,000
                                                         ---    ---------
   Steam Subtotal..........                                5      482,000
                                                         ---    ---------
Combustion Turbines:
 Hunters Point(1).......... San Francisco                  1       52,000
 Mobile Turbines(2)........ Humboldt and Mendocino         3       45,000
                                                         ---    ---------
   Combustion Turbines
    Subtotal...............                                4       97,000
                                                         ---    ---------
Nuclear:
 Diablo Canyon............. San Luis Obispo                2    2,174,000
                                                         ---    ---------
   Total...................                              121    6,649,100
                                                         ===    =========
</TABLE>
--------
(1) In July 1998, the Utility reached an agreement with the City and County of
    San Francisco regarding the Hunters Point fossil-fueled power plant, which
    the ISO has designated as a "must run" facility. The agreement expresses
    the Utility's intention to retire the plant when it is no longer needed by
    the ISO.
(2) Listed to show capability; subject to relocation within the system as
    required.

   The Utility is interconnected with electric power systems in 14 Western
states, Alberta and British Columbia, Canada, and Mexico.


                                      24
<PAGE>

   Hydroelectric Generation Assets

   The Utility's hydroelectric system consists of 110 generating units at 68
powerhouses with a total generating capacity of 3,896 megawatts (MW). The
system includes 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals,
44 miles of flumes, 135 miles of tunnels, 19 miles of pipe, and 5 miles of
natural waterways. The system also includes 94 contracts for water rights and
163 statements of water diversion and use.

   Under AB 1890 all generation assets must be market-valued by December 31,
2001 through appraisal, sale or other divestiture. In 1999, the Utility filed
an application with the CPUC to determine the market value of the Utility's
hydroelectric generation facilities and related assets through an open
competitive auction similar to the auction process used in the previous sales
of the Utility's fossil fueled and geothermal plants. In November 2000, the
CPUC's draft environmental impact report (EIR) reviewing the potential
environmental impacts of the proposed auction under the California
Environmental Quality Act (CEQA) was issued.

   As an alternative to the auction proposal, in August 2000, the Utility and
other parties filed an application with the CPUC for approval of a settlement
under which the hydroelectric facilities would be transferred to a California-
based affiliate of PG&E Corporation at a value of $2.8 billion, subject to a
40-year revenue sharing agreement. In November 2000, the Utility withdrew its
support from the settlement. In December 2000, the Utility submitted updated
testimony in the valuation proceedings indicating that the market value of the
hydroelectric assets ranges from $3.9 billion to $4.2 billion assuming that
the assets were sold in a competitive auction or other arm's-length sale.
Updated joint testimony was also submitted by the CPUC's Office of Ratepayer
Advocates (ORA), TURN, and the California Farm Bureau Federation (CFBF). These
parties had previously submitted joint testimony in which they recommended a
valuation of $2.665 billion assuming the hydroelectric facilities would be
retained by the Utility. Their updated testimony estimates that recent higher
market prices result in an increase in the value of the assets by
approximately $943 million, although they do not recommend any change to their
previous valuation of $2.665 billion. Instead, they recommend that ratepayers
receive all future operating profits from hydroelectric generation operations,
which, based on higher price forecasts, will ensure that ratepayers obtain the
full value of the assets. Further, the joint parties recommend that the amount
of the final market valuation that exceeds book value be used to reduce the
Utility's undercollected wholesale power purchase costs recorded in the
Utility's TRA rather than crediting the Utility's TCBA. The Utility has
opposed this proposal, as it would unlawfully delay the completion of
transition cost recovery by the Utility as well as delay the end of the rate
freeze.

   In response to the California wholesale electricity crisis, in January
2001, the California Governor signed Assembly Bill 6 (AB6) which prohibits
public utilities from disposing of any generation facility before January 1,
2006. In light of AB6, the hydroelectric valuation proceeding will no longer
address the disposition of the hydroelectric facilities. On February 21, 2001,
the Utility requested that the CPUC suspend the CEQA review in light of AB6.
Absent a resolution suspending the CEQA review, the Utility provided comments
on the draft EIR on March 9, 2001.

   In its rate stabilization proceeding, the Utility has proposed to defer
receiving a portion of its share of profits from its hydroelectric plants
until a later time and allow those funds instead to be used to offset
uncollected power purchase costs. The Utility has proposed that for the next
two years (after which the Utility expects the current supply shortage will be
less critical), the Utility sell the output of these facilities directly to
its retail distribution customers on an incentive ratemaking basis to lower
the costs of procured power for such customers.

   Diablo Canyon Nuclear Power Plant

   Diablo Canyon consists of two nuclear power reactor units, each capable of
generating up to approximately 26 million kilowatt-hours (kWh) of electricity
per day. Diablo Canyon Units 1 and 2 began commercial operation in May 1985
and March 1986, respectively. The operating license expiration dates for
Diablo Canyon Units 1 and 2 are September 2021 and April 2025, respectively.
As of December 31, 2000, Diablo Canyon Units 1 and 2 had achieved lifetime
capacity factors of 82% and 84%, respectively.


                                      25
<PAGE>

   The table below outlines Diablo Canyon's refueling schedule for the next
five years. Diablo Canyon refueling outages typically are scheduled every 19
to 21 months. The schedule below assumes that a refueling outage for a unit
will last approximately 35 days, depending on the scope of the work required
for a particular outage. The schedule is subject to change in the event of
unscheduled plant outages.

<TABLE>
<CAPTION>
                                           2001  2002   2003     2004     2005
                                           ----- ---- -------- -------- --------
<S>                                        <C>   <C>  <C>      <C>      <C>
Unit 1
  Refueling...............................       May           February October
  Startup.................................       June           March   November
Unit 2
  Refueling............................... April      February October
  Startup................................. June        March   November
</TABLE>

   Diablo Canyon Ratemaking. Since January 1, 1997, the Utility's sunk costs
in Diablo Canyon have been recovered from ratepayers through a sunk cost
revenue requirement, at a reduced return on common equity equal to 6.77% that
will remain in effect through the end of the transition period. (Sunk costs
are costs associated with the facility that are fixed and unavoidable.) The
Diablo Canyon sunk costs revenue requirement is being recovered as a
transition cost through the TCBA. In connection with the new ratemaking, the
CPUC ordered that a financial verification audit of Diablo Canyon plant
accounts be performed by an independent accounting firm, and that the CPUC
hold a proceeding to review the results of the audit, including any proposed
adjustments to Diablo Canyon accounts, following the completion of the audit.
The audit was completed in August 1998. In September 2000, the CPUC issued a
decision that concluded that because the audit found that Diablo Canyon costs
are presented fairly, no further action would be taken and the proceeding
would be closed.

   Also since January 1, 1997, a performance-based Incremental Cost Incentive
Price (ICIP) mechanism has been used to recover Diablo Canyon's operating
costs and the cost of capital additions incurred after December 31, 1996. The
ICIP mechanism establishes a rate per kWh generated by the facility for the
period 1997 through 2001. The CPUC-authorized ICIP price for 2001 is 3.49
cents per kWh, resulting in estimated ICIP revenues of $552 million based on
an assumed capacity factor of 83.6%. The estimated sunk cost revenue
requirement for 2001 is approximately $1.1 billion. Any variance between ICIP
revenues and related costs is reflected in earnings.

   After the transition period, Diablo Canyon generation must be sold at the
prevailing market price for power. Further, pursuant to the 1997 CPUC decision
establishing the ICIP, the Utility is required to begin sharing 50% of the net
benefits of operating Diablo Canyon with ratepayers beginning after the
transition period. In June 2000, the Utility filed an application with the
CPUC requesting approval of its proposal for sharing with ratepayers 50% of
the post-rate freeze net benefits of operating Diablo Canyon. The net benefit
sharing methodology proposed in the Utility's application would be effective
at the end of the current electric rate freeze for the Utility's customers and
would continue for as long as the Utility owned Diablo Canyon. Under the
proposal, the Utility would share the net benefits of operating Diablo Canyon
based on the audited profits from operations, determined consistent with the
prior CPUC decision. If Diablo Canyon experiences losses, such losses would be
accrued and netted against profits in the calculation of the net benefits in
subsequent periods (or against profits in prior periods if subsequent profits
are insufficient to offset such losses). Any changes to the net sharing
methodology would have to be approved by the CPUC. However, the CPUC has
suspended the proceeding to consider the net benefit sharing methodology. In
the Utility's rate stabilization proceeding (see "Electric Ratemaking" above),
parties have proposed that the requirement to establish a sharing methodology
be rescinded and that Diablo Canyon be placed on cost of service ratemaking.
It is uncertain what future ratemaking will be applicable to Diablo Canyon.

   Nuclear Fuel Supply and Disposal. The Utility has purchase contracts for,
and inventories of, uranium concentrates, uranium hexaflouride, and enriched
uranium, as well as one contract for fuel fabrication. Based on current Diablo
Canyon operations forecasts and a combination of existing contracts and
inventories, the requirement for uranium supply will be met through 2004, the
requirement for the conversion of uranium to

                                      26
<PAGE>

uranium hexaflouride will be met through 2001, and the requirement for the
enrichment of the uranium hexaflouride to enriched uranium will be met through
2002. The fuel fabrication contract for the two units will supply their
requirements for the next seven operating cycles of each unit. These contracts
are intended to ensure long-term fuel supply, but permit the Utility the
flexibility to take advantage of short-term supply opportunities. In most
cases, the Utility's nuclear fuel contracts are requirements-based, with the
Utility's obligations linked to the continued operation of Diablo Canyon.

   Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the DOE is
responsible for the transportation and ultimate long-term disposal of spent
nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act,
utilities are required to provide interim storage facilities until permanent
storage facilities are provided by the federal government. The Nuclear Waste
Act mandates that one or more such permanent disposal sites be in operation by
1998. Consistent with the law, Pacific Gas and Electric Company signed a
contract with the DOE providing for the disposal of the spent nuclear fuel and
high-level radioactive waste from the Utility's nuclear power facilities
beginning not later than January 1998. However, due to delays in identifying a
storage site, the DOE has been unable to meet its contract commitment to begin
accepting spent fuel by January 1998. Further, under the DOE's current
estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel may
not be accepted by the DOE for interim or permanent storage before 2010, at
the earliest. At the projected level of operation for Diablo Canyon, the
Utility's facilities are sufficient to store on-site all spent fuel produced
through approximately 2006 while maintaining the capability for a full-core
off-load. It is likely that an interim or permanent DOE storage facility will
not be available for Diablo Canyon's spent fuel by 2006. The Utility is
examining options for providing additional temporary spent fuel storage at
Diablo Canyon or other facilities, pending disposal or storage at a DOE
facility.

   In July 1988, the NRC gave final approval to the Utility to store
radioactive waste from the nuclear generating unit (Unit 3) at Humboldt Bay
Power Plant (Humboldt) at Humboldt before ultimately decommissioning the unit.
The Utility has agreed to remove all spent fuel when the federal disposal site
is available.

   Insurance. The Utility has insurance coverage for property damage and
business interruption losses as a member of Nuclear Electric Insurance Limited
(NEIL). NEIL, which is owned by utilities with nuclear generating facilities,
provides insurance coverage against property damage, decontamination,
decommissioning, and business interruption and/or extra expenses during
prolonged accidental outages for reactor units in commercial operation. Under
these insurance policies, if the nuclear generating facility of a member
utility suffers a loss due to a prolonged accidental outage, the Utility may
be subject to maximum retrospective premium assessments of $12 million
(property damage) and $4 million (business interruption), in each case per
one-year policy period, if losses exceed the resources of NEIL.

   The Price-Anderson Act, as amended by Congress in 1988 (Price Act), limits
public liability claims that could arise from a nuclear incident to a maximum
of $9.5 billion per incident. The Price Act requires that all nuclear
utilities share in the payment for nuclear liability claims resulting from a
nuclear incident. The Utility has purchased primary insurance of $200 million
for public liability claims resulting from a nuclear incident. An additional
$9.3 billion of coverage is provided by secondary financial protection
required by federal law and provides for loss sharing among utilities owning
nuclear generating facilities if a costly incident occurs. If a nuclear
incident results in claims in excess of $200 million, the Utility may be
assessed up to $176 million per incident, with payments in each year limited
to a maximum of $20 million per incident.

   Decommissioning. The Utility's estimated total obligation to decommission
and dismantle its nuclear power facilities is $1.7 billion in 2000 dollars
($5.1 billion in future dollars). This estimate, which includes labor,
materials, waste disposal charges, and other costs, is based on a 1997
decommissioning cost study. A contingency to capture engineering, regulatory,
and business environment changes is included in the total estimated
obligation. Actual decommissioning costs are expected to vary from this
estimate because of changes in the assumed dates of decommissioning,
regulatory requirements, and technology, as well as differences in the amount
of labor, materials, and equipment needed to complete decommissioning. The
estimated total obligation needed to complete decommissioning is recognized
proportionately over the license term of each facility.

                                      27
<PAGE>

   Nuclear decommissioning costs recovered in rates are placed in external
trusts. The funds in these trusts, along with accumulated earnings, will be
used exclusively for decommissioning and dismantling the nuclear facilities.
The trusts maintain substantially all of their investments in debt and equity
securities. All earnings on the funds held in the trusts, net of authorized
disbursements from the trusts and management and administrative fees, are
reinvested. Monies may not be released from the external trusts until
authorized by the CPUC. In December 1997, the CPUC granted the Utility's
request for authority to disburse up to $15.7 million from the Humboldt Bay
Power Plant decommissioning trusts to finance three partial nuclear
decommissioning projects at Humboldt Unit 3. Accordingly, as of December 31,
2000, $9.3 million ($15.7 million less $6.4 million in expected tax benefits)
has been disbursed from the Humboldt Unit 3 non-tax-qualified trust to
reimburse the Utility for nuclear decommissioning expenses associated with the
partial decommissioning projects. The remaining $6.4 million of the approved
expenses will be disbursed only if the Internal Revenue Service (IRS)
disallows the expected tax benefits. In February 2000, the CPUC granted the
Utility's request to disburse an additional amount of up to $7 million from
the Humboldt Bay Power Plant decommissioning trusts to explore licensing and
permitting of an on-site dry cask storage facility for the spent nuclear fuel
that would allow early decommissioning of Humboldt Bay Power Plant Unit 3. As
of December 31, 2000, $1.7 million ($2.9 million project cost less $1.2
million in expected tax benefits) has been disbursed from the Humboldt Unit 3
non-tax-qualified trust to reimburse the Utility for nuclear decommissioning
expenses associated with the dry cask storage facility. Additional licensing
and permitting activities are continuing.

   As of December 31, 2000, the Utility had accumulated external trust funds
with an estimated liquidation value of $1.36 billion, based on quoted market
prices and net of deferred taxes on unrealized gains, to be used for the
decommissioning of the Utility's nuclear facilities.

   The amount recovered in rates for nuclear decommissioning costs is
authorized by the CPUC as part of the GRC. The CPUC considers the trusts'
asset levels, together with revised earnings and decommissioning cost
assumptions, to determine the amount of decommissioning costs it will
authorize in rates for contribution to the trusts. The monies contributed to
the decommissioning trusts, together with existing trust fund balances and
projected earnings, are intended to satisfy the estimated future obligation
for decommissioning costs. For the year ended December 31, 2000, annual
nuclear decommissioning trust contributions collected in rates were
$26.47 million. Of this amount, the Utility was able to contribute only $14
million to the trusts in 2000 due to the Utility's liquidity crisis. The
Utility expects that it will be required to refund the difference to customers
in 2001. The Utility has filed for a new schedule of ruling amount (SRA) with
the IRS that would lower the amount collected through rates to $24 million.
The IRS has not yet approved the Utility's proposed SRA. If approved, the
difference between the previous amount collected in rates and the new amount
would be refunded to customers.

   Since January 1, 1998, nuclear decommissioning costs, which are not
transition costs, have been recovered through a nonbypassable charge that will
continue until those costs are fully recovered. Recovery of decommissioning
costs may be accelerated to the extent possible under the rate freeze. The
CPUC has established a Nuclear Decommissioning Costs Triennial Proceeding to
determine the decommissioning costs and to establish the annual revenue
requirement and attrition factors over subsequent three-year periods.

Other Electric Resources

   QF Generation and Other Power Purchase Contracts. The Utility is required
by CPUC decisions to purchase electric energy and capacity provided by
independent power producers that are qualifying facilities (QFs) under the
Public Utility Regulatory Policies Act of 1978 (PURPA). The CPUC required
California utilities to enter into a series of QF long-term power purchase
agreements (PPAs) and approved the applicable terms, conditions, price
options, and eligibility requirements. The PPAs require the Utility to pay for
energy and capacity. Energy payments are based on the QF project's actual
electrical output and capacity payments are based on the QF project's total
available capacity and contractual capacity commitment. Capacity payments may
be reduced if the facility does not meet the performance requirements
specified in the PPAs.


                                      28
<PAGE>

   Until December 15, 2000, the Utility was required to schedule into the PX
all of the electric power generated by QFs and other providers that the
Utility is required to purchase under existing contractual commitments. (The
December 15, 2000 FERC order eliminated this mandatory sell requirement.) The
Utility has paid these suppliers directly pursuant to price provisions
contained in their PPAs. The invoices sent by the PX for the cost to serve the
Utility's retail customers included credits for power provided by these
suppliers based on electric market prices.

   In general, before the steep increase in wholesale power prices that began
in June 2000, the price for energy payments under QF contracts was higher than
the market price. The amount of the contract payment exceeding the market
price is recoverable as a transition cost. Under Section 390(c) of the Public
Utilities Code (PUC) adopted in AB 1890 and implemented by a November 1999
CPUC decision, QFs could make a one-time election to receive energy payments
based on the PX day ahead market clearing price, on an interim basis and
subject to true-up, instead of receiving short-run avoided costs energy
payments based on the "transition formula" adopted by AB 1890 and set forth in
PUC Section 390(b). Those that elected not to exercise this option continued
to receive PPA payments based on the Utility's short-run avoided costs. As the
wholesale market price of power rose dramatically, many QFs elected to receive
PX-based payments, causing the Utility's procurement costs to increase
significantly. For the period from June 2000 through December 2000, energy
costs for deliveries from QFs who switched to PX pricing were approximately
$375 million more than these QFs would have received under the transition
formula. On January 10, 2001, the Utility filed an emergency motion with the
CPUC requesting that the CPUC true-up payments made to switching QFs since
June 2000 to the Utility's "transition formula" short-run avoided cost energy
rates or, in the alternative, to PX-based rates capped at $67.45 per megawatt-
hour. On February 22, 2001, the CPUC issued a decision ordering that QFs that
had exercised their one-time option to switch to PX-pricing would be paid
short-run avoided cost energy payments based on the transition formula
effective on January 19, 2001.

   The Utility paid approximately 15 percent of amounts due QFs for deliveries
made in December 2000 and January 2001. The Utility made no payment for QF
deliveries received in February 2001. On March 27, 2001, the CPUC issued a
decision requiring the Utility and the other California investor-owned
utilities to pay QFs fully for energy deliveries made on and after the date of
the decision. The CPUC decision requires the Utility to pay QFs for energy and
capacity deliveries within 15 days following the current monthly billing
period instead of the 30 days after the close of the billing period required
by the PPAs. The CPUC stated that its change to the payment provision was
required to maintain energy reliability in California. The CPUC held that a
failure to make a required payment would result in a fine in the amount owed
to the QF. The decision also adopts a revised pricing formula relating to the
California border price of gas applicable to energy payments to all QFs,
including those that do not use natural gas as a fuel. Based on the Utility's
preliminary review of the decision, the revised pricing formula would reduce
the Utility's 2001 average QF energy and capacity payments from approximately
12.7 cents per kWh to 12.3 cents per kWh.

   Most of the PPAs expire on various dates through 2028, though some have no
stated expiration date. Deliveries from these power producers account for
approximately 23% of the Utility's 2000 electric energy requirements and no
single contract accounted for more than 5% of the Utility's energy needs.

   As of December 31, 2000, the Utility had commitments to purchase
approximately 5,200 MW of capacity under CPUC-mandated PPAs. Of the 5,200 MW,
approximately 4,400 MW are operational. Development of the majority of the
balance is uncertain and it is estimated that very few of the remaining
contracts will become operational. The 4,400 MW of operational capacity
consists of 2,700 MW from cogeneration projects, 700 MW from wind projects,
and 1,000 MW from other projects, including biomass, waste-to-energy,
geothermal, solar, and hydroelectric.

   The Utility also has contracts with various irrigation districts and water
agencies to purchase hydroelectric power. Under these contracts, the Utility
must make specified semi-annual minimum payments whether or not any energy is
supplied (subject to the supplier's retention of the FERC's authorization) and
variable payments for operation and maintenance costs incurred by the
suppliers. These contracts expire on various dates from 2004

                                      29
<PAGE>

to 2031. Costs associated with these contracts to purchase power are eligible
for recovery by the Utility as transition costs through the collection of the
nonbypassable CTC. At December 31, 2000, the undiscounted future minimum
payments under these contracts are approximately $31.5 million for each of the
years 2001 through 2004 and a total of $221 million for periods thereafter.
Irrigation district and water agency deliveries in the aggregate account for
approximately 4.6% of the Utility's 2000 electric energy requirements.

   The amount of energy received and the total payments made under all these
power purchase contracts were:

<TABLE>
<CAPTION>
                                                     2000   1999   1998   1997
                                                    ------ ------ ------ ------
                                                          ($ in millions)
<S>                                                 <C>    <C>    <C>    <C>
Kilowatt-hours received............................ 25,446 25,910 25,994 24,389
Energy payments.................................... $1,549 $  837 $  943 $1,157
Capacity payments.................................. $  519 $  539 $  529 $  538
Irrigation district and water agency payments...... $   56 $   60 $   53 $   56
</TABLE>

   Bilateral Agreements. Until August 2000, CPUC decisions required the
Utility to purchase power for its retail customers solely through the PX and
ISO. On July 21, 2000, the Utility filed an emergency motion with the CPUC
seeking authorization to enter into bilateral agreements directly with third
parties to purchase power, capacity, and ancillary services, citing the need
to better hedge against high power prices in the PX day-ahead and ISO real-
time markets and to introduce new supply into California. In its July 2000
request, the Utility proposed that the CPUC adopt prospective reasonableness
standards which would allow the CPUC to determine at the time of inception
whether a transaction was reasonable per se compared to specific market
prices. Without such prospective reasonableness standards, the CPUC can
second-guess the Utility's decision to enter into contracts and disallow some
or all of those costs deemed after-the-fact to be "unreasonable."

   On August 3, 2000, the CPUC approved the Utility's emergency motion and
allowed the Utility to enter into bilateral contracts, subject to previous
limits established for BFM purchases (i.e., used to cover the Utility's net
open position), provided that all such contracts must expire on or before
December 31, 2005. The CPUC's approval of bilateral contracting authority was
subject to agreement on implementation details, such as appropriate pricing
benchmarks, with ORA and the CPUC's Energy Division. ORA and the Energy
Division rejected the Utility's proposed standards and neither has suggested
alternative standards. Despite this stalemate, during September and October
2000, the Utility held an auction soliciting offers for energy purchases at
fixed prices for one to five years. In October 2000, the Utility entered into
bilateral power purchase contracts with several suppliers. In December 2000,
the Utility again solicited offers from power suppliers, but the responses
were priced above then-current market prices so the Utility elected not to
enter into any contracts at that time. The downgrade of the Utility's credit
ratings since December 2000 has effectively barred the Utility from entering
into additional long-term contracts.

   In its December 15, 2000 order, the FERC noted that it was critical for the
CPUC to give timely and predictable approval of the prudence of a balanced
portfolio of short- and long-term contracts. On December 22, 2000, the CPUC
issued a decision requesting comments from interested parties on a set of
reasonableness standards proposed in the decision. In this decision, the CPUC
proposed price benchmarks which were well below the then current market
prices, making it impossible for the Utility to enter into bilateral purchases
which the CPUC could deem reasonable. The Utility filed comments to the
proposed decision objecting to the proposed standards as unworkable. In
January 2001, the CPUC issued another proposed decision adopting similar
unrealistic price benchmarks for bilateral purchases. Again, the Utility filed
comments expressing its concerns with the new draft decision. It is uncertain
whether or when the CPUC will issue appropriate realistic reasonableness
standards.

   Electric Transmission and Distribution

   To transport energy to load centers, Pacific Gas and Electric Company as of
December 31, 2000 owned approximately 18,376 circuit miles of interconnected
transmission lines of 60 kilovolts (kV) to 500 kV and

                                      30
<PAGE>

transmission substations having a capacity of approximately 39,859,000
kilovolt-amperes (kVA), including spares, excluding power plant
interconnection facilities. Energy is distributed to customers through
approximately 115,131 circuit miles of distribution system and distribution
substations having a capacity of approximately 23,524,000 kVA.

   In connection with electric industry restructuring, in 1998 the utilities
relinquished control, but not ownership, of their transmission facilities to
the ISO. The FERC has jurisdiction over the transmission facilities and
revenue requirements and rates for transmission service are set by the FERC.
The ISO commenced operations on March 31, 1998. The ISO, regulated by the
FERC, controls the operation of the transmission system and provides open
access transmission service on a nondiscriminatory basis. As control area
operator, the ISO is also responsible for assuring the reliability of the
transmission system.

   In 1998, the FERC approved the forms of agreements for reliability must-run
(RMR) generating facilities that have been entered into between RMR facility
owners and the ISO to ensure grid reliability and avoid the exercise of local
market power. The costs of RMR contracts attributed to supporting the
Utility's historic transmission control area are charged to the Utility as a
Participating Transmission Owner (PTO). These costs, which were approximately
$178 million in 2000, are currently recovered from the Utility's retail
customers and, subject to the outcome of current FERC proceedings, wholesale
transmission customers.

   In March 2000, the ISO filed an application with the FERC seeking to
establish its own Transmission Access Charge (TAC) as directed in AB 1890. The
FERC accepted the ISO's TAC filing, subject to refund, but suspended the
proceeding to allow the parties to enter into settlement discussions. In late
December 2000, the ISO made a further implementation filing, also accepted by
the FERC subject to refund, to establish specific TAC rates because a
transmission-owning municipality had applied to become a new PTO, thereby
triggering effectiveness of the ISO TAC rate methodology. The ISO's TAC
methodology provides for transition to a uniform statewide high voltage
transmission rate, based on the revenue requirements of all PTOs associated
with facilities operated at 200 kV and above. The TAC methodology also
requires original PTOs such as the Utility to pay certain increases incurred
by new PTOs resulting from joining the ISO during a 10-year transition period.
The Utility's obligation for this cost shift is currently capped at $32
million per year.

   The Utility has been working closely with the ISO to remedy transmission
constraints on the Utility's electric transmission system. Of particular
concern are the constraints on Path 15, which is located in the southern
portion of the Utility's service area, and serves as the part of the primary
transmission link between Northern and Southern California. At times, the
current facilities cannot accommodate all low-cost power intended to be
transmitted between Southern California (where the Utility's Diablo Canyon
nuclear power plant is located) and Northern California. This often results in
significant wholesale power price differentials between Northern and Southern
California with relatively high power prices in Northern California and
relatively low power prices in Southern California.

   The Utility's investment in maintenance and expansion of its transmission
system has been growing substantially over the past several years. The Utility
anticipates making an additional capital investment of approximately $260
million in its transmission system in 2001. Through the ISO's Long-Term Grid
Planning Process, the Utility annually files its transmission upgrade plans
and provides the ISO the opportunity to concur with the Utility's planned
upgrades.

   As a result of the ISO concluding that the available power reserves were
precipitously low, the ISO ordered the Utility to implement emergency
procedures in the Utility's service territory frequently during the summer
2000 and winter 2001, and as recently as March 2001. On some occasions these
measures included rolling outages affecting a large number of retail
customers. It is anticipated that a projected power supply shortage for peak
demand periods, including the summer of 2001, will result in further rolling
outages. To the extent conservation efforts are successful, the need for such
emergency measures may be lessened. Depending on the location of the available
power supply relative to the load, transmission constraints could exacerbate
the supply problem. Completion of the Utility's planned transmission projects
before the summer 2001 peak are expected to mitigate most of these
constraints.

                                      31
<PAGE>

   Most of the Utility's distribution services remain subject to CPUC
jurisdiction. The CPUC is considering whether it should pursue further reforms
in the structure and regulatory framework governing electricity distribution
service.

Gas Utility Operations

   Pacific Gas and Electric Company owns and operates an integrated gas
transmission, storage, and distribution system in California. The Utility
served approximately 3.8 million gas customers at December 31, 2000. Most of
these customers continue to obtain gas supplies from the Utility under
regulated tariff rates.

   The Utility offers transmission, distribution, and storage services as
separate and distinct services to its industrial and larger commercial gas
(non-core) customers. Customers have the opportunity to select from a menu of
services offered by the Utility and to pay only for the services that they
use. Access to the transmission system is possible for all gas marketers and
shippers, as well as non-core end users. The Utility's residential and smaller
commercial gas (core) customers can select the commodity gas supplier of their
choice. However, the Utility continues to purchase gas as a regulated supplier
for those core customers who request it.

   At December 31, 2000, the Utility's system consisted of approximately 6,261
miles of transmission pipelines, three gas storage facilities, and
approximately 37,958 miles of gas distribution lines. The Utility's
Line 400/401 interconnects with the natural gas transmission system of the
Utility's sister subsidiary, PG&E Gas Transmission, Northwest Corporation
(PG&E GTN). The PG&E GTN pipeline begins at the border of British Columbia,
Canada, and Idaho, and extends through northern Idaho, southeastern Washington
and central Oregon, and ends on the Oregon-California border where it connects
with the Utility's Line 400/401. The 840-mile combined Utility-PG&E GTN
pipeline provides about 2,700 million cubic feet per day (MMcf/d) of capacity.
More than 1,800 MMCf/d can be delivered to Northern and Southern California;
and the remaining capacity can be delivered to the Pacific Northwest. The
Utility's Line 300, which connects to the U.S. Southwest pipeline systems
(Transwestern, El Paso, and Kern River) owned by third parties has a capacity
of 1,140 MMcf/d. The Utility's underground gas storage facilities located at
McDonald Island, Los Medanos, and Pleasant Creek, have a total working gas
capacity of 98 billion cubic feet (Bcf).

   The Utility's peak day send-out of gas on its integrated system in
California during the year ended December 31, 2000, was 3,795 million cubic
feet (MMcf). The total volume of gas throughput during 2000 was approximately
937,000 MMcf, of which 281,000 MMcf was sold to direct end-use or resale
customers, 49,000 MMcf was used by the Utility primarily for its fossil-fueled
electric generating plants, and 606,000 MMcf was transported as customer-owned
gas.

   The California Gas Report, which presents the outlook for natural gas
requirements and supplies for California over a long-term planning horizon, is
prepared annually by the California electric and gas utilities. A
comprehensive biennial report is prepared in even-numbered years with a
supplemental report in intervening odd-numbered years updating recorded data
for the previous year.

   The 2000 California Gas Report updates the Utility's annual gas
requirements forecast (excluding bypass volumes) for the years 2000 through
2020, forecasting average annual growth in gas throughput served by the
Utility of approximately 1.4%. The gas requirements forecast is subject to
many uncertainties and there are many factors that can influence the demand
for natural gas, including weather conditions, level of utility electric
generation, fuel switching, and new technology. In addition, some large
customers, mostly in the industrial and enhanced oil recovery sectors, may
have the ability to use unregulated private pipelines or interstate pipelines,
bypassing the Utility's system entirely.

                                      32
<PAGE>

Gas Operating Statistics

   The following table shows Pacific Gas and Electric Company's operating
statistics (excluding subsidiaries) for gas, including the classification of
sales and revenues by type of service.

<TABLE>
<CAPTION>
                                         Years Ended December 31,
                          ---------------------------------------------------------
                             2000       1999        1998        1997        1996
                          ---------- ----------  ----------  ----------  ----------
<S>                       <C>        <C>         <C>         <C>         <C>
Customers (average for
 the year):
  Residential...........   3,642,266  3,593,355   3,536,089   3,491,963   3,455,086
  Commercial............     203,355    203,342     200,620     198,453     198,071
  Industrial............       1,719      1,625       1,610       1,650       1,500
  Other gas utilities...           6          4           5           3           2
                          ---------- ----------  ----------  ----------  ----------
     Total..............   3,847,346  3,798,326   3,738,324   3,692,069   3,654,659
                          ========== ==========  ==========  ==========  ==========
Gas supply--thousand
 cubic feet (Mcf) (in
 thousands):
  Purchased from
   suppliers in:
   Canada...............     216,684    230,808     298,125     280,084     253,209
   California...........      32,167     18,956      17,724      10,655      28,130
   Other states.........      75,834    107,226     122,342     131,074     110,604
                          ---------- ----------  ----------  ----------  ----------
     Total purchased....     324,685    356,990     438,191     421,813     391,943
  Net (to storage) from
   storage..............      19,420       (980)    (14,468)     14,160       6,871
                          ---------- ----------  ----------  ----------  ----------
     Total..............     344,105    356,010     423,723     435,973     398,814
  Pacific Gas and
   Electric Company use,
   losses, etc.(1)......      62,960     47,152     129,305     173,789     134,375
                          ---------- ----------  ----------  ----------  ----------
     Net gas for sales..     281,145    308,858     294,418     262,184     264,439
                          ========== ==========  ==========  ==========  ==========
Bundled gas sales and
 transportation
 service--Mcf
 (in thousands):
  Residential...........     210,515    233,482     223,706     191,327     190,246
  Commercial............      66,443     70,093      66,082      60,803      62,178
  Industrial............       4,146      5,255       4,616      10,054      12,015
  Other gas utilities...          41         28          14           0           0
                          ---------- ----------  ----------  ----------  ----------
     Total..............     281,145    308,858     294,418     262,184     264,439
                          ========== ==========  ==========  ==========  ==========
Transportation service
 only--Mcf (in
 thousands):
  Vintage system
   (Substantially all
   Industrial)(2).......     606,152    484,218     396,872     218,660     189,695
  PG&E Expansion (Line
   401)(3)..............           0          0           0     233,269     237,776
                          ---------- ----------  ----------  ----------  ----------
     Total..............     606,152    484,218     396,872     451,929     427,471
                          ========== ==========  ==========  ==========  ==========
Revenues (in thousands):
  Bundled gas sales and
   transportation
   service:
   Residential..........  $1,680,745 $1,542,705  $1,414,313  $1,170,135  $1,109,463
   Commercial...........     513,080    448,655     426,299     374,084     362,819
   Industrial...........      35,347     24,638      24,634      46,592      42,520
   Other gas utilities..           0         77       1,072       3,701         510
                          ---------- ----------  ----------  ----------  ----------
     Bundled gas
      revenues..........   2,229,172  2,016,075   1,866,318   1,594,512   1,515,312
  Transportation only
   revenue:
   Vintage system
    (Substantially all
    Industrial).........     324,319    267,544     232,038     207,160     180,197
   PG&E Expansion (Line
    401)................      13,392     19,091      42,194      90,180      85,144
                          ---------- ----------  ----------  ----------  ----------
  Transportation service
   only revenue.........     337,711    286,635     274,232     297,340     265,341
  Miscellaneous.........      84,526    (47,311)     41,364      50,295      (9,271)
  Regulatory balancing
   accounts.............     131,762   (259,648)   (448,351)   (137,787)     57,864
                          ---------- ----------  ----------  ----------  ----------
     Operating
      revenues..........  $2,783,171 $1,995,751  $1,733,563  $1,804,360  $1,829,246
                          ========== ==========  ==========  ==========  ==========
</TABLE>
--------
(1) Includes fuel for Pacific Gas and Electric Company's fossil-fueled
    generating plants.
(2) Does not include on-system transportation volumes transported on the PG&E
    Expansion of 4,833 MMcf, 1,251 MMcf, 34,169 MMcf, 72,958 MMcf, and 78,552
    MMcf for 2000, 1999, 1998, 1997, and 1996, respectively.
(3) Starting in 1998, Vintage system and PG&E Expansion are combined and
    reported as total transportation service.

                                      33
<PAGE>

<TABLE>
<CAPTION>
                                                  Years Ended December 31,
                                             ----------------------------------
                                              2000   1999   1998   1997   1996
                                             ------ ------ ------ ------ ------
<S>                                          <C>    <C>    <C>    <C>    <C>
Selected Statistics:
 Average annual residential usage (Mcf).....     59     65     63     55     55
 Heating temperature--% of normal (1).......  101.2  108.5   93.0   71.7   75.7
 Average billed bundled gas sales revenues
  per Mcf:
  Residential............................... $ 7.98 $ 6.61 $ 6.32 $ 6.12 $ 5.83
  Commercial................................   7.72   6.40   6.45   6.15   5.84
  Industrial................................   8.53   4.69   5.36   4.63   3.54
 Average billed transportation only revenue
  per Mcf:
  Vintage system............................   0.54   0.66   0.66   0.71   0.67
  PG&E Expansion (Line 401).................   2.04   0.53   0.54   0.39   0.36
  Net plant investment per customer (2)..... $1,003 $1,011 $1,040 $1,031 $1,061
</TABLE>
--------
(1) Over 100% indicates colder than normal.

Natural Gas Supplies

   The objective of Pacific Gas and Electric Company's Gas Procurement
Department is to maintain a balanced supply portfolio that provides supply
reliability and contract flexibility, minimizes costs, and fosters competition
among the Utility's gas suppliers. To ensure a diverse and competitive mix of
natural gas to serve the Utility's customers, the Utility purchases gas
directly from producers and marketers in both Canada and the United States.

   Due to the Utility's deteriorating financial condition resulting from the
dysfunctional California wholesale power market, in December 2000 and January
2001, several gas suppliers demanded prepayment, cash on delivery, or other
forms of payment assurance before they would deliver gas, instead of the
normal payment terms under which the Utility would pay for the gas after
delivery. As the Utility was unable to meet such demands at that time, several
gas suppliers refused to supply gas accelerating the depletion of the
Utility's gas storage reserves, and potentially accelerating the electric
power crisis if the Utility were required to divert gas from industrial users,
including natural gas fired power plant operators.

   The U.S. Secretary of Energy issued a temporary order on January 19, 2001,
requiring the gas suppliers to make deliveries to avoid a worsening natural
gas shortage emergency. However, this order expired on February 7, 2001, and
certain companies, representing about 10% of the Utility's natural gas
suppliers, terminated deliveries after the orders expired. The Utility tried
to mitigate the worsening supply situation by withdrawing more gas from
storage and, when able, purchasing additional gas on the spot market.
Additionally, on January 31, 2001, the CPUC authorized the Utility to pledge
its gas account receivables and its gas inventories for up to 90 days
(extended to 180 days in a CPUC draft decision issued on February 15, 2001) to
secure gas for its core customers. At March 29, 2001, the amount of gas
accounts receivables pledged was approximately $900 million. As of March 29,
2001, approximately 30% of the Utility's suppliers of natural gas had signed
security agreements with the Utility and discussions were continuing with the
Utility's other suppliers. Additionally, the Utility is currently implementing
a program to obtain longer-term summer and winter supplies and daily spot
supplies.

   The Utility has also filed an application with the CPUC to declare a gas
emergency, and require one of the Utility's larger gas suppliers to sell
incremental gas supplies to the Utility. The gas supplier has protested the
application. The CPUC is expected to rule on the application at its meeting on
April 19, 2001.

   Under current CPUC regulations, the Utility purchases natural gas from its
various suppliers based on economic considerations, consistent with
regulatory, contractual, and operational constraints. During the year ended
December 31, 2000, approximately 67% of the Utility's total purchases of
natural gas consisted of

                                      34
<PAGE>

Canadian-sourced gas transported by Canadian pipeline companies and PG&E GTN,
and Rocky Mountain-sourced gas transported by PG&E GTN, approximately 10% was
purchased in California, approximately 21% was purchased in the U.S. Southwest
and was transported primarily by the El Paso Natural Gas Company and
Transwestern Pipeline Company pipelines, and approximately 2% was purchased in
the Rocky Mountains and transported by Kern River Gas Transmission Company.
California purchases include supplies from various California producers and
supplies transported into California by others. The following table shows the
total volume and average price of gas in dollars per thousand cubic feet (Mcf)
purchased by the Utility from these sources during each of the last five
years.

<TABLE>
<CAPTION>
                               2000               1999               1998               1997               1996
                        ------------------ ------------------ ------------------ ------------------ ------------------
                        Thousands   Avg.   Thousands   Avg.   Thousands   Avg.   Thousands   Avg.   Thousands   Avg.
                         of Mcf   Price(1)  of Mcf   Price(1)  of Mcf   Price(1)  of Mcf   Price(1)  of Mcf   Price(1)
                        --------- -------- --------- -------- --------- -------- --------- -------- --------- --------
<S>                     <C>       <C>      <C>       <C>      <C>       <C>      <C>       <C>      <C>       <C>
Canada.................  216,684   $4.05    230,808   $2.50    298,125   $2.00    280,084   $1.77    253,209   $1.57
California.............   32,167    8.20     18,956    2.45     17,724    2.44     10,655    2.12     28,130    1.90
Other states
 (substantially all
 U.S. Southwest).......   75,835    5.99    107,227    2.42    122,342    2.62    131,074    3.75    110,604    3.72
                         -------   -----    -------   -----    -------   -----    -------   -----    -------   -----
Total/Weighted
 Average...............  324,686   $4.92    356,991   $2.47    438,191   $2.19    421,813   $2.39    391,943   $2.21
                         =======   =====    =======   =====    =======   =====    =======   =====    =======   =====
</TABLE>
--------
(1) The average prices for Canadian and U.S. Southwest gas include the
    commodity gas prices, interstate pipeline demand or reservation charges,
    transportation charges, and other pipeline assessments, including direct
    bills allocated over the quantities received at the California border.
    Beginning March 1, 1998, the average price for gas also includes
    intrastate pipeline demand and reservation charges. These costs previously
    were bundled in gas rates.

Gas Regulatory Framework

   In August 1997, the CPUC approved the Gas Accord, which restructured the
Utility's gas services and its role in the gas market. Among other matters,
the Gas Accord separates, or "unbundles," the rates for the Utility's gas
transmission services from its distribution services. As a result of the Gas
Accord, the Utility's customers may buy gas directly from competing suppliers
and purchase transmission-only and distribution-only services from the
Utility. Most of the Utility's industrial and larger commercial customers
(noncore customers) now purchase their gas from marketers and brokers.
Substantially all residential and smaller commercial customers (core
customers) buy gas as well as transmission and distribution services from the
Utility as a bundled service. Customer rates for gas are updated on a monthly
basis to reflect changes in the Utility's gas procurement costs.

   The Gas Accord also established an incentive mechanism (the core
procurement incentive mechanism or CPIM) for recovery of the Utility's core
gas procurement costs in rates through 2002. The CPIM provides the Utility
with a direct financial incentive to procure gas and transportation services
at the lowest reasonable costs. Under the CPIM, all Utility procurement costs
are compared to an aggregate market-based benchmark. If costs fall within a
range (tolerance band) around the benchmark, costs are deemed reasonable and
fully recoverable from ratepayers. If procurement costs fall outside the
tolerance band, the Utility's ratepayers and shareholders share savings or
costs, respectively. The Utility has recovered all gas costs through October
31, 1999. In February 2001, the Utility filed a CPIM performance report for
the period of November 1, 1999, through October 31, 2000. The report
determined that all gas commodity and transportation costs for the period are
within the tolerance band, and therefore should be deemed reasonable and
recoverable in full from ratepayers.

   The Gas Accord also established gas transmission and storage rates for the
period from March 1998 through December 31, 2002. Rates for gas distribution
service continue to be set by the CPUC in BCAP proceedings, and are designed
to provide the Utility an opportunity to recover its costs of service and
include a return on investment. See "Utility Operations--California Ratemaking
Mechanisms--Gas Ratemaking--The Biennial Cost Allocation Proceeding (BCAP)."

                                      35
<PAGE>

   In January 1998, the CPUC opened a rulemaking proceeding to explore
alternative market structures in the natural gas industry in California. In
January 2000, the Utility and a broad-based coalition of shippers, consumer
groups, marketers, and others filed a settlement with the CPUC which
reaffirmed the basic structure of the Gas Accord and would continue the Gas
Accord through its original term of December 31, 2002. In May 2000, the CPUC
approved the uncontested settlement.

Transportation Commitments

   The Utility has gas transportation service agreements with various Canadian
and interstate pipeline companies. These agreements include provisions for
payment of fixed demand charges for reserving firm capacity on the pipelines.
The total demand charges that the Utility will pay each year may change due to
changes in tariff rates. The total demand and volumetric transportation
charges paid by the Utility under these agreements were approximately $94
million in 2000. This amount includes payments made to PG&E GTN of
approximately $46 million in 2000, which are eliminated in the consolidated
financial statements of PG&E Corporation.

   As a result of regulatory changes, the Utility no longer procures gas for
most of its noncore customers, resulting in a decrease in the Utility's need
for firm transportation capacity for its gas purchases. The Utility continues
to procure gas for almost all of its core customers and, up until February
2001, procured gas for those noncore customers who chose bundled service (core
subscription customers). (Core subscription service ended on February 28,
2001, and most former core subscription customers elected to receive bundled
service as core customers.) The Utility is continuing its efforts to broker or
assign any of its remaining contracted-for but unused interstate and Canadian
transportation capacity, including unused capacity held for its core and core-
subscription customers.

   Under a firm transportation agreement with PG&E GTN that runs through
October 31, 2005, the Utility currently retains capacity of approximately 600
MMcf/d on the PG&E GTN system to support its core and core-subscription
customers. The Utility has been able to broker its unused capacity on PG&E
GTN's system, when not needed for core and core-subscription customers.

   The Utility may recover demand charges through the CPIM and through
brokering activities.

                       PG&E NATIONAL ENERGY GROUP, INC.

   PG&E Corporation's wholly owned subsidiary, PG&E National Energy Group,
Inc. (NEG), is an integrated energy company with a strategic focus on power
generation, new power plant development, natural gas transmission, and
wholesale energy marketing and trading in North America.

   On December 22, 2000, NEG completed the sale of PG&E Gas Transmission,
Texas Corporation and PG&E Gas Transmission Teco, Inc. and their subsidiaries,
to El Paso Field Services Company, a subsidiary of El Paso Energy Corporation.
The Texas operations that were sold included gas gathering, transportation,
and processing facilities, and natural gas liquids (NGL) pipelines. In
addition, during 2000, NEG completed the sale of the retail energy services
and value-added services businesses of its subsidiary, PG&E Energy Services
Corporation.

   NEG's ability to anticipate and capture profitable business opportunities
created by deregulation will have a significant impact on PG&E Corporation's
future operating results. Implementation of PG&E Corporation's national energy
strategy depends, in part, upon the opening of energy markets to provide
customer choice of supplier. Undue delays in deregulation of the electric
generation and natural gas supply business could impact the pace of growth of
NEG's businesses.

                                      36
<PAGE>

Integrated Power Generation, and Energy Trading and Marketing Business

   NEG manages the operations, fuel supply, and sale of electric output of its
owned and leased generating facilities as an integrated portfolio with its
contractually controlled generating facilities and its other marketing and
trading activities. NEG had a net ownership interest in 5,230 MW of generating
capacity as of December 31, 2000. In addition, NEG had 19,993 MW of gas-fired
generating facilities in construction or under development for which NEG has
secured the necessary turbines. NEG controls the output of 518 MW of operating
generating capacity and 3,722 MW of generating capacity in construction or
development through various long-term contracts as of December 31, 2000.

   NEG's energy marketing and trading activities are focused in markets in
which it owns or controls generating facilities and in developed competitive
markets. NEG's integrated power generation, and energy marketing and trading
business is principally engaged in the following areas:

  . ownership and operation of generating facilities,

  . new power plant development and construction,

  . contractual control of generating capacity,

  . energy marketing and trading, and

  . risk management.

   Ownership and Operation of Generating Facilities. As of December 31, 2000,
NEG had ownership or leasehold interests in 19 operating generating facilities
with a net generating capacity of 5,230 MW. These facilities include five gas-
fired generating facilities with a net generating capacity of 1,055 MW, ten
generating facilities that primarily burn coal or waste coal, in some cases in
combination with oil or gas, with a net generating capacity of 2,997 MW, three
hydroelectric systems or pumped storage facilities with a net generating
capacity of 1,166 MW, and one 12 MW wind generating facility. NEG provides
operating and management services for 16 of its 19 owned and leased generating
facilities.

   NEG's generating facilities fall into two categories: merchant plants and
independent power projects. Merchant plants sell their electrical output in the
competitive wholesale electric market on a spot basis or under contractual
arrangements of various terms. Independent power projects sell all or a
majority of their electrical capacity and output to one or more third parties
under long-term power purchase agreements tied directly to the output of that
plant. In order to provide fuel for independent power projects, natural gas and
coal supply commitments are typically purchased from third parties under long-
term supply agreements. All of the generating facilities developed or placed in
operation before 1997 are independent power projects. NEG had a net ownership
interest of 1,100 MW in independent power projects as of December 31, 2000. All
other generating facilities acquired, placed in operation, or controlled
through contracts, during or after 1997 are merchant plants. Generating
facilities under construction or in development are expected to be operated as
merchant plants.

   New Power Plant Development and Construction. NEG manages the development
and construction of power generating facilities (sometimes referred to as
"greenfield" development), which include natural gas-fired and coal-fired
generating facilities, and facilities that use other power generating
technologies, including hydroelectric power and wind. NEG considers a
generating facility to be under construction once NEG or the lessor has
acquired the necessary permits to begin construction, broken ground at the
project site, and contracted to purchase the major machinery for the project,
including the combustion turbines. In addition, NEG has a number of generating
facilities in development. NEG considers a generating facility to be in
development when NEG has contractual commitments or options to purchase the
turbines necessary to complete the project or when NEG has made substantial
progress in site selection, control of the site and permitting. The completion
of planned development projects is subject to many factors, including but not
limited to changes in governmental regulations, the timing of regulatory and
environmental approvals or the failure to obtain such approvals, failure to
obtain adequate financing on satisfactory terms, failure to obtain necessary
equipment to operate, failure of

                                       37
<PAGE>

third party contractors to perform their contractual obligations, a
competitor's development of a lower-cost generating plant, fluctuations in
natural gas and electricity prices and the ability to successfully manage such
price fluctuations, and the risks associated with marketing and selling power
in the newly competitive energy market.

   As of December 31, 2000 NEG owned or had committed to lease or acquire six
generating facilities currently under construction in five states,
representing 3,006 MW. These projects are expected to be placed in service in
2001 and 2002 and since year end, NEG has placed 350 MW in commercial
operation. In addition, NEG has five generating facilities in advanced
development in five states, representing over 5000 MW, which it expects to be
able to place into construction during 2001. NEG has secured contractual
commitments and options for 60 new combustion turbines for large, gas-fired
facilities, representing 19,808 MW of net generating capacity. Ten of these
turbines, representing approximately 2,821 MW, are for generating facilities
under construction as of December 31, 2000, (the Millennium, Lake Road, La
Paloma, and Attala power plant projects). Most of these turbine commitments
use the latest generation of combustion technology, commonly known as G
technology.

   The Lake Road and La Paloma facilities are being constructed by Alstom
Power, Inc. (Alstom) under fixed price construction contracts with guaranteed
dates for commercial operations. Alstom has advised NEG that it may take up to
three years to develop and implement modifications to its G technology
turbines that are necessary to achieve the guaranteed level of efficiency and
output. NEG expects that the Lake Road and La Paloma facilities will begin
commercial operations at reduced performance and output levels because of the
technology issues with Alstom's G technology turbines.

   NEG also encountered start-up problems with the Siemens Westinghouse G
technology turbine installed at its Millennium facility. These problems have
delayed the expected date of commercial operations for this facility, which
began commercial operations in April 2001. NEG does not expect that the start-
up problems with the Siemens Westinghouse G technology turbine installed at
the Millennium facility will result in a reduction in the guaranteed level of
efficiency or output.

   The construction contracts for each of the Millennium, Lake Road, and La
Paloma projects provide for liquidated damages. However, these liquidated
damages will not offset fully the financial impact associated with the delays
of these turbines in achieving their expected level of performance.

   Contractual Control of Generating Capacity. NEG has increased its
generating capacity through contractual control of the electric output of
generating facilities owned by others. NEG has executed various long-term
contracts representing 4,240 MW of generating capacity, which result in
control of 518 MW of operating generating capacity and 3,722 MW of generating
capacity in construction or development as of December 31, 2000. The primary
method of achieving contractual control of generating capacity is through
tolling agreements. Tolling agreements establish a contractual relationship
that grants NEG the right to use a third party's generating facility to
convert NEG's fuel, typically natural gas, to electricity. NEG has the right
to decide the timing and amount of electricity production within agreed
operating parameters. The owner of the facility typically receives a fixed
capacity payment for the committed availability of its facility and a variable
payment for production costs. The fixed payment is subject to reduction if the
owner fails to meet specified targets for facility availability or other
operating factors.

   The terms of the seven tolling agreements NEG has entered into as of
December 31, 2000, range from 10 to 25 years commencing on the date of initial
commercial operations of the generating facility. Most of the generating
facilities are under construction or in development, with commercial
operations expected to commence between 2001 and 2004. These tolling
agreements provide NEG with control of gas-fired plants in the Mid-Atlantic,
Midwestern, Southern, and Western regions of the United States.

   Energy Marketing and Trading. NEG's marketing and trading operations manage
fuel supply procurement and sale of electrical output of NEG's owned and
controlled generating facilities as an integrated portfolio with NEG's trading
positions. During the year ended December 31, 2000, NEG sold approximately
$283 million MW hours of power and an average of over 6.5 Bcf of natural gas
per day.


                                      38
<PAGE>

   Through over-the-counter and futures markets across North America, NEG
engages in the marketing and trading of (1) electric energy, (2) capacity and
ancillary services, (3) fuel and fuel services such as transport and storage,
(4) emission credits, and (5) other related products. NEG markets and trades
all types of fuels necessary for its owned and controlled generating
facilities, including natural gas, coal, and oil.

   NEG uses derivative financial instruments to provide flexible pricing to its
customers and suppliers and manage its purchase and sale commitments, including
those related to NEG's owned and controlled generating facilities, gas
pipelines, and storage facilities. NEG also uses derivative financial
instruments to reduce its exposure relative to the volatility of market prices.
Financial instruments are also used to hedge interest rate and currency
volatility.

   NEG also evaluates and implements highly structured long-term and short-term
transactions. These transactions include (1) management of third party energy
assets, (2) short-term tolling arrangements, (3) management of the requirements
of aggregated customer load through full requirement contracts,
(4) restructured independent power project contracts, and (5) purchase and sale
of transportation, storage and transmission rights through auctions and over-
the-counter markets.

   NEG's energy marketing and trading operations provide the following products
and services:

   Electricity Marketing and Trading. NEG aggregates electricity and related
products from its owned and controlled generating facilities and other from
generators and marketers. NEG then packages and sells such electricity and
related products to electric utilities, municipalities, cooperatives, large
industrials, aggregators and other marketing and retail entities. NEG also
buys, sells and transports power to and from third parties under a variety of
short-term contracts. NEG manages all of its power positions, whether from its
owned and controlled generating facilities or from other contracts, as an
integrated power portfolio.

   Natural Gas Marketing and Trading. NEG purchases natural gas from a variety
of suppliers under daily, monthly, seasonal and long-term contracts with
pricing, delivery and volume schedules to accommodate the requirements of NEG's
owned and controlled generating facilities and its obligations under long-term
structured transactions. NEG also buys, sells and arranges transportation to
and from third parties under a variety of short-term agreements. NEG's natural
gas marketing activities include contracting to buy natural gas from suppliers
at various points of receipt, arranging transportation, negotiating the sale of
natural gas, and matching natural gas receipt and delivery points to the
customer based on geographic logistics and delivery costs. NEG sold an average
of 6.5 Bcf per day of natural gas in 2000 transported on 44 pipelines
throughout North America.

   NEG arranges for transportation of natural gas on interstate and intrastate
pipelines through a variety of means, including short-term and long-term firm
and interruptible agreements. NEG also enters into various short-term and long-
term firm and interruptible agreements for natural gas storage in order to
provide peak delivery services to satisfy winter heating and summer electric
generating demands.

   Coal, Oil and Emissions Marketing and Trading. NEG buys, secures
transportation for and manages the sulfur content of the coal and oil
requirements of its owned and controlled generating facilities. NEG also
purchases and sells coal, oil, and emissions credits from and to third parties.

   Load Management or Full Requirements Arrangements. Deregulation of the
energy industry has provided many consumers with the ability to seek and
receive customized energy services. Consumers are particularly interested in
purchasing volumes of fuel and electricity that closely match their specific
needs. In order to satisfy this consumer demand, an increasing number of
companies aggregate blocks of customers, buy power at wholesale and deliver it
to end-user consumers. As part of NEG's integrated generation, energy marketing
and trading business, NEG enters into contracts to supply natural gas and
electricity, known as load management or full requirements supply, to these
load aggregator companies in the exact amount and quality purchased by their
end-user customers.

                                       39
<PAGE>

   NEG's largest load management contracts are the wholesale standard offer
service agreements with affiliates of New England Power, from whom NEG
purchased 4,800 MW of owned and controlled generating capacity in 1998. Under
the wholesale standard offer service agreements, NEG supplies a fixed
percentage of the full requirements of the retail customers of New England
Power's affiliates who receive standard offer service in Massachusetts and
Rhode Island. The price NEG receives for the electricity it provides under the
wholesale standard offer service agreements has a fixed floor (which escalates
automatically over time) and is subject to upward escalation if the price of
natural gas and fuel oil exceed a specified threshold. NEG receives a fixed
price for the electricity it provides under the standard offer service
agreements. Standard offer service is intended to stimulate the retail
electric markets in these states by gradually increasing the fixed price of
electricity under this service. The fixed price increases by a specified
amount each year and also increases if the prices of natural gas and fuel oil
exceed a specified threshold. These retail customers may select alternative
suppliers at any time. NEG's sales volumes and revenues under the wholesale
standard offer service agreements totaled 13.2 million MW hours and $563.4
million in 2000. The wholesale standard offer service agreement for
Massachusetts terminates on December 31, 2004, and the wholesale standard
offer service agreement for Rhode Island terminates on December 31, 2009.

   Fuel Supply, Transport, and Electric Transmission Management. NEG enters
into contracts for fuel supply, fuel transportation, and electric transmission
primarily to meet the needs of its owned and controlled generating facilities
and to capitalize on other trading opportunities.

   Risk Management Controls. NEG manages the risk associated with its
marketing and trading operations through a comprehensive set of policies and
procedures involving senior levels of its management. NEG's senior management
sets value-at-risk limitations and regularly reviews NEG's risk management
policies and procedures. Within this framework, NEG's risk management
committee oversees all of NEG's marketing and trading activities. All of NEG's
risk management models are validated by third party experts, such as
independent accountants and consultants with extensive experience in specific
derivative applications.

   NEG's risk management group is structured as a separate unit in its
organization. This management group is responsible for the day-to-day
enforcement of the policies, procedures and limits of its trading and
marketing activities and evaluating the risks inherent in proposed
transactions. These key activities include evaluating and monitoring the
creditworthiness of trading counterparties, setting and monitoring volumetric
and loss limits on portfolio risks, establishing and monitoring trading limits
on products, as well as on individual traders, validating trading
transactions, and performing daily portfolio valuation reporting including
mark-to-market valuation.

                                      40
<PAGE>

   Description of Generating Facilities. The following table provides
information regarding each of NEG's owned or controlled operating generating
facilities, as well as those under construction as of December 31, 2000.

<TABLE>
<CAPTION>
                                       NEG Net
                                       Interest                                                                    Date of
                                Total  in Total                              Primary Output Sales                 Commercial
 Generating Facility    State     MW    MW(1)   Structure       Fuel                Method              Status    Operation
 -------------------   --------------  -------- ---------  --------------- ------------------------- ------------ ----------
<S>                    <C>      <C>    <C>      <C>        <C>             <C>                       <C>          <C>
New England Region
 Brayton Point
  Station.............    MA     1,599  1,599     Owned       Coal/Oil        Competitive Market     Operational  1963-1974
 Salem Harbor
  Station.............    MA       745    745     Owned       Coal/Oil        Competitive Market     Operational  1952-1972
 Bear Swamp Facility..    MA       599    599    Leased         Water         Competitive Market     Operational     1974
 Manchester St.
  Station.............    RI       495    495     Owned      Natural Gas      Competitive Market     Operational     1995
 Connecticut River
  System..............  NH/VT      484    484     Owned         Water         Competitive Market     Operational  1909-1957
 Masspower............    MA       267     35     Owned      Natural Gas   Power Purchase Agreements Operational     1993
 Pittsfield(2)........    MA       173    143    Leased      Natural Gas   Power Purchase Agreements Operational     1990
                                                                            and Competitive Market
 Milford Power(2).....    MA       171     96   Contract     Natural Gas      Competitive Market     Operational     1994
 Deerfield River
  System..............  MA/VT       83     83     Owned         Water         Competitive Market     Operational  1912-1927
 Pawtucket Power(2)...    RI        69     69   Contract     Natural Gas      Competitive Market     Operational     1991
 14 Smaller
  Facilities(2)....... Various     193    193   Contract   Renewable/Waste    Competitive Market     Operational   Various
 Millennium(3)........    MA       360    360     Owned      Natural Gas      Competitive Market     Construction    2001
 Lake Road............    CT       840    840    Leased      Natural Gas      Competitive Market     Construction    2001
                                ------  -----
  Subtotal............           6,078  5,741
Mid-Atlantic and New York
 Region
 Selkirk..............    NY       345    145     Owned      Natural Gas   Power Purchase Agreements Operational     1992
                                                                            and Competitive Market
 Carneys Point........    NJ       269    135     Owned         Coal       Power Purchase Agreements Operational     1994
 Logan................    NJ       225    113     Owned         Coal       Power Purchase Agreement  Operational     1994
 Northampton..........    PA       110     55     Owned      Waste Coal    Power Purchase Agreements Operational     1995
 Panther Creek........    PA        80     40     Owned      Waste Coal    Power Purchase Agreement  Operational     1992
 Scrubgrass...........    PA        87     44     Owned      Waste Coal    Power Purchase Agreement  Operational     1993
 Madison..............    NY        12     12     Owned         Wind          Competitive Market     Operational     2000
 Liberty..............    PA       530    530   Contract     Natural Gas      Competitive Market     Construction    2002
                                ------  -----
  Subtotal............           1,658  1,074
Midwest Region
 Georgetown...........    IN       240    160   Contract     Natural Gas      Competitive Market     Operational     2000
 Ohio Peakers.........    OH       141    141     Owned      Natural Gas      Competitive Market     Operational     2001
                                ------  -----
  Subtotal............             381    301
Southern Region
 Indiantown...........    FL       360    126     Owned         Coal       Power Purchase Agreement  Operational     1995
 Cedar Bay............    FL       269    135     Owned         Coal       Power Purchase Agreement  Operational     1994
 Attala...............    MS       500    500     Owned      Natural Gas      Competitive Market     Construction    2001
 SRW(4)...............    TX       420    250   Contract     Natural Gas      Competitive Market     Construction    2001
                                ------  -----
  Subtotal............           1,549  1,011
Western Region
 Hermiston............    OR       474    237     Owned      Natural Gas   Power Purchase Agreement  Operational     1996
 Colstrip.............    MT        40      5     Owned      Waste Coal    Power Purchase Agreement  Operational     1990
 Mountain View........    CA        44     44     Owned(5)      Wind          Competitive Market     Construction    2001
 La Paloma............    CA     1,121  1,121    Leased      Natural Gas      Competitive Market     Construction    2002
                                ------  -----
  Subtotal............           1,679  1,407
                                ------  -----
     Total............          11,345  9,534
                                ======  =====
</TABLE>
-------
(1) NEG's net interest in an independent power project is determined by
    multiplying NEG's percentage of the project's expected cash flow by the
    project's total MW.
(2) NEG controls all or a portion of the output of 17 smaller generating
    facilities under long-term power purchase agreements. In return for NEG's
    assumption of the purchase obligations under these agreements from the New
    England Power Company, the New England Power Company has agreed to pay an
    average of $111 million per year through January 2008 to offset NEG's
    payment obligations under these contracts. The facilities NEG controls in
    whole or in part through these power purchase agreements include the
    Milford Power Project, the Pittsfield Project, the Pawtucket Power
    Project, and 14 other small generating facilities with a total generation
    capacity of 193 MW fueled by municipal waste, water, landfill gas, or
    wood. The power purchase agreements terminate between 2009 and 2029.
(3) Millenium achieved commercial operation in April 2001.
(4) An NEG subsidiary entered into a contract with SRW Cogeneration Limited
    partnership dated as of July 30, 1999 pursuant to which NEG would control
    250 MW of a 420 MW cogeneration facility the limited partnership is
    building and is to operate. The limited partnership has provided NEG with
    notice of its purported termination of the contract, which NEG is
    contesting.
(5) NEG has executed a contract to purchase the Mountain View facility. The
    purchase has not yet closed.

                                      41
<PAGE>

   Competition. Some of the competitive factors affecting the results of
operations of NEG's owned and controlled generating facilities include new
market entrants, construction by others of more efficient generating
facilities and the number of years and extent of operations in a particular
energy market. Other competitors operate generating facilities in the regions
where NEG has invested in generation facilities. Although local permitting and
siting issues often reduce the risk of a rapid growth in supply of generating
capacity in any particular region, projects are likely to be built over time
which will increase competition and lower the value of some of NEG's
generating facilities.

   There is also significant competition for the development and acquisition
of domestic unregulated generating facilities. NEG competes against a number
of other participants in the non-utility power generation industry.
Competitive factors relevant to the non-utility power industry include
financial resources, development expenses, and regulatory factors. Some of
NEG's competitors have greater financial resources than NEG has.

   NEG's energy marketing and trading operations compete with other energy
merchants based on the ability to aggregate supplies at competitive prices
from different sources and locations and to efficiently utilize transportation
from third-party pipelines and transmission from electric utilities. These
operations also compete against other energy marketers on the basis of their
relative financial position and access to credit sources. This competitive
factor reflects the tendency of energy customers, wholesale energy suppliers,
and transporters to seek financial guarantees and other assurances that their
energy contracts will be satisfied. As pricing information becomes
increasingly available in the energy marketing and trading business and as
deregulation in the electricity markets continues to evolve, NEG anticipates
that its energy, marketing and trading operations will experience greater
competition and downward pressure on per-unit profit margins.

Natural Gas Transmission Business

   NEG's natural gas transmission business currently consists of the PG&E GT-
Northwest (PG&E GTN) pipeline, a 5.2% interest in the Iroquois Gas
Transmission System and the North Baja pipeline under development.

   The following table summarizes NEG's gas transmission pipelines:

<TABLE>
<CAPTION>
                                                        12 month
                                    In Service Capacity capacity Length  Ownership
Pipeline Name             Location     Date    (MMcf/d)  factor  (miles) Interest
-------------             --------  ---------- -------- -------- ------- ---------
<S>                      <C>        <C>        <C>      <C>      <C>     <C>
PG&E GT-Northwest....... ID, OR, WA    1961     2,700      96%    1,335     100%
Iroquois Gas
 Transmission System.... NY            1991       900      95%      375     5.2%
North Baja.............. AZ, CA,       2002       500     N/A        80     100%
</TABLE>

   PG&E GT-Northwest (PG&E GTN). PG&E GTN owns and operates the PG&E GTN
pipeline. This pipeline consists of over 1,300 miles of natural gas
transmission mainline pipe with a capacity of 2.7 Bcf of natural gas per day.
The PG&E GTN pipeline begins at the British Columbia-Idaho border, extends
through northern Idaho, southeastern Washington and central Oregon, and ends
on the Oregon-California border where it connects with other pipelines. This
pipeline is the largest transporter of Canadian natural gas into the United
States. For the year ended December 31, 2000, this pipeline transported 967
Bcf of natural gas, resulting in a 5% growth in transported volumes from the
previous year. Since this pipeline commenced commercial operations in 1961, it
has experienced a five-fold increase in peak system capacity. The PG&E GTN
pipeline is the only interstate pipeline directly connecting the large and
rapidly growing gas markets of California, Nevada, and the Pacific Northwest
with the abundant natural gas supplies of the Western Canadian Sedimentary
Basin and potentially the natural gas rich North Slope of Alaska and Northwest
Territories of Canada. The pipeline transports over 30% of California's
natural gas demand requirements and over 20% of the Pacific Northwest natural
gas demand requirements.

                                      42
<PAGE>

   The mainline system of the PG&E GTN pipeline consists of two parallel
pipelines with 13 compressor stations totaling approximately 414,450
horsepower. This dual-pipeline system consists of approximately 639 miles of
36-inch mainline pipe and approximately 590 miles of 42-inch mainline pipe.
The original pipeline commenced commercial operations in 1961 and was expanded
throughout the 1960's and 1970, 1981, 1993, 1995 and 1998. The PG&E GTN
pipeline includes two laterals, the Coyote Springs Lateral that supplies
natural gas to Portland General Electric Company and the Medford Lateral that
supplies natural gas to Avista Utilities. This pipeline interconnects with
facilities owned by the Utility at the Oregon-California border and with
interstate pipelines in northern Oregon, eastern Washington, and southern
Oregon. It also delivers gas along various mainline delivery points to two
local gas distribution companies of various mainline delivery points.

   The PG&E GTN pipeline provides firm and interruptible transportation
services to third party shippers on a nondiscriminatory basis. Firm
transportation services means that the customer has the highest priority
rights to ship a quantity of gas between two points for the term of the
applicable contract. The pipeline's long-term capacity is 100% committed to
firm transportation services agreements with terms in excess of one year. The
remaining terms of these agreements range between one and 26 years with a
volume-weighted average of approximately 13 years. In addition, due to
weather, maintenance schedules, and other conditions, additional firm capacity
may become available on a short-term basis. Interruptible transportation is
offered when short-term capacity is available due to a firm transportation
customer not fully utilizing its committed capacity. Hub services are also
offered, which allow customers the ability to park or lend volumes of gas on
the pipeline.

   The PG&E GTN pipeline currently provides transportation services for over
65 customers, including local retail gas distribution utilities, electric
utilities that utilize natural gas to generate electricity, natural gas
marketing companies that purchase and resell natural gas on a wholesale and
retail basis, natural gas producers, and industrial companies. The customers
are responsible for securing their own gas supplies and delivering them to the
pipeline system. The customers' natural gas supplies are transported either to
downstream pipelines and distribution companies or directly to points of
consumption.

   PG&E GTN's current rates were set in a rate settlement approved by the FERC
in September 1996.

   North Baja Pipeline. NEG recently joined with Sempra Energy International
and Mexico's Proxima Gas, S.A. de C.V. to develop a 215-mile pipeline that
will supply natural gas to Northern Mexico and Southern California. This
pipeline will begin at an interconnection with El Paso Natural Gas Company
near Ehrenberg, Arizona, traverse southeastern California and northern Baja
California, Mexico and terminate at an interconnection with the Rosarito
Pipeline south of Tijuana. An application has been filed with the FERC for a
certificate to build the 80-mile U.S. segment of this proposed $230 million
project. Sempra Energy International and Proxima Gas will direct development
of the 135-mile Mexico segment. This pipeline will have an initial capacity of
500 million cubic feet per day with expansion capability to 800 million cubic
feet per day.

   NEG has signed agreements with five anchor customers to transport almost
90% of the projected daily capacity of 500,000 million cubic feet of natural
gas. The average term of these agreements is 20 years. NEG is continuing
discussions and negotiations with other potential customers. This pipeline is
projected to be in service by the fourth quarter of 2002. In its initial
design, this pipeline is intended primarily to serve electric generating needs
in northern Mexico and Southern California, as well as industrial and local
distribution company load along the Mexico segment. Further, NEG believes that
this pipeline will also have the potential to serve delivery points along its
entire route.

   Competition. NEG's gas transmission business competes with other pipeline
companies for transportation customers on the basis of transportation rates,
access to competitively priced gas supply and growing markets served by its
pipelines, and the quality and reliability of transportation services. The
competitiveness of a pipeline's transportation services to any market is
generally determined by the total delivered natural gas price from a
particular natural gas supply basin to the market served by the pipeline.

                                      43
<PAGE>

   The PG&E GTN pipeline accesses natural gas supplies from Western Canada and
serves markets in the Pacific Northwest, California, and Nevada. PG&E GTN
competes with other pipelines to access natural gas supplies in Western
Canada, the Rocky Mountain, the Southwest, and British Columbia.

   NEG's transportation volumes are also affected by the availability and
economic attractiveness of other energy sources. Hydroelectric generation, for
example, may become available based on ample snowfall and displace demand for
natural gas as a fuel for electric generation. Finally, in providing
interruptible and short-term firm transportation service, NEG competes with
released capacity offered by shippers holding firm contracts for NEG's
capacity.

                                      44
<PAGE>

                             ENVIRONMENTAL MATTERS

Environmental Matters

   The following discussion includes certain forward-looking information
relating to estimated expenditures for environmental protection measures and
the possible future impact of environmental compliance. This information below
reflects current estimates, which are periodically evaluated and revised.
Future estimates and actual results may differ materially from those indicated
below. These estimates are subject to a number of assumptions and
uncertainties, including changing laws and regulations, the ultimate outcome
of complex factual investigations, evolving technologies, selection of
compliance alternatives, the nature and extent of required remediation, the
extent of the facility owner's responsibility, and the availability of
recoveries or contributions from third parties.

   PG&E Corporation, the Utility, and various NEG affiliates (including USGen
New England, Inc. (USGenNE)) are subject to a number of federal, state, and
local laws and regulations designed to protect human health and the
environment by imposing stringent controls with regard to planning and
construction activities, land use, air and water pollution, and treatment,
storage, and disposal of hazardous or toxic materials. These laws and
regulations affect future planning and existing operations, including
environmental protection and remediation activities. The Utility has
undertaken compliance efforts with specific emphasis on its purchase, use, and
disposal of hazardous materials, the cleanup or mitigation of historic waste
spill and disposal activities, and the upgrading or replacement of the
Utility's bulk waste handling and storage facilities. The costs of compliance
with environmental laws and regulations generally have been recovered in
rates.

   Although the Utility has sold most of its fossil-fueled power plants and
its geothermal generation facilities in connection with electric industry
restructuring, the Utility has retained liability for certain required
environmental remediation of pre-closing soil or groundwater contamination for
fossil and geothermal generation facilities that have been sold. See "Utility
Operations--Electric Utility Operations--California Electric Industry
Restructuring--Voluntary Generation Asset Divestiture" above.

   Environmental Protection Measures

   The estimated expenditures of PG&E Corporation's subsidiaries for
environmental protection are subject to periodic review and revision to
reflect changing technology and evolving regulatory requirements. It is likely
that the stringency of environmental regulations will increase in the future.
As a result of the Utility's divestiture of most of its fossil-fueled power
plants and its geothermal generation facilities, the Utility's oxides of
nitrogen (NOx) emission reduction compliance costs have been reduced
significantly.

   Air Quality

   Pacific Gas and Electric Company's thermal electric generating plants are
subject to numerous air pollution control laws, including the California Clean
Air Act (CCAA) with respect to emissions. Pursuant to the CCAA and the Federal
Clean Air Act, two of the local air districts in which the Utility owns and
operates fossil-fueled generating plants have adopted final rules that require
a reduction in NOx emissions from the power plants of approximately 90% by
2004 (with numerous interim compliance deadlines).

   The Gas Accord authorizes $42 million to be included in rates through 2002
for gas NOx retrofit projects related to natural gas compressor stations on
Pacific Gas and Electric Company's Line 300, which delivers gas from the
Southwest. Other air districts are considering NOx rules that would apply to
the Utility's other natural gas compressor stations in California. Eventually
the rules are likely to require NOx reductions of up to 80% at many of these
natural gas compressor stations. The Utility currently estimates that the
total cost of complying with these various NOx rules will be up to $101
million from 2001 through 2004. The Utility is planing to replace some
compressor units because proven NOx retrofit technology is not available for
these units. Substantially all of these costs will be capital costs.

                                      45
<PAGE>

   Compliance by NEG affiliates with certain future regulatory requirements
limiting the total amount of NOx emissions from its fossil-fueled power plants
is expected to be achieved through installation of additional controls, fuel
switching, and purchase of NOx allowances. USGenNE has agreed to be bound by a
number of state and regional initiatives that will require it to achieve
significant reductions of sulfur dioxide (SO2) and NOx emissions by the time
its older fossil-fueled power plants have been in operation for 40 years or by
2010, whichever comes first. It is expected that USGenNE can meet these
requirements through utilization of allowances it currently owns, installation
of additional controls, or purchase of additional allowances. (SO2 allowances
are emission credits that are traded in a national market under the United
States Environmental Protection Agency's (EPA) Acid Rain Program. NOx
allowances are emission credits that are traded in a regional market
consisting of seven Northeast states known as the Ozone Transport Region.)

   In October and November 1999, the EPA and several states filed suits or
announced their intention to file suits against a number of coal-fired power
plants in Midwestern and Eastern states. These suits relate to alleged
violations of the Clean Air Act. More specifically, they allege violations of
the deterioration prevention and non-attainment provisions of the Clean Air
Act's new source review requirements arising out of certain physical changes
that may have been made at these facilities without first obtaining the
required permits.

   In May 2000, USGenNE received a request for information pursuant to Section
114 of the Clean Air Act from the EPA seeking detailed operating and
maintenance history for the Salem Harbor and Brayton Point power plants, which
USGenNE acquired in 1998 from the New England Electric System (NEES). USGenNE
believes that this request for information is part of the EPA's industry-wide
investigation of coal-fired electric power generators to determine compliance
with environmental requirements under the Clean Air Act associated with
repairs, maintenance, modifications, and operational changes made to coal-
fired facilities over the years. If the EPA were to find that there were
physical changes made in the past that were undertaken without first receiving
the required permits under the Clean Air Act, then penalties may be imposed
and further emission reductions might be necessary at these plants.

   A new ambient air quality standard was adopted by the EPA in July 1997 to
address emissions of fine particulate matter. It is widely understood that
attainment of the fine particulate matter standard may require reductions in
NOx and SO2, although under the time schedule announced by the EPA when the
new standard was adopted, non-attainment areas were not to have been
designated until 2002 and control measures to meet the standard were not to
have been identified until 2005. In May 1999, the United States Court of
Appeals for the District of Columbia Circuit held that Section 109(b)(1) of
the Clean Air Act, the section of the Clean Air Act requiring the promulgation
of national ambient air quality standards, as interpreted by the EPA, was an
unconstitutional delegation of legislative power. The Court of Appeals
remanded both the fine particulate matter standard and the revised ozone
standard to allow the EPA to determine whether it could articulate a
constitutional application of Section 109(b)(1). On February 27, 2001, the
Supreme Court, in Whitman v. American Trucking Associations, Inc., reversed
the Circuit Court's judgment on this issue and remanded the case to the Court
of Appeals to dispose of any other preserved challenges to the particulate
matter and ozone standards. Accordingly, as the final application of the
revised particulate matter ambient air quality standard is potentially subject
to further judicial proceedings, the impact of this standard on the Utility's
and NEG's facilities is uncertain at this time. If an ambient air quality
standard for fine particulates is promulgated, further NOx and SO2 reductions
may be required for those Utility and NEG facilities located in areas where
sampling indicates the ambient air does not comply with the final standards
that are adopted.

   Since the adoption of the United Nations Framework on Climate Change in
1992, there has been worldwide attention with respect to greenhouse gas
emissions. In December 1997, the Clinton Administration participated in the
Kyoto, Japan negotiations, where the basis of a Climate Change treaty was
formulated. Under the treaty, known as the Kyoto Protocol, the United States
would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7%
from 1990 levels. However, because of opposition to the treaty in the United
States Senate, the Kyoto Protocol has not been submitted to the Senate for
ratification. If the U.S. Senate ultimately ratifies the Kyoto Protocol and
greenhouse gas emission reduction requirements are implemented, the resulting
limitations on power plant carbon dioxide emissions could have a material
adverse impact on all fossil fuel-fired facilities, including Utility and NEG
facilities.

                                      46
<PAGE>

   The EPA has announced that it will regulate steam electric generating
plants under Title III of the Clean Air Act, which addresses emissions of
hazardous air pollutants from specific industrial categories. Power plants are
a source of mercury air emissions. The EPA recently signed a regulatory
finding that commits it to propose a mercury-emissions rule applicable to
fossil-fuel fired power plants by 2003 and to promulgate a final rule by 2004.
According to this regulatory finding, affected facilities will have to comply
with this final rule in 2007-2008. The rulemaking process will likely include
significant stakeholder and public participation both before and after the
emission standards are proposed. The applicable control level is uncertain, as
is the cost of these future rules.

   In addition to the EPA, states may impose more stringent air emissions
requirements. The Commonwealth of Massachusetts is considering the adoption of
more stringent air emission reductions from electric generating facilities. If
adopted, these requirements will impact Salem Harbor and Brayton Point. NEG
has proposed an emission reduction plan that may include modernization of the
Salem Harbor power plant and use of advanced technologies for emissions
removal. It is also studying various advanced technologies for emissions
removal for the Brayton Point power plant.

   NEG currently estimates that USGenNE's total capital cost for complying
with the requirements described here will be approximately $300 million.

   Water Quality

   Pacific Gas and Electric Company's existing power plants, including Diablo
Canyon, are subject to federal and state water quality standards with respect
to discharge constituents and thermal effluents. The Utility's fossil-fueled
power plants comply in all material respects with the discharge constituents
standards and the thermal standards. Additionally, pursuant to Section 316(b)
of the Federal Clean Water Act, the Utility is required to demonstrate that
the location, design, construction, and capacity of power plant cooling water
intake structures reflect the best technology available (BTA) for minimizing
adverse environmental impacts at its existing water-cooled thermal plants. The
Utility has submitted detailed studies of each power plant's intake structure
to various governmental agencies and each plant's existing intake structure
was found to meet the BTA requirements.

   The Diablo Canyon Power Plant employs a "once through" cooling water system
which is regulated under a National Pollutant Discharge Elimination System
(NPDES) permit issued by the Central Coast Regional Water Quality Control
Board (Central Coast Board). This permit allows Diablo Canyon to discharge the
cooling water at a temperature no more than 22 degrees above ambient receiving
water, and requires that the beneficial uses of the water be protected. The
beneficial uses of water in this region include industrial water supply,
recreation, commercial/sport fishing, marine and wildlife habitat, shellfish
harvesting, and preservation of rare and endangered species. In January 2000,
the Central Coast Board issued a proposed draft cease and desist order
alleging that, although the temperature limit has never been exceeded, Diablo
Canyon's discharge was not protective of beneficial uses. In October 2000, the
Central Coast Board and the Utility reached a tentative settlement of this
matter pursuant to which the Central Coast Board has agreed to find that the
Utility's discharge of cooling water from the Diablo Canyon plant protects
beneficial uses and that the intake technology meets the BTA requirements. As
part of the settlement, the Utility will take measures to preserve certain
acreage north of the plant and will fund approximately $4.5 million in
environmental projects related to coastal resources. The parties are
negotiating the documentation of the settlement. The final agreement will be
subject to public comment prior to final approval by the Central Coast Board
and, once signed by the parties, will be incorporated in a consent decree to
be entered in California Superior Court.

   For a description of another environmental regulatory matter affecting the
Utility, see "Item 3--Legal Proceedings--Moss Landing Power Plant," below.

   NEG's existing power plants, including USGenNE facilities, are subject to
federal and state water quality standards with respect to discharge
constituents and thermal effluents. Three of the fossil-fueled plants owned
and operated by USGenNE are operating pursuant to NPDES permits that have
expired. As to the facilities for which their NPDES permit has expired, permit
renewal applications are pending, and it is anticipated that all

                                      47
<PAGE>

three facilities will be able to continue to operate under existing terms and
conditions until new permits are issued. It is estimated that USGenNEs cost to
comply with the new permit conditions could be as much as $55 million through
2005.

   The promulgation or modification of statutes, regulations, or water quality
control plans at the federal, state, or regional level may impose increasingly
stringent cooling water discharge requirements on the Utility's and NEG's power
plants in the future. Costs to comply with new permit conditions required to
meet more stringent requirements that might be imposed cannot be estimated at
the present time.

   Hazardous Waste Compliance and Remediation

   PG&E Corporation subsidiaries assess, on an ongoing basis, measures that may
need to be taken to comply with laws and regulations related to hazardous
materials and hazardous waste compliance and remediation activities. The
Utility has a comprehensive program to comply with hazardous waste storage,
handling, and disposal requirements promulgated by the EPA under the RCRA and
the Comprehensive Environmental Response, Compensation, and Liability Act
(CERCLA), along with other state hazardous waste laws and other environmental
requirements.

   One part of this program is aimed at assessing whether and to what extent
remedial action may be necessary to mitigate potential hazards posed by certain
disposal sites and retired manufactured gas plant sites. During their
operation, manufactured gas plants produced lampblack and tar residues,
byproducts of a process that Pacific Gas and Electric Company, its predecessor
companies, and other utilities used as early as the 1850s to manufacture gas
from coal and oil. As natural gas became widely available (beginning about
1930), the Utility's manufactured gas plants were removed from service. The
residues that may remain at some sites contain chemical compounds that now are
classified as hazardous. The Utility has identified and reported to federal and
California environmental agencies 96 manufactured gas plant sites that operated
in the Utility's service territory. The Utility owns all or a portion of 29 of
these manufactured gas plant sites. The Utility has a program, in cooperation
with environmental agencies, to evaluate and take appropriate action to
mitigate any potential health or environmental hazards at sites that the
Utility owns. It is estimated that the Utility's program may result in
expenditures of approximately $5 million in 2001. The full long-term costs of
the program cannot be determined accurately until a closer study of each site
has been completed. It is expected that expenses will increase as remedial
actions related to these sites are approved by regulatory agencies or if the
Utility is found to be responsible for cleanup at sites it currently does not
own.

   In addition to the manufactured gas plant sites, the Utility may be required
to take remedial action at certain other disposal sites if they are determined
to present a significant threat to human health and the environment because of
an actual or potential release of hazardous substances. With respect to the
Casmalia site near Santa Maria, California, the Utility and several other
generators of waste sent to the site have entered into a court-approved
agreement with the EPA that requires these generators to perform certain site
investigation and mitigation measures, and provides a release from liability
for certain other site cleanup obligations. Recently, the EPA asserted that the
Utility sent more waste to the site than was believed previously. The Utility
is evaluating the significance of this information, which may impact the amount
the Utility ultimately has to pay for this site. Although the Utility has not
been formally designated a potentially responsible party (PRP) with respect to
the Geothermal Incorporated site in Lake County, California, the Central Valley
Regional Water Quality Control Board and the California Attorney General's
office have directed the Utility and other parties to initiate measures with
respect to the study and remediation of that site.

   In addition, Pacific Gas and Electric Company has been named as a defendant
in several civil lawsuits in which plaintiffs allege that the Utility is
responsible for performing or paying for remedial action at sites the Utility
no longer owns or never owned.


                                       48
<PAGE>

   The cost of hazardous substance remediation ultimately undertaken by
Pacific Gas and Electric Company is difficult to estimate. It is reasonably
possible that a change in the estimate may occur in the near term due to
uncertainty concerning the Utility's responsibility, the complexity of
environmental laws and regulations, and the selection of compliance
alternatives. At December 31, 2000, the Utility expected to spend $320 million
for hazardous waste remediation costs at identified sites, including divested
fossil-fueled power plants, where such costs are probable and quantifiable.
(Although the Utility has sold most of its fossil-fueled power plants, the
Utility has retained pre-closing environmental liability with respect to these
plants.) The Utility had an accrued liability of $294 million at December 31,
2000, representing the discounted value of these costs. Environmental
remediation at identified sites may be as much as $462 million if, among other
things, other PRPs are not financially able to contribute to these costs or
further investigation indicates that the extent of contamination or necessary
remediation is greater than anticipated at sites for which the Utility is
responsible. The Utility estimated the upper limit of the range of costs using
assumptions least favorable to the Utility based upon a range of reasonably
possible outcomes. Costs may be higher if the Utility is found to be
responsible for cleanup costs at additional sites or identifiable possible
outcomes change.

   USGenNE acquired the onsite environmental liability associated with its
acquisition of electric generating facilities from NEES, but did not acquire
any offsite liability associated with the past disposal practices at the
acquired facilities. NEG has obtained pollution liability and environmental
remediation insurance coverage to limit the financial risk associated with the
on-site pollution liability at all of its facilities.

   During April 2000, an environmental group served various affiliates of NEG,
including USGenNE, with a notice of intent to file a citizen's suit under
RCRA. The group stated that it planned to allege that USGenNE, as the
generator of fossil fuel combustion wastes at Salem Harbor and Brayton Point,
has contributed and is contributing to the past and present handling, storage,
treatment and disposal of wastes at those facilities which may present an
imminent and substantial endangerment to the public health or the environment.
During September 2000, USGenNE signed a series of agreements with the
Massachusetts Department of Environmental Protection and the environmental
group that address and resolve these matters. The agreements, which have been
filed in federal court and are now incorporated in a consent decree, require,
among other things, that USGenNE alter its existing waste water treatment
facilities at both facilities by replacing certain unlined treatment basins,
submit and implement a plan for the closure of such basins, and perform
certain environmental testing at the facilities. These activities are now well
underway. The cost of these activities is expected to be approximately $21
million.

   Potential Recovery of Hazardous Waste Compliance and Remediation Costs

   In 1994, the CPUC established a ratemaking mechanism for hazardous waste
remediation costs (HWRC). That mechanism assigns 90% of the includable
hazardous substance cleanup costs to utility ratepayers and 10% to utility
shareholders, without a reasonableness review of such costs or of underlying
activities. Under the HWRC mechanism, 70% of the ratepayer portion of Pacific
Gas and Electric Company's cleanup costs is attributed to its gas department
and 30% is attributed to its electric department. Insurance recoveries are
assigned 70% to shareholders and 30% to ratepayers until both are reimbursed
for the costs of pursuing insurance recoveries. The balance of insurance
recoveries is allocated 90% to shareholders and 10% to ratepayers until
shareholders are reimbursed for their 10% share of cleanup costs. Any
unallocated funds remaining are held for five years and then distributed 60%
to ratepayers and 40% to shareholders over the next five years. The Utility
can seek to recover hazardous substance cleanup costs under the HWRC in the
rate proceeding it deems most appropriate. In connection with electric
industry restructuring, the HWRC mechanism may no longer be used to recover
electric generation-related cleanup costs for contamination caused by events
occurring after January 1, 1998.

   For each divested generation facility where the Utility retained
environmental remediation liabilities, the plant's decommissioning cost
estimate was adjusted by the Utility's estimated forecast of environmental
remediation costs. (The buyers assumed the non-environmental decommissioning
liability for these plants.) The CPUC ordered that excess recoveries of
environmental and non-environmental decommissioning accruals related to the
divested plants be used to offset other transition costs. As of December 31,
2000, the Utility has recovered

                                      49
<PAGE>

from ratepayers approximately $114 million for environmental decommissioning
accrual related to the divested plants. This amount will earn interest at 3%
per year that will be used to meet the future environmental remediation costs
for the divested plants. The net decommissioning accruals recovered from
ratepayers attributable to the non-environmental liability for the divested
plants was approximately $53 million. Because the Utility no longer has this
non-environmental decommissioning liability, it has used this excess recovery
amount to reduce other transition costs.

   The $320 million accrued liability at December 31, 2000 mentioned above
includes (1) $140 million related to the pre-closing remediation liability,
discounted to present value at 7%, associated with divested generation
facilities (see further discussion in the "Generation Divestiture" section of
Note 2 of the Notes to the Consolidated Financial Statements of the 2000
Annual Report to Shareholders), and (2) $180 million related to remediation
costs for those generation facilities that the Utility still owns. Of the $320
million environmental remediation liability, the Utility has recovered $168
million through rates, and expects to recover another $87 million in future
rates. The Utility is seeking recovery of the remainder of its costs from
insurance carriers and from other third parties as appropriate.

   In 1992, Pacific Gas and Electric Company filed a complaint in San
Francisco County Superior Court against more than 100 of its domestic and
foreign insurers, seeking damages and declaratory relief for remediation and
other costs associated with hazardous waste mitigation. The Utility previously
had notified its insurance carriers that it seeks coverage under its
comprehensive general liability policies to recover costs incurred at certain
specified sites. In general, the Utility's carriers neither admitted nor
denied coverage, but requested additional information from the Utility.
Although the Utility has received some amounts in settlements with certain of
its insurers (approximately $83 million through December 31, 2000), the
ultimate amount of recovery from insurance coverage, either in the aggregate
or with respect to a particular site, cannot be quantified at this time.
Insurance recoveries are subject to the HWRC mechanism discussed above.

   Compressor Station Litigation

   Several cases have been brought against Pacific Gas and Electric Company
seeking damages from alleged chromium contamination at the Utility's Hinkley,
Topock, and Kettleman Compressor Stations. See Item 3, "Legal Proceedings--
Compressor Station Chromium Litigation" below, for a description of the
pending litigation.

   Electric and Magnetic Fields

   In January 1991, the CPUC opened an investigation into potential interim
policy actions to address increasing public concern, especially with respect
to schools, regarding potential health risks that may be associated with
electric and magnetic fields (EMF) from utility facilities. In its order
instituting the investigation, the CPUC acknowledged that the scientific
community has not reached consensus on the nature of any health impacts from
contact with EMF, but went on to state that a body of evidence has been
compiled that raises the question of whether adverse health impacts might
exist.

   In November 1993, the CPUC adopted an interim EMF policy for California
energy utilities that, among other things, requires California energy
utilities to take no-cost and low-cost steps to reduce EMF from new and
upgraded utility facilities. California energy utilities are required to fund
a $1.5 million EMF education program and a $5.6 million EMF research program
managed by the California Department of Health Services. It is expected that
the CPUC and the California Department of Health Services will complete its
EMF research program by December 2001.

   As part of its effort to educate the public about EMF, Pacific Gas and
Electric Company provides interested customers with information regarding the
EMF exposure issue. The Utility also provides a free field measurement service
to inform customers about EMF levels at different locations in and around
their residences or commercial buildings.

                                      50
<PAGE>

   The Utility currently is not involved in third-party litigation concerning
EMF. In August 1996, the California Supreme Court held that homeowners are
barred from suing utilities for alleged property value losses caused by fear
of EMF from power lines. The Court expressly limited its holding to property
value issues, leaving open the question as to whether lawsuits for alleged
personal injury resulting from exposure to EMF are similarly barred. The
Utility was a defendant in civil litigation in which plaintiffs alleged
personal injuries resulting from exposure to EMF. In January 1998, the appeals
court in this matter held that the CPUC has exclusive jurisdiction over
personal injury and wrongful death claims arising from allegations of harmful
exposure to EMF and barred plaintiffs' personal injury claims. Plaintiffs
filed an appeal of this decision with the California Supreme Court. The
California Supreme Court declined to hear the case.

   If the scientific community reaches a consensus that EMF presents a health
hazard and further determines that the impact of utility-related EMF exposures
can be isolated from other exposures, the Utility may be required to take
mitigation measures at its facilities. The costs of such mitigation measures
cannot be estimated with any certainty at this time. However, such costs could
be significant, depending on the particular mitigation measures undertaken,
especially if relocation of existing power lines ultimately is required.

   Low Emission Vehicle Programs

   In December 1995, the CPUC issued its decision in the Low Emission Vehicle
(LEV) proceeding, which approved approximately $42 million in funding for
Pacific Gas and Electric Company's LEV program for the six-year period
beginning in 1996. The CPUC's decision on electric industry restructuring
found that the costs of utility LEV programs should continue to be collected
by the utility for the duration of the six-year period. The Utility continues
to run its LEV program as funded. Annual LEV accomplishment reports are filed
with the CPUC on November 1.

                                      51
<PAGE>

ITEM 2. Properties.

   Information concerning Pacific Gas and Electric Company's electric
generation units, electric and gas transmission facilities, and electric and
gas distribution facilities is included in response to Item 1. All of the
Utility's real properties and substantially all of the Utility's personal
properties are subject to the lien of an indenture that provides security to
the holders of the Utility's First and Refunding Mortgage Bonds.

   Information concerning properties and facilities owned by PG&E National
Energy Group, Inc. and other PG&E Corporation subsidiaries is included in the
discussion under the heading of this report entitled "PG&E National Energy
Group, Inc."

ITEM 3. Legal Proceedings.

   See Item 1, Business, for other proceedings pending before governmental and
administrative bodies. In addition to the following legal proceedings, PG&E
Corporation and Pacific Gas and Electric Company are subject to routine
litigation incidental to their business.

Pacific Gas and Electric Company Bankruptcy

   On April 6, 2001, Pacific Gas and Electric Company filed a voluntary
petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy
Code in the U.S. Bankruptcy Court for the Northern District of California.
Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains
control of its assets and is authorized to operate its business as a debtor in
possession while being subject to the jurisdiction of the Bankruptcy Court.
For more information about the Utility's financial condition and the factors
leading up to the filing for bankruptcy protection, see "Management's
Discussion and Analysis" and Notes 2 and 3 of the 2000 Annual Report to
Shareholders, which portions are incorporated herein by reference and filed as
Exhibit 13 to this report.

Pacific Gas and Electric Company vs. California Public Utilities Commissioners

   On November 8, 2000, Pacific Gas and Electric Company filed a lawsuit in
the United States District Court for the Northern District of California
against the CPUC commissioners, asking the court to declare that the federally
approved wholesale power costs the Utility has incurred to serve its customers
are recoverable in retail rates. As of December 31, 2000, the uncollected
wholesale power purchase costs recorded in the Utility's TRA was $6.6 billion.
(As described above, the Utility recognized a fourth quarter 2000 charge to
earnings of $6.9 billion ($4.1 billion after tax), reflecting the write-off of
undercollected power purchase costs and other generation-related regulatory
assets.) The complaint states that the wholesale power costs which the Utility
has prudently incurred are paid pursuant to filed rates which the FERC has
authorized and approved, and that under the United States Constitution and
numerous court decisions, such costs cannot be disallowed by state regulators.
The Utility's complaint also alleges that to the extent that the Utility is
denied recovery of these mandated wholesale power costs by order of the CPUC,
such action constitutes an unlawful taking and confiscation of the Utility's
property. The Utility argues that the CPUC's decisions violate federal
preemption law and the filed rate doctrine, which requires the CPUC to allow
the Utility to recover in full its reasonable procurement costs incurred under
lawful rates and tariffs approved by the FERC, a federal governmental agency.
The complaint also pleads claims under the Commerce Clause, Due Process
Clause, and Equal Protection Clause of the United States Constitution.

   On January 29, 2001, the Utility's lawsuit was transferred to the U.S.
District Court for the Central District of California where a similar lawsuit
filed by Southern California Edison is pending. On March 19, 2001, the court
heard argument on the CPUC's motion to dismiss the case. The judge took the
matter under submission.

Wilson vs. PG&E Corporation and Pacific Gas and Electric Company

   On February 13, 2001, two complaints were filed against PG&E Corporation
and Pacific Gas and Electric Company in the Superior Court of the State of
California, San Francisco County: Richard D. Wilson v. Pacific

                                      52
<PAGE>

Gas and Electric Company et al. ("Wilson I"), and Richard D. Wilson v. Pacific
Gas and Electric Company et al., ("Wilson II").

   In Wilson I, the plaintiff alleges that in 1998 and 1999, PG&E Corporation
violated its fiduciary duties and California Business and Professions Code
Section 17200 by causing the Utility to repurchase shares of Pacific Gas and
Electric Company common stock from PG&E Corporation at an aggregate price of
$2.326 billion. The complaint alleges an unlawful business act or practice
under Section 17200 because these repurchases allegedly violated PG&E
Corporation's fiduciary duties, a first priority capital requirement allegedly
imposed by the CPUC's decision approving the formation of a holding company,
and also an implicit public trust imposed by AB 1890, which granted authority
for the issuance of rate reduction bonds. The complaint seeks to enjoin the
repurchase by the Utility of any more of its common stock from PG&E
Corporation or other entities or persons unless good cause is shown, and seeks
restitution from PG&E Corporation of $2.326 billion, with interest, on behalf
of the Utility. The complaint also seeks an accounting, costs of suit, and
attorney's fees.

   In Wilson II, the plaintiff alleges that PG&E Corporation, the Utility, and
other subsidiaries have been parties to a tax-sharing arrangement under which
PG&E Corporation annually files consolidated federal and state income tax
returns for, and pays, the income taxes of PG&E Corporation and participating
subsidiaries. According to the plaintiff, between 1997 and 1999, PG&E
Corporation collected $2.957 billion from the Utility under this tax-sharing
arrangement, but paid only $2.294 billion (net of refunds) to all governments
under the tax-sharing arrangement. Plaintiff alleges that these monies were
held under an express and implied trust to be used by PG&E Corporation to pay
the Utility's share of income taxes under the tax-sharing arrangement.
Plaintiff alleges that PG&E Corporation overcharged the Utility $663 million
under the tax-sharing arrangement and has declined voluntarily to return these
monies to the Utility, in violation of the alleged trust, the alleged first
priority capital condition, and California Business and Professions Code
Section 17200. The complaint seeks to enjoin PG&E Corporation from engaging in
the activities alleged in the complaint (including the tax-sharing
arrangement), and seeks restitution from PG&E Corporation of $663 million,
with interest, on behalf of the Utility. The complaint also seeks an
accounting, costs of suit, and attorney's fees.

   PG&E Corporation and the Utility believe these complaints to be without
merit. The Utility filed a notice of automatic stay on April 11, 2001,
pursuant to the Bankruptcy Code. PG&E Corporation believes that these actions
also are stayed against PG&E Corporation. PG&E Corporation and the Utility are
unable to predict whether the outcome of this litigation, if it were to
proceed, will have a material adverse affect on their financial condition or
results of operation.

Moss Landing Power Plant

   In December 1999, the Utility was notified by the purchaser of its former
Moss Landing power plant that it had identified a cleaning procedure used at
the plant that released heated water and organic debris from the intake, and
that this procedure is not specified in the plant's National Pollutant
Discharge Elimination System (NPDES) permit issued by the Central Coast
Regional Water Quality Control Board (Central Coast Board). The purchaser
notified the Central Coast Board of its findings and the Central Coast Board
requested additional information from the purchaser. The Utility initiated an
investigation of these activities during the time it owned the plant. The
Utility notified the Central Coast Board that it had undertaken an
investigation and that it would present the results to the Central Coast Board
when the investigation was completed. In March 2000, the Central Coast Board
requested the Utility to provide specific information regarding the
"backflush" procedure used at Moss Landing. The Utility provided the requested
information in April 2000. The Utility's investigation indicated that while
the Utility owned Moss Landing, significant amounts of water were discharged
from the cooling water intake. While the Utility's investigation did not
clearly indicate that discharged waters had a temperature higher than ambient
receiving water, the Utility believes that the temperature of the discharged
water was higher than that of the receiving water. In December 2000, the
executive officer of the Central Coast Board made a settlement proposal to the
Utility under which the Utility would pay $10 million, a portion of which
would be used for environmental projects and the balance of which would
constitute civil penalties. Settlement negotiations are continuing.

                                      53
<PAGE>

   PG&E Corporation and the Utility believe that the ultimate outcome of this
matter will not have a material adverse impact on PG&E Corporation's or the
Utility's financial position or results of operations.

Compressor Station Chromium Litigation

   Pacific Gas and Electric Company is currently a defendant in nine civil
actions pending in California courts. These cases are (1) Aguayo v. Pacific
Gas and Electric Company, filed March 15, 1995 in Los Angeles County Superior
Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996
in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories,
Inc., et al., filed November 27, 1996 in Los Angeles County Superior Court,
(4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed
on July 25, 2000 in Los Angeles Superior Court, (5) Baldonado vs. Pacific Gas
and Electric Company, filed On October 25, 2000 in Los Angeles Superior Court,
(6) Gale v. Pacific Gas and Electric Company, filed on January 30, 2001 in Los
Angeles Superior Court, (7) Monice v. PG&E, filed March 15, 2001, in San
Bernardino County Superior Court, (8) Puckett v. PG&E, filed March 30, 2001,
in Los Angeles Superior Court, and (9) Alderson, et al. v. PG&E Corporation,
Pacific Gas and Electric Company, Betz Chemical Company, et al., filed April
11, 2001, in Los Angeles Superior Court. PG&E has not yet been served with the
complaint in Gale v. PG&E, Puckett v. PG&E, or Alderson v. PG&E. There are now
approximately 1,150 plaintiffs in the compressor station chromium litigation
with claims against the Utility. PG&E Corporation has been named as a
defendant in Alderson v. PG&E, et al., a complaint brought on behalf of
approximately 100 plaintiffs. PG&E Corporation has not yet been served with
the complaint. Betz Chemical Company (Betz), the supplier of water treatment
products containing chromium used at the gas compressor stations, also was
named as a defendant in some of these cases. During 2000, pursuant to a
settlement that Betz reached with the approximately 1,650 plaintiffs suing
Betz, the Utility received a credit of up to $40 million to be allocated among
the approximately 900 plaintiffs suing the Utility at the time of the Betz
settlement. The credit will apply to future awards of damages against the
Utility with respect to all claims and causes of actions by these plaintiffs
except claims for punitive or exemplary damages.

   Each of the complaints alleges personal injuries and seek compensatory and
punitive damages in an unspecified amount arising out of alleged exposure to
chromium contamination in the vicinity of the Utility's gas compressor
stations located at Kettleman, Hinkley, and Topock, California. The plaintiffs
include current and former Utility employees and their relatives, residents in
the vicinity of the compressor stations, and persons who visited the gas
compressor stations. The plaintiffs also include spouses or children of these
plaintiffs who claim loss of consortium or wrongful death.

   The discovery referee has set the procedures for selecting 18 trial test
plaintiffs and 2 alternates in the Aguayo, Acosta, and Aguilar cases (the
"Aguayo Litigation"). Ten of these trial test plaintiffs were selected by
plaintiffs' counsel, seven plaintiffs were selected by defense counsel, and
one plaintiff and two alternates were selected at random. Although a date for
the first test trial in the Aguayo Litigation has been set for July 2, 2001,
in Los Angeles Superior Court, the Utility's Chapter 11 bankruptcy filing on
April 6, 2001, automatically stayed all proceedings.

   The Utility is responding to the complaints and asserting affirmative
defenses. The Utility will pursue factual defenses including lack of exposure
to chromium and the inability of chromium to cause certain of the illnesses
alleged and appropriate legal defenses including statute of limitations or
exclusivity of workers' compensation laws. At this stage of the proceedings,
there is substantial uncertainty concerning the claims alleged, and the
Utility is attempting to gather information concerning the alleged type and
duration of exposure, the nature of injuries alleged by individual plaintiffs,
and the additional facts necessary to support its legal defenses, in order to
better evaluate and defend this litigation.

   There has been heightened media attention to the chromium litigation for a
variety of reasons. In a letter dated March 27, 2001, the California
Department of Health Services asked the California Environmental Protection
Agency's Office of Environmental Health Hazard Assessment, ("OEHHA") to
establish a public health goal for chromium 6 in drinking water. In turn,
OEHHA has asked the University of California to establish a blue-ribbon panel
of scientists to study the potential of chromium 6 to cause cancer when
ingested. These

                                      54
<PAGE>

regulatory developments followed in part from substantial media attention
concerning the presence of chromium 6 in certain water sources in Los Angeles,
where the Aguayo Litigation is pending. The chromium issues have also been
mentioned in media stories concerning the California energy crisis. All of
this media and regulatory attention has the potential to adversely impact the
Utility's defense of these cases.

   PG&E Corporation believes that the ultimate outcome of this matter will not
have a material adverse impact on its or the Utility's future financial
position or results of operations. See Note 15 of the "Notes to Consolidated
Financial Statements" beginning on page 83 of the 2000 Annual Report to
Shareholders, portions of which are filed as Exhibit 13 to this report.

Texas Franchise Fee Litigation

   On December 22, 2000, NEG completed the sale of PG&E GTT to El Paso Energy
Field Services, Inc., a subsidiary of El Paso Energy Corporation. The PG&E GTT
entities which were sold included the defendants in several cases which have
been referred to as the Texas Franchise Fee Litigation in PG&E Corporation's
and the Utility's Annual Report on Form 10-K for the year ended December 31,
1999 and previous reports filed with the Securities and Exchange Commission.
Only one PG&E Corporation affiliate, PG&E Energy Trading--Gas Corporation,
remains as a nominal defendant in some of these cases and any potential
liability of this entity is expected to be immaterial.

ITEM 4. Submission of Matters to a Vote of Security Holders.

   Not applicable.

                                      55
<PAGE>

                     EXECUTIVE OFFICERS OF THE REGISTRANTS

   "Executive officers," as defined by Rule 3b-7 of the General Rules and
Regulations under the Securities and Exchange Act of 1934, of PG&E Corporation
are as follows:

<TABLE>
<CAPTION>
                         Age at
                      December 31,
         Name             2000                      Position
         ----         ------------                  --------
 <C>                  <C>          <S>
 R. D. Glynn, Jr.....      58      Chairman of the Board, Chief Executive
                                    Officer, and President
 T. G. Boren.........      51      Executive Vice President; Chairman,
                                    President, and Chief Executive Officer,
                                    PG&E National Energy Group, Inc.
 P. A. Darbee........      48      Senior Vice President, Chief Financial
                                    Officer, and Treasurer
 T. W. High..........      53      Senior Vice President, Administration and
                                    External Relations
 P. C. Iribe.........      50      Senior Vice President; President and Chief
                                    Operating Officer, East Region, PG&E
                                    National Energy Group, Inc.
 T. B. King..........      39      Senior Vice President; President and Chief
                                    Operating Officer, West Region, PG&E
                                    National Energy Group, Inc.
 L. E. Maddox........      45      Senior Vice President; President and Chief
                                    Operating Officer, Trading, PG&E National
                                    Energy Group, Inc.
 G. R. Smith.........      52      Senior Vice President; President and Chief
                                    Executive Officer, Pacific Gas and
                                    Electric Company
 G. B. Stanley.......      54      Senior Vice President, Human Resources
 B. R. Worthington...      51      Senior Vice President and General Counsel
</TABLE>

   All officers of PG&E Corporation serve at the pleasure of the Board of
Directors. During the past five years, the executive officers of PG&E
Corporation had the following business experience. Except as otherwise noted,
all positions have been held at PG&E Corporation.

<TABLE>
<CAPTION>
       Name                Position                   Period Held Office
       ----                --------                   ------------------
 <C>               <S>                        <C>
 R. D. Glynn,      Chairman of the Board,     January 1, 1998 to present
 Jr. .............  Chief Executive
                    Officer, and President
                   Chairman of the Board,     January 1, 1998 to present
                    Pacific Gas and
                    Electric Company
                   President and Chief        June 1, 1997 to present
                    Executive Officer
                   President and Chief        December 18, 1996 to May 31, 1997
                    Operating Officer
                   President and Chief        June 1, 1995 to May 31, 1997
                    Operating Officer,
                    Pacific Gas and
                    Electric Company
 T. G. Boren...... Executive Vice President   August 1, 1999 to present
                   Chairman, President, and   July 1, 2000 to present
                    Chief Executive
                    Officer, PG&E National
                    Energy Group, Inc.
                   President, and Chief
                    Executive Officer, PG&E
                   National Energy Group,     August 1, 1999 to June 30, 2000
                    Inc.
                   President and Chief        February 18, 1992 to July 31, 1999
                    Executive Officer,
                    Southern Energy, Inc.
                   Executive Vice             June 1, 1999 to July 31, 1999
                    President, Southern
                    Company
                   Senior Vice President,     February 16, 1998 to May 31, 1999
                    Southern Company
                   Vice President, Southern   July 17, 1995 to February 15, 1998
                    Company
 P. A. Darbee..... Senior Vice President,     September 20, 1999 to present
                    Chief Financial
                    Officer, and Treasurer
                   Vice President and Chief   June 30, 1997 to September 19, 1999
                    Financial Officer,
                    Advance Fibre
                    Communications, Inc.
                   Vice President, Chief      January 10, 1994 to June 30, 1997
                    Financial Officer, and
                    Controller, Pacific
                    Bell
</TABLE>

                                      56
<PAGE>

<TABLE>
<CAPTION>
       Name                Position                     Period Held Office
       ----                --------                     ------------------
 <C>               <S>                        <C>
 T. W. High....... Senior Vice President,     June 1, 1997 to present
                    Administration and
                    External Relations
                   Senior Vice President,     June 1, 1995 to May 31, 1997
                    Corporate Services,
                    Pacific Gas and
                    Electric Company
 P. C. Iribe...... Senior Vice President      January 1, 1999 to present
                   President and Chief        April 6, 2000 to present
                    Operating Officer, East
                    Region, PG&E National
                    Energy Group, Inc.
                   President and Chief        November 1, 1998 to April 5, 2000
                    Operating Officer, PG&E
                    Generating Company
                    (formerly known as U.S.
                    Generating Company)
                   Executive Vice President   September 1, 1997 to October 31, 1998
                    and Chief Operating
                    Officer, U.S.
                    Generating Company
                   Executive Vice             May 17, 1994 to September 1, 1997
                    President, Marketing,
                    Development, and Asset
                    Management, U.S.
                    Generating Company
 T. B. King....... Senior Vice President      January 1, 1999 to present
                   President and Chief        April 6, 2000 to present
                    Operating Office, West
                    Region, PG&E National
                    Energy Group, Inc.
                   President and Chief        November 23, 1998 to present
                    Operating Officer, PG&E
                    Gas Transmission
                    Corporation
                   President and Chief        February 14, 1997 to November 22, 1998
                    Operating Officer,
                    Kinder Morgan Energy
                    Partners, L.P.
                   Vice President,            July 1, 1995 to February 14, 1997
                    Commercial Operations--
                    Midwest Region, Enron
                    Liquid Services
                    Corporation
 L. E. Maddox..... Senior Vice President      June 1, 1997 to present
                   President and Chief        April 6, 2000 to present
                    Operating Officer,
                    Trading, PG&E National
                    Energy Group, Inc.
                   President and Chief        May 12, 1997 to April 5, 2000
                    Executive Officer, PG&E
                    Energy Trading-Gas
                    Corporation
                   President, PennUnion       May 1995 to May 1997
                    Energy Services, L.L.C.
 G. R. Smith...... Senior Vice President      January 1, 1999 to present
                    (Please refer to
                    description of business
                    experience for
                    executive officers of
                    Pacific Gas and
                    Electric Company
                    below.)
 G. B. Stanley.... Senior Vice President,     January 1, 1998 to present
                    Human Resources
                   Vice President, Human      June 1, 1997 to December 31, 1997
                    Resources
                   Vice President, Human      July 1, 1996 to May 31, 1997
                    Resources, Pacific Gas
                    and Electric Company
 B. R.
 Worthington...... Senior Vice President      June 1, 1997 to present
                   and General Counsel
                   General Counsel            December 18, 1996 to May 31, 1997
                   Senior Vice President      June 1, 1995 to June 30, 1997
                    and General Counsel,
                    Pacific Gas and
                    Electric Company
</TABLE>

                                       57
<PAGE>

   "Executive officers," as defined by Rule 3b-7 of the General Rules and
Regulations under the Securities and Exchange Act of 1934, of Pacific Gas and
Electric Company are as follows:

<TABLE>
<CAPTION>
        Name         Age at December 31, 2000             Position
        ----         ------------------------             --------
 <C>                 <C>                      <S>
 G. R. Smith........            52            President and Chief Executive
                                               Officer
 K. M. Harvey.......            42            Senior Vice President, Chief
                                               Financial Officer, and
                                               Treasurer
 R. J. Peters.......            46            Senior Vice President and
                                               General Counsel
 J. K. Randolph.....            56            Senior Vice President and Chief
                                               of Utility Operations
 D. D. Richard,                 50            Senior Vice President, Public
 Jr. ...............                           Affairs
 G. M. Rueger.......            50            Senior Vice President, and Chief
                                               Nuclear Officer
</TABLE>

   All officers of Pacific Gas and Electric Company serve at the pleasure of
the Board of Directors. During the past five years, the executive officers of
Pacific Gas and Electric Company had the following business experience. Except
as otherwise noted, all positions have been held at Pacific Gas and Electric
Company.

<TABLE>
<CAPTION>
         Name                  Position                    Period Held Office
         ----                  --------                    ------------------
 <C>                   <S>                        <C>
 G. R. Smith.......... President and Chief        June 1, 1997 to present
                        Executive Officer
                       Chief Financial Officer,   December 18, 1996 to May 31, 1997
                        PG&E Corporation
                       Senior Vice President      June 1, 1995 to May 31, 1997
                        and Chief Financial
                        Officer
                       Vice President and Chief   November 1, 1991 to May 31, 1995
                        Financial Officer
 K. M. Harvey......... Senior Vice President,     November 1, 2000 to present
                        Chief Financial
                        Officer, and Treasurer
                       Senior Vice President,     January 1, 2000 to October 31, 2000
                        Chief Financial
                        Officer, Controller,
                        and Treasurer
                       Senior Vice President,     July 1, 1997 to December 31, 1999
                        Chief Financial
                        Officer, and Treasurer
                       Vice President and         June 1, 1995 to June 30, 1997
                        Treasurer
 R. J. Peters......... Senior Vice President      January 1, 1999 to present
                        and General Counsel
                       Vice President and         July 1, 1997 to December 31, 1998
                        General Counsel
                       Chief Counsel,             January 1, 1993 to June 30, 1997
                        Regulatory
 J. K. Randolph....... Senior Vice President      April 6, 2000 to present
                        and Chief of Utility
                        Operations
                       Senior Vice President      July 1, 1997 to April 5, 2000
                        and General Manager,
                        Transmission,
                        Distribution and
                        Customer Service
                        Business Unit
                       Vice President and         January 1, 1997,to June 30, 1997
                        General Manager, Power
                        Generation, Business
                        Unit
                       Vice President, Power      November 1, 1991 to December 31, 1996
                        Generation
 D. D. Richard, Jr. .. Senior Vice President,     May 1, 1998 to present
                        Public Affairs
                       Senior Vice President,     July 1, 1997 to April 30, 1998
                        Governmental and
                        Regulatory Relations
                       Senior Vice President,     October 18, 2000 to present
                        Public Affairs, PG&E
                        Corporation
                       Vice President,            July 1, 1997 October 17, 2000
                        Governmental Relations,
                        PG&E Corporation
                       Vice President,            January 1, 1997 to June 30, 1997
                        Governmental Relations
                       Executive Vice President   January 1993 to December 1996
                        and Principal, Morse,
                        Richard, Weisenmiller &
                        Assoc., Inc. (energy,
                        project finance, and
                        environmental
                        consulting)
 G. M. Rueger......... Senior Vice President,     April 6, 2000 to present
                        Generation and chief
                        Nuclear Officer
                       Senior Vice President      November 1, 1991 to April 5, 2000
                        and General Manager,
                        Nuclear Power
                        Generation Business
                        Unit
</TABLE>

                                      58
<PAGE>

                                    PART II

ITEM 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.

   Information responding to part of Item 5, for each of PG&E Corporation and
Pacific Gas and Electric Company, is set forth on page 89 under the heading
"Quarterly Consolidated Financial Data (Unaudited)" in the 2000 Annual Report
to Shareholders, which information is hereby incorporated by reference and
filed as part of Exhibit 13 to this report. As of April 9, 2001, there were
132,612 holders of record of PG&E Corporation common stock. PG&E Corporation
common stock is listed on the New York, Pacific, and Swiss stock exchanges.
The discussion of dividends with respect to PG&E Corporation's common stock is
hereby incorporated by reference from "Management's Discussion and Analysis--
Dividends" on page 20 of the 2000 Annual Report to Shareholders.

   Neither Pacific Gas and Electric Company nor PG&E Corporation made any
sales of unregistered equity securities during 2000, the period covered by
this report.

ITEM 6. Selected Financial Data.

   A summary of selected financial information, for each of PG&E Corporation
and Pacific Gas and Electric Company for each of the last five fiscal years,
is set forth on page 5 under the heading "Selected Financial Data" in the 2000
Annual Report to Shareholders, which information is hereby incorporated by
reference and filed as part of Exhibit 13 to this report.

   Pacific Gas and Electric Company's ratio of earnings to fixed charges for
the year ended December 31, 2000 was a negative 7.70. Pacific Gas and Electric
Company's ratio of earnings to combined fixed charges and preferred stock
dividends for the year ended December 31, 2000 was a negative 7.29. The
negative ratios of earnings to fixed charges and earnings to combined fixed
charges and preferred stock dividends indicates a deficiency in earnings of
$5,637 million and $5,673 million respectively. The statement of the foregoing
ratios, together with the statements of the computation of the foregoing
ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the
purpose of incorporating such information and exhibits into Registration
Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific
Gas and Electric Company's various classes of debt and first preferred stock
outstanding.

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

   A discussion of PG&E Corporation's and Pacific Gas and Electric Company's
consolidated results of operations and financial condition is set forth on
pages 6 through 31 under the heading "Management's Discussion and Analysis" in
the 2000 Annual Report to Shareholders, which discussion is hereby
incorporated by reference and filed as part of Exhibit 13 to this report.

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.

   Information responding to Item 7A appears in the 2000 Annual Report to
Shareholders on pages 28-31 under the heading "Management's Discussion and
Analysis--Quantitative and Qualitative Disclosures about Market Risk," and on
pages 46-47, 60-62 and 68-71 under Notes 1, 4, 8 and 9 of the "Notes to the
Consolidated Financial Statements" of the 2000 Annual Report to Shareholders,
which information is hereby incorporated by reference and filed as part of
Exhibit 13 to this report.

ITEM 8. Financial Statements and Supplementary Data.

   Information responding to Item 8 appears on pages 32 through 92 of the 2000
Annual Report to Shareholders under the following headings for PG&E
Corporation: "Statement of Consolidated Operations," "Consolidated Balance
Sheets," "Statement of Consolidated Cash Flows," and "Statement of
Consolidated Common Stock Equity;" under the following headings for Pacific
Gas and Electric Company: "Statement of Consolidated Operations,"
"Consolidated Balance Sheets," "Statement of Consolidated Cash Flows," and

                                      59
<PAGE>

"Statement of Consolidated Stockholders' Equity;" and under the following
headings for PG&E Corporation and Pacific Gas and Electric Company jointly:
"Notes to the Consolidated Financial Statements," "Quarterly Consolidated
Financial Data (Unaudited)," "Independent Auditors' Report," and
"Responsibility for the Consolidated Financial Statements," which information
is hereby incorporated by reference and filed as part of Exhibit 13 to this
report.

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

   Not applicable.

                                   PART III

ITEM 10. Directors and Executive Officers of the Registrant.

   Information regarding executive officers of PG&E Corporation and Pacific
Gas and Electric Company is included in a separate item captioned "Executive
Officers of the Registrant" contained on pages 56 through 58 in Part I of this
report. Other information responding to Item 10 is included on pages 3 through
5 under the heading "Item No. 1: Election of Directors of PG&E Corporation and
Pacific Gas and Electric Company" and page 40 under the heading "Section 16(a)
Beneficial Ownership Reporting Compliance" in the Joint Proxy Statement
relating to the 2001 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.

ITEM 11. Executive Compensation.

   Information responding to Item 11, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on pages 8 and 9 under the heading
"Compensation of Directors" and on pages 31 through 37 under the headings
"Summary Compensation Table," "Option/SAR Grants in 2000," "Aggregated
Option/SAR Exercises in 2000 and Year-End Option/SAR Values," "Long-Term
Incentive Plan--Awards in 2000," "Retirement Benefits," "Employment
Contracts/Arrangements," and "Termination of Employment and Change In Control
Provisions" in the Joint Proxy Statement relating to the 2001 Annual Meetings
of Shareholders, which information is hereby incorporated by reference.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management.

   Information responding to Item 12, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on pages 10 and 11 under the heading
"Security Ownership of Management" and on page 40 under the heading "Principal
Shareholders" in the Joint Proxy Statement relating to the 2001 Annual
Meetings of Shareholders, which information is hereby incorporated by
reference.

ITEM 13. Certain Relationships and Related Transactions.

   Information responding to Item 13, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on page 9 under the heading "Certain
Relationships and Related Transactions" in the Joint Proxy Statement relating
to the 2001 Annual Meetings of Shareholders, which information is hereby
incorporated by reference.

                                      60
<PAGE>

                                    PART IV

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

    (a) The following documents are filed as a part of this report:

    1. The following consolidated financial statements, supplemental
       information, and report of independent public accountants contained
       in the Report to Shareholders, which have been incorporated by
       reference in this report:

         Statements of Consolidated Operations for the Years Ended
         December 31, 2000, 1999, and 1998, for each of PG&E Corporation
         and Pacific Gas and Electric Company.

         Statements of Consolidated Cash Flows for the Years Ended
         December 31, 2000, 1999, and 1998, for each of PG&E Corporation
         and Pacific Gas and Electric Company.

         Consolidated Balance Sheets at December 31, 2000 and 1999 for
         each of PG&E Corporation and Pacific Gas and Electric Company.

         Statement of Consolidated Common Stock Equity for the Years Ended
         December 31, 2000, 1999, and 1998, for PG&E Corporation.

         Statement of Consolidated Stockholders' Equity for the Years
         Ended December 31, 2000, 1999, and 1998, for Pacific Gas and
         Electric Company.

         Notes to Consolidated Financial Statements.

         Quarterly Consolidated Financial Data (Unaudited).

         Independent Auditors' Report (Deloitte & Touche LLP).

    2. Independent Auditors' Report (Deloitte & Touche LLP) included at page
       69 of this Form 10-K.

    3. Report of Independent Public Accountants (Arthur Andersen LLP)
       included at page 70 of this Form 10-K.

    4. Report of Independent Public Accountants (Arthur Andersen LLP)
       included at page 71 of this Form 10-K.

    5. Financial statement schedules:

         I--Condensed Financial Information of Parent for the Years Ended
         December 31, 2000 and 1999.

         II--Consolidated Valuation and Qualifying Accounts for each of
         PG&E Corporation and Pacific Gas and Electric Company for the
         Years Ended December 31, 2000, 1999 and 1998.

   Schedules not included are omitted because of the absence of conditions
under which they are required or because the required information is provided
in the consolidated financial statements including the notes thereto.

    6. Exhibits required to be filed by Item 601 of Regulation S-K:

<TABLE>
       <C> <S>
       3.1 Restated Articles of Incorporation of PG&E Corporation effective as
           of May 5, 2000 (incorporated by reference to PG&E Corporation's Form
           10-Q for the quarter ended March 31, 2000 (File No. 1-12609),
           Exhibit 3.1)

       3.2 Certificate of Determination for PG&E Corporation Series A Preferred
           Stock filed December 22, 2000

       3.3 By-Laws of PG&E Corporation amended as of February 21, 2001

       3.4 Restated Articles of Incorporation of Pacific Gas and Electric
           Company effective as of May 6, 1998 (incorporated by reference to
           Pacific Gas and Electric Company's Form 10-Q for the quarter ended
           March 31, 1998 (File No. 1-2348), Exhibit 3.1)
</TABLE>

                                      61
<PAGE>

<TABLE>
       <C>   <S>
         3.5 By-Laws of Pacific Gas and Electric Company amended as of February
             21, 2001

         4.1 First and Refunding Mortgage of Pacific Gas and Electric Company
             dated December 1, 1920, and supplements thereto dated April 23,
             1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15,
             1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965,
             July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and
             December 1, 1988 (incorporated by reference to Registration No. 2-
             1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-
             22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-
             8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B;
             Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910,
             Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No.
             2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C;
             Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849,
             Exhibit 4.3; Pacific Gas and Electric Company's Form 8-K dated
             January 18, 1989 (File No. 1-2348), Exhibit 4.2)

             In accordance with Item 601(b)(4)(iii) of Regulation S-K, each of
             PG&E Corporation or Pacific Gas and Electric Company agrees to
             furnish to the Commission any instruments respecting long-term
             debt not required to be filed by application of such item

         4.2 Form of Rights Agreement dated as of December 22, 2000 between
             PG&E Corporation and Mellon Investor Services LLC, including the
             Form of Rights Certificate as Exhibit A, the Summary of Rights to
             Purchase Preferred Stock as Exhibit B, and the Form of Certificate
             of Determination of Preferences for the Preferred Stock as Exhibit
             C

        10.  The Gas Accord Settlement Agreement, together with accompanying
             tables, adopted by the California Public Utilities Commission on
             August 1, 1997, in Decision 97-08-055 (incorporated by reference
             to PG&E Corporation and Pacific Gas and Electric Company's Form
             10-K for the year ended December 31, 1997 (File No. 1-12609 and
             File No. 1-2348), Exhibit No. 10.2), as amended by Operational
             Flow Order (OFO) Settlement Agreement, approved by the California
             Public Utilities Commission on February 17, 2000, in Decision 00-
             02-050, as amended by Comprehensive Gas OII Settlement Agreement,
             approved by the California Public Utilities Commission on May 18,
             2000, in Decision 00-05-049

        10.1 Stock Purchase Agreement By and Between PG&E National Energy
             Group, Inc. and El Paso Field Services Company, dated as of
             January 27, 2000 (incorporated by reference to PG&E Corporation's
             Form 10-K for the year ended December 31, 1999 (File No. 1-12609),
             Exhibit No. 10.1)

        10.2 Credit Agreement between PG&E Corporation, General Electric
             Capital Corporation and Lehman Commercial Paper, Inc. dated March
             1, 2001

       *10.3 PG&E Corporation Supplemental Retirement Savings Plan dated as of
             January 1, 2000 (incorporated by reference to PG&E Corporation's
             Form 10-K for the year ended December 31, 2000 (File No. 1-12609),
             Exhibit 10.2)

       *10.4 Description of Compensation Arrangement between PG&E Corporation
             and Thomas G. Boren (incorporated by reference to PG&E
             Corporation's Form 10-Q for the quarter ended September 30, 1999
             (File No. 1-12609), Exhibit 10.2)

       *10.5 Description of Compensation Arrangement between PG&E Corporation
             and Peter Darbee (incorporated by reference to PG&E Corporation's
             Form 10-Q for the quarter ended September 30, 1999 (File No. 1-
             12609), Exhibit 10.3)

       *10.6 Letter regarding Compensation Arrangement between PG&E Corporation
             and Thomas B. King dated November 4, 1998
</TABLE>

                                       62
<PAGE>

<TABLE>
       <C>       <S>
       *10.7     Letter regarding Compensation Arrangement between PG&E
                 Corporation and Lyn E. Maddox dated April 25, 1997

       *10.8      Letter Regarding Relocation Arrangement Between PG&E
                  Corporation and Thomas B. King dated March 16, 2000
                  (incorporated by reference to PG&E Corporation's Form 10-Q
                  for the quarter ended March 31, 2000 (File No. 1-12609),
                  Exhibit 10)

       *10.9      Description of Relocation Arrangement Between PG&E
                  Corporation and Lyn E. Maddox

       *10.10     PG&E Corporation Senior Executive Officer Retention Program
                  approved December 20, 2000

       *10.10.1   Letter regarding retention award to Robert D. Glynn, Jr.
                  dated January 22, 2001

       *10.10.2   Letter regarding retention award to Gordon R. Smith dated
                  January 22, 2001

       *10.10.3   Letter regarding retention award to Peter A. Darbee dated
                  January 22, 2001

       *10.10.4   Letter regarding retention award to Bruce R. Worthington
                  dated January 22, 2001

       *10.10.5   Letter regarding retention award to G. Brent Stanley dated
                  January 22, 2001

       *10.10.6   Letter regarding retention award to Daniel D. Richard dated
                  January 22, 2001

       *10.10.7   Letter regarding retention award to James K Randolph dated
                  February 27, 2001

       *10.10.8   Letter regarding retention award to Gregory M. Rueger dated
                  February 27, 2001

       *10.10.9   Letter regarding retention award to Kent Harvey dated
                  February 27, 2001

       *10.10.10  Letter regarding retention award to Roger J. Peters dated
                  February 27, 2001

       *10.10.11  Letter regarding retention award to Thomas G. Boren dated
                  February 27, 2001

       *10.10.12  Letter regarding retention award to Lyn E. Maddox dated
                  February 27, 2001

       *10.10.13  Letter regarding retention award to P. Chrisman Iribe dated
                  February 27, 2001

       *10.10.14  Letter regarding retention award to Thomas B. King dated
                  February 27, 2001

       *10.11     Agreement and Release between PG&E Corporation and Thomas W.
                  High dated December 8, 2000

       *10.12     PG&E Corporation Deferred Compensation Plan for Non-Employee
                  Directors, as amended and restated effective as of July 22,
                  1998 (incorporated by reference to PG&E Corporation's Form
                  10-Q for the quarter ended September 30, 1998 (File
                  No. 1-12609), Exhibit 10.2)

       *10.13     Description of Short-Term Incentive Plan for Officers of
                  PG&E Corporation and its subsidiaries, effective January 1,
                  2000 (incorporated by reference to PG&E Corporation's Form
                  10-K for the year ended December 31, 1999 (File No. 1-
                  12609), Exhibit 10.7)

       *10.14     Description of Short-Term Incentive Plan for Officers of
                  PG&E Corporation and its subsidiaries, effective January 1,
                  2001

       *10.15     Supplemental Executive Retirement Plan of the Pacific Gas
                  and Electric Company, effective January 1, 1998
                  (incorporated by reference to PG&E Corporation's Form 10-K
                  for the year ended December 31, 1998 (File No. 1-12609),
                  Exhibit 10.7)

       *10.16     Pacific Gas and Electric Company Relocation Assistance
                  Program for Officers (incorporated by reference to Pacific
                  Gas and Electric Company's Form 10-K for fiscal year 1989
                  (File No. 1-2348), Exhibit 10.16)
</TABLE>


                                       63
<PAGE>

<TABLE>
       <C>    <S>
       *10.17  Postretirement Life Insurance Plan of the Pacific Gas and
               Electric Company (incorporated by reference to Pacific Gas and
               Electric Company's Form 10-K for fiscal year 1991 (File No. 1-
               2348), Exhibit 10.16)

       *10.18  PG&E Corporation Retirement Plan for Non-Employee Directors, as
               amended and terminated January 1, 1998 (incorporated by
               reference to incorporated by reference to PG&E Corporation Form
               10-K for the year ended December 31, 1997 (File No. 1-12609),
               Exhibit No. 10.13)

       *10.19  PG&E Corporation Long-Term Incentive Program, as amended
               February 16, 2000, including the PG&E Corporation Stock Option
               Plan, Performance Unit Plan, and Non-Employee Director Stock
               Incentive Plan (incorporated by reference to incorporated by
               reference to PG&E Corporation Form 10-K for the year ended
               December 31, 1999, (File No. 1-12609), Exhibit No. 10.12)

       *10.20  PG&E Corporation Executive Stock Ownership Program, amended as
               of September 19, 2000

       *10.21  PG&E Corporation Officer Severance Policy, amended as of July
               21, 1999 (incorporated by reference to PG&E Corporation's Form
               10-Q for the quarter ended September 30, 1999 (File No. 1-
               12609), Exhibit 10.1)

       *10.22  PG&E Corporation Director Grantor Trust Agreement dated April
               1, 1998 (incorporated by reference to PG&E Corporation's Form
               10-Q for the quarter ended March 31, 1998 (File No. 1-12609),
               Exhibit 10.1)

       *10.23  PG&E Corporation Officer Grantor Trust Agreement dated April 1,
               1998 (incorporated by reference to PG&E Corporation's Form 10-Q
               for the quarter ended March 31, 1998 (File No. 1-12609),
               Exhibit 10.2)

        11.    Computation of Earnings Per Common Share

        12.1   Computation of Ratios of Earnings to Fixed Charges for Pacific
               Gas and Electric Company

        12.2   Computation of Ratios of Earnings to Combined Fixed Charges and
               Preferred Stock Dividends for Pacific Gas and Electric Company

        13.    2000 Annual Report to Shareholders of PG&E Corporation and
               Pacific Gas and Electric Company--portions of the Report to
               Shareholders under the headings "Selected Financial Data,"
               "Management's Discussion and Analysis," "Independent Auditors'
               Report," "Responsibility for Consolidated Financial
               Statements," financial statements of PG&E Corporation entitled
               "Statement of Consolidated Operations," "Consolidated Balance
               Sheet," "Statement of Consolidated Cash Flows," "Statement of
               Consolidated Common Stock Equity," financial statements of
               Pacific Gas and Electric Company entitled "Statement of
               Consolidated Operations," "Consolidated Balance Sheet,"
               "Statement of Consolidated Cash Flows," "Statement of
               Consolidated Stockholders' Equity," "Notes to Consolidated
               Financial Statements" and "Quarterly Consolidated Financial
               Data (Unaudited)" are included only (Except for those portions
               that are expressly incorporated herein by reference, such
               Report to Shareholders is furnished for the information of the
               Commission and is not deemed to be "filed" herein.)

        21.    Subsidiaries of the Registrant

        23.1   Independent Auditors' Consent (Deloitte & Touche LLP)

        23.2   Consent of Arthur Andersen LLP
</TABLE>

                                       64
<PAGE>

<TABLE>
       <C>   <S>
        24.1  Resolutions of the Boards of Directors of PG&E Corporation and
              Pacific Gas and Electric Company authorizing the execution of
              the Form 10-K

        24.2  Powers of Attorney
</TABLE>
--------
*  Management contract or compensatory plan or arrangement required to be
   filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.

   The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission and are hereby incorporated by reference. All exhibits filed
herewith or incorporated by reference are filed with respect to both PG&E
Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No.
1-2348), unless otherwise noted. Exhibits will be furnished to security
holders of PG&E Corporation or Pacific Gas and Electric Company upon written
request and payment of a fee of $0.30 per page, which fee covers only the
registrants' reasonable expenses in furnishing such exhibits. The registrants
agree to furnish to the Commission upon request a copy of any instrument
defining the rights of long-term debt holders not otherwise required to be
filed hereunder.

    (b) Reports on Form 8-K

   Reports on Form 8-K(1) during the quarter ended December 31, 2000 and
through the date hereof:

     1. October 25, 2000

     Item 5. Other Events--

            B. Third Quarter 2000 Consolidated Earnings
            C. Pacific Gas and Electric Company's Wholesale Power Purchase
              Costs
            D. Transition Cost Recovery
            E. Earnings Outlook

     2. November 22, 2000

     Item 5. Other Events--

            A. Valuation and Disposition of Pacific Gas and Electric Company's
              Hydroelectric Generating Assets
            B. Recovery of Wholesale Power Purchase Costs
            C. Pacific Gas and Electric Company's Rate Stabilization Plan
            D. Federal Energy Regulatory Commission Order
            E. Pacific Gas and Electric Company's Federal Complaint

     3. December 8, 2000

     Item 5. Other Events--

            A. Valuation and Disposition of Pacific Gas and Electric Company's
              Hydroelectric Generating Assets
            B. Pacific Gas and Electric Company's Rate Stabilization Plan
            C. CPUC's Post-transition Period Ratemaking Decision

     4. December 18, 2000

     Item 5. Other Events--

            A. Recent Regulatory Actions Addressing the California Energy
              Market
            B. Pacific Gas and Electric Company's Wholesale Power Purchase
              Costs
            C. Liquidity and Financial Impacts

                                      65
<PAGE>

     5. December 22, 2000

     Item 5. Other Events--

            A. California Energy Crisis
            B. PG&E Corporation Shareholder Rights Plan

     6. December 29, 2000

     Item 5. Other Events--California Energy Crisis

     7. January 4, 2001

     Item 5. Other Events--California Energy Crisis

     8. January 5, 2001

     Item 5. Other Events--

            California Public Utilities Commission Decision Issued

     9. January 10, 2001

     Item 5. Other Events--

            A. Current Financial Condition
            B. Impending Natural Gas Shortage
            C. ISO's Requested Tariff Amendment to Creditworthiness Standards

      10. January 10, 2001

    Item 5. Other Events--Suspension of PG&E Corporation and Pacific Gas
          and Electric Company Dividends

      11. January 17, 2001

     Item 5. Other Events--

            A. Ratings Downgrades
            B. Liquidity Impacts and Financial Condition

      12. February 1, 2001

     Item 5. Other Events--

            A. Wholesale Power Payments
            B. Liquidity Impacts and Financial Condition
            C. Federal Lawsuit
            D. Rate Stabilization Plan Proceeding
            E. Consulting Report
            F. CPUC Emergency Action

      13. February 14, 2001

     Item 5. Other Events--

            A. Assembly Bill 1X
            B. Liquidity Impacts and Financial Condition
            C. Federal Lawsuit

      14. February 28, 2001

     Item 5. Other Events--

            A. Recent Regulatory Action
            B. Liquidity
            C. Wilson vs. PG&E Corporation and Pacific Gas and Electric
              Company

                                      66
<PAGE>

      15. March 2, 2001--Filed by PG&E Corporation only

     Item 5. Other Events--PG&E Corporation debt restructure

      16. March 9, 2001

     Item 5. Other Events

            A. Recent Regulatory Action
            B. 2001 Cost of Capital Proceeding

      17. March 16, 2001

     Item 5. Other Events--Liquidity and Financial Condition

     18. March 23, 2001

     Item 5. Other Events

            A. Recent Legislative and Regulatory Actions
            B. Accounting Treatment
            C. Bank Forbearance Agreement

      19. March 30, 2001

     Item 5. Other Events

            A. Recent Regulatory Actions
            B. Accounting Treatment
            C. Liquidity and Financial Condition

      20. April 6, 2001 (as amended)--Filed by PG&E Corporation only

     Item 5. Other Events--Pacific Gas and Electric Company Bankruptcy

      21. April 6, 2001 (as amended)--Filed by Pacific Gas and Electric
  Company only

     Item 3. Other Events--Bankruptcy or Receivership.
--------
(1) Unless otherwise noted, all reports were filed under Commission File
    Number 1-2348 (Pacific Gas and Electric Company) and Commission File
    Number 1-12609 (PG&E Corporation).

                                      67
<PAGE>

                                   SIGNATURES

   Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrants have duly caused this report to be signed
on their behalf by the undersigned, thereunto duly authorized, in the City and
County of San Francisco, on the 16th day of April, 2001.

<TABLE>
<S>                                        <C>
                PG&E CORPORATION                   PACIFIC GAS AND ELECTRIC COMPANY
                  (Registrant)                               (Registrant)
             /s/ Gary P. Encinas                        /s/ Gary P. Encinas
By  ______________________________________ By  ______________________________________
      (Gary P. Encinas, Attorney-in-Fact)        (Gary P. Encinas, Attorney-in-Fact)
</TABLE>

   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
registrants and in the capacities and on the dates indicated.

<TABLE>
<CAPTION>
               Signature                          Title                   Date
               ---------                          -----                   ----
 <C>                                    <S>                          <C>
 A. Principal Executive Officers
        *ROBERT D. GLYNN, JR.           Chairman of the Board,       April 16, 2001
                                         Chief Executive Officer,
                                         and President
                                         (PG&E Corporation)
        *GORDON R. SMITH                President and Chief          April 16, 2001
                                         Executive Officer
                                         (Pacific Gas and
                                         Electric Company)
 B. Principal Financial Officers
        *PETER A. DARBEE                Senior Vice President,       April 16, 2001
                                         Chief Financial Officer,
                                         and Treasurer
                                         (PG&E Corporation)
        *KENT M. HARVEY                 Senior Vice President,       April 16, 2001
                                         Chief Financial Officer,
                                         and Treasurer
                                         (Pacific Gas and Electric
                                         Company)
 C. Principal Accounting Officers
        *CHRISTOPHER P. JOHNS           Vice President and           April 16, 2001
                                         Controller
                                         (PG&E Corporation)
        *DINYAR B. MISTRY               Vice President-Controller    April 16, 2001
                                         (Pacific Gas and Electric
                                         Company)
 D. Directors
        *DAVID ANDREWS
        *DAVID A. COULTER
        *C. LEE COX
        *WILLIAM S. DAVILA
        *ROBERT D. GLYNN, JR.           Directors of PG&E
        *DAVID M. LAWRENCE, M.D.         Corporation and
        *MARY S. METZ                    Pacific Gas and Electric April 16, 2001
        *CARL E. REICHARDT               Company,
        *GORDON R. SMITH                 except as noted
          (Director of Pacific Gas and
          Electric Company only)
        *BARRY LAWSON WILLIAMS

           /s/ Gary P. Encinas
 *By __________________________________
    (Gary P. Encinas, Attorney-in-Fact)
</TABLE>

                                       68
<PAGE>

                         INDEPENDENT AUDITORS' REPORT

To the Shareholders and the Boards of Directors of
PG&E Corporation and Pacific Gas and Electric Company:

We have audited the consolidated financial statements of PG&E Corporation and
subsidiaries and Pacific Gas and Electric Company and subsidiaries as of and
for the years ended December 31, 2000 and 1999 and have issued our report
thereon dated April 6, 2001, which report includes an explanatory paragraph
concerning the ability of Pacific Gas and Electric Company to continue as a
going concern; such consolidated financial statements are included in your
2000 Annual Report to shareholders and are incorporated herein by reference.
Our audits also included the financial statement schedules of PG&E Corporation
and Pacific Gas and Electric Company, listed in Item 14(a)5. These financial
statement schedules are the responsibility of the management of PG&E
Corporation and Pacific Gas and Electric Company. Our responsibility is to
express an opinion based on our audits. In our opinion, such financial
statement schedules, when considered in relation to the basic financial
statements taken as a whole, present fairly in all material respects the
information set forth therein.

DELOITTE & TOUCHE LLP

San Francisco, California
April 6, 2001

                                      69
<PAGE>

                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and Board of Directors of
PG&E Corporation and Pacific Gas and Electric Company:

We have audited in accordance with generally accepted auditing standards, the
consolidated financial statements for the year ended December 31, 1998
included in the PG&E Corporation and Pacific Gas and Electric Company Annual
Report to Shareholders incorporated by reference in this Form 10-K, and have
issued our report thereon dated February 8, 1999. Our audits were made for the
purpose of forming an opinion on the basic consolidated financial statements
taken as a whole. The Condensed Financial Information of Parent for the Year
Ended December 31, 1998 and the Consolidated Valuation and Qualifying Accounts
for each of PG&E Corporation and Pacific Gas and Electric Company for the Year
Ended December 31, 1998 are the responsibility of the management of PG&E
Corporation and of Pacific Gas and Electric Company. These schedules are for
purposes of complying with the Securities and Exchange Commission's rules and
are not part of the basic consolidated financial statements. These schedules
have been subjected to the auditing procedures applied in the audits of the
basic consolidated 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 consolidated financial statements taken as a whole.

ARTHUR ANDERSEN LLP

San Francisco, California
February 8, 1999

                                      70
<PAGE>

                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and the Board of Directors of PG&E Corporation
and Pacific Gas and Electric Company:

We have audited the accompanying statements of consolidated operations, cash
flows, and common stock equity of PG&E Corporation (a California corporation)
and subsidiaries and the statements of consolidated operations, cash flows,
and stockholders' equity of Pacific Gas and Electric Company (a California
corporation) and subsidiaries for the year ended December 31, 1998. These
financial statements are the responsibility of the management of PG&E
Corporation and Pacific Gas and Electric Company. Our responsibility is to
express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. 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 results of operations and cash flows of PG&E
Corporation and subsidiaries and Pacific Gas and Electric and subsidiaries for
the year ended December 31, 1998, in conformity with generally accepted
accounting principles.

ARTHUR ANDERSEN LLP

San Francisco, California
February 8, 1999

                                      71
<PAGE>

             SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT

                            CONDENSED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                December 31,
                                                               ----------------
                                                                2000     1999
                                                               -------  -------
                                                                (in millions)
<S>                                                            <C>      <C>
Assets:
Cash and cash equivalents..................................... $   351  $   155
Advances to affiliates........................................     295      299
Note receivable from subsidiary...............................     308       --
Other current assets..........................................       6       --
                                                               -------  -------
   Total current assets.......................................     960      454

Equipment.....................................................      15       16
Accumulated depreciation......................................      (6)      (3)
                                                               -------  -------
Net equipment.................................................       9       13

Investments in subsidiaries...................................   3,439    6,931
Other investments.............................................      64       52
Deferred income taxes.........................................      --      396
Other deferred charges........................................       1       --
                                                               -------  -------
   Total Assets............................................... $ 4,473  $ 7,846
                                                               =======  =======
Liabilities and Stockholders' Equity:
Current Liabilities:
 Short-term borrowings........................................ $   931  $   526
 Accounts payable--related parties............................      59       76
 Accounts payable--trade......................................      13       10
 Note payable to subsidiary...................................      75       --
 Accrued taxes................................................     108      117
 Dividends payable............................................     109      110
 Other........................................................      25      112
                                                               -------  -------
   Total current liabilities..................................   1,320      951
Noncurrent Liabilities:
 Deferred income taxes........................................       9       --
 Other........................................................      10        5
                                                               -------  -------
   Total noncurrent liabilities...............................      19        5
Stockholders' Equity:
 Common stock.................................................   5,971    5,906
 Common stock held by subsidiary..............................    (690)    (690)
 Reinvested earnings..........................................  (2,147)   1,674
                                                               -------  -------
   Total stockholders' equity.................................   3,134    6,890
                                                               -------  -------

   Total Liabilities and Stockholders' Equity................. $ 4,473  $ 7,846
                                                               =======  =======
</TABLE>

                                       72
<PAGE>

       SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT--(Continued)

                         CONDENSED STATEMENTS OF INCOME
             For the Years Ended December 31, 2000, 1999, and 1998

<TABLE>
<CAPTION>
                                                       2000     1999     1998
                                                     --------  -------  ------
                                                     (in millions except per
                                                         share amounts)
<S>                                                  <C>       <C>      <C>
Administrative service revenue ....................  $    111  $    82  $   64
Equity in earnings (losses) of subsidiaries........    (3,316)     853     736
Operating expenses.................................      (111)     (86)    (63)
Loss on assets held for sale.......................        --   (1,275)     --
Interest expense...................................       (27)     (30)    (52)
Other income.......................................        22       16       5
                                                     --------  -------  ------
Income (Loss) Before Income Taxes..................    (3,321)    (440)    690
Less: Income Taxes.................................        (4)    (447)    (83)
                                                     --------  -------  ------
Income (Loss) from continuing operations...........    (3,317)       7     773
Discontinued operations............................       (40)     (98)    (52)
Cumulative effect of a change in an accounting
 principle.........................................        --       12      --
                                                     --------  -------  ------
Net income (loss) before intercompany elimination..    (3,357)     (79)    721
Eliminations of intercompany (profit) loss.........        (7)       6      (2)
                                                     --------  -------  ------
Net income (loss)..................................  $ (3,364) $   (73) $  719
                                                     ========  =======  ======
Weighted Average Common Shares Outstanding, Basic
 and Diluted.......................................       362      368     382
Earnings (Loss) Per Common Share, Basic and
 Diluted...........................................  $  (9.29) $ (0.20) $ 1.88
                                                     ========  =======  ======

                       CONDENSED STATEMENTS OF CASH FLOWS
             For the Years Ended December 31, 2000, 1999, and 1998

<CAPTION>
                                                       2000     1999     1998
                                                     --------  -------  ------
                                                          (in millions)
<S>                                                  <C>       <C>      <C>
Cash Flows From Operating Activities:
Net income (loss)..................................  $ (3,364) $   (73) $  719
Adjustments to reconcile net income (loss) to net
 cash provided by operating activities:
 Equity in earnings of subsidiaries................     3,316     (853)   (736)
 Deferred taxes....................................        20     (415)     19
 Loss on assets held for sale......................        --    1,275      --
 Distributions from consolidated subsidiaries......       475      527     561
 Other-net.........................................       232       77    (688)
                                                     --------  -------  ------
Net cash provided by operating activities..........  $    679  $   538  $ (125)
Cash Flows From Investing Activities:
 Capital expenditures..............................         1       (8)     (8)
 Investment in subsidiaries........................      (555)    (722)   (575)
 Loans to subsidiaries.............................      (308)      --      --
 Return of capital by Utility (share repurchases)..       275      926   1,600
 Other-net.........................................        (9)     (12)     --
                                                     --------  -------  ------
Net cash provided (used) by investing activities...  $   (596) $   184  $1,017
 Cash Flows From Financing Activities:
 Common stock issued...............................        65       54      63
 Common stock repurchased..........................        (2)      (3) (1,158)
 Loans from subsidiary.............................        75       --      --
 Short-term debt issued (redeemed)-net.............       405     (157)    683
 Dividends paid....................................      (436)    (465)   (470)
 Other-net.........................................         6       (5)     (2)
                                                     --------  -------  ------
Net cash provided (used) by financing activities...  $    113  $  (576) $ (884)
Net Change in Cash & Cash Equivalents..............       196      146       8
Cash & Cash Equivalents at January 1...............       155        9       1
                                                     --------  -------  ------
Cash & Cash Equivalents at December 31.............  $    351  $   155  $    9
                                                     ========  =======  ======
</TABLE>

                                       73
<PAGE>

                                PG&E CORPORATION

         SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

             For the Years Ended December 31, 2000, 1999, and 1998

<TABLE>
<CAPTION>
        Column A           Column B       Column C         Column D     Column E
                                          Additions
                                     -------------------
                          Balance at Charged to Charged                Balance at
                          Beginning  Costs and  to Other                 End of
       Description        of Period   Expenses  Accounts  Deductions     Period
       -----------        ---------- ---------- --------  ----------   ----------
                                             (in thousands)
<S>                       <C>        <C>        <C>       <C>          <C>
Valuation and qualifying
 accounts deducted from
 assets:
2000:
  Allowance for
   uncollectible accounts
   (2)...................  $65,128   $   47,980 $ 1,484    $44,092(1)  $   70,500
                           =======   ========== =======    =======     ==========
  Provision for loss on
   generation-related
   regulatory assets and
   undercollected
   purchased power costs
   (3)...................  $    --   $6,939,000 $    --    $    --     $6,939,000
                           =======   ========== =======    =======     ==========
1999:
  Allowance for
   uncollectible accounts
   (2)...................  $58,577   $   25,243 $  (183)   $18,509(1)  $   65,128
                           =======   ========== =======    =======     ==========
1998:
  Allowance for
   uncollectible accounts
   (2)...................  $72,912   $   10,978 $(2,893)   $22,420(1)  $   58,577
                           =======   ========== =======    =======     ==========
</TABLE>
--------
(1) Deductions consist principally of write-offs, net of collections of
    receivables previously written off.
(2) Allowance for uncollectible accounts are deducted from "Accounts receivable
    Customers, net" and "Accounts receivable Energy Marketing."
(3) Provision was deducted from "Regulatory Assets."

                                       74
<PAGE>

                        PACIFIC GAS AND ELECTRIC COMPANY

         SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

             For the Years Ended December 31, 2000, 1999, and 1998

<TABLE>
<CAPTION>
        Column A           Column B       Column C        Column D     Column E
                                          Additions
                                     -------------------
                          Balance at Charged to Charged               Balance at
                          Beginning  Costs and  to Other                End of
       Description        of Period   Expenses  Accounts Deductions     Period
       -----------        ---------- ---------- -------- ----------   ----------
                                             (in thousands)
<S>                       <C>        <C>        <C>      <C>          <C>
Valuation and qualifying
 accounts deducted from
 assets:
2000:
  Allowance for
   uncollectible accounts
   (2)...................  $46,421   $   19,008  $1,484   $15,344(1)  $   51,569
                           =======   ==========  ======   =======     ==========
  Provision for loss on
   generation-related
   regulatory assets and
   undercollected
   purchased power costs
   (3)...................  $    --   $6,939,000  $   --   $    --     $6,939,000
                           =======   ==========  ======   =======     ==========
1999:
  Allowance for
   uncollectible accounts
   (2)...................  $47,347   $   17,011  $   44   $17,981(1)  $   46,421
                           =======   ==========  ======   =======     ==========
1998:
  Allowance for
   uncollectible accounts
   (2)...................  $59,608   $   10,007  $  152   $22,420(1)  $   47,347
                           =======   ==========  ======   =======     ==========
</TABLE>
--------
(1) Deductions consist principally of write-offs, net of collections of
    receivables previously written off.
(2) Allowance for uncollectible accounts are deducted from "Accounts receivable
    Customers, net."
(3) Provision was deducted from "Regulatory Assets."

                                       75
<PAGE>

                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
 Exhibit No. Description of Exhibit
 ----------- ----------------------
 <C>         <S>
      3.1    Restated Articles of Incorporation of PG&E Corporation effective
             as of May 5, 2000 (incorporated by reference to PG&E Corporation's
             Form 10-Q for the quarter ended March 31, 2001 (File No. 1-12609),
             Exhibit 3.1)


      3.2    Certificate of Determination for PG&E Corporation Series A
             Preferred Stock filed December 22, 2000


      3.3    By-Laws of PG&E Corporation amended as of February 21, 2001


      3.4    Restated Articles of Incorporation of Pacific Gas and Electric
             Company effective as of May 6, 1998 (incorporated by reference to
             Pacific Gas and Electric Company's Form 10-Q for the quarter ended
             March 31, 1998 (File No. 1-2348), Exhibit 3.1)


      3.5    By-Laws of Pacific Gas and Electric Company amended as of February
             21, 2001


      4.1    First and Refunding Mortgage of Pacific Gas and Electric Company
             dated December 1, 1920, and supplements thereto dated April 23,
             1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15,
             1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965,
             July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and
             December 1, 1988 (incorporated by reference to Registration No. 2-
             1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-
             22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-
             8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B;
             Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910,
             Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No.
             2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C;
             Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849,
             Exhibit 4.3; Pacific Gas and Electric Company's Form 8-K dated
             January 18, 1989 (File No. 1-2348), Exhibit 4.2)


             In accordance with Item 601(b)(4)(iii) of Regulation S-K, each of
             PG&E Corporation or Pacific Gas and Electric Company agrees to
             furnish to the Commission any instruments respecting long-term
             debt not required to be filed by application of such item


      4.2    Form of Rights Agreement dated as of December 22, 2000 between
             PG&E Corporation and Mellon Investor Services LLC, including the
             Form of Rights Certificate as Exhibit A, the Summary of Rights to
             Purchase Preferred Stock as Exhibit B, and the Form of Certificate
             of Determination of Preferences for the Preferred Stock as Exhibit
             C


     10.     The Gas Accord Settlement Agreement, together with accompanying
             tables, adopted by the California Public Utilities Commission on
             August 1, 1997, in Decision 97-08-055 (incorporated by reference
             to PG&E Corporation and Pacific Gas and Electric Company's Form
             10-K for the year ended December 31, 1997 (File No. 1-12609 and
             File No. 1-2348), Exhibit No. 10.2), as amended by Operational
             Flow Order (OFO) Settlement Agreement, approved by the California
             Public Utilities Commission on February 17, 2000, in Decision 00-
             02-050, as amended by Comprehensive Gas OII Settlement Agreement,
             approved by the California Public Utilities Commission on May 18,
             2000, in Decision 00-05-049


     10.1    Stock Purchase Agreement By and Between PG&E National Energy
             Group, Inc. and El Paso Field Services Company, dated as of
             January 27, 2000 (incorporated by reference to PG&E Corporation's
             Form 10-K for the year ended December 31, 1999 (File No. 1-12609),
             Exhibit No. 10.1)


     10.2    Credit Agreement between PG&E Corporation, General Electric
             Capital Corporation and Lehman Commercial Paper, Inc. dated March
             1, 2001


    *10.3    PG&E Corporation Supplemental Retirement Savings Plan dated as of
             January 1, 2000 (incorporated by reference to PG&E Corporation's
             Form 10-K for the year ended December 31, 2000 (File No. 1-12609),
             Exhibit 10.2)
</TABLE>
<PAGE>

<TABLE>
<CAPTION>
 Exhibit No. Description of Exhibit
 ----------- ----------------------
 <C>         <S>
  *10.4      Description of Compensation Arrangement between PG&E Corporation
             and Thomas G. Boren (incorporated by reference to PG&E
             Corporation's Form 10-Q for the quarter ended September 30, 1999
             (File No. 1-12609), Exhibit 10.2)


  *10.5      Description of Compensation Arrangement between PG&E Corporation
             and Peter Darbee (incorporated by reference to PG&E Corporation's
             Form 10-Q for the quarter ended September 30, 1999 (File No. 1-
             12609), Exhibit 10.3)


  *10.6      Letter regarding Compensation Arrangement between PG&E Corporation
             and Thomas B. King dated November 4, 1998


  *10.7      Letter regarding Compensation Arrangement between PG&E Corporation
             and Lyn E. Maddox dated April 25, 1997


  *10.8      Letter Regarding Relocation Arrangement Between PG&E Corporation
             and Thomas B. King dated March 16, 2000 (incorporated by reference
             to PG&E Corporation's Form 10-Q for the quarter ended March 31,
             2000 (File No. 1-12609), Exhibit 10)


  *10.9      Description of Relocation Arrangement Between PG&E Corporation and
             Lyn E. Maddox


  *10.10     PG&E Corporation Senior Executive Officer Retention Program
             approved December 20, 2000


  *10.10.1   Letter regarding retention award to Robert D. Glynn, Jr. dated
             January 22, 2001


  *10.10.2   Letter regarding retention award to Gordon R. Smith dated January
             22, 2001


  *10.10.3   Letter regarding retention award to Peter A. Darbee dated January
             22, 2001


  *10.10.4   Letter regarding retention award to Bruce R. Worthington dated
             January 22, 2001


  *10.10.5   Letter regarding retention award to G. Brent Stanley dated January
             22, 2001


  *10.10.6   Letter regarding retention award to Daniel D. Richard dated
             January 22, 2001


  *10.10.7   Letter regarding retention award to James K Randolph dated
             February 27, 2001


  *10.10.8   Letter regarding retention award to Gregory M. Rueger dated
             February 27, 2001


  *10.10.9   Letter regarding retention award to Kent Harvey dated February 27,
             2001


  *10.10.10  Letter regarding retention award to Roger J. Peters dated February
             27, 2001


  *10.10.11  Letter regarding retention award to Thomas G. Boren dated February
             27, 2001


  *10.10.12  Letter regarding retention award to Lyn E. Maddox dated February
             27, 2001


  *10.10.13  Letter regarding retention award to P. Chrisman Iribe dated
             February 27, 2001


  *10.10.14  Letter regarding retention award to Thomas B. King dated February
             27, 2001


  *10.11     Agreement and Release between PG&E Corporation and Thomas W. High
             dated December 8, 2000


  *10.12     PG&E Corporation Deferred Compensation Plan for Non-Employee
             Directors, as amended and restated effective as of July 22, 1998
             (incorporated by reference to PG&E Corporation's Form 10-Q for the
             quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)


  *10.13     Description of Short-Term Incentive Plan for Officers of PG&E
             Corporation and its subsidiaries, effective January 1, 2000
             (incorporated by reference to PG&E Corporation's Form 10-K for the
             year ended December 31, 1999 (File No. 1-12609), Exhibit 10.7)


  *10.14     Description of Short-Term Incentive Plan for Officers of PG&E
             Corporation and its subsidiaries, effective January 1, 2001


  *10.15     Supplemental Executive Retirement Plan of the Pacific Gas and
             Electric Company, effective January 1, 1998 (incorporated by
             reference to PG&E Corporation's Form 10-K for the year ended
             December 31, 1998 (File No. 1-12609), Exhibit 10.7)
</TABLE>
<PAGE>

<TABLE>
<CAPTION>
 Exhibit No. Description of Exhibit
 ----------- ----------------------
 <C>         <S>
   *10.16    Pacific Gas and Electric Company Relocation Assistance Program for
             Officers (incorporated by reference to Pacific Gas and Electric
             Company's Form 10-K for fiscal year 1989 (File No. 1-2348),
             Exhibit 10.16)


   *10.17    Postretirement Life Insurance Plan of the Pacific Gas and Electric
             Company (incorporated by reference to Pacific Gas and Electric
             Company's Form 10-K for fiscal year 1991 (File No. 1-2348),
             Exhibit 10.16)


   *10.18    PG&E Corporation Retirement Plan for Non-Employee Directors, as
             amended and terminated January 1, 1998 (incorporated by reference
             to incorporated by reference to PG&E Corporation Form 10-K for the
             year ended December 31, 1997 (File No. 1-12609), Exhibit No.
             10.13)


   *10.19    PG&E Corporation Long-Term Incentive Program, as amended February
             16, 2000, including the PG&E Corporation Stock Option Plan,
             Performance Unit Plan, and Non-Employee Director Stock Incentive
             Plan (incorporated by reference to incorporated by reference to
             PG&E Corporation Form 10-K for the year ended December 31, 1999
             (File No. 1-12609), Exhibit No. 10.12)


   *10.20    PG&E Corporation Executive Stock Ownership Program, amended as of
             September 19, 2000


   *10.21    PG&E Corporation Officer Severance Policy, amended as of July 21,
             1999 (incorporated by reference to PG&E Corporation's Form 10-Q
             for the quarter ended September 30, 1999 (File No. 1-12609),
             Exhibit 10.1)


   *10.22    PG&E Corporation Director Grantor Trust Agreement dated April 1,
             1998 (incorporated by reference to PG&E Corporation's Form 10-Q
             for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit
             10.1)


   *10.23    PG&E Corporation Officer Grantor Trust Agreement dated April 1,
             1998 (incorporated by reference to PG&E Corporation's Form 10-Q
             for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit
             10.2)


    11.      Computation of Earnings Per Common Share


    12.1     Computation of Ratios of Earnings to Fixed Charges for Pacific Gas
             and Electric Company


    12.2     Computation of Ratios of Earnings to Combined Fixed Charges and
             Preferred Stock Dividends for Pacific Gas and Electric Company


    13.      2000 Annual Report to Shareholders of PG&E Corporation and Pacific
             Gas and Electric Company--portions of the Report to Shareholders
             under the headings "Selected Financial Data," "Management's
             Discussion and Analysis," "Independent Auditors' Report,"
             "Responsibility for Consolidated Financial Statements," financial
             statements of PG&E Corporation entitled "Statement of Consolidated
             Income," "Consolidated Balance Sheet," "Statement of Consolidated
             Cash Flows," "Statement of Consolidated Common Stock Equity,"
             financial statements of Pacific Gas and Electric Company entitled
             "Statement of Consolidated Income," "Consolidated Balance Sheet,"
             "Statement of Consolidated Cash Flows," "Statement of Consolidated
             Stockholders' Equity," "Notes to Consolidated Financial
             Statements" and "Quarterly Consolidated Financial Data
             (Unaudited)" are included only. (Except for those portions that
             are expressly incorporated herein by reference, such Report to
             Shareholders is furnished for the information of the Commission
             and is not deemed to be "filed" herein.)


    21.      Subsidiaries of the Registrant


    23.1     Independent Auditors' Consent (Deloitte & Touche LLP)


    23.2     Consent of Arthur Andersen LLP


    24.1     Resolutions of the Boards of Directors of PG&E Corporation and
             Pacific Gas and Electric Company authorizing the execution of the
             Form 10-K


    24.2     Powers of Attorney
</TABLE>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-3.2
<SEQUENCE>2
<FILENAME>dex32.txt
<DESCRIPTION>CERTIFICATE OF DETERMINATION FOR PG&E
<TEXT>

<PAGE>

                                                                    EXHIBIT 3.2

                  CERTIFICATE OF DETERMINATION OF PREFERENCES

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

                        Pursuant to Section 401 of the
                      California General Corporation Law

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

ROBERT D. GLYNN, JR. and LESLIE H. EVERETT certify that:

          1.  They are the Chairman of the Board, Chief Executive Officer, and
President, and the Vice President and Corporate Secretary, respectively, of PG&E
Corporation, a California corporation.

          2.  Pursuant to authority conferred upon the Board of Directors of the
Corporation by its Restated Articles of Incorporation (the "Articles"), and,
                                                            --------
pursuant to the provisions of Section 401 of the California General Corporation
Law, said Board of Directors, at a duly called meeting held on December 20,
2000, at which a quorum was present and acted throughout, adopted the following
resolutions, which resolutions remain in full force and effect on the date
hereof creating a series of 5,000,000 shares of Preferred Stock having a par
value of $100 per share, designated as Series A Preferred Stock (the "Series A
                                                                      --------
Preferred Stock") out of the class of 85,000,000 shares of preferred stock (the
---------------
"Preferred Stock"):
 ---------------

          RESOLVED, that pursuant to the authority vested in the Board of
Directors in accordance with the provisions of the Articles, the Board of
Directors does hereby create, authorize and provide for the issuance of the
Series A Preferred Stock having the voting powers, designation, relative,
participating, optional and other special rights, preferences and
qualifications, limitations and restrictions thereof that are set forth as
follows:

          Section 1.  Designation and Amount.  The shares of such series shall
                      ----------------------
be designated as "Series A Preferred Stock" and the number of shares
constituting such series shall be 5,000,000.

          Section 2.  Dividends and Distributions.  (A)  Subject to the prior
                      ---------------------------
and superior rights of the holders of any shares of any other series of
Preferred Stock or any other shares of preferred stock of the Corporation
ranking prior and superior to the shares of Series A Preferred Stock with
respect to dividends, each holder of one one-hundredth (1/100) of a share (a
"Unit") of Series A Preferred Stock shall be entitled to receive, when, as and
 ----
if declared by the Board of Directors out of funds legally available for that
purpose, (i) quarterly dividends payable in cash on the last day of March, June,
September and December in each year (each such date being a "Quarterly Dividend
                                                             ------------------
Payment Date"), commencing on the first Quarterly Dividend Payment Date after
------------
the first issuance of such Unit of Series A Preferred Stock, in an amount per
Unit (rounded to the nearest cent) equal to the greater of (a) $.01 or (b)
subject to the provision for adjustment hereinafter set forth, the aggregate per
share amount of all cash dividends declared on shares of the Common Stock since
the immediately preceding Quarterly Dividend Payment Date, or, with respect to
the first Quarterly Dividend Payment Date, since the first issuance of a Unit of
Series A Preferred Stock, and (ii) subject to the provision for adjustment
hereinafter set forth, quarterly distributions (payable in kind) on each
Quarterly Dividend Payment Date in an amount per Unit equal to the aggregate per
share amount of all non-cash dividends or other distributions (other than a
dividend payable in shares of Common Stock or a subdivision of the outstanding
shares of Common Stock, by reclassification or otherwise) declared on shares of
Common Stock since the immediately preceding Quarterly Dividend Payment Date, or
with respect to the first Quarterly Dividend Payment Date, since the first
issuance of a Unit of Series A Preferred Stock.  In the event that the
Corporation shall at any time after December 20, 2000 (the "Rights Declaration
                                                            ------------------
Date") (i) declare any dividend on outstanding shares of Common Stock payable in
----
shares of Common Stock, (ii) subdivide outstanding shares of Common Stock or
(iii) combine outstanding shares of Common Stock into a smaller number of
shares, then in each such case the amount to which the holder of a Unit of
Series A Preferred Stock was entitled immediately prior to such event pursuant
to the preceding sentence shall be adjusted by multiplying such amount by a
fraction the numerator of which shall be the number of shares of Common Stock
that are outstanding immediately after such event and the denominator of which

<PAGE>

shall be the number of shares of Common Stock that were outstanding immediately
prior to such event.

          (B) The Corporation shall declare a dividend or distribution on Units
of Series A Preferred Stock as provided in paragraph (A) above immediately after
it declares a dividend or distribution on the shares of Common Stock (other than
a dividend payable in shares of Common Stock); provided, however, that, in the
                                               --------  -------
event no dividend or distribution shall have been declared on the Common Stock
during the period between any Quarterly Dividend Payment Date and the next
subsequent Quarterly Dividend Payment Date, a dividend of $.01 per Unit on the
Series A Preferred Stock shall nevertheless be payable on such subsequent
Quarterly Dividend Payment Date.

          (C) Dividends shall begin to accrue and shall be cumulative on each
outstanding Unit of Series A Preferred Stock from the Quarterly Dividend Payment
Date next preceding the date of issuance of such Unit of Series A Preferred
Stock, unless the date of issuance of such Unit is prior to the record date for
the first Quarterly Dividend Payment Date, in which case, dividends on such Unit
shall begin to accrue from the date of issuance of such Unit, or unless the date
of issuance is a Quarterly Dividend Payment Date or is a date after the record
date for the determination of holders of Units of Series A Preferred Stock
entitled to receive a quarterly dividend and before such Quarterly Dividend
Payment Date, in either of which events such dividends shall begin to accrue and
be cumulative from such Quarterly Dividend Payment Date.  Accrued but unpaid
dividends shall not bear interest. Dividends paid on Units of Series A Preferred
Stock in an amount less than the aggregate amount of all such dividends at the
time accrued and payable on such Units shall be allocated pro rata on a Unit-by-
Unit basis among all Units of Series A Preferred Stock at the time outstanding.
The Board of Directors may fix a record date for the determination of holders of
Units of Series A Preferred Stock entitled to receive payment of a dividend or
distribution declared thereon, which record date shall be no more than 30 days
prior to the date fixed for the payment thereof.

          Section 3.  Voting Rights.  The holders of Units of Series A Preferred
                      -------------
Stock shall have the following voting rights:

          (A) Subject to the provision for adjustment hereinafter set forth,
each Unit of Series A Preferred Stock shall entitle the holder thereof to one
vote on all ma tters submitted for a vote of the shareholders of the
Corporation. In the event the Corporation shall at any time after the Rights
Declaration Date (i) declare any dividend on outstanding shares of Common Stock
payable in shares of Common Stock, (ii) subdivide outstanding shares of Common
Stock or (iii) combine the outstanding shares of Common Stock into a smaller
number of shares, then in each such case the number of votes per Unit to which
holders of Units of Series A Preferred Stock were entitled immediately prior to
such event shall be adjusted by multiplying such number by a fraction the
numerator of which shall be the number of shares of Common Stock outstanding
immediately after such event and the denominator of which shall be the number of
shares of Common Stock that were outstanding immediately prior to such event.

          (B) Except as otherwise provided herein or by law, the holders of
Units of Series A Preferred Stock and the holders of shares of Common Stock
shall vote together as one class on all matters submitted to a vote of
shareholders of the Corporation.

          (C) (i)  If, at any time, dividends on any Units of Series A Preferred
Stock shall be in arrears in an amount equal to six quarterly dividends thereon,
then during the period (a "default period") from the occurrence of such event
                           --------------
until such time as all accrued and unpaid dividends for all previous quarterly
dividend periods and for the current quarterly dividend period on all Units of
Series A Preferred Stock then outstanding shall have been declared and paid or
set apart for payment, all holders of Units of Series A Preferred Stock, voting
separately as a class, shall have the right to elect two Directors.

              (ii) During any default period, such voting rights of the holders
of Units of Series A Preferred Stock may be exercised initially at a special
meeting called pursuant to subparagraph (iii) of this Section 3(C) or at any
annual meeting of shareholders, and thereafter at annual meetings of
shareholders, provided that such voting rights may not be exercised at any
meeting unless one-third of the outstanding Units of Preferred Stock shall be
present at such meeting in person or by proxy. The absence of a quorum of the
holders of Common Stock shall not affect the exercise by the holders of Units of
Series A Preferred Stock of such rights. At any meeting at which the holders of
Units of Series A Preferred Stock shall exercise such voting rights initially
during an existing default period, they

<PAGE>

shall have the right, voting separately as a class, to elect Directors to fill
up to two vacancies in the Board of Directors, if any such vacancies may then
exist, or, if such right is exercised at an annual meeting, to elect two
Directors. After the holders of Units of Series A Preferred Stock shall have
exercised their right to elect Directors during any default period, the number
of Directors shall not be increased or decreased except as approved by a vote of
the holders of Units of Series A Preferred Stock as herein provided or pursuant
to the rights of any equity securities ranking senior to the Series A Preferred
Stock.

          (iii)  Unless the holders of Series A Preferred Stock shall, during an
existing default period, have previously exercised their right to elect
Directors, the Board of Directors may order, or any shareholder or shareholders
owning in the aggregate not less than 10% of the total number of the Units of
Series A Preferred Stock outstanding may request, the calling of a special
meeting of the holders of Units of Series A Preferred Stock, which meeting shall
thereupon be called by the Secretary of the Corporation. Notice of such meeting
and of any annual meeting at which holders of Units of Series A Preferred Stock
are entitled to vote pursuant to this paragraph (C)(iii) shall be given to each
holder of record of Units of Series A Preferred Stock by mailing a copy of such
notice to him at his last address as the same appears on the books of the
Corporation. Such meeting shall be called for a time not earlier than 20 days
and not later then 60 days after such order or request, or, in default of the
calling of such meeting within 60 days after such order or request, such meeting
may be called on similar notice by any shareholder or shareholders owning in the
aggregate not less than 10% of the total number of outstanding Units of Series A
Preferred Stock. Notwithstanding the provisions of this paragraph (C)(iii), no
such special meeting shall be called during the 60 days immediately preceding
the date fixed for the next annual meeting of the shareholders.

          (iv)   During any default period, the holders of shares of Common
Stock and Units of Series A Preferred Stock, and other classes or series of
stock of the Corporation, if applicable, shall continue to be entitled to elect
all the Directors until holders of the Units of Series A Preferred Stock shall
have exercised their right to elect, voting as a separate class, two Directors,
after the exercise of which right (x) the Directors so elected by the holders of
Units of Series A Preferred Stock shall continue in office until their
successors shall have been elected by such holders or until the expiration of
the default period, and (y) any vacancy in the Board of Directors may (except as
provided in paragraph (C)(ii) of this Section 3) be filled by vote of a majority
of the remaining Directors theretofore elected by the holders of the class of
capital stock which elected the Director whose office shall have become vacant.
References in this paragraph (C) to Directors elected by the holders of a
particular class of capital stock shall include Directors elected by such
Directors to fill vacancies as provided in clause (y) of the foregoing sentence.

          (v)    Immediately upon the expiration of a default period, (x) the
right of the holders of Units of Series A Preferred Stock as a separate class to
elect Directors shall cease, (y) the term of any Directors elected by the
holders of Units of Series A Preferred Stock as a separate class shall
terminate, and (z) the number of Directors shall be such number as may be
provided for in the Articles or Bylaws of the Company (the "Bylaws").  Any
                                                            ------
vacancies in the Board of Directors effected by the provisions of clauses (y)
and (z) in the preceding sentence may be filled by a majority of the remaining
Directors.

          (vi)   The provisions of this paragraph (C) shall govern the election
of Directors by holders of Units of Preferred Stock during any default period
notwithstanding any provisions of the Articles or the Bylaws to the contrary.

          (D)    Except as set forth herein, holders of Units of Series A
Preferred Stock shall have no special voting rights and their consents shall not
be required (except to the extent they are entitled to vote with holders of
shares of Common Stock as set forth herein) for taking any corporate action.

          Section 4.  Certain Restrictions.  (A)  Whenever quarterly dividends
                      --------------------
or other dividends or distributions payable on Units of Series A Preferred Stock
as provided in Section 2 are in arrears, thereafter and until all accrued and
unpaid dividends and distributions, whether or not declared, on outstanding
Units of Series A Preferred Stock shall have been paid in full, the Corporation
shall not:

          (i)  declare or pay dividends on, make any other distributions on, or
     redeem or purchase or otherwise acquire for consideration any shares of
     junior stock;

<PAGE>

          (ii)   declare or pay dividends on or make any other distributions on
     any shares of parity stock, except dividends paid ratably on Units of
     Series A Preferred Stock and shares of all such parity stock on which
     dividends are payable or in arrears in proportion to the total amounts to
     which the holders of such Units and all such shares are then entitled;

          (iii)  redeem or purchase or otherwise acquire for consideration
     shares of any parity stock, provided, however, that the Corporation may at
                                 --------  -------
     any time redeem, purchase or otherwise acquire shares of any such parity
     stock in exchange for shares of any junior stock;

          (iv)   purchase or otherwise acquire for consideration any Units of
     Series A Preferred Stock, except in accordance with a purchase offer made
     in writing or by publication (as determined by the Board of Directors) to
     all holders of such Units.

          (B)    The Corporation shall not permit any subsidiary of the
Corporation to purchase or otherwise acquire for consideration any shares of
stock of the Corporation unless the Corporation could, under paragraph (A) of
this Section 4, purchase or otherwise acquire such shares at such time and in
such manner.

          Section 5.  Reacquired Shares.  Any Units of Series A Preferred Stock
                      -----------------
purchased or otherwise acquired by the Corporation in any manner whatsoever
shall be retired and cancelled promptly after the acquisition thereof.  All such
Units shall, upon their cancellation, become authorized but unissued Units of
Preferred Stock and may be reissued as part of a new series of Preferred Stock
to be created by resolution or resolutions of the Board of Directors, subject to
the conditions and restrictions on issuance set forth herein.

          Section 6.  Liquidation, Dissolution or Winding Up.  (A)  Upon any
                      --------------------------------------
voluntary or involuntary liquidation, dissolution or winding up of the
Corporation, no distribution shall be made (i) to the holders of shares of
junior stock unless the holders of Units of Series A Preferred Stock shall have
received, subject to adjustment as hereinafter provided in paragraph (B), the
greater of either (a) $1.00 per Unit plus an amount equal to accrued and unpaid
dividends and distributions thereon, whether or not earned or declared, up until
the date of such payment, or (b) the amount equal to the aggregate per share
amount to be distributed to holders of shares of Common Stock, or (ii) to the
holders of shares of parity stock, unless simultaneously therewith distributions
are made ratably on Units of Series A Preferred Stock and all other shares of
such parity stock in proportion to the total amounts to which the holders of
Units of Series A Preferred Stock are entitled under clause (i)(a) of this
sentence and to which the holders of shares of such parity stock are entitled,
in each case upon such liquidation, dissolution or winding up.

          (B)    In the event the Corporation shall, at any time after the
Rights Declaration Date, (i) declare any dividend on outstanding shares of
Common Stock payable in shares of Common Stock, (ii) subdivide outstanding
shares of Common Stock, or (iii) combine outstanding shares of Common Stock into
a smaller number of shares, then in each such case the aggregate amount to which
holders of Units of Series A Preferred Stock were entitled immediately prior to
such event pursuant to clause (i)(b) of paragraph (A) of this Section 6 shall be
adjusted by multiplying such amount by a fraction the numerator of which shall
be the number of shares of Common Stock that are outstanding immediately after
such event and the denominator of which shall be the number of shares of Common
Stock that were outstanding immediately prior to such event.

          Section 7.  Consolidation, Merger, etc.  In case the Corporation shall
                      --------------------------
enter into any consolidation, merger, combination or other transaction in which
the shares of common stock are exchanged for or converted into other stock or
securities, cash and/or any other property, then in any such case Units of
Series A Preferred Stock shall at the same time be similarly exchanged for or
converted into an amount per Unit (subject to the provision for adjustment
hereinafter set forth) equal to the aggregate amount of stock, securities, cash
and/or any other property (payable in kind), as the case may be, into which or
for which each share of Common Stock is converted or exchanged.  In the event
the Corporation shall at any time after the Rights Declaration Date (i) declare
any dividend on outstanding shares of Common Stock payable in shares of Common
Stock, (ii) subdivide outstanding shares of Common Stock, or (iii) combine
outstanding Common Stock into a smaller number of shares, then in each such case
the amount set forth in the immediately preceding

<PAGE>

sentence with respect to the exchange or conversion of Units of Series A
Preferred Stock shall be adjusted by multiplying such amount by a fraction the
numerator of which shall be the number of shares of Common Stock that are
outstanding immediately after such event and the denominator of which shall be
the number of shares of Common Stock that were outstanding immediately prior to
such event.

          Section 8.   Redemption.  The Units of Series A Preferred Stock shall
                       ----------
not be redeemable.

          Section 9.   Ranking.  The Units of Series A Preferred Stock shall
                       -------
rank junior to all other series of the Preferred Stock and to any other class of
preferred stock that hereafter may be issued by the Corporation as to the
payment of dividends and the distribution of assets, unless the terms of any
such series or class shall provide otherwise.

          Section 10.  Amendment.  The Articles, including, without limitation,
                       ---------
this resolution, shall not hereafter be amended, either directly or indirectly,
or through merger or consolidation with any other corporation or corporations in
any manner that would alter or change the powers, preferences or special rights
of the Series A Preferred Stock so as to affect them adversely without the
affirmative vote of the holders of a majority or more of the outstanding Units
of Series A Preferred Stock, voting separately as a class.

          Section 11.  Fractional Shares.  The Series A Preferred Stock may be
                       -----------------
issued in Units or other fractions of a share, which Units or fractions shall
entitle the holder, in proportion to such holder's fractional shares, to
exercise voting rights, receive dividends, participate in distributions and to
have the benefit of all other rights of holders of Series A Preferred Stock.

          Section 12.  Certain Definitions.  As used herein with respect to the
                       -------------------
Series A Preferred Stock, the following terms shall have the following meanings:

          (A) The term "Common Stock" shall mean the class of stock designated
                        ------------
as the common stock, no par value per share, of the Corporation at the date
hereof or any other class of stock resulting from successive changes or
reclassification of such common stock.

          (B) The term "junior stock" (i) as used in Section 4 shall mean the
                        ------------
Common Stock and any other class or series of capital stock of the Corporation
hereafter authorized or issued over which the Series A Preferred Stock has
preference or priority as to the payment of dividends and (ii) as used in
Section 6 shall mean the Common Stock and any other class or series of capital
stock of the Corporation over which the Series A Preferred Stock has preference
or priority in the distribution of assets upon any liquidation, dissolution or
winding up of the Corporation.

          (C) The term "parity stock" (i) as used in Section 4, shall mean any
                        ------------
class or series of stock of the Corporation hereafter authorized or issued
ranking pari passu with the Series A Preferred Stock as to the payment of
        ---- -----
dividends and (ii) as used in Section 6, shall mean any class or series of
capital stock ranking pari passu with the Series A Preferred Stock in the
                      ---- -----
distribution of assets upon any liquidation, dissolution or winding up of the
Corporation.

          3.  The number of shares constituting the Series A Preferred Stock is
5,000,000.

          4.  None of the Series A Preferred Stock has been issued.

<PAGE>

          We further declare under penalty of perjury under the laws of the
State of California that the matters set forth in this Certificate are true and
correct of our own knowledge.

Date:  December 22, 2000


                              ROBERT D. GLYNN, JR.
                              ---------------------------------------------
                              Robert D. Glynn, Jr.
                              Chairman of the Board,
                              Chief Executive Officer, and President


                              LESLIE H. EVERETT
                              ---------------------------------------------
                              Leslie H. Everett
                              Vice President and
                              Corporate Secretary

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-3.3
<SEQUENCE>3
<FILENAME>dex33.txt
<DESCRIPTION>BY-LAWS OF PG&E CORPORATION
<TEXT>

<PAGE>

                                                                     EXHIBIT 3.3


                                    Bylaws
                                      of
                               PG&E Corporation
                        amended as of February 21, 2001
                        -------------------------------


                                  Article I.
                                 SHAREHOLDERS.


     1.   Place of Meeting.  All meetings of the shareholders shall be held at
the office of the Corporation in the City and County of San Francisco, State of
California, or at such other place, within or without the State of California,
as may be designated by the Board of Directors.

     2.   Annual Meetings.  The annual meeting of shareholders shall be held
each year on a date and at a time designated by the Board of Directors.

     Written notice of the annual meeting shall be given not less than ten (or,
if sent by third-class mail, thirty) nor more than sixty days prior to the date
of the meeting to each shareholder entitled to vote thereat.  The notice shall
state the place, day, and hour of such meeting, and those matters which the
Board, at the time of mailing, intends to present for action by the
shareholders.

     Notice of any meeting of the shareholders shall be given by mail or
telegraphic or other written communication, postage prepaid, to each holder of
record of the stock entitled to vote thereat, at his address, as it appears on
the books of the Corporation.

     At an annual meeting of shareholders, only such business shall be conducted
as shall have been properly brought before the annual meeting.  To be properly
brought before an annual meeting, business must be (i) specified in the notice
of the annual meeting (or any supplement thereto) given by or at the direction
of the Board, or (ii) otherwise properly brought before the annual meeting by a
shareholder.  For business to be properly brought before an annual meeting by a
shareholder, including the nomination of any person (other than a person
nominated by or at the direction of the Board) for election to the Board, the
shareholder must have given timely and proper written notice to the Corporate
Secretary of the Corporation.  To be timely, the shareholder's written notice
must be received at the principal executive office of the Corporation not less
than forty-five days before the date corresponding to the mailing date of the
notice and proxy materials for the prior year's annual meeting of shareholders;
provided, however, that if the annual meeting to which the shareholder's written
notice relates is to be held on a date that differs by more than thirty days
from the date of the last annual meeting of shareholders, the shareholder's
written notice to
<PAGE>

be timely must be so received not later than the close of business on the tenth
day following the date on which public disclosure of the date of the annual
meeting is made or given to shareholders. To be proper, the shareholder's
written notice must set forth as to each matter the shareholder proposes to
bring before the annual meeting (a) a brief description of the business desired
to be brought before the annual meeting, (b) the name and address of the
shareholder as they appear on the Corporation's books, (c) the class and number
of shares of the Corporation that are beneficially owned by the shareholder, and
(d) any material interest of the shareholder in such business. In addition, if
the shareholder's written notice relates to the nomination at the annual meeting
of any person for election to the Board, such notice to be proper must also set
forth (a) the name, age, business address, and residence address of each person
to be so nominated, (b) the principal occupation or employment of each such
person, (c) the number of shares of capital stock of the Corporation
beneficially owned by each such person, and (d) such other information
concerning each such person as would be required under the rules of the
Securities and Exchange Commission in a proxy statement soliciting proxies for
the election of such person as a Director, and must be accompanied by a consent,
signed by each such person, to serve as a Director of the Corporation if
elected. Notwithstanding anything in the Bylaws to the contrary, no business
shall be conducted at an annual meeting except in accordance with the procedures
set forth in this Section.

     3.   Special Meetings.  Special meetings of the shareholders shall be
called by the Corporate Secretary or an Assistant Corporate Secretary at any
time on order of the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee, or the
President.  Special meetings of the shareholders shall also be called by the
Corporate Secretary or an Assistant Corporate Secretary upon the written request
of holders of shares entitled to cast not less than ten percent of the votes at
the meeting.  Such request shall state the purposes of the meeting, and shall be
delivered to the Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, the President, or the Corporate Secretary.

     A special meeting so requested shall be held on the date requested, but not
less than thirty-five nor more than sixty days after the date of the original
request.  Written notice of each special meeting of shareholders, stating the
place, day, and hour of such meeting and the business proposed to be transacted
thereat, shall be given in the manner stipulated in Article I, Section 2,
Paragraph 3 of these Bylaws within twenty days after receipt of the written
request.

     4.   Attendance at Meetings.  At any meeting of the shareholders, each
holder of record of stock entitled to vote thereat may attend in person or may
designate an agent or a reasonable number of agents, not to exceed three to
attend the meeting and cast votes for his or her shares.  The authority of
agents must be evidenced by a written proxy signed by the shareholder
designating the agents authorized to attend the meeting and be delivered to the
Corporate Secretary of the Corporation prior to the commencement of the meeting.

                                       2
<PAGE>

     5.   Shareholder Action by Written Consent.  Subject to Section 603 of the
California Corporations Code, any action which, under any provision of the
California Corporations Code, may be taken at any annual or special meeting of
shareholders may be taken without a meeting and without prior notice if a
consent in writing, setting forth the action so taken, shall be signed by the
holders of outstanding shares having not less than the minimum number of votes
that would be necessary to authorize or take such action at a meeting at which
all shares entitled to vote thereon were present and voted.

     Any party seeking to solicit written consent from shareholders to take
corporate action must deliver a notice to the Corporate Secretary of the
Corporation which requests the Board of Directors to set a record date for
determining shareholders entitled to give such consent.  Such written request
must set forth as to each matter the party proposes for shareholder action by
written consents (a) a brief description of the matter and (b) the class and
number of shares of the Corporation that are beneficially owned by the
requesting party.  Within ten days of receiving the request in the proper form,
the Board shall set a record date for the taking of such action by written
consent in accordance with California Corporations Code Section 701 and Article
IV, Section 1 of these Bylaws.  If the Board fails to set a record date within
such ten-day period, the record date for determining shareholders entitled to
give the written consent for the matters specified in the notice shall be the
day on which the first written consent is given in accordance with California
Corporations Code Section 701.

     Each written consent delivered to the Corporation must set forth (a) the
action sought to be taken, (b) the name and address of the shareholder as they
appear on the Corporation's books, (c) the class and number of shares of the
Corporation that are beneficially owned by the shareholder, (d) the name and
address of the proxyholder authorized by the shareholder to give such written
consent, if applicable, and (d) any material interest of the shareholder or
proxyholder in the action sought to be taken.

     Consents to corporate action shall be valid for a maximum of sixty days
after the date of the earliest dated consent delivered to the Corporation.
Consents may be revoked by written notice (i) to the Corporation, (ii) to the
shareholder or shareholders soliciting consents or soliciting revocations in
opposition to action by consent proposed by the Corporation (the "Soliciting
Shareholders"), or (iii) to a proxy solicitor or other agent designated by the
Corporation or the Soliciting Shareholders.

     Within three business days after receipt of the earliest dated consent
solicited by the Soliciting Shareholders and delivered to the Corporation in the
manner provided in California Corporations Code Section 603 or the determination
by the Board of Directors of the Corporation that the Corporation should seek
corporate action by written consent, as the case may be, the Corporate Secretary
shall engage nationally recognized independent inspectors of elections for the
purpose of performing a ministerial review of the validity of the consents and
revocations.  The cost of retaining inspectors of election shall be borne by the
Corporation.

                                       3
<PAGE>

     Consents and revocations shall be delivered to the inspectors upon receipt
by the Corporation, the Soliciting Shareholders or their proxy solicitors, or
other designated agents.  As soon as consents and revocations are received, the
inspectors shall review the consents and revocations and shall maintain a count
of the number of valid and unrevoked consents.  The inspectors shall keep such
count confidential and shall not reveal the count to the Corporation, the
Soliciting Shareholder or their representatives, or any other entity.  As soon
as practicable after the earlier of (i) sixty days after the date of the
earliest dated consent delivered to the Corporation in the manner provided in
California Corporations Code Section 603, or (ii) a written request therefor by
the Corporation or the Soliciting Shareholders (whichever is soliciting
consents), notice of which request shall be given to the party opposing the
solicitation of consents, if any, which request shall state that the Corporation
or Soliciting Shareholders, as the case may be, have a good faith belief that
the requisite number of valid and unrevoked consents to authorize or take the
action specified in the consents has been received in accordance with these
Bylaws, the inspectors shall issue a preliminary report to the Corporation and
the Soliciting Shareholders stating:  (a) the number of valid consents, (b) the
number of valid revocations, (c) the number of valid and unrevoked consents, (d)
the number of invalid consents, (e) the number of invalid revocations, and (f)
whether, based on their preliminary count, the requisite number of valid and
unrevoked consents has been obtained to authorize or take the action specified
in the consents.

     Unless the Corporation and the Soliciting Shareholders shall agree to a
shorter or longer period, the Corporation and the Soliciting Shareholders shall
have forty-eight hours to review the consents and revocations and to advise the
inspectors and the opposing party in writing as to whether they intend to
challenge the preliminary report of the inspectors.  If no written notice of an
intention to challenge the preliminary report is received within forty-eight
hours after the inspectors' issuance of the preliminary report, the inspectors
shall issue to the Corporation and the Soliciting Shareholders their final
report containing the information from the inspectors' determination with
respect to whether the requisite number of valid and unrevoked consents was
obtained to authorize and take the action specified in the consents.  If the
Corporation or the Soliciting Shareholders issue written notice of an intention
to challenge the inspectors' preliminary report within forty-eight hours after
the issuance of that report, a challenge session shall be scheduled by the
inspectors as promptly as practicable.  A transcript of the challenge session
shall be recorded by a certified court reporter.  Following completion of the
challenge session, the inspectors shall as promptly as practicable issue their
final report to the Soliciting Shareholders and the Corporation, which report
shall contain the information included in the preliminary report, plus all
changes in the vote totals as a result of the challenge and a certification of
whether the requisite number of valid and unrevoked consents was obtained to
authorize or take the action specified in the consents.  A copy of the final
report of the inspectors shall be included in the book in which the proceedings
of meetings of shareholders are recorded.

     Unless the consent of all shareholders entitled to vote have been solicited
in writing, the Corporation shall give prompt notice to the shareholders in
accordance with

                                       4
<PAGE>

California Corporations Code Section 603 of the results of any consent
solicitation or the taking of the corporate action without a meeting and by less
than unanimous written consent.


                                  Article II.
                                  DIRECTORS.


     1.   Number.  As stated in paragraph I of Article Third of this
Corporation's Articles of Incorporation, the Board of Directors of this
Corporation shall consist of such number of directors, not less than seven (7)
nor more than thirteen (13).  The exact number of directors shall be nine (9)
until changed, within the limits specified above, by an amendment to this Bylaw
duly adopted by the Board of Directors or the shareholders.

     2.   Powers.  The Board of Directors shall exercise all the powers of the
Corporation except those which are by law, or by the Articles of Incorporation
of this Corporation, or by the Bylaws conferred upon or reserved to the
shareholders.

     3.   Committees.  The Board of Directors may, by resolution adopted by a
majority of the authorized number of directors, designate and appoint one or
more committees as the Board deems appropriate, each consisting of two or more
directors, to serve at the pleasure of the Board; provided, however, that, as
required by this Corporation's Articles of Incorporation, the members of the
Executive Committee (should the Board of Directors designate an Executive
Committee) must be appointed by the affirmative vote of two-thirds of the
authorized number of directors.  Any such committee, including the Executive
Committee, shall have the authority to act in the manner and to the extent
provided in the resolution of the Board of Directors designating such committee
and may have all the authority of the Board of Directors, except with respect to
the matters set forth in California Corporations Code Section 311.

     4.   Time and Place of Directors' Meetings.  Regular meetings of the Board
of Directors shall be held on such days and at such times and at such locations
as shall be fixed by resolution of the Board, or designated by the Chairman of
the Board or, in his absence, the Vice Chairman of the Board, or the President
of the Corporation and contained in the notice of any such meeting.  Notice of
meetings shall be delivered personally or sent by mail or telegram at least
seven days in advance.

     5.   Special Meetings.  The Chairman of the Board, the Vice Chairman of the
Board, the Chairman of the Executive Committee, the President, or any five
directors may call a special meeting of the Board of Directors at any time.
Notice of the time and place of special meetings shall be given to each Director
by the Corporate Secretary.  Such notice shall be delivered personally or by
telephone to each Director at least four

                                       5
<PAGE>

hours in advance of such meeting, or sent by first-class mail or telegram,
postage prepaid, at least two days in advance of such meeting.

     6.   Quorum.  A quorum for the transaction of business at any meeting of
the Board of Directors or any committee thereof shall consist of one-third of
the authorized number of directors or committee members, or two, whichever is
larger.

     7.   Action by Consent.  Any action required or permitted to be taken by
the Board of Directors may be taken without a meeting if all Directors
individually or collectively consent in writing to such action.  Such written
consent or consents shall be filed with the minutes of the proceedings of the
Board of Directors.

     8.   Meetings by Conference Telephone.  Any meeting, regular or special, of
the Board of Directors or of any committee of the Board of Directors, may be
held by conference telephone or similar communication equipment, provided that
all Directors participating in the meeting can hear one another.


                                 Article III.
                                   OFFICERS.


     1.   Officers.  The officers of the Corporation shall be a Chairman of the
Board, a Vice Chairman of the Board, a Chairman of the Executive Committee
(whenever the Board of Directors in its discretion fills these offices), a
President, a Chief Financial Officer, a General Counsel, one or more Vice
Presidents, a Corporate Secretary and one or more Assistant Corporate
Secretaries, a Treasurer and one or more Assistant Treasurers, and a Controller,
all of whom shall be elected by the Board of Directors.  The Chairman of the
Board, the Vice Chairman of the Board, the Chairman of the Executive Committee,
and the President shall be members of the Board of Directors.

     2.   Chairman of the Board.  The Chairman of the Board, if that office be
filled, shall preside at all meetings of the shareholders and of the Directors,
and shall preside at all meetings of the Executive Committee in the absence of
the Chairman of that Committee.  He shall be the chief executive officer of the
Corporation if so designated by the Board of Directors.  He shall have such
duties and responsibilities as may be prescribed by the Board of Directors or
the Bylaws.  The Chairman of the Board shall have authority to sign on behalf of
the Corporation agreements and instruments of every character, and, in the
absence or disability of the President, shall exercise the President's duties
and responsibilities.

     3.   Vice Chairman of the Board.  The Vice Chairman of the Board, if that
office be filled, shall have such duties and responsibilities as may be
prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws.
He shall be the chief executive officer of the Corporation if so designated by
the Board of Directors.  In the

                                       6
<PAGE>

absence of the Chairman of the Board, he shall preside at all meetings of the
Board of Directors and of the shareholders; and, in the absence of the Chairman
of the Executive Committee and the Chairman of the Board, he shall preside at
all meetings of the Executive Committee. The Vice Chairman of the Board shall
have authority to sign on behalf of the Corporation agreements and instruments
of every character.

     4.   Chairman of the Executive Committee.  The Chairman of the Executive
Committee, if that office be filled, shall preside at all meetings of the
Executive Committee.  He shall aid and assist the other officers in the
performance of their duties and shall have such other duties as may be
prescribed by the Board of Directors or the Bylaws.

     5.   President.  The President shall have such duties and responsibilities
as may be prescribed by the Board of Directors, the Chairman of the Board, or
the Bylaws.  He shall be the chief executive officer of the Corporation if so
designated by the Board of Directors.  If there be no Chairman of the Board, the
President shall also exercise the duties and responsibilities of that office.
The President shall have authority to sign on behalf of the Corporation
agreements and instruments of every character.

     6.   Chief Financial Officer.  The Chief Financial Officer shall be
responsible for the overall management of the financial affairs of the
Corporation.  He shall render a statement of the Corporation's financial
condition and an account of all transactions whenever requested by the Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, or the
President.

     The Chief Financial Officer shall have such other duties as may from time
to time be prescribed by the Board of Directors, the Chairman of the Board, the
Vice Chairman of the Board, the President, or the Bylaws.

     7.   General Counsel.  The General Counsel shall be responsible for
handling on behalf of the Corporation all proceedings and matters of a legal
nature.  He shall render advice and legal counsel to the Board of Directors,
officers, and employees of the Corporation, as necessary to the proper conduct
of the business.  He shall keep the management of the Corporation informed of
all significant developments of a legal nature affecting the interests of the
Corporation.

     The General Counsel shall have such other duties as may from time to time
be prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws.

     8.   Vice Presidents.  Each Vice President, if those offices are filled,
shall have such duties and responsibilities as may be prescribed by the Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws.  Each Vice President's authority to sign agreements
and instruments on behalf of the Corporation shall be as prescribed by the Board
of Directors.  The Board of

                                       7
<PAGE>

Directors, the Chairman of the Board, the Vice Chairman of the Board, or the
President may confer a special title upon any Vice President.

     9.   Corporate Secretary.  The Corporate Secretary shall attend all
meetings of the Board of Directors and the Executive Committee, and all meetings
of the shareholders, and he shall record the minutes of all proceedings in books
to be kept for that purpose.  He shall be responsible for maintaining a proper
share register and stock transfer books for all classes of shares issued by the
Corporation.  He shall give, or cause to be given, all notices required either
by law or the Bylaws.  He shall keep the seal of the Corporation in safe
custody, and shall affix the seal of the Corporation to any instrument requiring
it and shall attest the same by his signature.

     The Corporate Secretary shall have such other duties as may be prescribed
by the Board of Directors, the Chairman of the Board, the Vice Chairman of the
Board, the President, or the Bylaws.

     The Assistant Corporate Secretaries shall perform such duties as may be
assigned from time to time by the Board of Directors, the Chairman of the Board,
the Vice Chairman of the Board, the President, or the Corporate Secretary.  In
the absence or disability of the Corporate Secretary, his duties shall be
performed by an Assistant Corporate Secretary.

     10.  Treasurer.  The Treasurer shall have custody of all moneys and funds
of the Corporation, and shall cause to be kept full and accurate records of
receipts and disbursements of the Corporation.  He shall deposit all moneys and
other valuables of the Corporation in the name and to the credit of the
Corporation in such depositaries as may be designated by the Board of Directors
or any employee of the Corporation designated by the Board of Directors.  He
shall disburse such funds of the Corporation as have been duly approved for
disbursement.

     The Treasurer shall perform such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, the Chief Financial Officer, or the
Bylaws.

     The Assistant Treasurers shall perform such duties as may be assigned from
time to time by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, the Chief Financial Officer, or the
Treasurer.  In the absence or disability of the Treasurer, his duties shall be
performed by an Assistant Treasurer.

     11.  Controller.  The Controller shall be responsible for maintaining the
accounting records of the Corporation and for preparing necessary financial
reports and statements, and he shall properly account for all moneys and
obligations due the Corporation and all properties, assets, and liabilities of
the Corporation.  He shall render to the officers such periodic reports covering
the result of operations of the Corporation as may be required by them or any
one of them.

                                       8
<PAGE>

     The Controller shall have such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, the Chief Financial Officer, or the
Bylaws.  He shall be the principal accounting officer of the Corporation, unless
another individual shall be so designated by the Board of Directors.


                                  Article IV.
                                MISCELLANEOUS.


     1.   Record Date.  The Board of Directors may fix a time in the future as a
record date for the determination of the shareholders entitled to notice of and
to vote at any meeting of shareholders, or entitled to receive any dividend or
distribution, or allotment of rights, or to exercise rights in respect to any
change, conversion, or exchange of shares.  The record date so fixed shall be
not more than sixty nor less than ten days prior to the date of such meeting nor
more than sixty days prior to any other action for the purposes for which it is
so fixed.  When a record date is so fixed, only shareholders of record on that
date are entitled to notice of and to vote at the meeting, or entitled to
receive any dividend or distribution, or allotment of rights, or to exercise the
rights, as the case may be.

     2.   Transfers of Stock.  Upon surrender to the Corporate Secretary or
Transfer Agent of the Corporation of a certificate for shares duly endorsed or
accompanied by proper evidence of succession, assignment, or authority to
transfer, and payment of transfer taxes, the Corporation shall issue a new
certificate to the person entitled thereto, cancel the old certificate, and
record the transaction upon its books.  Subject to the foregoing, the Board of
Directors shall have power and authority to make such rules and regulations as
it shall deem necessary or appropriate concerning the issue, transfer, and
registration of certificates for shares of stock of the Corporation, and to
appoint and remove Transfer Agents and Registrars of transfers.

     3.   Lost Certificates.  Any person claiming a certificate of stock to be
lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of
that fact and verify the same in such manner as the Board of Directors may
require, and shall, if the Board of Directors so requires, give the Corporation,
its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form
approved by counsel, and in amount and with such sureties as may be satisfactory
to the Corporate Secretary of the Corporation, before a new certificate may be
issued of the same tenor and for the same number of shares as the one alleged to
have been lost, stolen, mislaid, or destroyed.

                                       9
<PAGE>

                                  Article V.
                                  AMENDMENTS.


     1.   Amendment by Shareholders.  Except as otherwise provided by law, these
Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the
affirmative vote of a majority of the outstanding shares entitled to vote at any
regular or special meeting of the shareholders.

     2.   Amendment by Directors.  To the extent provided by law, these Bylaws,
or any of them, may be amended or repealed or new Bylaws adopted by resolution
adopted by a majority of the members of the Board of Directors.

                                       10
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-3.5
<SEQUENCE>4
<FILENAME>dex35.txt
<DESCRIPTION>BY-LAWS OF PACIFIC GAS & ELECTRIC COMPANY
<TEXT>

<PAGE>

                                                                     EXHIBIT 3.5

                                    Bylaws
                                      of
                       Pacific Gas and Electric Company
                        amended as of February 21, 2001
                        -------------------------------


                                  Article I.
                                 SHAREHOLDERS.


    1. Place of Meeting.  All meetings of the shareholders shall be held at
the office of the Corporation in the City and County of San Francisco, State of
California, or at such other place, within or without the State of California,
as may be designated by the Board of Directors.

    2. Annual Meetings. The annual meeting of shareholders shall be held each
year on a date and at a time designated by the Board of Directors.

    Written notice of the annual meeting shall be given not less than ten (or,
if sent by third-class mail, thirty) nor more than sixty days prior to the date
of the meeting to each shareholder entitled to vote thereat.  The notice shall
state the place, day, and hour of such meeting, and those matters which the
Board, at the time of mailing, intends to present for action by the
shareholders.

    Notice of any meeting of the shareholders shall be given by mail or
telegraphic or other written communication, postage prepaid, to each holder of
record of the stock entitled to vote thereat, at his address, as it appears on
the books of the Corporation.

    At an annual meeting of shareholders, only such business shall be conducted
as shall have been properly brought before the annual meeting.  To be properly
brought before an annual meeting, business must be (i) specified in the notice
of the annual meeting (or any supplement thereto) given by or at the direction
of the Board, or (ii) otherwise properly brought before the annual meeting by a
shareholder.  For business to be properly brought before an annual meeting by a
shareholder, including the nomination of any person (other than a person
nominated by or at the direction of the Board) for election to the Board, the
shareholder must have given timely and proper written notice to the Corporate
Secretary of the Corporation.  To be timely, the shareholder's written notice
must be received at the principal executive office of the Corporation not less
than forty-five days before the date corresponding to the mailing date of the
notice and proxy materials for the prior year's annual meeting of shareholders;
provided, however, that if the annual meeting to which the shareholder's written
notice relates is to be held on a date that differs by more than thirty days
from the date of the last annual meeting of shareholders, the shareholder's
written notice to
<PAGE>

be timely must be so received not later than the close of business on the tenth
day following the date on which public disclosure of the date of the annual
meeting is made or given to shareholders. To be proper, the shareholder's
written notice must set forth as to each matter the shareholder proposes to
bring before the annual meeting (a) a brief description of the business desired
to be brought before the annual meeting, (b) the name and address of the
shareholder as they appear on the Corporation's books, (c) the class and number
of shares of the Corporation that are beneficially owned by the shareholder, and
(d) any material interest of the shareholder in such business. In addition, if
the shareholder's written notice relates to the nomination at the annual meeting
of any person for election to the Board, such notice to be proper must also set
forth (a) the name, age, business address, and residence address of each person
to be so nominated, (b) the principal occupation or employment of each such
person, (c) the number of shares of capital stock of the Corporation
beneficially owned by each such person, and (d) such other information
concerning each such person as would be required under the rules of the
Securities and Exchange Commission in a proxy statement soliciting proxies for
the election of such person as a Director, and must be accompanied by a consent,
signed by each such person, to serve as a Director of the Corporation if
elected. Notwithstanding anything in the Bylaws to the contrary, no business
shall be conducted at an annual meeting except in accordance with the procedures
set forth in this Section.

    3. Special Meetings.  Special meetings of the shareholders shall be called
by the Secretary or an Assistant Secretary at any time on order of the Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, or the President.  Special meetings of the
shareholders shall also be called by the Secretary or an Assistant Secretary
upon the written request of holders of shares entitled to cast not less than ten
percent of the votes at the meeting.  Such request shall state the purposes of
the meeting, and shall be delivered to the Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee, the President or
the Secretary.

    A special meeting so requested shall be held on the date requested, but not
less than thirty-five nor more than sixty days after the date of the original
request.  Written notice of each special meeting of shareholders, stating the
place, day, and hour of such meeting and the business proposed to be transacted
thereat, shall be given in the manner stipulated in Article I, Section 2,
Paragraph 3 of these Bylaws within twenty days after receipt of the written
request.

    4. Attendance at Meetings.    At any meeting of the shareholders, each
holder of record of stock entitled to vote thereat may attend in person or may
designate an agent or a reasonable number of agents, not to exceed three to
attend the meeting and cast votes for his shares.  The authority of agents must
be evidenced by a written proxy signed by the shareholder designating the agents
authorized to attend the meeting and be delivered to the Secretary of the
Corporation prior to the commencement of the meeting.

                                       2
<PAGE>

    5. No Cumulative Voting.  No shareholder of the Corporation shall be
entitled to cumulate his or her voting power.


                                  Article II.
                                  DIRECTORS.


    1. Number.   The Board of Directors of this Corporation shall consist of
such number of directors, not less than nine (9) nor more than seventeen (17).
The exact number of directors shall be ten (10) until changed, within the limits
specified above, by an amendment to this Bylaw duly adopted by the Board of
Directors or the shareholders.

    2. Powers.   The Board of Directors shall exercise all the powers of the
Corporation except those which are by law, or by the Articles of Incorporation
of this Corporation, or by the Bylaws conferred upon or reserved to the
shareholders.

    3. Committees.   The Board of Directors may, by resolution adopted by a
majority of the authorized number of directors, designate and appoint one or
more committees as the Board deems appropriate, each consisting of two or more
directors, to serve at the pleasure of the Board; provided, however, that, as
required by this Corporation's Articles of Incorporation, the members of the
Executive Committee (should the Board of Directors designate an Executive
Committee) must be appointed by the affirmative vote of two-thirds of the
authorized number of directors.  Any such committee, including the Executive
Committee, shall have the authority to act in the manner and to the extent
provided in the resolution of the Board of Directors designating such committee
and may have all the authority of the Board of Directors, except with respect to
the matters set forth in California Corporations Code Section 311.

    4. Time and Place of Directors' Meetings.   Regular meetings of the Board of
Directors shall be held on such days and at such times and at such locations as
shall be fixed by resolution of the Board, or designated by the Chairman of the
Board or, in his absence, the Vice Chairman of the Board, or the President of
the Corporation and contained in the notice of any such meeting. Notice of
meetings shall be delivered personally or sent by mail or telegram at least
seven days in advance.

    5. Special Meetings.   The Chairman of the Board, the Vice Chairman of the
Board, the Chairman of the Executive Committee, the President, or any five
directors may call a special meeting of the Board of Directors at any time.
Notice of the time and place of special meetings shall be given to each Director
by the Secretary. Such notice shall be delivered personally or by telephone to
each Director at least four hours in advance of such meeting, or sent by first-
class mail or telegram, postage prepaid, at least two days in advance of such
meeting.

                                       3
<PAGE>

    6.  Quorum.   A quorum for the transaction of business at any meeting of the
Board of Directors or any committee thereof shall consist of one-third of the
authorized number of directors or committee members, or two, whichever is
larger.

    7.  Action by Consent.  Any action required or permitted to be taken by the
Board of Directors may be taken without a meeting if all Directors individually
or collectively consent in writing to such action. Such written consent or
consents shall be filed with the minutes of the proceedings of the Board of
Directors.

    8.  Meetings by Conference Telephone.   Any meeting, regular or special, of
the Board of Directors or of any committee of the Board of Directors, may be
held by conference telephone or similar communication equipment, provided that
all Directors participating in the meeting can hear one another.


                                 Article III.
                                   OFFICERS.


    1. Officers.  The officers of the Corporation shall be a Chairman of the
Board, a Vice Chairman of the Board, a Chairman of the Executive Committee
(whenever the Board of Directors in its discretion fills these offices), a
President, one or more Vice Presidents, a Secretary and one or more Assistant
Secretaries, a Treasurer and one or more Assistant Treasurers, a General
Counsel, a General Attorney (whenever the Board of Directors in its discretion
fills this office), and a Controller, all of whom shall be elected by the Board
of Directors. The Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, and the President shall be members of the
Board of Directors.

    2. Chairman of the Board.   The Chairman of the Board, if that office be
filled, shall preside at all meetings of the shareholders, of the Directors, and
of the Executive Committee in the absence of the Chairman of that Committee. He
shall be the chief executive officer of the Corporation if so designated by the
Board of Directors. He shall have such duties and responsibilities as may be
prescribed by the Board of Directors or the Bylaws. The Chairman of the Board
shall have authority to sign on behalf of the Corporation agreements and
instruments of every character, and in the absence or disability of the
President, shall exercise his duties and responsibilities.

    3. Vice Chairman of the Board.   The Vice Chairman of the Board, if that
office be filled, shall have such duties and responsibilities as may be
prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws.
He shall be the chief executive officer of the Corporation if so designated by
the Board of Directors. In the absence of the Chairman of the Board, he shall
preside at all meetings of the Board of Directors and of the shareholders; and,
in the absence of the Chairman of the Executive Committee and the Chairman of
the Board, he shall preside at all meetings of the Executive Committee. The Vice
Chairman of the Board shall have authority to sign on behalf of the Corporation
agreements and instruments of every character.

                                       4
<PAGE>

    4. Chairman of the Executive Committee.    The Chairman of the Executive
Committee, if that office be filled, shall preside at all meetings of the
Executive Committee.  He shall aid and assist the other officers in the
performance of their duties and shall have such other duties as may be
prescribed by the Board of Directors or the Bylaws.

    5. President.   The President shall have such duties and responsibilities as
may be prescribed by the Board of Directors, the Chairman of the Board, or the
Bylaws.  He shall be the chief executive officer of the Corporation if so
designated by the Board of Directors.  If there be no Chairman of the Board, the
President shall also exercise the duties and responsibilities of that office.
The President shall have authority to sign on behalf of the Corporation
agreements and instruments of every character.

    6. Vice Presidents.    Each Vice President shall have such duties and
responsibilities as may be prescribed by the Board of Directors, the Chairman of
the Board, the Vice Chairman of the Board, the President, or the Bylaws.  Each
Vice President's authority to sign agreements and instruments on behalf of the
Corporation shall be as prescribed by the Board of Directors.  The Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, or the
President may confer a special title upon any Vice President.

    7. Secretary.    The Secretary shall attend all meetings of the Board of
Directors and the Executive Committee, and all meetings of the shareholders, and
he shall record the minutes of all proceedings in books to be kept for that
purpose.  He shall be responsible for maintaining a proper share register and
stock transfer books for all classes of shares issued by the Corporation.  He
shall give, or cause to be given, all notices required either by law or the
Bylaws.  He shall keep the seal of the Corporation in safe custody, and shall
affix the seal of the Corporation to any instrument requiring it and shall
attest the same by his signature.

    The Secretary shall have such other duties as may be prescribed by the Board
of Directors, the Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws.

    The Assistant Secretaries shall perform such duties as may be assigned from
time to time by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Secretary.  In the absence or
disability of the Secretary, his duties shall be performed by an Assistant
Secretary.

    8. Treasurer.    The Treasurer shall have custody of all moneys and funds of
the Corporation, and shall cause to be kept full and accurate records of
receipts and disbursements of the Corporation.  He shall deposit all moneys and
other valuables of the Corporation in the name and to the credit of the
Corporation in such depositaries as may be designated by the Board of Directors
or any employee of the Corporation designated by the Board of Directors.  He
shall disburse such funds of the Corporation as have been duly approved for
disbursement.

                                       5
<PAGE>

    The Treasurer shall perform such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws.

    The Assistant Treasurer shall perform such duties as may be assigned from
time to time by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Treasurer. In the absence or
disability of the Treasurer, his duties shall be performed by an Assistant
Treasurer.

    9.  General Counsel.  The General Counsel shall be responsible for handling
on behalf of the Corporation all proceedings and matters of a legal nature. He
shall render advice and legal counsel to the Board of Directors, officers, and
employees of the Corporation, as necessary to the proper conduct of the
business. He shall keep the management of the Corporation informed of all
significant developments of a legal nature affecting the interests of the
Corporation.

    The General Counsel shall have such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws.

    10. Controller.  The Controller shall be responsible for maintaining the
accounting records of the Corporation and for preparing necessary financial
reports and statements, and he shall properly account for all moneys and
obligations due the Corporation and all properties, assets, and liabilities of
the Corporation.  He shall render to the officers such periodic reports covering
the result of operations of the Corporation as may be required by them or any
one of them.

    The Controller shall have such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws. He shall be the principal
accounting officer of the Corporation, unless another individual shall be so
designated by the Board of Directors.

                                       6
<PAGE>

                                  Article IV.
                                MISCELLANEOUS.


    1. Record Date.    The Board of Directors may fix a time in the future as a
record date for the determination of the shareholders entitled to notice of and
to vote at any meeting of shareholders, or entitled to receive any dividend or
distribution, or allotment of rights, or to exercise rights in respect to any
change, conversion, or exchange of shares.  The record date so fixed shall be
not more than sixty nor less than ten days prior to the date of such meeting nor
more than sixty days prior to any other action for the purposes for which it is
so fixed.  When a record date is so fixed, only shareholders of record on that
date are entitled to notice of and to vote at the meeting, or entitled to
receive any dividend or distribution, or allotment of rights, or to exercise the
rights, as the case may be.

    2. Transfers of Stock.   Upon surrender to the Secretary or Transfer Agent
of the Corporation of a certificate for shares duly endorsed or accompanied by
proper evidence of succession, assignment, or authority to transfer, and payment
of transfer taxes, the Corporation shall issue a new certificate to the person
entitled thereto, cancel the old certificate, and record the transaction upon
its books.  Subject to the foregoing, the Board of Directors shall have power
and authority to make such rules and regulations as it shall deem necessary or
appropriate concerning the issue, transfer, and registration of certificates for
shares of stock of the Corporation, and to appoint and remove Transfer Agents
and Registrars of transfers.

    3. Lost Certificates.    Any person claiming a certificate of stock to be
lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of
that fact and verify the same in such manner as the Board of Directors may
require, and shall, if the Board of Directors so requires, give the Corporation,
its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form
approved by counsel, and in amount and with such sureties as may be satisfactory
to the Secretary of the Corporation, before a new certificate may be issued of
the same tenor and for the same number of shares as the one alleged to have been
lost, stolen, mislaid, or destroyed.


                                  Article V.
                                  AMENDMENTS.


    1. Amendment by Shareholders.    Except as otherwise provided by law, these
Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the
affirmative vote of a majority of the outstanding shares entitled to vote at any
regular or special meeting of the shareholders.

    2. Amendment by Directors.    To the extent provided by law, these Bylaws,
or any of them, may be amended or repealed or new Bylaws adopted by resolution
adopted by a majority of the members of the Board of Directors.

                                       7
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4.2
<SEQUENCE>5
<FILENAME>dex42.txt
<DESCRIPTION>FORM OF RIGHTS AGREEMENT
<TEXT>

<PAGE>

                                                                     EXHIBIT 4.2


                           Form of Rights Agreement



                               PG&E CORPORATION

                                      and


                         MELLON INVESTOR SERVICES LLC

                                 Rights Agent




                               Rights Agreement

                         Dated as of December 22, 2000
<PAGE>

                               TABLE OF CONTENTS
                               -----------------



<TABLE>
<CAPTION>
                                                                            Page
                                                                            ----
<S>                                                                         <C>
SECTION 1. Certain Definitions...........................................    1

SECTION 2. Appointment of Rights Agent...................................    5

SECTION 3. Issue of Rights Certificates..................................    5

SECTION 4. Form of Rights Certificates...................................    7

SECTION 5. Countersignature and Registration.............................    8

SECTION 6. Transfer, Split Up, Combination and Exchange of Rights
           Certificates; Mutilated, Destroyed, Lost or Stolen Rights
           Certificates..................................................    8

SECTION 7. Exercise of Rights; Purchase Price; Expiration Date
           of Rights.....................................................    9

SECTION 8. Cancellation and Destruction of Rights Certificates...........   11

SECTION 9. Reservation and Availability of Capital Stock.................   11

SECTION 10. Preferred Stock Record Date..................................   12

SECTION 11. Adjustment of Purchase Price, Number and Kind of Shares
            or Number of Rights..........................................   13

SECTION 12. Certificate of Adjusted Purchase Price or Number of Shares...   21

SECTION 13. Consolidation, Merger or Sale or Transfer of Assets or
            Earning Power................................................   21

SECTION 14. Fractional Rights and Fractional Shares......................   24

SECTION 15. Rights of Action.............................................   25

SECTION 16. Agreement of Rights Holders..................................   25

SECTION 17. Rights Certificate Holder Not Deemed a Shareholder...........   26

SECTION 18. Concerning the Rights Agent..................................   26

SECTION 19. Merger or Consolidation or Change of Name of Rights Agent....   27

SECTION 20. Duties of Rights Agent.......................................   27

SECTION 21. Change of Rights Agent.......................................   30

SECTION 22. Issuance of New Rights Certificates..........................   31

SECTION 23. Redemption and Termination...................................   31
</TABLE>

                                       i
<PAGE>

<TABLE>
<S>                                                                         <C>
SECTION 24. Notice of Certain Events......................................  32

SECTION 25. Notices.......................................................  32

SECTION 26. Supplements and Amendments....................................  33

SECTION 27. Successors....................................................  34

SECTION 28. Determinations and Actions by the Board of Directors, etc.....  34

SECTION 29. Benefits of this Agreement....................................  34

SECTION 30. Severability..................................................  35

SECTION 31. Governing Law.................................................  35

SECTION 32. Counterparts..................................................  35

SECTION 33. Descriptive Headings..........................................  35

SECTION 34. Exchange......................................................  35
</TABLE>

                                      ii
<PAGE>

                               RIGHTS AGREEMENT


       RIGHTS AGREEMENT, dated as of December 22, 2000 (this "Agreement"),
between PG&E CORPORATION, a California corporation (the "Company"), and MELLON
INVESTOR SERVICES LLC, a New Jersey limited liability company (the "Rights
Agent").

       WHEREAS, effective December 20, 2000 (the "Rights Dividend Declaration
Date"), the Board of Directors of the Company authorized and declared a
distribution of one Right (each, a "Right") for each share of Common Stock, no
par value per share, of the Company (the "Company Common Stock") outstanding at
the Close of Business (as defined below) on January 2, 2001 (the "Record Date"),
and has authorized the issuance of one Right (as such number may hereinafter be
adjusted pursuant hereto) for each share of Company Common Stock issued between
the Record Date and, except as otherwise provided in Section 22, the
Distribution Date, each Right initially representing the right to purchase upon
the terms and subject to the conditions hereinafter set forth one Unit (as
defined below) of Series A Preferred Stock (as defined below);

       WHEREAS, the Company desires to set forth certain terms and conditions
governing the Rights; and

       WHEREAS, the Company desires to appoint the Rights Agent to act as rights
agent hereunder, in accordance with the terms and conditions hereof;

       NOW, THEREFORE, in consideration of the premises and the mutual
agreements herein set forth, the parties hereby agree as follows:

       SECTION 1. Certain Definitions. For purposes of this Agreement, the
following terms have the meanings indicated:

       (a) "Acquiring Person" shall mean any Person who or which, alone or
   together with all Affiliates and Associates of such Person, shall be the
   Beneficial Owner of 15% or more of the shares of Company Common Stock then
   outstanding, but shall not include (i) the Company, any Subsidiary of the
   Company, any employee benefit plan maintained by the Company or any of its
   Subsidiaries or any trustee or fiduciary with respect to such plan acting in
   such capacity or (ii) any such Person who has become and is such a Beneficial
   Owner solely because (A) of a change in the aggregate number of shares of the
   Company Common Stock since the last date on which such Person acquired
   Beneficial Ownership of any shares of the Company Common Stock or (B) it
   acquired such Beneficial Ownership in the good faith belief that such
   acquisition would not (1) cause such Beneficial Ownership to be equal to or
   exceed 15% of the shares of the Company Common Stock then outstanding and
   such Person relied in good faith in computing the percentage of its
   Beneficial Ownership on publicly filed reports or documents of the Company
   that are inaccurate or out-of-date or (2) otherwise cause a Distribution Date
   or the adjustment provided for in Section 11(a)(iii) to occur.
   Notwithstanding clause (ii)(B) of the prior sentence, if any Person that is
   not an Acquiring Person due to such clause (ii)(B) does not reduce its
   percentage of Beneficial Ownership of the Company Common Stock to less than
   15% by the Close of Business on
<PAGE>

   the fifth Business Day after notice from the Company (the date on which such
   notice is first mailed or sent or delivered being the first day) that such
   person's Beneficial Ownership of the Company Common Stock is equal to or
   exceeds 15%, such Person shall, at the end of such five Business Day period,
   become an Acquiring Person (and such clause (ii)(B) shall no longer apply to
   such Person). For purposes of this definition, the determination whether any
   Person acted in "good faith" shall be conclusively determined by the Board of
   Directors of the Company, acting by a vote of those directors of the Company
   whose approval would be required to redeem the Rights under Section 23
   hereof.

       (b) "Adjustment Shares" has the meaning set forth in Section 11(a)(iii).

       (c) "Adjustment Spread" has the meaning set forth in Section 34(a)(ii).

       (d) "Affiliate" and "Associate" shall have the respective meanings
   ascribed to such terms in Rule 12b-2 of the Exchange Act Regulations as in
   effect on the date of this Agreement.

       (e) "Agreement" has the meaning set forth in the preamble to this
   Agreement.

       (f) A Person shall be deemed the "Beneficial Owner" of, and shall be
   deemed to "beneficially own", and shall be deemed to have "Beneficial
   Ownership" of, any securities:

             (i)   of which such Person or any of such Person's Affiliates or
       Associates is considered to be a "beneficial owner" under Rule 13d-3 of
       the Exchange Act Regulations as in effect on the date of this Agreement;
       provided, however, that a Person shall not be deemed the "Beneficial
       Owner" of, or to "beneficially own", or to have "Beneficial Ownership"
       of, any securities under this subparagraph (i) as a result of an
       agreement, arrangement or understanding to vote such securities if such
       agreement, arrangement or understanding (A) arises solely from a
       revocable proxy given in response to a proxy or consent solicitation made
       pursuant to, and in accordance with, the applicable provisions of the
       Exchange Act and the Exchange Act Regulations, and (B) is not reportable
       by such Person on Schedule 13D under the Exchange Act (or any comparable
       or successor report);

             (ii)  that are beneficially owned, directly or indirectly, by any
       other Person (or any Affiliate or Associate of such other Person) with
       which such Person (or any of such Person's Affiliates or Associates) has
       any agreement, arrangement or understanding (whether or not in writing),
       for the purpose of acquiring, holding, voting (except pursuant to a
       revocable proxy as described in the proviso to subparagraph (i) of this
       paragraph (f)) or disposing of such securities; or

             (iii) that such Person or any of such Person's Affiliates or
       Associates, directly or indirectly, has the right to acquire (whether
       such right is exercisable immediately or only after the passage of time
       or upon the satisfaction of

                                       2
<PAGE>

       conditions) pursuant to any agreement, arrangement or understanding
       (whether or not in writing) or upon the exercise of conversion rights,
       exchange rights, rights, warrants or options, or otherwise;

   provided, however, that under this paragraph (f) a Person shall not be deemed
   the "Beneficial Owner" of, or to "beneficially own", or to have "Beneficial
   Ownership" of, (A) securities tendered pursuant to a tender or exchange offer
   made in accordance with Exchange Act Regulations by such Person or any of
   such Person's Affiliates or Associates until such tendered securities are
   accepted for purchase or exchange, (B) securities that may be issued upon
   exercise of Rights at any time prior to the occurrence of a Triggering Event
   or (C) securities that may be issued upon exercise of Rights from and after
   the occurrence of a Triggering Event, which Rights were acquired by such
   Person or any of such Person's Affiliates or Associates prior to the
   Distribution Date or pursuant to Section 3(c) or Section 22 or pursuant to
   Section 11(i) in connection with an adjustment made with respect to any such
   Rights.

       (g) "Business Day" shall mean any day other than a Saturday, Sunday or a
   day on which banking institutions in the State of California or the State of
   New Jersey are authorized or obligated by law or executive order to close.

       (h) "Close of Business" on any given date shall mean 5:00 p.m.,
   California time, on such date; provided, however, that if such date is not a
   Business Day it shall mean 5:00 p.m., California time, on the next succeeding
   Business Day.

       (i) "Common Stock" of any Person other than the Company shall mean the
   capital stock of such Person with the greatest voting power, or, if such
   Person shall have no capital stock, the equity securities or other equity
   interest having power to control or direct the management of such Person.

       (j) "Company" has the meaning set forth in the preamble to this
   Agreement.

       (k) "Company Common Stock" has the meaning set forth in the recitals to
   this Agreement.

       (l) "Current Value" has the meaning set forth in Section 11(a)(iv).

       (m) "Depositary Agent" has the meaning set forth in Section 7(c).

       (n) "Distribution Date" has the meaning set forth in Section 3(a).

       (o) "Equivalent Preferred Stock" has the meaning set forth in Section
   11(b).

       (p) "Exchange Act" shall mean the Securities Exchange Act of 1934, as
   amended.

       (q) "Exchange Act Regulations" shall mean the General Rules and
   Regulations promulgated under the Exchange Act.

                                       3
<PAGE>

       (r)  "Expiration Date" has the meaning set forth in Section 7(a).

       (s)  "Final Expiration Date" has the meaning set forth in Section 7(a).

       (t)  "Person" shall mean any individual, partnership, limited liability
   company, firm, corporation, joint venture, association, trust, unincorporated
   organization or other entity, as well as any syndicate or group deemed to be
   a person under Section 14(d)(2) of the Exchange Act.

       (u)  "Preferred Stock" shall mean the Series A Preferred Stock, par value
   $100 per share, of the Company having the voting powers, designation,
   preferences and relative, participating, optional or other special rights and
   qualifications, limitations and restrictions described in the Certificate of
   Determination set forth as Exhibit C hereto.

       (v)  "Preferred Stock Equivalents" has the meaning set forth in Section
   11(a)(iv).

       (w)  "Principal Party" has the meaning set forth in Section 13(b).

       (x)  "Purchase Price" has the meaning set forth in Section 7(b).

       (y)  "Record Date" has the meaning set forth in the recitals to this
   Agreement.

       (z)  "Redemption Price" has the meaning set forth in Section 23(a).

       (aa) "Registered Common Stock" has the meaning set forth in Section
   13(b)(ii).

       (bb) "Registration Date" has the meaning set forth in Section 9(c).

       (cc) "Registration Statement" has the meaning set forth in Section 9(c).

       (dd) "Right" has the meaning set forth in the recitals to this Agreement.

       (ee) "Rights Agent" has the meaning set forth in the preamble to this
   Agreement.

       (ff) "Rights Certificates" has the meaning set forth in Section 3(a).

       (gg) "Rights Dividend Declaration Date" has the meaning set forth in the
   recitals to this Agreement.

       (hh) "Section 11(a)(iii) Event" has the meaning set forth in Section
   11(a)(iii).

       (ii) "Section 11(a)(iv) Trigger Date" has the meaning set forth in
   Section 11(a)(iv).

       (jj) "Section 13 Event" has the meaning set forth in Section 13(a).

                                       4
<PAGE>

       (kk) "Section 34(a)(i) Exchange Ratio" has the meaning set forth in
   Section 34(a)(i).

       (ll) "Section 34(a)(ii) Exchange Ratio" has the meaning set forth in
   Section 34(a)(ii).

       (mm) "Securities Act" shall mean the Securities Act of 1933, as amended.

       (nn) "Spread" has the meaning set forth in Section 11(a)(iv).

       (oo) "Stock Acquisition Date" shall mean the first date of public
   announcement (including, without limitation, the filing of any report
   pursuant to Section 13(d) of the Exchange Act) by the Company or an Acquiring
   Person that an Acquiring Person has become such.

       (pp) "Subsidiary" of any Person shall mean any corporation or other
   Person of which a majority of the voting power of the voting equity
   securities or equity interest is beneficially owned, directly or indirectly,
   by such Person, or otherwise controlled by such Person.

       (qq) "Summary of Rights" has the meaning set forth in Section 3(b).

       (rr) "Trading Day" has the meaning set forth in Section 11(d)(i).

       (ss) "Triggering Event" shall mean any Section 11(a)(iii) Event or any
   Section 13 Event.

       (tt) "Unit" has the meaning set forth in Section 7(b).

       SECTION 2. Appointment of Rights Agent. The Company hereby appoints the
Rights Agent to act as agent for the Company in accordance with the terms and
conditions hereof, and the Rights Agent hereby accepts such appointment. With
the consent of the Rights Agent, the Company may from time to time appoint such
Co-Rights Agents as it may deem necessary or desirable. The Rights Agent shall
have no duty to supervise, and in no event shall be liable for, the acts or
omissions of any such co-Rights Agent.

       SECTION 3. Issue of Rights Certificates. (a) Until the earlier of (i) the
Close of Business on the tenth day after the Stock Acquisition Date and (ii) the
Close of Business on the tenth Business Day (or such later date as may be
determined by action of the Company's Board of Directors prior to such time as
any Person becomes an Acquiring Person, and of which the Company will give the
Rights Agent prompt written notice) after the date that a tender or exchange
offer by any Person (other than the Company, any Subsidiary of the Company, any
employee benefit plan maintained by the Company or any of its Subsidiaries or
any trustee or fiduciary with respect to such plan acting in such capacity) is
first published or sent or given within the meaning of Rule 14d-4(a) of the
Exchange Act Regulations or any successor rule, if upon consummation thereof
such Person would be the Beneficial Owner of 15% or more of the shares of
Company Common Stock then outstanding (the earlier of (i) and (ii) above being
the "Distribution Date"), (x) the Rights will be evidenced (subject to the
provisions of paragraph (b)

                                       5
<PAGE>

of this Section 3) by the certificates for shares of Company Common Stock
registered in the names of the holders of shares of Company Common Stock as of
and subsequent to the Record Date (which certificates for shares of Company
Common Stock shall be deemed also to be certificates for Rights) and not by
separate certificates, and (y) the Rights will be transferable only in
connection with the transfer of the underlying shares of Company Common Stock
(including a transfer to the Company). As soon as practicable after the
Distribution Date, the Company shall promptly notify in writing the Rights Agent
of the occurrence of the Distribution Date and, if the Rights Agent is no
longer the Company's transfer agent, provide the Rights Agent with the names and
addresses of all record holders of Commmon shares (together with all other
necessary information), and the Rights Agent will send by first-class, insured,
postage prepaid mail, to each record holder of shares of Company Common Stock as
of the Close of Business on the Distribution Date, at the address of such holder
shown on the records of the Company, one or more rights certificates, in
substantially the form attached hereto as Exhibit A (the "Rights Certificates"),
evidencing one Right for each share of Company Common Stock so held, subject to
adjustment as provided herein. In the event that an adjustment in the number of
Rights per share of Company Common Stock has been made pursuant to Section
11(p), at the time of distribution of the Rights Certificates, the Company may
make the necessary and appropriate rounding adjustments (in accordance with
Section 14(a)) so that Rights Certificates evidencing only whole numbers of
Rights are distributed and cash is paid in lieu of any fractional Rights. As of
and after the Distribution Date, the Rights will be evidenced solely by such
Rights Certificates.

       (b) As promptly as practicable following the Record Date, the Company
will send a copy of a Summary of Rights to Purchase Preferred Stock, in a form
that may be appended to certificates that evidence shares of Company Common
Stock, in substantially the form attached hereto as Exhibit B (the "Summary of
Rights"), by first-class, postage prepaid mail, to each record holder of shares
of Company Common Stock as of the Close of Business on the Record Date, at the
address of such holder shown on the records of the Company.

       (c) Rights shall, without any further action, be issued in respect of all
shares of Company Common Stock that are issued (including any shares of Company
Common Stock held in treasury) after the Record Date but prior to the earlier of
the Distribution Date and the Expiration Date. Certificates evidencing such
shares of Company Common Stock issued after the Record Date shall bear the
following legend or such similar legend as the Company may deem appropriate and
as is not inconsistent with the provisions of this Agreement:

       "This certificate also evidences and entitles the holder hereof to
   certain Rights as set forth in the Rights Agreement, dated as of December 22,
   2000 (the "Rights Agreement"), between PG&E Corporation (the "Company") and
   Mellon Investor Services LLC (the "Rights Agent"), the terms of which are
   hereby incorporated herein by reference and a copy of which is on file at the
   office of the Rights Agent designated for such purpose. Under certain
   circumstances, as set forth in the Rights Agreement, such Rights will be
   evidenced by separate certificates and will no longer be evidenced by this
   certificate. The Company will mail to the holder of this certificate a copy
   of the Rights Agreement, as in effect on the date of mailing, without charge
   promptly after receipt of a written request therefor. Under certain
   circumstances set forth in the Rights Agreement, Rights issued to, or held
   by, any Person who is, was or becomes an Acquiring Person or any Affiliate or
   Associate thereof (as such terms are defined in the Rights

                                       6
<PAGE>

   Agreement), whether currently held by or on behalf of such Person or by any
   subsequent holder, may become null and void."

       With respect to certificates evidencing shares of Company Common Stock
(whether or not such certificates include the foregoing legend or have appended
to them the Summary of Rights), until the earlier of the Distribution Date and
the Expiration Date, the Rights associated with the shares of Company Common
Stock evidenced by such certificates shall be evidenced by such certificates
alone and registered holders of the shares of Company Common Stock shall also be
the registered holders of the associated Rights, and the transfer of any of such
certificates shall also constitute the transfer of the Rights associated with
the shares of Company Common Stock evidenced by such certificates.

       SECTION 4. Form of Rights Certificates. (a) The Rights Certificates (and
the forms of election to purchase, assignment and certificate to be printed on
the reverse thereof) shall each be substantially in the form attached hereto as
Exhibit A and may have such marks of identification or designation and such
legends, summaries or endorsements printed thereon as the Company may deem
appropriate (which do not affect the duties or responsibilities of the Rights
Agent) and as are not inconsistent with the provisions of this Agreement, or as
may be required to comply with any applicable law or any rule or regulation
thereunder or with any rule or regulation of any stock exchange on which the
Rights may from time to time be listed or to conform to usage. Subject to the
provisions of Section 11 and Section 22, the Rights Certificates, whenever
distributed, shall be dated as of the Record Date and on their face shall
entitle the holders thereof to purchase such number of Units of Preferred Stock
as shall be set forth therein at the price set forth therein, but the amount and
type of securities, cash or other assets that may be acquired upon the exercise
of each Right and the Purchase Price thereof shall be subject to adjustment as
provided herein.

       (b) Any Rights Certificate issued pursuant hereto that evidences Rights
beneficially owned by: (i) an Acquiring Person or any Associate or Affiliate of
an Acquiring Person, (ii) a transferee of an Acquiring Person (or of any such
Associate or Affiliate) that becomes a transferee after the Acquiring Person
becomes such, or (iii) a transferee of an Acquiring Person (or of any such
Associate or Affiliate) that becomes a transferee prior to or concurrently with
the Acquiring Person becoming such and that receives such Rights pursuant to
either (A) a transfer (whether or not for consideration) from the Acquiring
Person (or any such Associate or Affiliate) to holders of equity interests in
such Acquiring Person (or such Associate or Affiliate) or to any Person with
whom such Acquiring Person (or such Associate or Affiliate) has any continuing
agreement, arrangement or understanding regarding either the transferred Rights,
shares of Company Common Stock or the Company or (B) a transfer that a majority
of the Company's Board of Directors has determined to be part of a plan,
arrangement or understanding that has as a primary purpose or effect the
avoidance of Section 7(e), shall, upon the written direction of a majority of
the Company's Board of Directors, contain (to the extent the Rights Agent has
notice thereof and to the extent feasible) the following legend or such similar
legend as the Company may deem appropriate and as is not inconsistent with the
provisions of this Agreement:

       "The Rights evidenced by this Rights Certificate are or were beneficially
   owned by a Person who was or became an Acquiring Person or an Affiliate or

                                       7
<PAGE>

   Associate of an Acquiring Person (as such terms are defined in the Rights
   Agreement). Accordingly, this Rights Certificate and the Rights evidenced
   hereby may become null and void in the circumstances specified in Section
   7(e) of such Agreement."

       SECTION 5. Countersignature and Registration. (a) Rights Certificates
shall be executed on behalf of the Company by its Chairman of the Board, the
President or any of its Senior Vice Presidents, under its corporate seal
reproduced thereon attested by its Secretary or one of its Assistant
Secretaries. The signature of any one or more of these officers on the Rights
Certificates may be manual or facsimile. Rights Certificates bearing the manual
or facsimile signatures of the individuals who were at any time the proper
officers of the Company shall bind the Company, notwithstanding that such
individuals or any of them have ceased to hold such offices prior to the
countersignature of such Rights Certificates or did not hold such offices at the
date of such Rights Certificates. No Rights Certificate shall be entitled to any
benefit under this Agreement or be valid for any purpose unless there appears on
such Rights Certificate a countersignature duly executed by the Rights Agent by
manual signature of an authorized signatory, and such countersignature upon any
Rights Certificate shall be conclusive evidence, and the only evidence, that
such Rights Certificate has been duly countersigned as required hereunder. In
case any officer of the Company who shall have signed any of the Rights
Certificates shall cease to be such officer of the Company before
countersignature by the Rights Agent and issuance and delivery by the Company,
such Rights Certificates, nevertheless, may be countersigned by the Rights Agent
and issued and delivered by the Company with the same force and effect as though
the person who signed such Rights Certificates on behalf of the Company had not
ceased to be such officer of the Company.

       (b) Following the Distribution Date and receipt by the Rights Agent of
the written notice referred to in Section 3(a), the Rights Agent will keep or
cause to be kept, at its office designated for surrender of Rights Certificates
upon exercise or transfer, books for registration and transfer of the Rights
Certificates issued hereunder. Such books shall show the name and address of
each holder of the Rights Certificates, the number of Rights evidenced on its
face by each Rights Certificate and the date of each Rights Certificate.

       SECTION 6. Transfer, Split Up, Combination and Exchange of Rights
Certificates; Mutilated, Destroyed, Lost or Stolen Rights Certificates. (a)
Subject to the provisions of Sections 4(b), 7(e) and 14, at any time after the
Close of Business on the Distribution Date, and at or prior to the Close of
Business on the Expiration Date, any Rights Certificate or Certificates may be
transferred, split up, combined or exchanged for another Rights Certificate or
Certificates, entitling the registered holder to purchase a like number of Units
of Preferred Stock (or, following a Triggering Event, other securities, cash or
other assets, as the case may be) as the Rights Certificate or Certificates
surrendered then entitled such holder to purchase. Any registered holder
desiring to transfer, split up, combine or exchange any Rights Certificate or
Certificates shall make such request in writing delivered to the Rights Agent,
and shall surrender the Rights Certificate or Certificates to be transferred,
split up, combined or exchanged at the office of the Rights Agent designated for
such purpose. Neither the Rights Agent nor the Company shall be obligated to
take any action whatsoever with respect to the transfer of any such surrendered
Rights Certificate until the registered holder shall have properly completed and
executed the certificate set forth in the form of assignment on the reverse side
of

                                       8
<PAGE>

such Rights Certificate and shall have provided such additional evidence of the
identity of the Beneficial Owner (or former Beneficial Owner) of the Rights
evidenced by such Rights Certificate or Affiliates or Associates thereof as the
Company or the Rights Agent shall reasonably request; whereupon the Rights Agent
shall, subject to the provisions of Sections 4(b), 7(e) and 14, countersign and
deliver to the Person entitled thereto a Rights Certificate or Rights
Certificates, as the case may be, as so requested. The Company may require
payment of a sum sufficient to cover any tax or governmental charge that may be
imposed in connection with any transfer, split up, combination or exchange of
Rights Certificates. The Rights Agent shall have no duty or obligation under
this Section 6 or any other similar provision of this Agreement unless and until
it is satisfied that all such taxes and/or governmental charges have been paid.

       (b) If a Rights Certificate shall be mutilated, destroyed, lost or
stolen, upon request by the registered holder of the Rights evidenced thereby
and upon payment to the Company and the Rights Agent of all reasonable expenses
incident thereto, there shall be issued, in exchange for and upon cancellation
of the mutilated Rights Certificate, or in substitution for the lost, stolen or
destroyed Rights Certificate, a new Rights Certificate, in substantially the
form of the prior Rights Certificate, of like tenor and evidencing the
equivalent number of Rights, but, in the case of loss, theft or destruction,
only upon receipt of evidence satisfactory to the Company and the Rights Agent
of such loss, theft or destruction of such Rights Certificate and, if requested
by the Company or the Rights Agent, indemnity also satisfactory to it.

       SECTION 7. Exercise of Rights; Purchase Price; Expiration Date of Rights.
(a) Prior to the earlier of (i) the Close of Business on the tenth anniversary
hereof (the "Final Expiration Date") and (ii) the time at which the Rights are
redeemed as provided in Section 23 (the earlier of (i) and (ii) being the
"Expiration Date"), the registered holder of any Rights Certificate may, subject
to the provisions of Sections 7(e) and 9(c), exercise the Rights evidenced
thereby in whole or in part at any time after the Distribution Date upon
surrender of the Rights Certificate, with the form of election to purchase and
the certificate on the reverse side thereof duly executed, to the Rights Agent
at the office of the Rights Agent designated for such purpose, together with
payment of the aggregate Purchase Price (as hereinafter defined) for the number
of Units of Preferred Stock (or, following a Triggering Event, other securities,
cash or other assets, as the case may be) for which such surrendered Rights are
then exercisable.

       (b) The purchase price for each one one-hundredth of a share (each such
one one-hundredth of a share being a "Unit") of Preferred Stock upon exercise of
Rights shall be $95, subject to adjustment from time to time as provided in
Sections 11 and 13(a) (such purchase price, as so adjusted, being the "Purchase
Price"), and shall be payable in accordance with paragraph (c) below.

       (c) As promptly as practicable following the occurrence of the
Distribution Date, the Company shall deposit with a Person in good standing
organized under the laws of the United States or any State of the United States,
that is authorized under such laws to exercise shareholder services business,
corporate trust or stock transfer powers and is subject to supervision or
examination by federal or state authority (such institution being the
"Depositary Agent"), certificates evidencing the shares of Preferred Stock that
may be acquired upon exercise of the Rights and shall cause such Depositary
Agent to enter into an agreement pursuant to which the Depositary Agent shall
issue receipts evidencing interests in the shares of Preferred Stock so

                                       9
<PAGE>

deposited. Upon receipt of written notice that the Distribution Date has
occurred and receipt of a Rights Certificate evidencing exercisable Rights, with
the form of election to purchase and the certificate duly executed, accompanied
by payment, with respect to each Right so exercised, of the Purchase Price for
the Units of Preferred Stock (or, following a Triggering Event, other
securities, cash or other assets, as the case may be) to be purchased thereby as
set forth below and an amount equal to any applicable tax or governmental charge
or evidence satisfactory to the Company of payment of such tax or governmental
charge, the Rights Agent shall, subject to Section 20(k), thereupon promptly (i)
requisition from the Depositary Agent depositary receipts or certificates
evidencing such number of Units of Preferred Stock as are to be purchased and
the Company will direct the Depositary Agent to comply with such request, (ii)
requisition from the Company the amount of cash, if any, to be paid in lieu of
fractional shares in accordance with Section 14, (iii) after receipt of such
depositary receipts or certificates, cause the same to be delivered to or upon
the order of the registered holder of such Rights Certificate, registered in
such name or names as may be designated by such holder, and (iv) after receipt
thereof, deliver such cash, if any, to or upon the order of the registered
holder of such Rights Certificate. In the event that the Company is obligated to
issue Company Common Stock, other securities of the Company, pay cash and/or
distribute other property pursuant to Section 11(a), the Company will make all
arrangements necessary so that such Company Common Stock, other securities, cash
and/or other property are available for distribution by the Rights Agent, if and
when necessary to comply with this Agreement. Subject to Section 34, the payment
of the Purchase Price (as such amount may be reduced pursuant to Section
11(a)(iv)) may be made in cash or by certified or bank check payable to the
order of the Company, or by wire transfer of immediately available funds to the
account of the Company (provided that notice of such wire transfer shall be
given by the holder of the related Right to the Rights Agent).

       (d) In case the registered holder of any Rights Certificate shall
exercise less than all the Rights evidenced thereby, a new Rights Certificate
evidencing the Rights remaining unexercised shall be issued by the Rights Agent
and delivered to, or upon the order of, the registered holder of such Rights
Certificate, registered in such name or names as may be designated by such
holder, subject to the provisions of Section 14 hereof.

       (e) Notwithstanding anything in this Agreement to the contrary, from and
after the first occurrence of any Section 11(a)(iii) Event or Section 13 Event,
any Rights beneficially owned by (i) an Acquiring Person or an Associate or
Affiliate of an Acquiring Person, (ii) a transferee of an Acquiring Person (or
of any such Associate or Affiliate) that becomes a transferee after the
Acquiring Person becomes such, or (iii) a transferee of an Acquiring Person (or
of any such Associate or Affiliate) that becomes a transferee prior to or
concurrently with the Acquiring Person becoming such and that receives such
Rights pursuant to either (A) a transfer (whether or not for consideration) from
the Acquiring Person (or any such Associate or Affiliate) to holders of equity
interests in such Acquiring Person (or such Associate or Affiliate) or to any
Person with whom such Acquiring Person (or such Associate or Affiliate) has any
continuing agreement, arrangement or understanding regarding the transferred
Rights, shares of Company Common Stock or the Company or (B) a transfer that a
majority of the Company's Board of Directors has determined to be part of a
plan, arrangement or understanding that has as a primary purpose or effect the
avoidance of this Section 7(e), shall be null and void without any further
action, and no holder of such Rights shall have any rights whatsoever with
respect to such Rights, whether under any provision of this Agreement or
otherwise. The

                                      10
<PAGE>

Company shall use all reasonable efforts to ensure that the provisions of this
Section 7(e) and Section 4(b) are complied with, but neither the Company nor the
Rights Agent shall have any liability to any holder of Rights or any other
Person as a result of the Company's failure to make any determination under this
Section 7(e) or Section 4(b) with respect to an Acquiring Person or its
Affiliates, Associates or transferees.

       (f) Notwithstanding anything in this Agreement or any Rights Certificate
to the contrary, neither the Rights Agent nor the Company shall be obligated to
undertake any action with respect to a registered holder upon the occurrence of
any purported exercise by such registered holder unless such registered holder
shall have (i) properly completed and executed the certificate following the
form of election to purchase set forth on the reverse side of the Rights
Certificate surrendered for such exercise and (ii) provided such additional
evidence of the identity of the Beneficial Owner (or former Beneficial Owner) of
the Rights evidenced by such Rights Certificate or Affiliates or Associates
thereof as the Company shall request.

       SECTION 8. Cancellation and Destruction of Rights Certificates. All
Rights Certificates surrendered for the purpose of exercise, transfer, split up,
combination or exchange shall, if surrendered to the Company or any of its
agents, be delivered to the Rights Agent for cancellation or in cancelled form,
or, if surrendered to the Rights Agent, shall be cancelled by it, and no Rights
Certificates shall be issued in lieu thereof except as expressly permitted by
this Agreement. The Company shall deliver to the Rights Agent for cancellation
and retirement, and the Rights Agent shall so cancel and retire, any Rights
Certificates acquired by the Company otherwise than upon the exercise thereof.
The Rights Agent shall deliver all cancelled Rights Certificates to the Company,
or shall, at the written request of the Company, destroy such cancelled Rights
Certificates, and in such case shall deliver a certificate of destruction
thereof to the Company.

       SECTION 9. Reservation and Availability of Capital Stock. (a) The Company
shall at all times prior to the Expiration Date cause to be reserved and kept
available, out of its authorized and unissued shares of Preferred Stock, the
number of shares of Preferred Stock that, as provided in this Agreement, will be
sufficient to permit the exercise in full of all outstanding Rights. Upon the
occurrence of any events resulting in an increase in the aggregate number of
shares of Preferred Stock (or other equity securities of the Company) issuable
upon exercise of all outstanding Rights above the number then reserved, the
Company shall make appropriate increases in the number of shares so reserved.

       (b) If the shares of Preferred Stock to be issued and delivered upon the
exercise of the Rights may be listed on any national securities exchange, the
Company shall during the period from the Distribution Date through the
Expiration Date use its best efforts to cause all securities reserved for such
issuance to be listed on such exchange upon official notice of issuance upon
such exercise.

       (c) The Company shall use its best efforts (i) as soon as practicable
following the occurrence of a Section 11(a)(iii) Event and a determination by
the Company in accordance with Section 11(a)(iv) of the consideration to be
delivered by the Company upon exercise of the Rights or, if so required by law,
as soon as practicable following the Distribution Date (such date being the
"Registration Date"), to file a registration statement on an appropriate form
under the

                                      11
<PAGE>

Securities Act with respect to the securities that may be acquired upon exercise
of the Rights (the "Registration Statement"), (ii) to cause the Registration
Statement to become effective as soon as practicable after such filing, (iii) to
cause the Registration Statement to continue to be effective (and to include a
prospectus complying with the requirements of the Securities Act) until the
earlier of (A) the date as of which the Rights are no longer exercisable for the
securities covered by the Registration Statement and (B) the Expiration Date and
(iv) to take as soon as practicable following the Registration Date such action
as may be required to ensure that any acquisition of securities upon exercise of
the Rights complies with any applicable state securities or "blue sky" laws. If
the Registration Statement does not become effective prior to the Close of
Business on the 45th Business Day following the occurrence of a Section
11(a)(iii) Event, the Company shall, unless otherwise determined by a majority
of the Company's Board of Directors, on the 46th Business Day following the
occurrence of such Section 11(a)(iii) Event, be obligated to exercise the option
described in Section 34 and shall promptly notify the Rights Agent in writing of
such exercise.

       (d) The Company shall take such action as may be necessary to ensure that
all shares of Preferred Stock (and, following the occurrence of a Triggering
Event, any other securities that may be delivered upon exercise of Rights) shall
be, at the time of delivery of the certificates or depositary receipts for such
securities, duly and validly authorized and issued and fully paid and non-
assessable.

       (e) The Company shall pay any tax or governmental charge imposed in
connection with the issuance or delivery of the Rights Certificates or upon the
exercise of Rights; provided, however, that the Company shall not be required to
pay any such tax imposed in connection with the issuance or delivery of Units of
Preferred Stock, or any certificates or depositary receipts for such Units of
Preferred Stock (or, following the occurrence of a Triggering Event, any other
securities, cash or assets, as the case may be) to any Person other than the
registered holder of the Rights Certificates evidencing the Rights surrendered
for exercise. The Company shall not be required to issue or deliver any
certificates or depositary receipts for Units of Preferred Stock (or, following
the occurrence of a Triggering Event, any other securities, cash or assets, as
the case may be) to, or in a name other than that of, the registered holder of
the Rights Certificate upon the exercise of any Rights evidenced thereby until
any such tax or governmental charge shall have been paid (any such tax or
governmental charge being payable by the holder of such Rights Certificate at
the time of surrender) or until it has been established to the Company's
satisfaction that no such tax or governmental charge is due.

       SECTION 10. Preferred Stock Record Date. Each Person in whose name any
certificate or depositary receipt for Units of Preferred Stock (or, following
the occurrence of a Triggering Event, other securities) is issued upon the
exercise of Rights shall for all purposes be deemed to have become the holder of
record of the Units of Preferred Stock (or, following the occurrence of a
Triggering Event, other securities) evidenced thereby on, and such certificate
or depositary receipt shall be dated, the date upon which the Rights Certificate
evidencing such Rights was duly surrendered and payment of the Purchase Price
(and any applicable taxes or governmental charges) was made; provided, however,
that if the date of such surrender and payment is a date upon which the
Preferred Stock (or, following the occurrence of a Triggering Event, other
securities) transfer books of the Company are closed, such Person shall be
deemed

                                      12
<PAGE>

to have become the record holder of such securities on, and such certificate or
depositary receipt shall be dated, the next succeeding Business Day on which the
Preferred Stock (or, following the occurrence of a Triggering Event, other
securities) transfer books of the Company are open; and further provided,
however, that if delivery of Units of Preferred Stock is delayed as a result of
a failure to register such Units of Preferred Stock pursuant to Section 9(c),
such Persons shall be deemed to have become the record holders of such Units of
Preferred Stock only when such Units first become deliverable. Prior to the
exercise of the Rights evidenced thereby, the holder of a Rights Certificate
shall not be entitled to any rights of a shareholder of the Company with respect
to securities for which the Rights shall be exercisable, including, without
limitation, the right to vote, to receive dividends or other distributions or to
exercise any preemptive rights, and shall not be entitled to receive any notice
of any proceedings of the Company, except as provided herein.

       SECTION 11. Adjustment of Purchase Price, Number and Kind of Shares or
Number of Rights. The Purchase Price, the number and kind of securities covered
by each Right and the number of Rights outstanding are subject to adjustment
from time to time as provided in this Section 11.

       (a) (i)  In the event the Company shall at any time after the date of
this Agreement (A) declare a dividend on the Preferred Stock payable in shares
of Preferred Stock, (B) subdivide the outstanding Preferred Stock, (C) combine
the outstanding Preferred Stock into a smaller number of shares or (D) issue any
shares of its capital stock in a reclassification of the Preferred Stock
(including any such reclassification in connection with a consolidation or
merger in which the Company is the continuing or surviving corporation), except
as otherwise provided in this Section 11(a), the Purchase Price in effect at the
time of the record date for such dividend or of the effective date of such
subdivision, combination or reclassification, and the number and kind of shares
of Preferred Stock or capital stock, as the case may be, issuable on such date
upon exercise of the Rights, shall be proportionately adjusted so that the
holder of any Right exercised after such time shall be entitled to receive, upon
payment of the Purchase Price then in effect, the aggregate number and kind of
shares of Preferred Stock or capital stock, as the case may be, which, if such
Right had been exercised immediately prior to such date, such holder would have
owned upon such exercise and been entitled to receive by virtue of such
dividend, subdivision, combination or reclassification. If an event occurs that
would require an adjustment under both this Section 11(a)(i) and Section
11(a)(iii), the adjustment provided for in this Section 11(a)(i) shall be in
addition to, and shall be made prior to, any adjustment required pursuant to
Section 11(a)(iii).

           (ii) Upon the declaration of a dividend in connection with any spin-
off or other similar transaction effected by the Company (whether occurring
before or after a Distribution Date), the Purchase Price in effect at the time
of the record date therefor, and the number and kind of shares of Preferred
Stock or capital stock, as the case may be, issuable at such time upon exercise
of the Rights, may be adjusted by action of a majority of the Company's Board of
Directors, after receiving advice from a nationally recognized investment
banking firm, in a manner that reflects the impact on the Company Common Stock
of such spin-off or other similar transaction. If an event occurs that the
Company's Board of Directors determines would require an adjustment under both
this Section 11(a)(ii) and Section 11(a)(iii), the adjustment

                                      13
<PAGE>

provided for in this Section 11(a)(ii) shall be in addition to, and shall be
made prior to, any adjustment required pursuant to Section 11(a)(iii).

       (iii) In the event:

       (A) any Acquiring Person or any Associate or Affiliate of any Acquiring
   Person, at any time after the date of this Agreement, directly or indirectly,
   shall (1) merge into the Company or otherwise combine with the Company and
   the Company shall be the continuing or surviving corporation of such merger
   or combination and Company Common Stock shall remain outstanding and
   unchanged, (2) in one transaction or a series of transactions, transfer any
   assets to the Company or to any of its Subsidiaries in exchange (in whole or
   in part) for shares of Company Common Stock, for other equity securities of
   the Company or any such Subsidiary, or for securities exercisable for or
   convertible into shares of equity securities of the Company or any of its
   Subsidiaries (whether Company Common Stock or otherwise) or otherwise obtain
   from the Company or any of its Subsidiaries, with or without consideration,
   any additional shares of such equity securities or securities exercisable for
   or convertible into such equity securities (other than pursuant to a pro rata
   distribution to all holders of Company Common Stock), (3) sell, purchase,
   lease, exchange, mortgage, pledge, transfer or otherwise acquire or dispose
   of, in one transaction or a series of transactions, to, from or with the
   Company or any of its Subsidiaries or any employee benefit plan maintained by
   the Company or any of its Subsidiaries or any trustee or fiduciary with
   respect to such plan acting in such capacity, assets (including securities)
   on terms and conditions less favorable to the Company or such Subsidiary or
   plan than those that could have been obtained in arm's-length negotiations
   with an unaffiliated third party, other than pursuant to a transaction set
   forth in Section 13(a), (4) sell, purchase, lease, exchange, mortgage,
   pledge, transfer or otherwise acquire or dispose of, in one transaction or a
   series of transactions, to, from or with the Company or any of the Company's
   Subsidiaries or any employee benefit plan maintained by the Company or any of
   its Subsidiaries or any trustee or fiduciary with respect to such plan acting
   in such capacity (other than transactions, if any, consistent with those
   engaged in, as of the date hereof, by the Company and such Acquiring Person
   or such Associate or Affiliate), assets (including securities) having an
   aggregate fair market value of more than $5,000,000, other than pursuant to a
   transaction set forth in Section 13(a), (5) sell, purchase, lease, exchange,
   mortgage, pledge, transfer or otherwise acquire or dispose of, in one
   transaction or a series of transactions, to, from or with the Company or any
   of its Subsidiaries or any employee benefit plan maintained by the Company or
   any of its Subsidiaries or any trustee or fiduciary with respect to such plan
   acting in such capacity, any material trademark or material service mark,
   other than pursuant to a transaction set forth in Section 13(a), (6) receive,
   or any designee, agent or representative of such Acquiring Person or any
   Affiliate or Associate of such Acquiring Person shall receive, any
   compensation from the Company or any of its Subsidiaries other than
   compensation for full-time employment as a regular employee at rates in
   accordance with the Company's (or its Subsidiaries') past practices, or (7)
   receive the benefit, directly or indirectly (except proportionately as a
   holder of Company Common Stock or as required by law or governmental
   regulation), of any loans, advances, guarantees, pledges or other financial
   assistance or any tax credits or other tax advantage provided by the Company
   or any of its Subsidiaries or any employee benefit plan

                                      14
<PAGE>

   maintained by the Company or any of its Subsidiaries or any trustee or
   fiduciary with respect to such plan acting in such capacity; or

       (B)  any Person shall become an Acquiring Person, unless the event
   causing such Person to become an Acquiring Person is a transaction set forth
   in Section 13(a); or

       (C)  during such time as there is an Acquiring Person, there shall be any
   reclassification of securities (including any reverse stock split), or
   recapitalization of the Company, or any merger or consolidation of the
   Company with any of its Subsidiaries or any other transaction or series of
   transactions involving the Company or any of its Subsidiaries, other than a
   transaction or transactions to which the provisions of Section 13(a) apply
   (whether or not with or into or otherwise involving an Acquiring Person),
   which has the effect, directly or indirectly, of increasing by more than 1%
   the proportionate share of the outstanding shares of any class of equity
   securities of the Company or any of its Subsidiaries that is directly or
   indirectly beneficially owned by any Acquiring Person or any Associate or
   Affiliate of any Acquiring Person;

then, immediately upon the date of the occurrence of an event described in
Section 11(a)(iii)(A), (B) or (C) (a "Section 11(a)(iii) Event"), proper
provision shall be made so that each holder of a Right (except as provided below
and in Section 7(e)) shall thereafter have the right to receive, upon exercise
thereof at the then-current Purchase Price in accordance with the terms of this
Agreement, in lieu of the number of Units of Preferred Stock for which a Right
was exercisable immediately prior to the first occurrence of a Section
11(a)(iii) Event, such number of Units of Preferred Stock as shall equal the
result obtained by (x) multiplying the then-current Purchase Price by the then
number of Units of Preferred Stock for which a Right was exercisable immediately
prior to the first occurrence of a Section 11(a)(iii) Event (such product
thereafter being, for all purposes of this Agreement other than Section 13, the
"Purchase Price"), and (y) dividing that product by 50% of the then-current
market price (determined pursuant to Section 11(d)) per Unit of Preferred Stock
on the date of such first occurrence (such Units of Preferred Stock being the
"Adjustment Shares").

       (iv) In the event that the number of shares of Preferred Stock that are
authorized by the Company's Articles of Incorporation but not outstanding or
reserved for issuance for purposes other than upon exercise of the Rights is not
sufficient to permit the exercise in full of the Rights in accordance with the
foregoing subparagraph (iii) of this Section 11(a), the Company, by the vote of
a majority of the Company's Board of Directors, shall: (A) determine the excess
of (1) the value of the Adjustment Shares issuable upon the exercise of a Right
(the "Current Value") over (2) the Purchase Price (such excess being the
"Spread"), and (B) with respect to each Right, make adequate provision to
substitute for such Adjustment Shares, upon payment of the applicable Purchase
Price, (1) cash, (2) a reduction in the Purchase Price, (3) Company Common Stock
or other equity securities of the Company (including, without limitation,
shares, or units of shares, of preferred stock (such other shares being
"Preferred Stock Equivalents")), (4) debt securities of the Company, (5) other
assets or (6) any combination of the foregoing, having an aggregate value equal
to the Current Value, where such aggregate value has been determined by a
majority of the Company's Board of Directors, after receiving advice from a
nationally recognized investment banking firm; provided, however, that if the
Company shall not have made adequate provision to deliver value

                                      15
<PAGE>

pursuant to clause (B) above within thirty days following the later of (x) the
first occurrence of a Section 11(a)(iii) Event and (y) the date on which the
Company's right of redemption pursuant to Section 23(a) expires (the later of
(x) and (y) being referred to herein as the "Section 11(a)(iv) Trigger Date"),
then the Company shall be obligated to deliver, upon the surrender for exercise
of a Right and without requiring payment of the Purchase Price, Units of
Preferred Stock (to the extent available) and then, if necessary, cash, which
Units of Preferred Stock and/or cash shall have an aggregate value equal to the
Spread. To the extent that the Company determines that some action need be taken
pursuant to the first sentence of this Section 11(a)(iv), the Company shall
provide, subject to Section 7(e), that such action shall apply uniformly to all
outstanding Rights. For purposes of this Section 11(a)(iv), the value of a Unit
of Preferred Stock shall be the current market price (as determined pursuant to
Section 11(d)) per Unit of Preferred Stock on the Section 11(a)(iv) Trigger Date
and the value of any preferred stock equivalent shall be deemed to have the same
value as the Preferred Stock on such date.

       (b) In case the Company shall fix a record date for the issuance of
rights, options or warrants to all holders of Preferred Stock entitling them to
subscribe for or purchase (for a period expiring within forty-five calendar days
after such record date) shares of Preferred Stock (or shares having
substantially the same rights, privileges and preferences as shares of Preferred
Stock ("Equivalent Preferred Stock")) or securities convertible into Preferred
Stock or Equivalent Preferred Stock at a price per share of Preferred Stock or
per share of Equivalent Preferred Stock (or having a conversion price per share,
if a security convertible into Preferred Stock or Equivalent Preferred Stock)
less than the current market price (as determined pursuant to Section 11(d)) per
share of Preferred Stock on such record date, the Purchase Price to be in effect
after such record date shall be determined by multiplying the Purchase Price in
effect immediately prior to such record date by a fraction, the numerator of
which shall be the sum of the number of shares of Preferred Stock outstanding on
such record date plus the number of shares of Preferred Stock which the
aggregate offering price of the total number of shares of Preferred Stock and/or
Equivalent Preferred Stock so to be offered (and/or the aggregate initial
conversion price of the convertible securities so to be offered) would purchase
at such current market price, and the denominator of which shall be the number
of shares of Preferred Stock outstanding on such record date plus the number of
additional shares of Preferred Stock and/or Equivalent Preferred Stock to be
offered for subscription or purchase (or into which the convertible securities
so to be offered are initially convertible). In case such subscription price may
be paid by delivery of consideration part or all of which may be in a form other
than cash, the value of such consideration shall be as determined in good faith
by a majority of the Company's Board of Directors, whose determination shall be
described in a statement filed with the Rights Agent and shall be binding on the
Rights Agent and the holders of the Rights. Shares of Preferred Stock owned by
or held for the account of the Company or any Subsidiary shall not be deemed
outstanding for the purpose of any such computation. Such adjustment shall be
made successively whenever such a record date is fixed, and in the event that
such rights or warrants are not so issued, the Purchase Price shall be adjusted
to be the Purchase Price that would then be in effect if such record date had
not been fixed.

       (c) In case the Company shall fix a record date for a distribution to all
holders of shares of Preferred Stock (including any such distribution made in
connection with a consolidation or merger in which the Company is the continuing
corporation) of evidences of indebtedness, cash (other than a regular quarterly
cash dividend out of the earnings or retained

                                      16
<PAGE>

earnings of the Company), assets (other than a dividend payable in shares of
Preferred Stock, but including any dividend payable in stock other than
Preferred Stock) or subscription rights or warrants (excluding those referred to
in Section 11(b)), the Purchase Price to be in effect after such record date
shall be determined by multiplying the Purchase Price in effect immediately
prior to such record date by a fraction, the numerator of which shall be the
current market price (as determined pursuant to Section 11(d)) per share of
Preferred Stock on such record date less the fair market value (as determined in
good faith by a majority of the Company's Board of Directors, whose
determination shall be described in a statement filed with the Rights Agent and
shall be binding on the Rights Agent and the holder of the Rights) of the cash,
assets or evidences of indebtedness so to be distributed or of such subscription
rights or warrants distributable in respect of a share of Preferred Stock and
the denominator of which shall be such current market price (as determined
pursuant to Section 11(d)) per share of Preferred Stock. Such adjustments shall
be made successively whenever such a record date is fixed, and in the event that
such distribution is not so made, the Purchase Price shall be adjusted to be the
Purchase Price that would have been in effect if such record date had not been
fixed.

       (d) (i)  For the purpose of any computation hereunder, the "current
market price" per share of Company Common Stock or Common Stock on any date
shall be deemed to be the average of the daily closing prices per share of such
shares for the ten consecutive Trading Days immediately prior to, but not
including, such date; provided, however, if prior to the expiration of such
requisite ten Trading Day period the issuer announces either (A) a dividend or
distribution on such shares payable in such shares or securities convertible
into such shares (other than the Rights) or (B) any subdivision, combination or
reclassification of such shares, then, following the ex-dividend date for such
dividend or the record date for such subdivision, as the case may be, the
"current market price" shall be properly adjusted to take into account such
event. The closing price for each day shall be, if the shares are listed and
admitted to trading on a national securities exchange, as reported in the
principal consolidated transaction reporting system with respect to securities
listed on the principal national securities exchange on which such shares are
listed or admitted to trading or, if such shares are not listed or admitted to
trading on any national securities exchange, the last quoted price or, if not so
quoted, the average of the high bid and low asked prices in the over-the-counter
market, as reported by The Nasdaq Stock Market Consolidated Quotations Service
or such other system then in use, or, if on any such date such shares are not
quoted by any such organization, the average of the closing bid and asked prices
as furnished by a professional market maker making a market in such shares
selected by a majority of the Company's Board of Directors. If, on any such date
no market maker is making a market in such shares, the fair value of such shares
on such date as determined in good faith by a majority of the Company's Board of
Directors shall be used. If such shares are not publicly held or not so listed
or traded, "current market price" per share shall mean the fair value per share
as determined in good faith by a majority of the Company's Board of Directors,
whose determination shall be described in a statement filed with the Rights
Agent and shall be conclusive for all purposes. The term "Trading Day" shall
mean, if such shares are listed or admitted to trading on any national
securities exchange, a day on which the principal national securities exchange
on which such shares are listed or admitted to trading is open for the
transaction of business or, if such shares are not so listed or admitted, a
Business Day.

           (ii) For the purpose of any computation hereunder, the "current
market price" per share of Preferred Stock shall be determined in the same
manner as set forth above for

                                      17
<PAGE>

Company Common Stock in clause (i) of this Section 11(d) (other than the fourth
sentence thereof). If the current market price per share of Preferred Stock
cannot be determined in the manner provided above or if the Preferred Stock is
not publicly held or listed or traded in a manner described in clause (i) of
this Section 11(d), the "current market price" per share of Preferred Stock
shall be conclusively deemed to be an amount equal to 100 (as such amount may be
appropriately adjusted for such events as stock splits, stock dividends and
recapitalizations with respect to Company Common Stock occurring after the date
of this Agreement) multiplied by the current market price per share of Company
Common Stock. If neither Company Common Stock nor Preferred Stock is publicly
held or so listed or traded, "current market price" per share of the Preferred
Stock shall mean the fair value per share as determined in good faith by a
majority of the Company's Board of Directors, whose determination shall be
described in a statement filed with the Rights Agent and shall be binding on the
Rights Agent and the holders of the Rights. For all purposes of this Agreement,
the "current market price" of a Unit of Preferred Stock shall be equal to the
"current market price" of one share of Preferred Stock divided by 100.

       (e) Anything herein to the contrary notwithstanding, no adjustment in the
Purchase Price shall be required unless such adjustment would require an
increase or decrease of at least 1% in the Purchase Price; provided, however,
that any adjustments which by reason of this Section 11(e) are not required to
be made shall be carried forward and taken into account in any subsequent
adjustment. All calculations under this Section 11 shall be made to the nearest
cent or to the nearest one-hundredth of a share of Company Common Stock or
Common Stock or other share or ten-thousandth of a share of Preferred Stock, as
the case may be. Notwithstanding the first sentence of this Section 11(e), any
adjustment required by this Section 11 shall be made no later than the earlier
of (i) three years from the date of the transaction that mandates such
adjustment and (ii) the Expiration Date.

       (f) If, as a result of an adjustment made pursuant to Section 11(a)(iii)
or 13(a), the holder of any Right thereafter exercised shall become entitled to
receive any shares of capital stock other than Preferred Stock, thereafter the
number of such other shares so receivable upon exercise of any Right and the
Purchase Price thereof shall be subject to adjustment from time to time in a
manner and on terms as nearly equivalent as practicable to the provisions with
respect to the Preferred Stock contained in Sections 11(a), (b), (c), (d), (e),
(g), (h), (i), (j), (k), (l) and (m), and the provisions of Sections 7, 9, 10,
13 and 14 with respect to the Preferred Stock shall apply on like terms to any
such other shares.

       (g) All Rights originally issued by the Company subsequent to any
adjustment made to the Purchase Price hereunder shall evidence the right to
purchase, at the adjusted Purchase Price, the number of Units of Preferred Stock
(or other securities or amount of cash or combination thereof) that may be
acquired from time to time hereunder upon exercise of the Rights, all subject to
further adjustment as provided herein.

       (h) Unless the Company shall have exercised its election as provided in
Section 11(i), upon each adjustment of the Purchase Price as a result of the
calculations made in Sections 11(b) and (c), each Right outstanding immediately
prior to the making of such adjustment shall thereafter evidence the right to
purchase, at the adjusted Purchase Price, that number of Units of Preferred
Stock (calculated to the nearest one ten-thousandth of a Unit)

                                      18
<PAGE>

obtained by (i) multiplying (x) the number of Units of Preferred Stock covered
by a Right immediately prior to this adjustment by (y) the Purchase Price in
effect immediately prior to such adjustment of the Purchase Price and (ii)
dividing the product so obtained by the Purchase Price in effect immediately
after such adjustment of the Purchase Price.

       (i) The Company may elect on or after the date of any adjustment of the
Purchase Price to adjust the number of Rights, in lieu of any adjustment in the
number of Units of Preferred Stock that may be acquired upon the exercise of a
Right. Each of the Rights outstanding after the adjustment in the number of
Rights shall be exercisable for the number of Units of Preferred Stock for which
a Right was exercisable immediately prior to such adjustment. Each Right held of
record prior to such adjustment of the number of Rights shall become that number
of Rights (calculated to the nearest ten-thousandth) obtained by dividing the
Purchase Price in effect immediately prior to adjustment of the Purchase Price
by the Purchase Price in effect immediately after adjustment of the Purchase
Price. The Company shall make a public announcement (with prompt written notice
thereof to the Rights Agent) of its election to adjust the number of Rights,
indicating the record date for the adjustment, and, if known at the time, the
amount of the adjustment to be made. This record date may be the date on which
the Purchase Price is adjusted or any day thereafter, but, if the Rights
Certificates have been issued, shall be at least ten days later than the date of
such public announcement. If Rights Certificates have been issued, upon each
adjustment of the number of Rights pursuant to this Section 11(i), the Company
shall, as promptly as practicable, cause to be distributed to holders of record
of Rights Certificates on such record date Rights Certificates evidencing,
subject to Section 14, the additional Rights to which such holders shall be
entitled as a result of such adjustment, or, at the option of the Company, shall
cause to be distributed to such holders of record in substitution and
replacement for the Rights Certificates held by such holders prior to the date
of adjustment, and upon surrender thereof, if required by the Company, new
Rights Certificates evidencing all the Rights to which such holders shall be
entitled after such adjustment. Rights Certificates to be so distributed shall
be issued, executed and countersigned in the manner provided for herein (and may
bear, at the option of the Company, the adjusted Purchase Price) and shall be
registered in the names of the holders of record of Rights Certificates on the
record date specified in the public announcement.

       (j) Irrespective of any adjustment or change in the Purchase Price or the
number of Units of Preferred Stock issuable upon the exercise of the Rights, the
Rights Certificates theretofore and thereafter issued may continue to express
the Purchase Price per Unit and the number of Units of Preferred Stock that were
expressed in the Initial Rights Certificates issued hereunder without prejudice
to any such adjustment or change.

       (k) Before taking any action that would cause an adjustment reducing the
Purchase Price below the then-par value of the number of Units of Preferred
Stock issuable upon exercise of the Rights, the Company shall take any corporate
action that may, in the opinion of its counsel, be necessary in order that the
Company may validly and legally issue such fully paid and non-assessable number
of Units of Preferred Stock at such adjusted Purchase Price.

       (l) In any case in which this Section 11 shall require that an adjustment
in the Purchase Price be made effective as of a record date for a specified
event, the Company may elect to defer (and shall promptly notify the Rights
Agent of any such election) until the

                                      19
<PAGE>

occurrence of such event the issuance to the holder of any Right exercised after
such record date of that number of Units of Preferred Stock and shares of other
capital stock or securities of the Company, if any, issuable upon such exercise
over and above the number of Units of Preferred Stock and shares of other
capital stock or securities of the Company, if any, issuable upon such exercise
on the basis of the Purchase Price in effect prior to such adjustment; provided,
however, that the Company shall deliver to such holder a due bill or other
appropriate instrument evidencing such holder's right to receive such additional
shares (fractional or otherwise) or securities upon the occurrence of the event
requiring such adjustment.

       (m) Anything in this Section 11 to the contrary notwithstanding, the
Company shall be entitled to make such reductions in the Purchase Price, in
addition to those adjustments expressly required by this Section 11, as and to
the extent that in their good faith judgment a majority of the Company's Board
of Directors shall determine to be advisable in order that any (i) consolidation
or subdivision of the Preferred Stock, (ii) issuance wholly for cash of any
shares of Preferred Stock at less than the current market price, (iii) issuance
wholly for cash or shares of Preferred Stock or securities that by their terms
are convertible into or exchangeable for shares of Preferred Stock, (iv) stock
dividends or (v) issuance of rights, options or warrants referred to in this
Section 11, hereafter made by the Company to holders of its Preferred Stock,
shall not be taxable to such holders or shall reduce the taxes payable by such
holders.

       (n) The Company shall not, at any time after the Distribution Date, (i)
consolidate with any other Person (other than a Subsidiary of the Company in a
transaction that complies with Section 11(o)), (ii) merge with or into any other
Person (other than a Subsidiary of the Company in a transaction that complies
with Section 11(o)), or (iii) sell or transfer (or permit any Subsidiary to sell
or transfer), in one transaction, or a series of transactions, assets or earning
power aggregating more than 50% of the assets or earning power of the Company
and its Subsidiaries (taken as a whole) to any other Person or Persons (other
than the Company and/or any of its Subsidiaries in one or more transactions each
of which complies with Section 11(o) and other than in connection with any
public offering of the capital stock of any of the Company's subsidiaries or any
spin-off or other similar transaction), if (x) at the time of or immediately
after such consolidation, merger or sale there are any rights, warrants or other
instruments or securities outstanding or agreements in effect that would
substantially diminish or otherwise eliminate the benefits intended to be
afforded by the Rights or (y) prior to, simultaneously with or immediately after
such consolidation, merger or sale, the Person that constitutes, or would
constitute, the "Principal Party" for purposes of Section 13(a) shall have
distributed or otherwise transferred to its shareholders or other Persons
holding an equity interest in such Person Rights previously owned by such Person
or any of its Affiliates and Associates; provided, however, that this Section
11(n) shall not affect the ability of any Subsidiary of the Company to
consolidate with, merge with or into, or sell or transfer assets or earning
power to, any other Subsidiary of the Company.

       (o) After the Distribution Date, the Company shall not, except as
permitted by Section 23 or Section 26, take (or permit any Subsidiary to take)
any action if at the time such action is taken it is reasonably foreseeable that
such action will diminish substantially or otherwise eliminate the benefits
intended to be afforded by the Rights.

                                      20
<PAGE>

       (p) Anything in this Agreement to the contrary notwithstanding, in the
event that the Company shall at any time after the Rights Dividend Declaration
Date and prior to the Distribution Date (i) declare a dividend on the
outstanding shares of Company Common Stock payable in shares of Company Common
Stock, (ii) subdivide the outstanding shares of Company Common Stock, (iii)
combine the outstanding shares of Company Common Stock into a smaller number of
shares, or (iv) issue any shares of its capital stock in a reclassification of
Company Common Stock (including any such reclassification in connection with a
consolidation or merger in which the Company is the continuing or surviving
corporation), the number of Rights associated with each share of Company Common
Stock then outstanding, or issued or delivered thereafter but prior to the
Distribution Date, shall be proportionately adjusted so that the number of
Rights thereafter associated with each share of Company Common Stock following
any such event shall equal the result obtained by multiplying the number of
Rights associated with each share of Company Common Stock immediately prior to
such event by a fraction the numerator of which shall be the total number of
shares of Company Common Stock outstanding immediately prior to the occurrence
of the event and the denominator of which shall be the total number of shares of
Company Common Stock outstanding immediately following the occurrence of such
event.

       SECTION 12. Certificate of Adjusted Purchase Price or Number of Shares.
Whenever an adjustment is made as provided in Section 11 or Section 13, the
Company shall (a) promptly prepare a certificate setting forth such adjustment
and a brief statement of the facts and computations accounting for such
adjustment, (b) promptly file with the Rights Agent, and with each transfer
agent for the Preferred Stock and the Company Common Stock, a copy of such
certificate, and (c) mail a brief summary thereof to each holder of a Rights
Certificate (or, if prior to the Distribution Date, to each holder of a
certificate evidencing shares of Company Common Stock) in accordance with
Section 25. The Rights Agent shall be fully protected in relying on any such
certificate and on any adjustment therein contained, and shall have no duty with
respect to and shall not be deemed to have knowledge of any such adjustment
unless and until it shall have received such certificate.

       SECTION 13. Consolidation, Merger or Sale or Transfer of Assets or
Earning Power. (a) In the event that, following the Stock Acquisition Date,
directly or indirectly, either (x) the Company shall consolidate with, or merge
with and into, any other Person (other than a Subsidiary of the Company in a
transaction that complies with Section 11(o)), and the Company shall not be the
continuing or surviving corporation of such consolidation or merger, (y) any
Person (other than a Subsidiary of the Company in a transaction that complies
with Section 11(o)) shall consolidate with, or merge with or into, the Company,
and the Company shall be the continuing or surviving corporation of such
consolidation or merger and, in connection with such consolidation or merger,
all or part of the outstanding shares of Company Common Stock shall be converted
into or exchanged for stock or other securities of any other Person or cash or
any other property, or (z) the Company shall sell or otherwise transfer (or one
or more of its Subsidiaries shall sell or otherwise transfer) to any Person or
Persons (other than the Company or any of its Subsidiaries in one or more
transactions each of which complies with Section 11(o) and other than in
connection with any public offering of the capital stock of any of the Company's
subsidiaries or any spin-off or other similar transaction), in one or more
transactions, assets or earning power aggregating more than 50% of the assets or
earning power of the Company and its Subsidiaries, taken as a whole (any such
event described in clause (x),

                                      21
<PAGE>

(y) or (z) being a "Section 13 Event"), then, and in each such case, proper
provision shall be made so that: (i) each holder of a Right, except as provided
in Section 7(e), shall thereafter have the right to receive, upon the exercise
thereof at the then-current Purchase Price, such number of validly authorized
and issued, fully paid and non-assessable shares of Common Stock of the
Principal Party, which shares shall not be subject to any liens, encumbrances,
rights of first refusal, transfer restrictions or other adverse claims, as shall
be equal to the result obtained by (1) multiplying the then-current Purchase
Price by the number of Units of Preferred Stock for which a Right is exercisable
immediately prior to the first occurrence of a Section 13 Event (or, if a
Section 11(a)(iii) Event has occurred prior to the first occurrence of a Section
13 Event, multiplying the number of such Units for which a Right would be
exercisable hereunder but for the occurrence of such Section 11(a)(iii) Event by
the Purchase Price that would be in effect hereunder but for such first
occurrence) and (2) dividing that product (which, following the first occurrence
of a Section 13 Event, shall be the "Purchase Price" for all purposes of this
Agreement) by 50% of the current market price (determined pursuant to Section
11(d)) per share of the Common Stock of such Principal Party on the date of
consummation of such Section 13 Event; (ii) such Principal Party shall
thereafter be liable for, and shall assume, by virtue of such Section 13 Event,
all the obligations and duties of the Company pursuant to this Agreement; (iii)
the term "Company" shall, for all purposes of this Agreement, thereafter be
deemed to refer to such Principal Party, it being specifically intended that the
provisions of Section 11 shall apply only to such Principal Party following the
first occurrence of a Section 13 Event; (iv) such Principal Party shall take
such steps (including, but not limited to, the reservation of a sufficient
number of shares of its Common Stock) in connection with the consummation of any
such transaction as may be necessary to ensure that the provisions of this
Agreement shall thereafter be applicable to its shares of Common Stock
thereafter deliverable upon the exercise of the Rights; and (v) the provisions
of Section 11(a)(iii) shall be of no further effect following the first
occurrence of any Section 13 Event.

       (b)  "Principal Party" shall mean:

       (i)  in the case of any transaction described in clause (x) or (y) of the
   first sentence of Section 13(a), (A) the Person that is the issuer of any
   securities into which shares of Company Common Stock are converted in such
   merger or consolidation, or, if there is more than one such issuer, the
   issuer of Common Stock that has the highest aggregate current market price
   (determined pursuant to Section 11(d)) and (B) if no securities are so
   issued, the Person that is the other party to such merger or consolidation,
   or, if there is more than one such Person, the Person the Common Stock of
   which has the highest aggregate current market price (determined pursuant to
   Section 11(d)); and

       (ii) in the case of any transaction described in clause (z) of the first
   sentence of Section 13(a), the Person that is the party receiving the largest
   portion of the assets or earning power transferred pursuant to such
   transaction or transactions, or, if each Person that is a party to such
   transaction or transactions receives the same portion of the assets or
   earning power transferred pursuant to such transaction or transactions or if
   the Person receiving the largest portion of the assets or earning power
   cannot be determined, whichever Person the Common Stock of which has the
   highest aggregate current market price (determined pursuant to Section
   11(d)); provided, however, that in any such case, (1) if the Common Stock of
   such Person is not at such time and has not been

                                      22
<PAGE>

   continuously over the preceding twelve-month period registered under Section
   12 of the Exchange Act ("Registered Common Stock"), or such Person is not a
   corporation, and such Person is a direct or indirect Subsidiary of another
   Person that has Registered Common Stock outstanding, "Principal Party" shall
   refer to such other Person; (2) if the Common Stock of such Person is not
   Registered Common Stock or such Person is not a corporation, and such Person
   is a direct or indirect Subsidiary of another Person but is not a direct or
   indirect Subsidiary of another Person that has Registered Common Stock
   outstanding, "Principal Party" shall refer to the ultimate parent entity of
   such first-mentioned Person; (3) if the Common Stock of such Person is not
   Registered Common Stock or such Person is not a corporation, and such Person
   is directly or indirectly controlled by more than one Person, and one or more
   of such other Persons has Registered Common Stock outstanding, "Principal
   Party" shall refer to whichever of such other Persons is the issuer of the
   Registered Common Stock having the highest aggregate current market price
   (determined pursuant to Section 11(d)); and (4) if the Common Stock of such
   Person is not Registered Common Stock or such Person is not a corporation,
   and such Person is directly or indirectly controlled by more than one Person,
   and none of such other Persons have Registered Common Stock outstanding,
   "Principal Party" shall refer to whichever ultimate parent entity is the
   corporation having the greatest shareholders' equity or, if no such ultimate
   parent entity is a corporation, shall refer to whichever ultimate parent
   entity is the entity having the greatest net assets.

       (c)  The Company shall not consummate any such consolidation, merger,
sale or transfer unless the Principal Party shall have a sufficient number of
authorized shares of its Common Stock that have not been issued or reserved for
issuance to permit the exercise in full of the Rights in accordance with this
Section 13, and unless prior thereto the Company and such Principal Party shall
have executed and delivered to the Rights Agent a supplemental agreement
providing for the terms set forth in paragraphs (a) and (b) of this Section 13
and further providing that the Principal Party will:

       (i)  (A) file on an appropriate form, as soon as practicable following
   the execution of such agreement, a registration statement under the
   Securities Act with respect to the Common Stock that may be acquired upon
   exercise of the Rights, (B) cause such registration statement to remain
   effective (and to include a prospectus complying with the requirements of the
   Securities Act) until the Expiration Date, and (C) as soon as practicable
   following the execution of such agreement take such action as may be required
   to ensure that any acquisition of such Common Stock upon the exercise of the
   Rights complies with any applicable state securities or "blue sky" laws; and

       (ii) deliver to holders of the Rights historical financial statements for
   the Principal Party and each of its Affiliates that comply in all respects
   with the requirements for registration on Form 10 under the Exchange Act.

       (d)  In case the Principal Party that is to be a party to a transaction
referred to in this Section 13 has a provision in any of its authorized
securities or in its Articles of Incorporation or By-laws or other instrument
governing its corporate affairs, which provision would have the effect of (i)
causing such Principal Party to issue, in connection with, or as a consequence
of, the consummation of a transaction referred to in this Section 13, shares of

                                      23
<PAGE>

Common Stock of such Principal Party at less than the then-current market price
per share (determined pursuant to Section 11(d)) or securities exercisable for,
or convertible into, Common Stock of such Principal Party at less than such
then-current market price (other than to holders of Rights pursuant to this
Section 13) or (ii) providing for any special payment, tax or similar provisions
in connection with the issuance of the Common Stock of such Principal Party
pursuant to the provisions of this Section 13, then, in such event, the Company
shall not consummate any such transaction unless prior thereto the Company and
such Principal Party shall have executed and delivered to the Rights Agent a
supplemental agreement providing that the provision in question of such
Principal Party shall have been cancelled, waived or amended, or that the
authorized securities shall be redeemed, so that the applicable provision will
have no effect in connection with, or as a consequence of, the consummation of
the proposed transaction.

       (e) The provisions of this Section 13 shall similarly apply to successive
mergers or consolidations or sales or other transfers. In the event that a
Section 13 Event shall occur at any time after the occurrence of a Section
11(a)(iii) Event, the Rights that have not theretofore been exercised shall
thereafter become exercisable in the manner described in Section 13(a).

       SECTION 14. Fractional Rights and Fractional Shares. (a) The Company
shall not be required to issue fractions of Rights or to distribute Rights
Certificates that evidence fractional Rights. In lieu of such fractional Rights,
there shall be paid to the Persons to which such fractional Rights would
otherwise be issuable, an amount in cash equal to such fraction of the market
value of a whole Right. For purposes of this Section 14(a), the market value of
a whole Right shall be the closing price of the Rights for the Trading Day
immediately prior to the date on which such fractional Rights would have been
otherwise issuable. The closing price of the Rights for any day shall be, if the
Rights are listed or admitted to trading on a national securities exchange, as
reported in the principal consolidated transaction reporting system with respect
to securities listed on the principal national securities exchange on which the
Rights are listed or admitted to trading or, if the Rights are not listed or
admitted to trading on any national securities exchange, the last quoted price
or, if not so quoted, the average of the high bid and low asked prices in the
over-the-counter market, as reported by The Nasdaq Stock Market Consolidated
Quotations Service or such other system then in use or, if on any such date the
Rights are not quoted by any such organization, the average of the closing bid
and asked prices as furnished by a professional market maker making a market in
the Rights selected by a majority of the Company's Board of Directors. If on any
such date no such market maker is making a market in the Rights, the fair value
of the Rights on such date as determined in good faith by a majority of the
Company's Board of Directors shall be used and such determination shall be
described in a statement filed with the Rights Agent and shall be conclusive for
all purposes.

       (b) The Company shall not be required to issue fractions of shares of
Preferred Stock (other than fractions that are integral multiples of one one-
hundredth of a share of Preferred Stock) upon exercise of the Rights or to
distribute certificates that evidence such fractional shares of Preferred Stock
(other than fractions that are integral multiples of one one-hundredth of a
share of Preferred Stock). In lieu of such fractional shares of Preferred Stock
that are not integral multiples of one one-hundredth of a share, the Company may
pay to the registered holders of Rights Certificates at the time such Rights are
exercised as herein provided

                                      24
<PAGE>

an amount in cash equal to the same fraction of the then-current market price of
a share of Preferred Stock on the day of exercise, determined in accordance with
Section 11(d).

       (c) The holder of a Right by the acceptance of such Right expressly
waives his right to receive any fractional Rights or any fractional shares upon
exercise of a Right, except as permitted by this Section 14.

       (d) Whenever a payment for fractional Rights or fractional shares is to
be made by the Rights Agent, the Company shall (i) promptly prepare and deliver
to the Rights Agent a certificate setting forth the prices and/or formulas
utilized in calculating such payments, and (ii) provide sufficient monies to the
Rights Agent in the form of fully collected funds to make such payments. The
Rights Agent shall be fully protected in relying upon such a certificate and
shall have no duty with respect to, and shall not be deemed to have knowledge of
any payment for fractional Rights or fractional shares under any Section of this
Agreement relating to the payment of fractional Rights or fractional shares
unless and until the Rights Agent shall have received such a certificate and
sufficient monies.

       SECTION 15. Rights of Action. All rights of action in respect of this
Agreement, other than rights of action vested in the Rights Agent pursuant to
Section 18 and Section 20 hereof, are vested in the respective registered
holders of the Rights Certificates (and, prior to the Distribution Date, the
registered holders of certificates evidencing shares of Company Common Stock);
and any registered holder of a Rights Certificate (or, prior to the Distribution
Date, of a certificate evidencing shares of Company Common Stock), without the
consent of the Rights Agent or of the holder of any other Rights Certificate
(or, prior to the Distribution Date, of a certificate evidencing shares of
Company Common Stock), may, on such registered holder's own behalf and for such
registered holder's own benefit, enforce, and may institute and maintain any
suit, action or proceeding against the Company or any other Person to enforce,
or otherwise act in respect of, such registered holder's right to exercise the
Rights evidenced by such Rights Certificate in the manner provided in such
Rights Certificate and in this Agreement. Without limiting the foregoing or any
remedies available to the holders of Rights, it is specifically acknowledged
that the holders of Rights would not have an adequate remedy at law for any
breach of this Agreement and shall be entitled to specific performance of the
obligations hereunder and injunctive relief against actual or threatened
violations of the obligations hereunder of any Person subject to this Agreement.

       SECTION 16. Agreement of Rights Holders. Every holder of a Right by
accepting the same consents and agrees with the Company and the Rights Agent and
with every other holder of a Right that:

       (a) prior to the Distribution Date, the Rights will be transferable only
   in connection with the transfer of Company Common Stock;

       (b) after the Distribution Date, the Rights Certificates are transferable
   only on the registry books of the Rights Agent if surrendered at the office
   of the Rights Agent designated for such purposes, duly endorsed or
   accompanied by a proper instrument of transfer and with the appropriate forms
   and certificates duly executed;

                                      25
<PAGE>

          (c) subject to Section 6(a) and Section 7(f), the Company and
     the Rights Agent may deem and treat the Person in whose name a Rights
     Certificate (or, prior to the Distribution Date, the associated Company
     Common Stock certificate) is registered as the absolute owner thereof
     and of the Rights evidenced thereby (notwithstanding any notations of
     ownership or writing on the Rights Certificates or the associated
     Company Common Stock certificate made by anyone other than the Company
     or the Rights Agent) for all purposes whatsoever, and neither the
     Company nor the Rights Agent, subject to the last sentence of Section
     7(e), shall be affected by any notice to the contrary; and

          (d) notwithstanding anything in this Agreement to the
     contrary, neither the Company nor the Rights Agent shall have any
     liability to any holder of a Right or any other Person as a result of
     its inability to perform any of its obligations under this Agreement by
     reason of any preliminary or permanent injunction or other order,
     decree, judgment or ruling (whether interlocutory or final) issued by a
     court of competent jurisdiction or by a governmental, regulatory or
     administrative agency or commission, or any statute, rule, regulation
     or executive order promulgated or enacted by any governmental
     authority, prohibiting or otherwise restraining performance of such
     obligation; provided, however, the Company must use its best efforts to
     have any such order, decree, judgment or ruling lifted or otherwise
     overturned as promptly as practicable.

          SECTION 17. Rights Certificate Holder Not Deemed a Shareholder. No
holder, as such, of any Rights Certificate shall be entitled to vote, receive
dividends or be deemed for any purpose the holder of the number of shares of
Preferred Stock or any other securities of the Company that may at any time be
issuable on the exercise of the Rights evidenced thereby, nor shall anything
contained herein or in any Rights Certificate be construed to confer upon the
holder of any Rights Certificate, as such, any of the rights of a shareholder of
the Company or any right to vote for the election of directors or upon any
matter submitted to shareholders at any meeting thereof, or to give or withhold
consent to any corporate action, or, except as provided in Section 24, to
receive notice of meetings or other actions affecting shareholders, or to
receive dividends or subscription rights, or otherwise.

          SECTION 18. Concerning the Rights Agent. (a) The Company agrees to pay
to the Rights Agent reasonable compensation for all services rendered by it
hereunder and, from time to time, on demand of the Rights Agent, its reasonable
expenses, including reasonable fees and disbursements of its counsel, incurred
in connection with the preparation, delivery, execution, administration and
amendment of this Agreement and the exercise and performance of its duties
hereunder. The Company shall indemnify the Rights Agent for, and hold it
harmless against, any loss, liability, damage, judgment, fine, penalty, claim,
demand, settlement, cost or expense, incurred without gross negligence, bad
faith or willful misconduct (each as finally determined by a court of competent
jurisdiction) on the part of the Rights Agent, for any action taken, suffered or
omitted by the Rights Agent in connection with the acceptance and administration
of this Agreement or the exercise and performance of its duties hereunder,
including, without limitation, the costs and expenses of defending against any
claim of liability hereunder. The indemnity provided herein shall survive the
termination of this Agreement, the termination and the expiration of the Rights,
and the resignation or removal of the Rights Agent. The costs and expenses
incurred in enforcing this right of indemnification shall be paid by the
Company.

                                       26
<PAGE>

     (b)  The Rights Agent shall be protected and shall incur no liability for
or in respect of any action taken, suffered or omitted by it in connection with
the acceptance and administration of this Agreement in reliance upon any Rights
Certificate or certificate or depositary receipt for Preferred Stock or for
other securities of the Company, instrument of assignment or transfer, power of
attorney, endorsement, affidavit, letter, notice, direction, consent,
certificate, statement or other paper or document believed by it to be genuine
and to have been signed, executed and, where necessary, verified or acknowledged
by the proper Person or Persons. The Rights Agent shall not be deemed to have
any duty or notice unless and until the Company has provided the Rights Agent
with written notice.

     SECTION 19. Merger or Consolidation or Change of Name of Rights Agent.
(a) Any Person into which the Rights Agent or any successor Rights Agent may be
merged or with which it may be consolidated, or any Person resulting from any
merger or consolidation to which the Rights Agent or any successor Rights Agent
shall be a party, or any Person succeeding to the corporate trust or shareholder
services business of the Rights Agent or any successor Rights Agent, shall be
the successor to the Rights Agent under this Agreement without the execution or
filing of any document or any further act on the part of any of the parties
hereto; provided that such Person would be eligible for appointment as a
successor Rights Agent under the provisions of Section 21. In case at the time
such successor Rights Agent shall succeed to the agency created by this
Agreement, any of the Rights Certificates shall have been countersigned but not
delivered, any such successor Rights Agent may adopt the countersignature of a
predecessor Rights Agent and deliver such Rights Certificates so countersigned;
and in case at that time any of the Rights Certificates shall not have been
countersigned, any successor Rights Agent may countersign such Rights
Certificates either in the name of the predecessor or in the name of the
successor Rights Agent; and in all such cases such Rights Certificates shall
have the full force provided in the Rights Certificates and in this Agreement.

     (b)  In case at any time the name of the Rights Agent shall be changed and
at such time any of the Rights Certificates shall have been countersigned but
not delivered, the Rights Agent may adopt the countersignature under its prior
name and deliver Rights Certificates so countersigned; and in case at that time
any of the Rights Certificates shall not have been countersigned, the Rights
Agent may countersign such Rights Certificates either in its prior name or in
its changed name; and in all such cases such Rights Certificates shall have the
full force provided in the Rights Certificates and in this Agreement.

       SECTION 20. Duties of Rights Agent. The Rights Agent only
undertakes the duties and obligations expressly imposed by this Agreement (and
no implied duties or obligations) upon the following terms and conditions, by
all of which the Company and the holders of Rights Certificates, by their
acceptance thereof, shall be bound:

     (a)  The Rights Agent may consult with legal counsel (who may be legal
   counsel for the Company), and the advice or opinion of such counsel shall be
   full and complete authorization and protection to the Rights Agent, and the
   Rights Agent shall incur no liability for or in respect of any action taken,
   suffered or omitted by it in good faith and in accordance with such advice or
   opinion.

                                       27
<PAGE>

       (b) Whenever in the performance of its duties under this Agreement the
   Rights Agent shall deem it necessary or desirable that any fact or matter
   (including, without limitation, the identity of any Acquiring Person and the
   determination of "current market price") be proved or established by the
   Company prior to taking, suffering or omitting any action hereunder, such
   fact or matter (unless other evidence in respect thereof be specified herein)
   may be deemed to be conclusively proved and established by a certificate
   signed by the Chairman of the Board, the President, any Vice President, the
   Treasurer, any Assistant Treasurer, the Secretary or any Assistant Secretary
   of the Company and delivered to the Rights Agent and such certificate shall
   be full authorization and protection to the Rights Agent, and the Rights
   Agent shall incur no liability for or in respect of any action taken,
   suffered or omitted by it under the provisions of this Agreement in reliance
   upon such certificate.

       (c) The Rights Agent shall be liable hereunder only for its own gross
negligence, bad faith or willful misconduct (each as finally determined by a
court of competent jurisdiction). Anything in this Agreement to the contrary
notwithstanding, in no event shall the Rights Agent be liable for special,
indirect, incidental or consequential loss or damage of any kind whatsoever
(including, without limitation, loss profits), even if the Rights Agent has been
advised of the possibility of such loss or damage.

       (d) The Rights Agent shall not be liable for or by reason of
   any of the statements of fact or recitals contained in this Agreement
   or in the Rights Certificates or be required to verify the same (except
   as to its countersignature on such Rights Certificates), but all such
   statements and recitals are and shall be deemed to have been made by
   the Company only.

       (e) The Rights Agent shall not have any liability for or be under any
   responsibility for the validity of this Agreement or the execution and
   delivery hereof (except the due execution and delivery hereof by the Rights
   Agent) or for the validity or execution of any Rights Certificate (except its
   countersignature thereof); nor shall it be responsible for any breach by the
   Company of any covenant or failure by the Company to satisfy conditions
   contained in this Agreement or in any Rights Certificate; nor shall it be
   responsible for any adjustment required under the provisions of Section 11 or
   Section 13 or for the manner, method or amount of any such adjustment or the
   ascertaining of the existence of facts that would require any such adjustment
   (except with respect to the exercise of Rights evidenced by Rights
   Certificates after receipt by the Rights Agent of the certificate describing
   any such adjustment contemplated by Section 12); nor shall it by any act
   hereunder be deemed to make any representation or warranty as to the
   authorization or reservation of any shares of Preferred Stock or any other
   securities to be issued pursuant to this Agreement or any Rights Certificate
   or as to whether any shares of Preferred Stock or any other securities will,
   when so issued, be validly authorized and issued, fully paid and non-
   assessable.

       (f) The Company shall perform, execute, acknowledge and deliver or cause
   to be performed, executed, acknowledged and delivered all such further acts,
   instruments and assurances as may reasonably be required by the Rights Agent
   for the performance by the Rights Agent of its duties under this Agreement.

                                       28
<PAGE>

       (g) The Rights Agent is hereby authorized and directed to accept
   instructions with respect to the performance of its duties hereunder from the
   Chairman of the Board, the President, any Vice President, the Secretary, any
   Assistant Secretary, the Treasurer or any Assistant Treasurer of the Company,
   and to apply to such officers for advice or instructions in connection with
   its duties, and such instructions shall be full authorization and protection
   to the Rights Agent, and the Rights Agent shall incur no liability for or in
   respect of any action taken, suffered or omitted to be taken by it in good
   faith in accordance with the advice or instructions of any such officer. The
   Rights Agent shall be fully protected and authorized in relying upon the most
   recent instructions received by any such officer. Any application by the
   Rights Agent for written instructions from the Company may, at the option of
   the Rights Agent, set forth in writing any action proposed to be taken,
   suffered or omitted by the Rights Agent under this Rights Agreement and the
   date on and/or after which such action shall be taken, suffered or such
   omission shall be effective. The Rights Agent shall not be liable for any
   action taken or suffered by, or omission of, the Rights Agent in accordance
   with a proposal included in any such application on or after the date
   specified in such application (which date shall not be less than five
   Business Days after the date any such officer of the Company actually
   receives such application, unless any such officer shall have consented in
   writing to an earlier date) unless, prior to taking or suffering any such
   action (or the effective date in the case of an omission), the Rights Agent
   shall have received written instructions in response to such application
   specifying the action to be taken, suffered or omitted.

       (h) The Rights Agent and any shareholder, affiliate, director, officer or
   employee of the Rights Agent may buy, sell or deal in any of the Rights or
   other securities of the Company or become pecuniarily interested in any
   transaction in which the Company may be interested, or contract with or lend
   money to the Company or otherwise act as fully and freely as though it were
   not Rights Agent under this Agreement. Nothing herein shall preclude the
   Rights Agent from acting in any other capacity for the Company or for any
   other Person.

       (i) The Rights Agent may execute and exercise any of the rights or powers
   hereby vested in it or perform any duty hereunder either itself or by or
   through its attorneys or agents, and the Rights Agent shall not be answerable
   or accountable for any act, default, neglect, or misconduct of any such
   attorneys or agents or for any loss to the Company or any other Person
   resulting from any such act, default, neglect or misconduct, absent gross
   negligence, bad faith or willful misconduct (each as finally determined by a
   court of competent jurisdiction) in the selection and continued employment
   thereof.

       (j) No provision of this Agreement shall require the Rights Agent to
   expend or risk its own funds or otherwise incur any financial liability in
   the performance of any of its duties or in the exercise of its rights
   hereunder if the Rights Agent shall have reasonable grounds for believing
   that repayment of such funds or adequate indemnification against such risk or
   liability is not reasonably assured to it.

       (k) If, with respect to any Rights Certificate surrendered to the Rights
   Agent for exercise or transfer, the certificate attached to the form of
   assignment or form of election to purchase, as the case may be, has either
   not been properly completed, not

                                       29
<PAGE>

   signed or indicates an affirmative response to clause 1 and/or 2 thereof, the
   Rights Agent shall not take any further action with respect to such requested
   exercise or transfer without first consulting with the Company. If such
   certificate has been properly completed and signed and shows a negative
   response to clauses 1 and 2 of such certificate, unless previously instructed
   otherwise in writing by the Company, the Rights Agent may assume without
   further inquiry that the Rights Certificate is not owned by a Person
   described in Section 4(b) or Section 7(e) and shall not be charged with any
   knowledge to the contrary.

       SECTION 21. Change of Rights Agent. The Rights Agent or any successor
Rights Agent may resign and be discharged from its duties under this Agreement
upon thirty days' prior notice in writing mailed to the Company, and to each
transfer agent of the Preferred Stock and the Company Common Stock, by
registered or certified mail, and to the holders of the Rights Certificates (or
certificates for the Company Common Stock prior to the Distribution Date) by
first-class mail. The Company may remove the Rights Agent or any successor
Rights Agent upon thirty days' prior notice in writing, mailed to the Rights
Agent or successor Rights Agent, as the case may be, and to each transfer agent
of the Preferred Stock and the Company Common Stock, by registered or certified
mail, and to the holders of the Rights Certificates (or certificates for the
Company Common Stock prior to the Distribution Date) by first-class mail. If the
Rights Agent shall resign or be removed or shall otherwise become incapable of
acting, the Company shall appoint a successor to the Rights Agent. If the
Company shall fail to make such appointment within a period of thirty days after
giving notice of such removal or after it has been notified in writing of such
resignation or incapacity by the resigning or incapacitated Rights Agent or by
the holder of a Rights Certificate or, prior to the Distribution Date, the
holder of a certificate for the Company Common Stock (who shall, with such
notice, submit such holder's Rights Certificate or certificate for Company
Common Stock, as the case may be, for inspection by the Company), then any
registered holder of any Rights Certificate or, prior to the Distribution Date,
the holder of a certificate for the Company Common Stock may apply to any court
of competent jurisdiction for the appointment of a new Rights Agent. Any
successor Rights Agent, whether appointed by the Company or by such a court,
shall be (a) a Person organized and doing business under the laws of the United
States or any state of the United States in good standing, shall be authorized
to do business in the State of California, shall be authorized under such laws
to conduct the shareholder services business, exercise corporate trust or stock
transfer powers, shall be subject to supervision or examination by federal or
state authorities and shall have at the time of its appointment as Rights Agent
a combined capital and surplus of at least $50,000,000 or (b) an Affiliate of a
Person described in clause (a). After appointment, the successor Rights Agent
shall be vested with the same powers, rights, duties and responsibilities as if
it had been originally named as Rights Agent without further act or deed; but
the predecessor Rights Agent shall deliver and transfer to the successor Rights
Agent any property at the time held by it hereunder, and execute and deliver any
further assurance, conveyance, act or deed necessary for the purpose. Not later
than the effective date of any such appointment, the Company shall file notice
thereof in writing with the predecessor Rights Agent and each transfer agent of
the Preferred Stock and the Company Common Stock, and mail a notice thereof in
writing to the registered holders of the Rights Certificates (or certificates
for the Company Common Stock prior to the Distribution Date). Failure to give
any notice provided for

                                       30
<PAGE>

in this Section 21, however, or any defect therein, shall not affect the
legality or validity of the resignation or removal of the Rights Agent or the
appointment of the successor Rights Agent.

       SECTION 22. Issuance of New Rights Certificates. Notwithstanding any of
the provisions of this Agreement or the Rights to the contrary, the Company may,
at its option, issue new Rights Certificates evidencing Rights in such form as
may be approved by a majority of the Company's Board of Directors to reflect any
adjustment or change made in accordance with the provisions of this Agreement in
the Purchase Price or the number or kind or class of shares or other securities
or property that may be acquired upon exercise of the Rights. In addition, in
connection with the issuance or sale of shares of Company Common Stock following
the Distribution Date and prior to the Expiration Date, the Company (a) shall,
with respect to shares of Company Common Stock so issued or sold pursuant to the
exercise of stock options or under any employee plan or arrangement, or upon the
exercise, conversion or exchange of securities hereinafter issued by the
Company, and (b) may, in any other case, if deemed necessary or appropriate by a
majority of the Company's Board of Directors, issue Rights Certificates
evidencing the appropriate number of Rights in connection with such issuance or
sale; provided, however, that (i) no such Rights Certificate shall be issued if,
and to the extent that, the Company shall be advised by counsel that such
issuance would create a significant risk of material adverse tax consequences to
the Company or the Person to whom such Rights Certificate would be issued and
(ii) no such Rights Certificate shall be issued if, and to the extent that,
appropriate adjustment shall otherwise have been made in lieu of the issuance
thereof.

       SECTION 23. Redemption and Termination. (a) Subject to Section
28, the Company may, at its option, by action of a majority of the Company's
Board of Directors, at any time prior to the earlier of (i) the Close of
Business on the tenth Day following the Stock Acquisition Date or (ii) the Final
Expiration Date, redeem all but not less than all of the then-outstanding Rights
at a redemption price of $.01 per Right, as such amount may be appropriately
adjusted to reflect any spin-off or other similar transaction or any stock
split, stock dividend or similar transaction occurring after the date hereof
(such redemption price being the "Redemption Price"), and the Company may, at
its option, by action of a majority of the Company's Board of Directors, pay the
Redemption Price either in shares of Company Common Stock (based on the current
market price, determined in accordance with Section 11(d), of the shares of
Company Common Stock at the time of redemption) or cash. Subject to the
foregoing, the redemption of the Rights may be made effective at such time, on
such basis and with such conditions as the Board of Directors in its sole
discretion may establish.

       (b) Immediately upon the action of a majority of the Company's
Board of Directors ordering the redemption of the Rights, evidence of which
shall be filed with the Rights Agent, and without any further action and without
any notice, the right to exercise the Rights will terminate and the only right
thereafter of the holders of Rights shall be to receive the Redemption Price for
each Right so held. Promptly after the action of a majority of the Company's
Board of Directors ordering the redemption of the Rights, the Company shall give
prompt written notice of such redemption to the Rights Agent and the holders of
the then-outstanding Rights by mailing such notice to all such holders at each
holder's last address as it appears upon the registry books of the Rights Agent
or, prior to the Distribution Date, on the registry books of the transfer agent
for Company Common Stock. Any notice that is mailed in the manner herein
provided shall be

                                       31
<PAGE>

deemed given, whether or not the holder receives the notice. Each such notice of
redemption will state the method by which the payment of the Redemption Price
will be made.

       SECTION 24. Notice of Certain Events. (a) In case the Company
shall propose, at any time after the Distribution Date, (i) to pay any dividend
payable in stock of any class to the holders of Preferred Stock or to make any
other distribution to the holders of Preferred Stock (other than a regular
quarterly cash dividend out of earnings or retained earnings of the Company),
(ii) to offer to the holders of Preferred Stock rights or warrants to subscribe
for or to purchase any additional shares of Preferred Stock or shares of stock
of any class or any other securities, rights or options, (iii) to effect any
reclassification of the Preferred Stock (other than a reclassification involving
only the subdivision of outstanding shares of Preferred Stock), (iv) to effect
any consolidation or merger into or with any other Person (other than a
Subsidiary of the Company in a transaction that complies with Section 11(o)
other than in connection with any public offering of the capital stock of any of
the Company's subsidiaries or any spin-off or other similar transaction), or to
effect any sale or other transfer (or to permit one or more of its Subsidiaries
to effect any sale or other transfer), in one or more transactions, of more than
50% of the assets or earning power of the Company and its Subsidiaries (taken as
a whole) to any other Person or Persons (other than the Company and/or any of
its Subsidiaries in one or more transactions each of which complies with Section
11(o)) or (v) to effect the liquidation, dissolution or winding up of the
Company, then, in each such case, the Company shall give to the Rights Agent and
to each holder of a Rights Certificate (or, prior to the Distribution Date, to
each holder of certificates for Company Common Stock), to the extent feasible
and in accordance with Section 25, a notice of such proposed action, which shall
specify the record date for the purposes of such stock dividend, distribution of
rights or warrants, or the date on which such reclassification, consolidation,
merger, sale, transfer, liquidation, dissolution or winding up is to take place
and the date of participation therein by the holders of the shares of Preferred
Stock, if any such date is to be fixed, and such notice shall be so given in the
case of any action covered by clause (i) or (ii) above at least 20 days prior to
the record date for determining holders of the shares of Preferred Stock for
purposes of such action, and in the case of any such other action, at least 20
days prior to the date of the taking of such proposed action or the date of
participation therein by the holders of the shares of Preferred Stock, whichever
shall be the earlier; provided, however, no such notice shall be required
pursuant to this Section 24 if any Subsidiary of the Company effects a
consolidation or merger with or into, or effects a sale or other transfer of
assets or earning power to, any other Subsidiary of the Company.

       (b) In case any of the events set forth in Section 11(a)(iii)
shall occur, then, in any such case, the Company shall as soon as practicable
thereafter give to the Rights Agent and to each holder of a Rights Certificate,
to the extent feasible and in accordance with Section 25, a notice of the
occurrence of such event, which shall specify the event and the consequences of
the event to holders of Rights under Section 11(a)(iii).

       SECTION 25. Notices. All notices and other communications
provided for hereunder shall, unless otherwise stated herein, be in writing and
mailed or sent or delivered (including by facsimile transmission), if to the
Company, at its address at:

       PG&E Corporation
       One Market, Spear Tower

                                       32
<PAGE>

       Suite 2400
       San Francisco, CA  94105
       Attention:  Corporate Secretary
       Telecopy No.:  (415) 267-7257

       with a copy to:

       PG&E Corporation
       One Market, Spear Tower
       Suite 2400
       San Francisco, CA  94105
       Attention:  Bruce Worthington, Esq.
                   Senior Vice President and General Counsel
       Telecopy No.:  (415) 267-7257

and if to the Rights Agent, at its address at:

       Mellon Investor Services LLC
       235 Montgomery Street, 23rd Floor
       San Francisco, CA  94104
       Attention:  Relationship Manager
       Telecopy No.:  (415) 743-1423



       with a copy to:

       Mellon Investor Services LLC
       85 Challenger Road
       Ridgefield Park, NJ  07660
       Attention:  General Counsel


Notices or demands authorized or required by this Agreement to be given or made
by the Company or the Rights Agent to the holder of any Rights Certificate (or,
if prior to the Distribution Date, to the holder of certificates evidencing
shares of Company Common Stock) shall be sufficiently given or made if sent by
first-class mail, postage prepaid, addressed to such holder at the address of
such holder as shown on the registry books of the Rights Agent or, prior to the
Distribution Date, on the registry books of the transfer agent for the Company
Common Stock.

       SECTION 26. Supplements and Amendments. Prior to the Distribution Date
and subject to the penultimate sentence of this Section 26, the Company and the
Rights Agent shall, if the Company so directs, supplement or amend any provision
of this Agreement without the approval of any holders of certificates evidencing
shares of Company Common Stock. From and after the Distribution Date and subject
to the penultimate sentence of this Section 26, the Company and the Rights Agent
shall, if the Company so directs, supplement or amend this Agreement without the
approval of any holders of Rights Certificates as contemplated by

                                       33
<PAGE>

Section 11(a)(ii) or in order (a) to cure any ambiguity, (b) to correct or
supplement any provision contained herein that may be defective or inconsistent
with any other provisions herein, (c) to shorten or lengthen any time period
hereunder or (d) to change or supplement the provisions hereunder in any manner
which the Company may deem necessary or desirable and which shall not adversely
affect the interests of the holders of Rights Certificates (other than an
Acquiring Person or an Affiliate or Associate of an Acquiring Person); provided,
however, that this Agreement may not be supplemented or amended to lengthen,
pursuant to clause (c) of this sentence, (i) subject to Section 30, a time
period relating to when the Rights may be redeemed at such time as the Rights
are not then redeemable or (ii) any other time period unless such lengthening is
for the purpose of protecting, enhancing or clarifying the rights of, and/or the
benefits to, the holders of Rights. Upon the delivery of a certificate from an
appropriate officer of the Company or, so long as any Person is an Acquiring
Person hereunder, from the majority of the Company's Board of Directors, that
states that the proposed supplement or amendment is in compliance with the terms
of this Section 26, the Rights Agent shall execute such supplement or amendment.
Prior to the Distribution Date, the interests of the holders of Rights shall be
deemed coincident with the interests of the holders of Company Common Stock.

     SECTION 27.    Successors. All the covenants and provisions of this
Agreement by or for the benefit of the Company or the Rights Agent shall bind
and inure to the benefit of their respective successors and assigns hereunder.

     SECTION 28.    Determinations and Actions by the Board of Directors, etc.
For all purposes of this Agreement, any calculation of the number of shares of
Company Common Stock outstanding at any particular time, including for purposes
of determining the particular percentage of such outstanding shares of Company
Common Stock of which any Person is the Beneficial Owner, shall be made in
accordance with the last sentence of Rule 13d-3(d)(1)(i) of the Exchange Act
Regulations as in effect on the date hereof. Except as otherwise specifically
provided herein, the Board of Directors of the Company shall have the exclusive
power and authority to administer this Agreement and to exercise all rights and
powers specifically granted to the Board of Directors of the Company or to the
Company, or as may be necessary or advisable in the administration of this
Agreement, including, without limitation, the right and power (i) to interpret
the provisions of this Agreement and (ii) to make all determinations deemed
necessary or advisable for the administration of this Agreement. All such
actions, calculations, interpretations and determinations (including, for
purposes of clause (y) below, all omissions with respect to the foregoing) that
are done or made by the Board of Directors in good faith shall (x) be final,
conclusive and binding on the Company, the Rights Agent, the holders of the
Rights and all other parties, and (y) not subject the Board of Directors of the
Company or any member thereof to any liability to the holders of the Rights. The
Rights Agent shall always be entitled to assume that the Company's Board of
Directors acted in good faith and shall be protected and incur no liability in
reliance theron.

     SECTION 29.    Benefits of this Agreement. Nothing in this Agreement shall
be construed to give to any Person other than the Company, the Rights Agent and
the registered holders of the Rights Certificates (and, prior to the
Distribution Date, registered holders of shares of Company Common Stock) any
legal or equitable right, remedy or claim under this Agreement. This Agreement
shall be for the sole and exclusive benefit of the Company, the Rights Agent and
the registered holders of the Rights Certificates (and, prior to the
Distribution Date, registered holders of shares of Company Common Stock).



                                       34
<PAGE>

     SECTION 30.    Severability. If any term, provision, covenant or
restriction of this Agreement is held by a court of competent jurisdiction or
other authority to be invalid, void or unenforceable, the remainder of the
terms, provisions, covenants and restrictions of this Agreement shall remain in
full force and effect and shall in no way be affected, impaired or invalidated;
provided, however, that notwithstanding anything in this Agreement to the
contrary, if any such term, provision, covenant or restriction is held by such
court or authority to be invalid, void or unenforceable and a majority of the
Company's Board of Directors determines in its good faith judgment that severing
the invalid language from this Agreement would adversely affect the purpose or
effect of this Agreement and the Rights shall not then be redeemable, the right
of redemption set forth in Section 23 shall be reinstated and shall not expire
until the Close of Business on the tenth Business Day following the date of such
determination by a majority of the Company's Board of Directors.

     SECTION 31.    Governing Law. This Agreement, each Right and each Rights
Certificate issued hereunder shall be governed by, and construed in accordance
with, the laws of the State of California; provided, however, that all
provisions regarding the rights, duties and obligations of the Rights Agent
shall be governed by and construed in accordance with the laws of the State of
New York applicable to contracts made and to be performed entirely within such
State.

     SECTION 32.    Counterparts. This Agreement may be executed (including by
facsimile) in one or more counterparts, and by the different parties hereto in
separate counterparts, each of which when executed shall be deemed to be an
original, but all of which taken together shall constitute one and the same
instrument.

     SECTION 33.    Descriptive Headings. The headings contained in this
Agreement are for descriptive purposes only and shall not affect in any way the
meaning or interpretation of this Agreement.

     SECTION 34.    Exchange. (a) (i) The Company may, at its option, at any
time after any person becomes an Acquiring Person, upon resolution adopted by a
majority of the Company's Board of Directors, exchange all or part of the then
outstanding and exercisable Rights (which shall not include Rights that have
become null and void pursuant Section 7(e)) for Units of Preferred Stock at an
exchange ratio of one Unit of Preferred Stock per Right, appropriately adjusted
to reflect any stock split, stock dividend or similar transaction occurring
after the date hereof (such exchange ratio being hereinafter referred to as the
"Section 34(a)(i) Exchange Ratio"). Notwithstanding the foregoing, the Company
may not effect such exchange at any time after any Person (other than the
Company, any Subsidiary of the Company, any employee benefit plan maintained by
the Company or any of its Subsidiaries, or any trustee or fiduciary with respect
to such plan acting in such capacity), together with all Affiliates and
Associates of such Person, becomes the Beneficial Owner of 50% or more of the
shares of Company Common Stock then outstanding.

     (ii)      The Company may, at its option, at any time after any person
becomes an Acquiring Person, upon resolution adopted by a majority of the
Company's Board of Directors, exchange all or part of the then outstanding and
exercisable Rights (which shall not include Rights that have become void
pursuant to Section 7(e)) for Units of Preferred Stock at an

                                       35
<PAGE>

exchange ratio specified in the following sentence, as appropriately adjusted to
reflect any stock split, stock dividend or similar transaction occurring after
the date hereof. Subject to such adjustment, each Right may be exchanged for
that number of Units of Preferred Stock obtained by dividing the Adjustment
Spread (as defined below) by the then-current market price (determined pursuant
to Section 11(d)) per Unit of Preferred Stock on the earlier of (i) the date on
which any Person becomes an Acquiring Person and (ii) the date on which a tender
or exchange offer by any Person (other than the Company, any Subsidiary of the
Company, any employee benefit plan maintained by the Company or any of its
Subsidiaries or any trustee or fiduciary with respect to such plan acting in
such capacity) is first published or sent or given within the meaning of Rule
14d-4(a) of the Exchange Act Regulations or any successor rule, if upon
consummation thereof such Person would be the Beneficial Owner of 15% or more of
the shares of Company Common Stock then outstanding (such exchange ratio being
the "Section 34(a)(ii) Exchange Ratio"). The "Adjustment Spread" shall equal (x)
the aggregate market price on the date of such event of the number of Adjustment
Shares determined pursuant to Section 11(a)(iii), minus (y) the Purchase Price.
Notwithstanding the foregoing, the Company may not effect such exchange at any
time after any Person (other than the Company, any Subsidiary of the Company,
any employee benefit plan maintained by the Company or any of its Subsidiaries,
or any trustee or fiduciary with respect to such plan acting in such capacity),
together with all Affiliates and Associates of such Person, becomes the
Beneficial Owner of 50% or more of the shares of the Company Common Stock then
outstanding.

     Notwithstanding anything contained in this Section 34(a) to the contrary,
the Company may not exchange any Rights pursuant to this Section 34(a) unless at
the time of the action of the Board of Directors of the Company approving such
exchange.

     (b)       Immediately upon the action of a majority of the Company's Board
of Directors ordering the exchange of any Rights pursuant to Section 34(a) and
without any further action and without any notice, the right to exercise such
Rights shall terminate and the only right thereafter of a holder of such Rights
shall be to receive that number of Units of Preferred Stock equal to the number
of such Rights held by such holder multiplied by the Section 34(a)(i) Exchange
Ratio or Section 34(a)(ii) Exchange Ratio, as the case may be. The Company shall
promptly notify the Rights Agent in writing of such exchange and shall promptly
give public notice of any such exchange; provided, however, that the failure to
give, or any defect in, such notice shall not affect the validity of such
exchange. The Company promptly shall mail a notice of any such exchange to all
of the holders of such Rights at their last addresses as they appear upon the
registry books of the Rights Agent. Any notice that is mailed in the manner
herein provided shall be deemed given, whether or not the holder receives the
notice. Each such notice of exchange shall state the method by which the
exchange of Units of Preferred Stock for Rights will be effected and, in the
event of any partial exchange, the number of Rights that will be exchanged. Any
partial exchange shall be effected pro rata based on the number of Rights (other
than Rights that have become null and void pursuant to Section 7(e)) held by
each holder of Rights.

     (c)       In the event that the number of shares of Preferred Stock that
are authorized by the Company's Articles of Incorporation but not outstanding or
reserved for issuance for purposes other than upon exercise of the Rights are
not sufficient to permit any exchange of Rights as contemplated in accordance
with this Section 34, the Company shall take

                                       36
<PAGE>

all such action as may be necessary to authorize additional shares of Preferred
Stock for issuance upon exchange of the Rights or make adequate provision to
substitute (1) cash, (2) Company Common Stock or other equity securities of the
Company, (3) debt securities of the Company, (4) other assets or (5) any
combination of the foregoing, having an aggregate value equal to the Adjustment
Spread, where such aggregate value has been determined by a majority of the
Company's Board of Directors.

     (d)       The Company shall not be required to issue fractions of Units of
Preferred Stock or to distribute certificates that evidence fractional Units. In
lieu of fractional Units, the Company may pay to the registered holders of
Rights Certificates at the time such Rights are exchanged as herein provided an
amount in cash equal to the same fraction of the current market price
(determined pursuant to Section 11(d)) of one Unit of Preferred Stock.

                                       37
<PAGE>

     IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
duly executed on their behalf as of the date first above written.


                                        PG&E CORPORATION

                                        By /s/ Robert D. Glynn, Jr.
                                           ------------------------------
                                           Name: Robert D. Glynn, Jr.
                                           Title: Chairman of the Board


Countersigned:

MELLON INVESTOR SERVICES LLC

By /s/ Joseph Thatcher
   ------------------------------
   Name: Joseph Thatcher
   Title: Assistant Vice President
<PAGE>

                                   EXHIBIT A


                          FORM OF RIGHTS CERTIFICATE

                                                                       EXHIBIT A
                                                                       ---------


Certificate No.                                                          Rights
              ------                                               ------

NOT EXERCISABLE AFTER THE EXPIRATION DATE (AS DEFINED IN THE RIGHTS AGREEMENT
REFERRED TO BELOW). THE RIGHTS ARE SUBJECT TO REDEMPTION, AT THE OPTION OF THE
COMPANY, ON THE TERMS SET FORTH IN THE RIGHTS AGREEMENT. UNDER CERTAIN
CIRCUMSTANCES (SPECIFIED IN THE RIGHTS AGREEMENT), RIGHTS BENEFICIALLY OWNED BY
ACQUIRING PERSONS (AS DEFINED IN THE RIGHTS AGREEMENT) OR ANY SUBSEQUENT HOLDER
OF SUCH RIGHTS MAY BECOME NULL AND VOID. [THE RIGHTS REPRESENTED BY THIS RIGHTS
CERTIFICATE ARE OR WERE BENEFICIALLY OWNED BY A PERSON WHO WAS OR BECAME AN
ACQUIRING PERSON OR AN AFFILIATE OR ASSOCIATE OF AN ACQUIRING PERSON (AS SUCH
TERMS ARE DEFINED IN THE RIGHTS AGREEMENT REFERRED TO BELOW). ACCORDINGLY, THIS
RIGHTS CERTIFICATE AND THE RIGHTS REPRESENTED HEREBY MAY BECOME NULL AND VOID IN
THE CIRCUMSTANCES SPECIFIED IN SECTION 7(e) OF THE RIGHTS AGREEMENT.]*

                              RIGHTS CERTIFICATE
                              ------------------

                               PG&E CORPORATION

     This certifies that, or registered assigns, is the registered
holder of the number of Rights set forth above, each of which entitles the
registered holder thereof, subject to the terms and conditions of the Rights
Agreement dated as of December 22, 2000 (the "Rights Agreement"; terms
defined therein are used herein with the same meaning unless otherwise defined
herein) between PG&E Corporation, a California corporation (the "Company"), and
Mellon Investor Services L.L.C., a New Jersey limited liability company, as
Rights Agent (which term shall include any successor Rights Agent under the
Rights Agreement), to purchase from the Company at any time after the
Distribution Date and prior to the Expiration Date at the office of the Rights
Agent, one one-hundredth of a fully paid and non-assessable share of Series A
Preferred Stock, par value $100 per share (the "Preferred Stock"), of the
Company at the Purchase Price initially of $95 per one one-hundredth share (each
such one one-hundredth of a share being a "Unit") of Preferred Stock, upon
presentation and surrender of this Rights Certificate with the Election to
Purchase and related certificate duly executed. The number of Rights evidenced
by this Rights Certificate (and the number of Units which may be purchased upon
exercise thereof) set forth above, and the Purchase Price per Unit set forth
above shall be subject to adjustment in certain events as provided in the Rights
Agreement.

     Upon the occurrence of a Section 11(a)(iii) Event or Section 13
Event, if the Rights evidenced by this Rights Certificate are beneficially owned
by an Acquiring Person or an Affiliate or Associate of any such Acquiring Person
or, under certain circumstances described in

--------
*     The portion of the legend in brackets shall be inserted only if applicable
      and shall replace the preceding sentence.
<PAGE>

                                       2

the Rights Agreement, a transferee of any such Acquiring Person, Associate or
Affiliate, such Rights shall become null and void and no holder hereof shall
have any right with respect to such Rights from and after the occurrence of such
Section 11(a)(iii) Event or Section 13 Event.

     In certain circumstances described in the Rights Agreement, the Rights
evidenced hereby may entitle the registered holder thereof to purchase capital
stock of an entity other than the Company or to receive common stock, cash or
other assets, all as provided in the Rights Agreement.

     This Rights Certificate is subject to all of the terms and conditions of
the Rights Agreement, which terms and conditions are hereby incorporated herein
by reference and made a part hereof and to which Rights Agreement reference is
hereby made for a full description of the rights, limitations of rights,
obligations, duties and immunities hereunder of the Rights Agent, the Company
and the holders of the Rights Certificates. Copies of the Rights Agreement are
on file at the principal office of the Company and are available from the
Company upon written request.

     This Rights Certificate, with or without other Rights Certificates, upon
surrender at the office of the Rights Agent designated for such purpose, may be
exchanged for another Rights Certificate or Rights Certificates of like tenor
and date evidencing an aggregate number of Rights equal to the aggregate number
of Rights evidenced by the Rights Certificate or Rights Certificates
surrendered. If this Rights Certificate shall be exercised in part, the
registered holder shall be entitled to receive, upon surrender hereof, another
Rights Certificate or Rights Certificates for the number of whole Rights not
exercised.

     Subject to the provisions of the Rights Agreement, the Rights evidenced by
this Certificate may be redeemed by the Company under certain circumstances at
its option at a redemption price of $.01 per Right, payable at the Company's
option in cash or in common stock of the Company, subject to adjustment in
certain events as provided in the Rights Agreement.

     No fractional shares of Preferred Stock will be issued upon the exercise of
any Right or Rights evidenced hereby (other than fractions which are integral
multiples of one one-hundredth of a share of Preferred Stock), but in lieu
thereof a cash payment will be made, as provided in the Rights Agreement.

     No holder of this Rights Certificate, as such, shall be entitled to vote or
receive dividends or be deemed for any purpose the holder of Preferred Stock or
of any other securities which may at any time be issuable upon the exercise
hereof, nor shall anything contained in the Rights Agreement or herein be
construed to confer upon the holder hereof, as such, any of the rights of a
shareholder of the Company or any right to vote for the election of directors or
upon any matter submitted to shareholders at any meeting thereof, or to give or
withhold consent to any corporate action, or to receive notice of meetings or
other actions affecting shareholders (except as provided in the Rights
Agreement), or to receive dividends or subscription rights, or otherwise, until
the Rights evidenced by this Rights Certificate shall have been exercised as
provided in the Rights Agreement.
<PAGE>

                                       3

     This Rights Certificate shall not be valid or obligatory for any purpose
until it shall have been countersigned by the Rights Agent.

     WITNESS the facsimile signature of the proper officers of the Company and
its corporate seal. Dated as of, -----------------  ---- ---------.



ATTEST:                                         PG&E CORPORATION

By ____________________                         By _______________________
   Name:                                           Name:
   Title:                                          Title:

Countersigned:

MELLON INVESTOR SERVICES L.L.C.,
as Rights Agent

By ____________________
   Name:
   Title:
<PAGE>

                  Form of Reverse Side of Rights Certificate



                              FORM OF ASSIGNMENT
                              ------------------


                  (To be executed by the registered holder if
                      such holder desires to transfer the
                              Rights Certificate)



FOR VALUE RECEIVED ____________________________________________________
                         (Please print name of registered holder)

hereby sells, assigns and transfers unto

___________________________________________________________________________
                 (Please print name and address of transferee)

this Rights Certificate, together with all right, title and interest therein,
and does hereby irrevocably constitute and appoint __________________, Attorney,
to transfer the within Rights Certificate on the books of the within-named
Company, with full power of substitution.


Dated:______________________ ___, ________


                                               _______________________________
                                               Signature

Signature Guaranteed:
<PAGE>

                                  CERTIFICATE

     The undersigned hereby certifies by checking the appropriate boxes
     that:

     (1) this Rights Certificate [_] is [_] is not being sold, assigned
and transferred by or on behalf of a Person who is or was an Acquiring Person or
an Affiliate or Associate of any such Acquiring Person (as such terms are
defined pursuant to the Rights Agreement); and

     (2) after due inquiry and to the best knowledge of the undersigned,
it [_] did [_] did not acquire the Rights evidenced by this Rights Certificate
from any Person who is, was or subsequently became an Acquiring Person or an
Affiliate or Associate of an Acquiring Person.

Dated:____________________,  ____  _______      ________________________________
                                                Signature

Signature Guaranteed:

        ______________________________________________________________

                                    NOTICE
                                    ------

     The signature to the foregoing Assignment and Certificate must
correspond to the name as written upon the face of this Rights Certificate in
every particular, without alteration or enlargement or any change whatsoever.

     In the event the certification set forth above is not completed, the
Company will deem the beneficial owner of the Rights evidenced by this Rights
Certificate to be an Acquiring Person or an Affiliate or Associate thereof (as
defined in the Rights Agreement) and, in the case of an Assignment, will affix a
legend to that effect on any Rights Certificates issued in exchange for this
Rights Certificate.
<PAGE>

                         FORM OF ELECTION TO PURCHASE
                         ----------------------------

                   (To be executed if the registered holder
                    desires to exercise Rights represented
                          by the Rights Certificate)


To:  PG&E CORPORATION

         The undersigned hereby irrevocably elects to exercise Rights
represented by this Rights Certificate to purchase the Units of Preferred
Stock issuable upon the exercise of the Rights (or such other securities
of the Company or of any other person or other property which may be
issuable upon the exercise of the Rights) and requests that certificates
for such Units be issued in the name of and delivered to:

--------------------------------------------------------------------------
(Please print name and address)
--------------------------------------------------------------------------

Please insert social security
or other identifying number:  ____________________________

     If such number of Rights shall not be all the Rights evidenced by
this Rights Certificate, a new Rights Certificate for the balance of such Rights
shall be registered in the name of and delivered to:

--------------------------------------------------------------------------
(Please print name and address)
--------------------------------------------------------------------------

Please insert social security
or other identifying number:  ____________________________

Dated: ____________________ ____, ________

                                                ________________________
                                                Signature

Signature Guaranteed:
<PAGE>

                                  CERTIFICATE
                                  -----------

     The undersigned hereby certifies by checking the appropriate boxes
     that:

     (1) the Rights evidenced by this Rights Certificate [ ] are [ ] are
not beneficially owned by an Acquiring Person or an Affiliate or an Associate
thereof (as defined in the Rights Agreement); and

     (2) after due inquiry and to the best knowledge of the undersigned,
the undersigned [ ] did [ ] did not acquire the Rights evidenced by this Rights
Certificate from any person who is, was or subsequently became an Acquiring
Person or an Affiliate or Associate thereof.

Dated: ____________________ ____, ________     _________________________________
                                               Signature

Signature Guaranteed:

      ______________________________________________________________

                                    NOTICE
                                    ------

     The signature in the foregoing Election to Purchase and Certificate
must conform to the name as written upon the face of this Rights Certificate in
every particular, without alteration or enlargement or any change whatsoever.

     In the event the certification set forth above is not completed, the
Company will deem the beneficial owner of the Rights evidenced by this Rights
Certificate to be an Acquiring Person or an Affiliate or Associate thereof (as
defined in the Rights Agreement) and, in the case of an Assignment, will affix a
legend to that effect on any Rights Certificates issued in exchange for this
Rights Certificate.
<PAGE>

                                                                       EXHIBIT B
                                                                       ---------

                         SUMMARY OF RIGHTS TO PURCHASE
                                PREFERRED STOCK

          On December 20, 2000, the Board of Directors of PG&E Corporation (the
"Corporation") declared a distribution of one Right for each outstanding share
 -----------
of Common Stock, no par value, of the Corporation (the "Corporation Common
                                                        ------------------
Stock"), to shareholders of record at the close of business on January 2, 2001
-----
(the "Record Date") and for each share of Corporation Common Stock issued by the
      -----------
Corporation thereafter and prior to the Distribution Date.  Each Right entitles
the registered holder, subject to the terms of the Rights Agreement (as defined
below), to purchase from the Corporation one one-hundredth of a share (a "Unit")
                                                                          ----
of Series A Preferred Stock, par value $100 per share (the "Preferred Stock"),
                                                            ---------------
at a Purchase Price of $95 per Unit, subject to adjustment.  The Purchase Price
is payable in cash or by certified or bank check payable to the order of the
Corporation or by wire transfer to the account of the Corporation (provided a
notice of such wire transfer is given by the holder of the related Right to the
Rights Agent).  The description and terms of the Rights are set forth in a
Rights Agreement between the Corporation and Mellon Investor Services LLC, a New
Jersey limited liability company, as Rights Agent (the "Rights Agreement").
                                                        ----------------

          Copies of the Rights Agreement and the form of Certificate of
Determination for the Preferred Stock have been filed with the Securities and
Exchange Commission as exhibits to a Registration Statement on Form 8-A dated
December 22, 2000 (the "Form 8-A").  Copies of the Rights Agreement and the
                        --------
Certificate of Determination are available free of charge from the Corporation.
This summary description of the Rights and the Preferred Stock does not purport
to be complete and is qualified in its entirety by reference to all the
provisions of the Rights Agreement and the Certificate of Determination,
including the definitions therein of certain terms, which Rights Agreement and
Certificate of Determination are incorporated herein by reference.

The Rights Agreement
--------------------

          Initially, the Rights will attach to all certificates representing
shares of outstanding Corporation Common Stock, and no separate Rights
Certificates will be distributed.  The Rights will separate from the Corporation
Common Stock and the "Distribution Date" will occur upon the earlier of (i) 10
                      -----------------
days following a public announcement (the date of such announcement being the
"Stock Acquisition Date") that a person or group of affiliated or associated
 ----------------------
persons (other than the Corporation, any subsidiary of the Corporation or any
employee benefit plan of the Corporation or such subsidiary) (an "Acquiring
                                                                  ---------
Person") has acquired, obtained the right to acquire, or otherwise obtained
------
beneficial ownership of 15% or more of the then-outstanding shares of
Corporation Common Stock, and (ii) 10 business days (or such later date as may
be determined by action of the Board of Directors prior to such time as any
person becomes an Acquiring Person) following the commencement of a tender offer
or exchange offer that would result in a person or group beneficially owning 15%
or more of the then-outstanding shares of Corporation Common Stock.  Until the
Distribution Date, (i) the Rights will be evidenced by Corporation Common Stock
certificates and will be transferred with and only with such Corporation Common
Stock certificates, (ii) new Corporation Common Stock certificates issued after
the Record Date will contain a notation incorporating the Rights Agreement by
reference and (iii) the surrender for transfer of any certificates representing
outstanding Corporation Common Stock will also constitute the transfer of the
Rights associated with the Corporation Common Stock represented by such
certificates.

          The Rights are not exercisable until the Distribution Date and will
expire at the close of business on the tenth anniversary of the Rights
Agreement, unless earlier redeemed by the Corporation as described below.

          As soon as practicable after the Distribution Date, Rights
Certificates will be mailed to holders of record of Corporation Common Stock as
of the close of business on the Distribution Date and, thereafter, the separate
Rights Certificates alone will represent the Rights.
<PAGE>

          In the event that (i) the Corporation is the surviving corporation in
a merger with an Acquiring Person and shares of Corporation Common Stock shall
remain outstanding, (ii) a Person becomes an Acquiring Person, (iii) an
Acquiring Person engages in one or more "self-dealing" transactions as set forth
in the Rights Agreement, or (iv) during such time as there is an Acquiring
Person, an event occurs which results in such Acquiring Person's ownership
interest being increased by more than 1% (e.g., by means of a recapitalization)
(each such event being a "Section 11(a)(iii) Event"), then, in each such case,
                          ------------------------
each holder of a Right will thereafter have the right to receive, upon exercise,
Units of Preferred Stock (or, in certain circumstances, Corporation Common
Stock, cash, property or other securities of the Corporation) having a value
equal to two times the exercise price of the Right.  The exercise price is the
Purchase Price multiplied by the number of Units of Preferred Stock issuable
upon exercise of a Right prior to the events described in this paragraph.
Notwithstanding any of the foregoing, following the occurrence of any of the
events set forth in this paragraph, all Rights that are, or (under certain
circumstances specified in the Rights Agreement) were, beneficially owned by any
Acquiring Person will be null and void.

          In the event that, at any time following the Stock Acquisition Date,
(i) the Corporation is acquired in a merger (other than a merger described in
the preceding paragraph) or other business combination and the Corporation is
not the surviving corporation, (ii) any Person consolidates or merges with the
Corporation and all or part of the Corporation Common Stock is converted or
exchanged for securities, cash or property of any other Person or (iii) 50% or
more of the Corporation's assets or earning power is sold or transferred, each
holder of a Right (except Rights which previously have been voided as described
above) shall thereafter have the right to receive, upon exercise, common stock
of the ultimate parent of the Acquiring Person having a value equal to two times
the exercise price of the Right.

          The Purchase Price payable, and the number of Units of Preferred Stock
issuable, upon exercise of the Rights are subject to adjustment from time to
time to prevent dilution (i) in the event of a stock dividend on, or a
subdivision, combination or reclassification of, the Preferred Stock, (ii) if
holders of the Preferred Stock are granted certain rights or warrants to
subscribe for Preferred Stock or convertible securities at less than the current
market price of the Preferred Stock, or (iii) upon the distribution to the
holders of the Preferred Stock of evidences of indebtedness, cash or assets
(excluding regular quarterly cash dividends) or of subscription rights or
warrants (other than those referred to above).

          With certain exceptions, no adjustment in the Purchase Price will be
required until cumulative adjustments amount to at least 1% of the Purchase
Price.  The Corporation is not required to issue fractional Units.  In lieu
thereof, an adjustment in cash may be made based on the market price of the
Preferred Stock prior to the date of exercise.

          At any time prior to the earlier of (i) ten business days following
the Stock Acquisition Date or (ii) the Final Expiration Date, a majority of the
Corporation's Board of Directors may redeem the Rights in whole, but not in
part, at a price of $.01 per Right (subject to adjustment in certain events)
(the "Redemption Price"), payable, at the election of such majority of the
      ----------------
Corporation's Board of Directors, in cash or shares of Corporation Common Stock.
Immediately upon the action of a majority of the Corporation's Board of
Directors ordering the redemption of the Rights, the Rights will terminate and
the only remaining right of the holders of Rights will be to receive the
Redemption Price.

          The Board of Directors, at its option, may exchange each Right for (i)
one Unit of Preferred Stock or (ii) such number of Units of Preferred Stock as
will equal (x) the difference between the aggregate market price of the number
of Units of Preferred Stock to be received upon a Section 11(a)(iii) Event and
the purchase price set forth in the Rights Agreement, divided by (y) the market
price per Unit of Preferred Stock upon a Section 11(a)(iii) Event.

          Until a Right is exercised, the holder thereof, as such, will have no
rights as a shareholder of the Corporation, including, without limitation, the
right to vote or to receive dividends.  While the distribution of the Rights
will not be taxable to shareholders or to the Corporation, shareholders may,
depending upon the circumstances, recognize taxable income in the event that the
Rights become exercisable for Units of Preferred Stock (or other consideration).
<PAGE>

          Any of the provisions of the Rights Agreement may be amended without
the approval of the holders of Corporation Common Stock at any time prior to the
Distribution Date.  After the Distribution Date, the provisions of the Rights
Agreement may be amended in order to cure any ambiguity, defect or
inconsistency, to make changes which do not adversely affect the interests of
the holders of Rights (excluding the interests of any Acquiring Person), or to
shorten or lengthen any time period under the Rights Agreement; provided,
however, that no amendment to adjust the time period governing redemption shall
be made at such time as the Rights are not redeemable.

Description of Preferred Stock
------------------------------

          The Units of Preferred Stock that may be acquired upon exercise of the
Rights will be nonredeemable and subordinate to any other shares of preferred
stock that may be issued by the Corporation.

          Each Unit of Preferred Stock will have a minimum preferential
quarterly dividend of $.01 per Unit or any higher per share dividend declared on
the Corporation Common Stock.

          In the event of liquidation, the holder of a Unit of Preferred Stock
will receive a preferred liquidation payment equal to the greater of $1.00 per
Unit or the per share amount paid in respect of a share of Corporation Common
Stock.

          Each Unit of Preferred Stock will have one vote, voting together with
the Corporation Common Stock.  The holders of Units of Preferred Stock, voting
as a separate class, shall be entitled to elect two directors if dividends on
the Preferred Stock are in arrears for six fiscal quarters.

          In the event of any merger, consolidation or other transaction in
which shares of Corporation Common Stock are exchanged, each Unit of Preferred
Stock will be entitled to receive the per share amount paid in respect of each
share of Corporation Common Stock.

          The rights of holders of the Preferred Stock to dividends, liquidation
and voting, and in the event of mergers and consolidations, are protected by
customary antidilution provisions.

          Because of the nature of the Preferred Stock's dividend, liquidation
and voting rights, the economic value of one Unit of Preferred Stock that may be
acquired upon the exercise of each Right is expected to approximate the economic
value of one share of Corporation Common Stock.
<PAGE>

                                                                       EXHIBIT C
                                                                       ---------

                  CERTIFICATE OF DETERMINATION OF PREFERENCES

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

                        Pursuant to Section 401 of the
                      California General Corporation Law

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

ROBERT D. GLYNN, JR. and LESLIE H. EVERETT certify that:

          1.  They are the Chairman of the Board, Chief Executive Officer, and
President, and the Vice President and Corporate Secretary, respectively, of PG&E
Corporation, a California corporation.

          2.  Pursuant to authority conferred upon the Board of Directors of the
Corporation by its Restated Articles of Incorporation (the "Articles"), and,
                                                            --------
pursuant to the provisions of Section 401 of the California General Corporation
Law, said Board of Directors, at a duly called meeting held on December 20,
2000, at which a quorum was present and acted throughout, adopted the following
resolutions, which resolutions remain in full force and effect on the date
hereof creating a series of 5,000,000 shares of Preferred Stock having a par
value of $100 per share, designated as Series A Preferred Stock (the "Series A
                                                                      --------
Preferred Stock") out of the class of 85,000,000 shares of preferred stock (the
---------------
"Preferred Stock"):
 ---------------

          RESOLVED, that pursuant to the authority vested in the Board of
Directors in accordance with the provisions of the Articles, the Board of
Directors does hereby create, authorize and provide for the issuance of the
Series A Preferred Stock having the voting powers, designation, relative,
participating, optional and other special rights, preferences and
qualifications, limitations and restrictions thereof that are set forth as
follows:

          Section 1.  Designation and Amount.  The shares of such series shall
                      ----------------------
be designated as "Series A Preferred Stock" and the number of shares
constituting such series shall be 5,000,000.

          Section 2.  Dividends and Distributions.  (A)  Subject to the prior
                      ---------------------------
and superior rights of the holders of any shares of any other series of
Preferred Stock or any other shares of preferred stock of the Corporation
ranking prior and superior to the shares of Series A Preferred Stock with
respect to dividends, each holder of one one-hundredth (1/100) of a share (a
"Unit") of Series A Preferred Stock shall be entitled to receive, when, as and
 ----
if declared by the Board of Directors out of funds legally available for that
purpose, (i) quarterly dividends payable in cash on the last day of March, June,
September and December in each year (each such date being a "Quarterly Dividend
                                                             ------------------
Payment Date"), commencing on the first Quarterly Dividend Payment Date after
------------
the first issuance of such Unit of Series A Preferred Stock, in an amount per
Unit (rounded to the nearest cent) equal to the greater of (a) $.01 or (b)
subject to the provision for adjustment hereinafter set forth, the aggregate per
share amount of all cash dividends declared on shares of the Common Stock since
the immediately preceding Quarterly Dividend Payment Date, or, with respect to
the first Quarterly Dividend Payment Date, since the first issuance of a Unit of
Series A Preferred Stock, and (ii) subject to the provision for adjustment
hereinafter set forth, quarterly distributions (payable in kind) on each
Quarterly Dividend Payment Date in an amount per Unit equal to the aggregate per
share amount of all non-cash dividends or other distributions (other than a
dividend payable in shares of Common Stock or a subdivision of the outstanding
shares of Common Stock, by reclassification or otherwise) declared on shares of
Common Stock since the immediately preceding Quarterly Dividend Payment Date, or
with respect to the first Quarterly Dividend Payment Date, since the first
issuance of a Unit of Series A Preferred Stock.  In the event that the
Corporation shall at any time after December 20, 2000 (the "Rights Declaration
                                                            ------------------
Date") (i) declare any dividend on outstanding shares of Common Stock payable in
----
shares of Common Stock, (ii) subdivide outstanding shares of Common Stock or
(iii) combine outstanding shares of Common Stock into a smaller number of
shares, then in each such case the amount to which the holder of a Unit of
Series A Preferred Stock was entitled immediately prior to such event pursuant
to the preceding sentence shall be adjusted by multiplying such amount by a
fraction the numerator of which shall be the number of shares of Common Stock
that are outstanding immediately after such event and the denominator of which
<PAGE>

shall be the number of shares of Common Stock that were outstanding immediately
prior to such event.

          (B) The Corporation shall declare a dividend or distribution on Units
of Series A Preferred Stock as provided in paragraph (A) above immediately after
it declares a dividend or distribution on the shares of Common Stock (other than
a dividend payable in shares of Common Stock); provided, however, that, in the
                                               --------  -------
event no dividend or distribution shall have been declared on the Common Stock
during the period between any Quarterly Dividend Payment Date and the next
subsequent Quarterly Dividend Payment Date, a dividend of $.01 per Unit on the
Series A Preferred Stock shall nevertheless be payable on such subsequent
Quarterly Dividend Payment Date.

          (C) Dividends shall begin to accrue and shall be cumulative on each
outstanding Unit of Series A Preferred Stock from the Quarterly Dividend Payment
Date next preceding the date of issuance of such Unit of Series A Preferred
Stock, unless the date of issuance of such Unit is prior to the record date for
the first Quarterly Dividend Payment Date, in which case, dividends on such Unit
shall begin to accrue from the date of issuance of such Unit, or unless the date
of issuance is a Quarterly Dividend Payment Date or is a date after the record
date for the determination of holders of Units of Series A Preferred Stock
entitled to receive a quarterly dividend and before such Quarterly Dividend
Payment Date, in either of which events such dividends shall begin to accrue and
be cumulative from such Quarterly Dividend Payment Date.  Accrued but unpaid
dividends shall not bear interest. Dividends paid on Units of Series A Preferred
Stock in an amount less than the aggregate amount of all such dividends at the
time accrued and payable on such Units shall be allocated pro rata on a Unit-by-
Unit basis among all Units of Series A Preferred Stock at the time outstanding.
The Board of Directors may fix a record date for the determination of holders of
Units of Series A Preferred Stock entitled to receive payment of a dividend or
distribution declared thereon, which record date shall be no more than 30 days
prior to the date fixed for the payment thereof.

          Section 3.  Voting Rights.  The holders of Units of Series A Preferred
                      -------------
Stock shall have the following voting rights:

          (A) Subject to the provision for adjustment hereinafter set forth,
each Unit of Series A Preferred Stock shall entitle the holder thereof to one
vote on all ma tters submitted for a vote of the shareholders of the
Corporation. In the event the Corporation shall at any time after the Rights
Declaration Date (i) declare any dividend on outstanding shares of Common Stock
payable in shares of Common Stock, (ii) subdivide outstanding shares of Common
Stock or (iii) combine the outstanding shares of Common Stock into a smaller
number of shares, then in each such case the number of votes per Unit to which
holders of Units of Series A Preferred Stock were entitled immediately prior to
such event shall be adjusted by multiplying such number by a fraction the
numerator of which shall be the number of shares of Common Stock outstanding
immediately after such event and the denominator of which shall be the number of
shares of Common Stock that were outstanding immediately prior to such event.

          (B) Except as otherwise provided herein or by law, the holders of
Units of Series A Preferred Stock and the holders of shares of Common Stock
shall vote together as one class on all matters submitted to a vote of
shareholders of the Corporation.

          (C) (i)  If, at any time, dividends on any Units of Series A Preferred
Stock shall be in arrears in an amount equal to six quarterly dividends thereon,
then during the period (a "default period") from the occurrence of such event
                           --------------
until such time as all accrued and unpaid dividends for all previous quarterly
dividend periods and for the current quarterly dividend period on all Units of
Series A Preferred Stock then outstanding shall have been declared and paid or
set apart for payment, all holders of Units of Series A Preferred Stock, voting
separately as a class, shall have the right to elect two Directors.

              (ii) During any default period, such voting rights of the holders
of Units of Series A Preferred Stock may be exercised initially at a special
meeting called pursuant to subparagraph (iii) of this Section 3(C) or at any
annual meeting of shareholders, and thereafter at annual meetings of
shareholders, provided that such voting rights may not be exercised at any
meeting unless one-third of the outstanding Units of Preferred Stock shall be
present at such meeting in person or by proxy. The absence of a quorum of the
holders of Common Stock shall not affect the exercise by the holders of Units of
Series A Preferred Stock of such rights. At any meeting at which the holders of
Units of Series A Preferred Stock shall exercise such voting rights initially
during an existing default period, they
<PAGE>

shall have the right, voting separately as a class, to elect Directors to fill
up to two vacancies in the Board of Directors, if any such vacancies may then
exist, or, if such right is exercised at an annual meeting, to elect two
Directors. After the holders of Units of Series A Preferred Stock shall have
exercised their right to elect Directors during any default period, the number
of Directors shall not be increased or decreased except as approved by a vote of
the holders of Units of Series A Preferred Stock as herein provided or pursuant
to the rights of any equity securities ranking senior to the Series A Preferred
Stock.

          (iii)  Unless the holders of Series A Preferred Stock shall, during an
existing default period, have previously exercised their right to elect
Directors, the Board of Directors may order, or any shareholder or shareholders
owning in the aggregate not less than 10% of the total number of the Units of
Series A Preferred Stock outstanding may request, the calling of a special
meeting of the holders of Units of Series A Preferred Stock, which meeting shall
thereupon be called by the Secretary of the Corporation. Notice of such meeting
and of any annual meeting at which holders of Units of Series A Preferred Stock
are entitled to vote pursuant to this paragraph (C)(iii) shall be given to each
holder of record of Units of Series A Preferred Stock by mailing a copy of such
notice to him at his last address as the same appears on the books of the
Corporation. Such meeting shall be called for a time not earlier than 20 days
and not later then 60 days after such order or request, or, in default of the
calling of such meeting within 60 days after such order or request, such meeting
may be called on similar notice by any shareholder or shareholders owning in the
aggregate not less than 10% of the total number of outstanding Units of Series A
Preferred Stock. Notwithstanding the provisions of this paragraph (C)(iii), no
such special meeting shall be called during the 60 days immediately preceding
the date fixed for the next annual meeting of the shareholders.

          (iv)   During any default period, the holders of shares of Common
Stock and Units of Series A Preferred Stock, and other classes or series of
stock of the Corporation, if applicable, shall continue to be entitled to elect
all the Directors until holders of the Units of Series A Preferred Stock shall
have exercised their right to elect, voting as a separate class, two Directors,
after the exercise of which right (x) the Directors so elected by the holders of
Units of Series A Preferred Stock shall continue in office until their
successors shall have been elected by such holders or until the expiration of
the default period, and (y) any vacancy in the Board of Directors may (except as
provided in paragraph (C)(ii) of this Section 3) be filled by vote of a majority
of the remaining Directors theretofore elected by the holders of the class of
capital stock which elected the Director whose office shall have become vacant.
References in this paragraph (C) to Directors elected by the holders of a
particular class of capital stock shall include Directors elected by such
Directors to fill vacancies as provided in clause (y) of the foregoing sentence.

          (v)    Immediately upon the expiration of a default period, (x) the
right of the holders of Units of Series A Preferred Stock as a separate class to
elect Directors shall cease, (y) the term of any Directors elected by the
holders of Units of Series A Preferred Stock as a separate class shall
terminate, and (z) the number of Directors shall be such number as may be
provided for in the Articles or Bylaws of the Company (the "Bylaws").  Any
                                                            ------
vacancies in the Board of Directors effected by the provisions of clauses (y)
and (z) in the preceding sentence may be filled by a majority of the remaining
Directors.

          (vi)   The provisions of this paragraph (C) shall govern the election
of Directors by holders of Units of Preferred Stock during any default period
notwithstanding any provisions of the Articles or the Bylaws to the contrary.

          (D)    Except as set forth herein, holders of Units of Series A
Preferred Stock shall have no special voting rights and their consents shall not
be required (except to the extent they are entitled to vote with holders of
shares of Common Stock as set forth herein) for taking any corporate action.

          Section 4.  Certain Restrictions.  (A)  Whenever quarterly dividends
                      --------------------
or other dividends or distributions payable on Units of Series A Preferred Stock
as provided in Section 2 are in arrears, thereafter and until all accrued and
unpaid dividends and distributions, whether or not declared, on outstanding
Units of Series A Preferred Stock shall have been paid in full, the Corporation
shall not:

          (i)  declare or pay dividends on, make any other distributions on, or
     redeem or purchase or otherwise acquire for consideration any shares of
     junior stock;
<PAGE>

          (ii)   declare or pay dividends on or make any other distributions on
     any shares of parity stock, except dividends paid ratably on Units of
     Series A Preferred Stock and shares of all such parity stock on which
     dividends are payable or in arrears in proportion to the total amounts to
     which the holders of such Units and all such shares are then entitled;

          (iii)  redeem or purchase or otherwise acquire for consideration
     shares of any parity stock, provided, however, that the Corporation may at
                                 --------  -------
     any time redeem, purchase or otherwise acquire shares of any such parity
     stock in exchange for shares of any junior stock;

          (iv)   purchase or otherwise acquire for consideration any Units of
     Series A Preferred Stock, except in accordance with a purchase offer made
     in writing or by publication (as determined by the Board of Directors) to
     all holders of such Units.

          (B)    The Corporation shall not permit any subsidiary of the
Corporation to purchase or otherwise acquire for consideration any shares of
stock of the Corporation unless the Corporation could, under paragraph (A) of
this Section 4, purchase or otherwise acquire such shares at such time and in
such manner.

          Section 5.  Reacquired Shares.  Any Units of Series A Preferred Stock
                      -----------------
purchased or otherwise acquired by the Corporation in any manner whatsoever
shall be retired and cancelled promptly after the acquisition thereof.  All such
Units shall, upon their cancellation, become authorized but unissued Units of
Preferred Stock and may be reissued as part of a new series of Preferred Stock
to be created by resolution or resolutions of the Board of Directors, subject to
the conditions and restrictions on issuance set forth herein.

          Section 6.  Liquidation, Dissolution or Winding Up.  (A)  Upon any
                      --------------------------------------
voluntary or involuntary liquidation, dissolution or winding up of the
Corporation, no distribution shall be made (i) to the holders of shares of
junior stock unless the holders of Units of Series A Preferred Stock shall have
received, subject to adjustment as hereinafter provided in paragraph (B), the
greater of either (a) $1.00 per Unit plus an amount equal to accrued and unpaid
dividends and distributions thereon, whether or not earned or declared, up until
the date of such payment, or (b) the amount equal to the aggregate per share
amount to be distributed to holders of shares of Common Stock, or (ii) to the
holders of shares of parity stock, unless simultaneously therewith distributions
are made ratably on Units of Series A Preferred Stock and all other shares of
such parity stock in proportion to the total amounts to which the holders of
Units of Series A Preferred Stock are entitled under clause (i)(a) of this
sentence and to which the holders of shares of such parity stock are entitled,
in each case upon such liquidation, dissolution or winding up.

          (B)    In the event the Corporation shall, at any time after the
Rights Declaration Date, (i) declare any dividend on outstanding shares of
Common Stock payable in shares of Common Stock, (ii) subdivide outstanding
shares of Common Stock, or (iii) combine outstanding shares of Common Stock into
a smaller number of shares, then in each such case the aggregate amount to which
holders of Units of Series A Preferred Stock were entitled immediately prior to
such event pursuant to clause (i)(b) of paragraph (A) of this Section 6 shall be
adjusted by multiplying such amount by a fraction the numerator of which shall
be the number of shares of Common Stock that are outstanding immediately after
such event and the denominator of which shall be the number of shares of Common
Stock that were outstanding immediately prior to such event.

          Section 7.  Consolidation, Merger, etc.  In case the Corporation shall
                      --------------------------
enter into any consolidation, merger, combination or other transaction in which
the shares of common stock are exchanged for or converted into other stock or
securities, cash and/or any other property, then in any such case Units of
Series A Preferred Stock shall at the same time be similarly exchanged for or
converted into an amount per Unit (subject to the provision for adjustment
hereinafter set forth) equal to the aggregate amount of stock, securities, cash
and/or any other property (payable in kind), as the case may be, into which or
for which each share of Common Stock is converted or exchanged.  In the event
the Corporation shall at any time after the Rights Declaration Date (i) declare
any dividend on outstanding shares of Common Stock payable in shares of Common
Stock, (ii) subdivide outstanding shares of Common Stock, or (iii) combine
outstanding Common Stock into a smaller number of shares, then in each such case
the amount set forth in the immediately preceding
<PAGE>

sentence with respect to the exchange or conversion of Units of Series A
Preferred Stock shall be adjusted by multiplying such amount by a fraction the
numerator of which shall be the number of shares of Common Stock that are
outstanding immediately after such event and the denominator of which shall be
the number of shares of Common Stock that were outstanding immediately prior to
such event.

          Section 8.   Redemption.  The Units of Series A Preferred Stock shall
                       ----------
not be redeemable.

          Section 9.   Ranking.  The Units of Series A Preferred Stock shall
                       -------
rank junior to all other series of the Preferred Stock and to any other class of
preferred stock that hereafter may be issued by the Corporation as to the
payment of dividends and the distribution of assets, unless the terms of any
such series or class shall provide otherwise.

          Section 10.  Amendment.  The Articles, including, without limitation,
                       ---------
this resolution, shall not hereafter be amended, either directly or indirectly,
or through merger or consolidation with any other corporation or corporations in
any manner that would alter or change the powers, preferences or special rights
of the Series A Preferred Stock so as to affect them adversely without the
affirmative vote of the holders of a majority or more of the outstanding Units
of Series A Preferred Stock, voting separately as a class.

          Section 11.  Fractional Shares.  The Series A Preferred Stock may be
                       -----------------
issued in Units or other fractions of a share, which Units or fractions shall
entitle the holder, in proportion to such holder's fractional shares, to
exercise voting rights, receive dividends, participate in distributions and to
have the benefit of all other rights of holders of Series A Preferred Stock.

          Section 12.  Certain Definitions.  As used herein with respect to the
                       -------------------
Series A Preferred Stock, the following terms shall have the following meanings:

          (A) The term "Common Stock" shall mean the class of stock designated
                        ------------
as the common stock, no par value per share, of the Corporation at the date
hereof or any other class of stock resulting from successive changes or
reclassification of such common stock.

          (B) The term "junior stock" (i) as used in Section 4 shall mean the
                        ------------
Common Stock and any other class or series of capital stock of the Corporation
hereafter authorized or issued over which the Series A Preferred Stock has
preference or priority as to the payment of dividends and (ii) as used in
Section 6 shall mean the Common Stock and any other class or series of capital
stock of the Corporation over which the Series A Preferred Stock has preference
or priority in the distribution of assets upon any liquidation, dissolution or
winding up of the Corporation.

          (C) The term "parity stock" (i) as used in Section 4, shall mean any
                        ------------
class or series of stock of the Corporation hereafter authorized or issued
ranking pari passu with the Series A Preferred Stock as to the payment of
        ---- -----
dividends and (ii) as used in Section 6, shall mean any class or series of
capital stock ranking pari passu with the Series A Preferred Stock in the
                      ---- -----
distribution of assets upon any liquidation, dissolution or winding up of the
Corporation.

          3.  The number of shares constituting the Series A Preferred Stock is
5,000,000.

          4.  None of the Series A Preferred Stock has been issued.
<PAGE>

          We further declare under penalty of perjury under the laws of the
State of California that the matters set forth in this Certificate are true and
correct of our own knowledge.

Date:  December 22, 2000



                              _______________________________
                              Robert D. Glynn, Jr.
                              Chairman of the Board,
                              Chief Executive Officer, and President



                              _______________________________
                              Leslie H. Everett
                              Vice President and
                              Corporate Secretary
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>6
<FILENAME>dex10.txt
<DESCRIPTION>THE GAS ACCORD SETTLEMENT AGREEMENT
<TEXT>

<PAGE>

                                                                      EXHIBIT 10

                          CPUC Promising Gas Options
                                 OII 99=07=003



                         Operational Flow Order (OFO)
                             Settlement Agreement



                               October 20, 1999



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    Rule 601 et seq. of the FERC Rules of Practice. Rule 408 of the Federal
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<PAGE>

                   CPUC Promising Gas Options OII 99-07-003
               Operational Flow Order (OFO) Settlement Agreement

                               TABLE OF CONTENTS
                               -----------------

<TABLE>
<S>                                                                         <C>
A.   Introduction..........................................................  1

B.   Forum for Resolving Future Balancing Issues...........................  3

C.   Provisions Designed to Reduce the Number and to Increase the
     Predictability of OFOs................................................  4

     1.  Operational Information...........................................  4

     2.  Pipeline Inventory Limits.........................................  6

     3.  Customer-Specific OFOs............................................  7

     4.  Cashout Prices....................................................  9

     5.  Core Procurement Group Imbalances................................. 10

     6.  Storage Allocation to Balancing................................... 11

D.   Provisions Designed to Reduce the Impact of OFOs...................... 12

     1.  OFO Notification.................................................. 12

     2.  Noncompliance Charges During an OFO............................... 12

     3.  OFO Noncompliance Charge Exemption................................ 13
</TABLE>



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October 20, 1999                                                          Page i
<PAGE>

                   CPUC Promising Gas Options OII 99-07-003

               Operational Flow Order (OFO) Settlement Agreement

A.   Introduction
     ------------

     The purpose of this OFO Settlement Agreement (Agreement, Settlement, or
     Settlement Agreement) is to revise Pacific Gas and Electric Company's
     (PG&E's) operating guidelines and gas tariffs to achieve the following
     goals:

     .  Improve market access to operational information necessary for the
        management of gas imbalances on PG&E's system.

     .  Significantly reduce the number of system-wide OFOs on the PG&E system.

     .  Reduce the impact of OFOs on the market.

     .  Revise certain procedures implemented under the Gas Accord, in order to
        improve system operating efficiency, to clarify criteria used by PG&E in
        making operational decisions, and to enhance customer interfaces with
        PG&E's gas operations.

     .  Improve the transparency of operations to improve upon operational
        signals to the market.

     .  Improve the ability of the market to foresee OFO events.

     .  Maintain the OFO process as both a signal and an incentive to the market
        to balance supply and demand.

     This Agreement is entered into by the Settlement Parties, as identified by
     their attached signatures. This Agreement shall become effective on the
     first day of the month following the thirtieth day after the date of a
     California Public Utilities Commission ("CPUC" or "Commission") order
     approving the OFO Settlement Agreement and shall continue in effect through
     December 31, 2002.

     On March 1, 1998, the Northern California natural gas market experienced a
     dramatic change with the restructuring of services on the PG&E system under
     a broadly-based settlement known as the "Gas Accord". Many
     previously-bundled PG&E services were unbundled, providing more choice to
     marketers, shippers, and end-use customers. PG&E and the Gas Accord
     settling parties worked to develop the rules and guidelines to operate
     PG&E's system under the Gas Accord provisions, including the unbundling of
     pipeline transmission and storage services within Northern California. The
     Gas Accord is effective through December 31, 2002.

     Experience under the Gas Accord has indicated that certain adjustments are
     appropriate, particularly with regard to customer balancing requirements
     and charges; to issuance of


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    Rule 601 et seq. of the FERC Rules of Practice. Rule 408 of the Federal
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    =======================================================================

October 20, 1999                                                          Page 1
<PAGE>

CPUC Promising Gas Options OII 99-07-003
OFO Settlement Agreement
------------------------

     OFOs; to whether OFOs are issued on a system-wide or customer-specific
     basis; and to the operational information provided to the market and to
     individual shippers.

     This Agreement represents a settlement on these issues set forth herein in
     the context of the natural gas strategy (D.99-07-015and I.99-07-003) of the
     CPUC. Not all of the provisions agreed to herein require tariff changes,
     and some provisions have already been implemented. Nevertheless, it is
     important and appropriate to document here all issues where parties have
     agreed to changes in operating guidelines and procedures.

     This Agreement does not change the basic principles and structure of the
     Gas Accord as agreed to by the settling parties to the Gas Accord and as
     approved by the Commission in Decision 97-08-055. The operating guideline
     and gas tariff changes included within this Agreement, and made a part
     hereof, are intended to modify certain limited implementation parameters of
     the Gas Accord, and the Settlement Parties agree that such revisions are
     within the original bounds of the Gas Accord structure.

     This Agreement is a negotiated compromise of operational issues and is
     broadly supported by parties who are marketers, shippers, wholesale and
     retail end-use customers, and regulatory representatives. Nothing contained
     herein shall be deemed to constitute an admission or an acceptance by any
     party of any fact, principle, or position contained herein, except to the
     extent that Settlement Parties, by signing this Agreement, acknowledge that
     they pledge support for Commission approval and subsequent implementation
     of these provisions.

     This Agreement is to be treated as a complete package and not as a
     collection of separate agreements on discrete issues or proceedings. To
     accommodate the interests of different parties on diverse issues, the
     Settlement Parties acknowledge that changes, concessions, or compromises by
     a party or parties in one section of this Agreement necessitated changes,
     concessions, or compromises by other parties in other sections.

     This Agreement is intended to quickly resolve specific operating issues.
     Decision 99-07-015 in R.98-01-011 contains additional proposals or issues
     related to utility balancing services, imbalance trading, real-time
     customer usage data, electronic bulletin boards, and other areas. PG&E and
     the parties are pursuing or intend to pursue settlement discussions of
     these additional issues. New settlement(s) may result in modifications to
     some of the provisions contained in this Agreement.

     As this OFO Settlement simply modifies the implementation of existing
     operating parameters, PG&E will not seek to recover any costs associated
     with implementing the provisions of this Settlement Agreement, except under
     the provisions of Section B, below. This agreement on cost recovery is not
     a precedent with respect to other settlements, litigation or regulatory
     cases.



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    Rule 601 et seq. of the FERC Rules of Practice. Rule 408 of the Federal
             -- ---
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    =======================================================================

October 20, 1999                                                          Page 2

<PAGE>

CPUC Promising Gas Options OII 99-07-003
OFO Settlement Agreement
------------------------

B.   Forum for Resolving Future Balancing Issues
     -------------------------------------------

     1.  The Settlement Parties intend that the provisions contained in this
         settlement will significantly reduce the number of system-wide OFOs on
         PG&E's system. The Settlement Parties, through the Gas OFO Forum,
         intend to monitor the effectiveness of the Settlement measures in
         reducing the number of OFOs and to address on an ongoing basis,
         improvements and/or modifications to PG&E's balancing and OFO
         procedures. Any interested shipper or customer on the PG&E transmission
         system who may be subject to OFOs may choose to participate in this
         Forum.

     2.  If, six months after the effective date of this Settlement, there has
         not been at least a twenty-five (25) percent reduction in the number of
         system-wide OFOs during this first six-month period compared to the
         same period in the prior year(s), PG&E in its next quarterly OFO report
         (see Section C.1.f), will provide an analysis of why the number of OFOs
         has not been reduced and propose additional measures to reduce the
         number of system-wide OFOs in addition to those measures outlined in
         this OFO Settlement Agreement. PG&E and the other members of the Forum
         will consider in good faith whether, and how, PG&E's proposed
         additional measures, as well as any other proposals suggested by other
         Forum members, should be adopted.

     3.  The Gas OFO Forum will further explore the following issues:
         a.  The effectiveness of customer-specific OFOs and possible
             improvements to the procedure outlined in this Settlement,
             including the need and methodology for changes to the Performance
             Factor set forth in Section C.3.b.(7).

         b.  Whether and how parties who significantly contribute to system-wide
             OFOs on a repeated basis, e.g. to three (3) or more per month,
             should be specifically identified. A "significant contributor" is
             defined as any balancing entity with total imbalances greater than
             5,000 Dth and 10 percent of its usage in the three days leading up
             to each system-wide or customer-specific OFO. For Core Procurement
             Groups, supply will be compared to their Determined Usage, which is
             the Cumulative Imbalance (except for OFO days when the 24-hour
             forecast will be used).

         c.  Whether the exemption for OFO noncompliance charges set forth in
             Section D.3.b should be increased.

         d.  The need for the allocation of additional storage to balancing (see
             Section C.6).

         e.  Changing the Cash-out procedures.

         f.  Other issues which relate to PG&E pipeline balancing and OFOs.

     4.  PG&E may seek recovery of implementation costs to provide additional
         information or implement additional procedures which are recommended by
         the Forum. Estimates of these costs will be provided to the Forum for
         discussion prior to PG&E filing for recovery. PG&E may seek such
         recovery and/or establishment of a balancing or memorandum account for
         these projected costs prior to implementing the recommendation. Other
         parties to this Settlement do not necessarily support PG&E's right to
         recover these implementation costs.



    =======================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure.
    Rule 601 et seq. of the FERC Rules of Practice. Rule 408 of the Federal
             -- ---
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<PAGE>

CPUC Promising Gas Options OII 99-07-003
OFO Settlement Agreement
------------------------

C.   Provisions Designed to Reduce the Number and to Increase the Predictability
     ---------------------------------------------------------------------------
     of OFOs
     -------

     1.  Operational Information

         a.    PG&E will provide the following daily operational information on
               its Pipe Ranger Web site.

               (1)  Composite system temperature

               (2)  System demand

               (3)  Off-system deliveries by delivery point

               (4)  Fuel and lost and unaccounted for (LUAF) gas

               (5)  Storage injection by storage operator

               (6)  Total system demand (sum of items 2, 3, 4, & 5 above)

               (7)  Interconnect supply by receipt point

               (8)  Storage withdrawal by storage operator

               (9)  Total system supply (sum of items 7 & 8 above)

               (10) Pipeline inventory change (supply minus demand, item 9 -
                    item 6)

               (11) Beginning and ending pipeline

               (12) Pipeline inventory lower and upper operating limits (as
                    established in this agreement)

               (13) Difference between ending pipeline inventory and operating
                    limits
               (14) Operational flow order (OFO), emergency flow order (EFO) and
                    involuntary diversion status

               (15) Storage activity by injection and withdrawal, not just net
                    activity

               (16) Storage injection and withdrawal used for pipeline balancing

               (17) On-system supply

         b.    Forecast information specified in C.1.a, above, will be provided
               for the current day and the next three days. This forecast is
               updated approximately five times per day. PG&E will establish
               specific not-later-than times of the day when the updates will
               occur. If for some reason the data is not available by this time,
               PG&E will place a notice on its Pipe Ranger Web site indicating
               when the forecast data will be available.

         c.    Historical data will be provided for the prior two weeks.

         d.    Additionally, PG&E will provide on its Pipe Ranger Web site:

               (1)  Maximum pipeline capacity by path.

               (2)  Maximum daily pipeline capacity at interconnection points
                    for current day and next day.

               (3)  Monthly demand forecast by customer class.

               (4)  Daily storage inventory level for pipeline balancing as part
                    of the three-day historical data (updated monthly to reflect
                    cashouts and other adjustments).

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        Subject to Rule 51 of the CPUC Rules of Practice and Procedure.
    Rule 601 et seq. of the FERC Rules of Practice. Rule 408 of the Federal
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October 20, 1999                                                          Page 4
<PAGE>

CPUC Promising Gas Options OII 99-07-003
OFO Settlement Agreement
------------------------

             (5)     Current month imbalance gas in storage.

             (6)     Receipt point allocation and end-user curtailment
                     quantities for the system when pipeline operational
                     conditions requires allocations (trimming for balancing
                     purposes) or end-user curtailment. Customer-specific data
                     will only be provided to that customer or their designated
                     agent.

             (7)     Daily demand by customer class using the "24-hour forecast"
                     with a three-day posting lag.

             (8)     Daily demand by customer class using the day-after forecast
                     with a three-day posting lag.

             (9)     Balance of cash-in/out gas in storage and prior month
                     imbalances not cleared on a monthly basis.

             (10)    Cumulative sum of the changes in pipeline inventory (line
                     pack).

         e.  PG&E will maintain records of daily injection and withdrawal and
             daily storage inventory levels for all storage accounts.

         f.  PG&E will post a quarterly OFO report on its Pipe Ranger Web site
             pertaining to the number and causes of each customer-specific and
             system-wide OFO, EFO, and "trimming" occasion ("Event") within the
             prior three (3) months. PG&E will post this report within 30 days
             after the close of the calendar quarter. The first OFO report may
             cover less than three months of operation under this Agreement.

             These quarterly OFO reports will show the sources of system
             imbalance for each of the three (3) days prior to an Event, as
             follows:

             1)      Imbalance and gas scheduled for each entity responsible for
                     managing imbalances as specified in C.3.b.(3). For Core
                     Procurement Groups, the supply will be compared to their
                     Determined Usage, which is their Cumulative Imbalance
                     (except for OFO days when the 24-hour forecast will be
                     used). Each such entity will be identified by a new and
                     unique numerical identifier, and not by name.

             2)      Pipeline imbalances.

             3)      Net market center imbalances for the aggregate of parking,
                     lending and storage services.

             4)      Pipeline balancing provided by allocated storage.

             5)      Beginning, ending and change in pipeline inventory.

             6)      Any proposed changes to any OFO and balancing procedures
                     and/or methodology addressed in this Settlement.

         g.  The Settlement Parties agree that for a period continuing until
             twelve (12) months after the date this Settlement is filed with the
             CPUC, the operational information provided herein is the
             information needed for the market to analyze the status of PG&E's
             pipeline balancing service and to anticipate OFOs. During this
             period, PG&E need not provide additional data relevant to OFOs,
             except as referenced in Section B.3.b or as agreed to by PG&E and
             the other Settlement Parties. After this 12 month period, the other
             Settlement Parties reserve their rights to bring to PG&E

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October 20, 1999                                                          Page 5
<PAGE>

CPUC Promising Gas Options OII 99-07-003
OFO Settlement Agreement
------------------------

             requests for further information, and PG&E agrees to engage in good
             faith efforts to resolve such requests. The limitation on
             information contained in this section does not limit, in any
             manner, information requests pertaining to other matters, e.g.
             electronic bulletin boards, imbalance trading, curtailments (local
             or system-wide), secondary markets, capacity rights, and/or any
             other issue contained in I.99-07-003 or a separate CPUC proceeding.

         h.  No tariff changes are needed to revise the operational information
             provided.

     2.  Pipeline Inventory Limits

         a.  PG&E will adjust its current procedures for determining when an OFO
             is needed and for issuing an OFO. PG&E will issue an OFO for a Gas
             Day if, on the day prior to this Gas Day, PG&E's forecast of
             pipeline inventory for the Gas Day is either below the Lower
             Pipeline Inventory Limit or above the Upper Pipeline Inventory
             Limit, as provided in Sections C.2.c through f below. PG&E will
             continue its current practice of determining the need for and
             issuing of an OFO by 7:30 a.m. on the day before the Gas Day, or as
             soon as possible thereafter. This practice is intended to allow
             parties whose imbalances exceed the OFO tolerance band to use all
             four nomination cycles, as specified in Gas Rule 21, Section B.3.d,
             to make supply adjustments and avoid or reduce noncompliance
             charges. Situations may still occur when an OFO needs to be issued
             later in the day prior to Gas Day as is allowed by Gas Rule 14,
             Section E.

         b.  The Lower and Upper Pipeline Inventory Limits are the levels below
             and above which the safety and reliability of pipeline operations
             are in jeopardy. These Limits replace the desired target inventory
             levels and the range of 200 MMcf/d above and the 150 MMcf/d below
             as currently specified in Gas Rule 14. This change allows the
             pipeline to operate to the operational limits each day, without
             anticipating trends in what suppliers schedule relative to market
             demand.

         c.  The Lower and Upper Pipeline Inventory Limits will change, as
             specified in Section C.2.d, below, depending on whether the
             forecast of total system demand (the sum of on-system demand and
             off-system deliveries) is "Low" or "High". The reason for the
             change in the Pipeline Inventory Lower Limit is that under low
             system demand, the required minimum pressures on the system can be
             maintained at a lower pipeline inventory level. Higher demand
             levels require higher pipeline inventories to maintain system
             minimum pressures. The Upper Pipeline Inventory Limit is set to
             allow for variations in supply or usage forecasts. Under low system
             demand conditions, the potential is greater that forecast
             variations must be absorbed by the pipeline inventory; therefore,
             the Upper Pipeline Inventory Limit is set lower to allow for this
             greater variability without jeopardizing operations. Under higher
             system demand conditions, forecast variations are often managed by
             supply or storage withdrawal adjustments, so the Upper Pipeline
             Inventory Limit can be set higher.

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    =======================================================================

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<PAGE>

CPUC Promising Gas Options OII 99-07-003
OFO Settlement Agreement
------------------------

         d.  The Pipeline Inventory Limits used to determine OFOs are:

                                                 Pipeline Inventory Limits, MMcf
                                                 -------------------------------
              Total Demand Forecast, MMcf               Lower        Upper
              ---------------------------               -----        -----
              Low Demand:         1,500 to 2,800        3,900        4,500
              High Demand:        2,800 to 3,900        4,000        4,600

         e.  PG&E may elect not to issue an OFO for a Gas Day if the forecast of
             pipeline inventory for the day following that Gas Day indicates the
             pipeline inventory will return to within the Pipeline Inventory
             Limits without the assistance of an OFO.

         f.  The Lower and Upper Pipeline Inventory Limits in effect each day
             will be shown in the pipeline inventory report on the Pipe Ranger
             Web site.

         g.  PG&E may revise these Pipeline Inventory Limits beyond those
             specified in the table in Section C.2.d above. Any such revisions
             will be established to ensure pipeline safety and reliability.

             (1)  Changes in the Pipeline Inventory Limits which are needed to
                  reflect operating conditions or limitations, including force
                  majeure events, can be implemented immediately as those
                  conditions warrant. PG&E will post these changes on its Pipe
                  Ranger Web site along with an explanation of the operational
                  limitation.

             (2)  Pipeline Inventory Limits may also change due to more
                  predictable factors. These include changes in end-user
                  demands, compressor operating conditions, pipeline and
                  compressor maintenance activities, and other operational
                  inputs which are used to determine the physical operating
                  limits of the pipeline. PG&E will post these changes on its
                  Pipe Ranger Web site at least two weeks before implementation,
                  along with a supporting explanation.

             (3)  If PG&E proposes to change the methodology used to decide when
                  to issue OFOs, PG&E will seek approval of such modifications
                  from the Gas OFO Forum before making this change.

     3.  Customer-Specific OFOs

         a.  PG&E's Gas Rule 14, Section E, currently provides for
             customer-specific OFOs to be issued. Since April 1, 1998, PG&E has
             issued several customer-specific OFOs when it was clear that a
             limited number of large customer imbalances were the main
             contributors to the system imbalance. To be more effective, a
             better definition of the guidelines for issuing customer-specific,
             or targeted, OFOs is needed.

         b.  PG&E will use the following process and criteria to determine when
             to issue customer-specific OFOs, rather than a system-wide OFO, and
             to determine which balancing entities are subject to the
             customer-specific OFO.

             (1)  PG&E determines whether an OFO is needed for a Gas Day, as
                  described in Section C.2, Pipeline Inventory Limits.

             (2)  If an OFO needs to be issued, the on-system imbalance is
                  estimated for that OFO Day as the difference between the
                  forecast on-system supply and on-system demand. A portion of
                  this imbalance can be accommodated by (i) the

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    =======================================================================

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<PAGE>

CPUC Promising Gas Options OII 99-07-003
OFO Settlement Agreement
------------------------

                  amount of pipeline inventory available within the Pipeline
                  Inventory Limits, plus (ii) the storage injection or
                  withdrawal capacity available for system load balancing. This
                  portion of the imbalance that can be accommodated is divided
                  by the forecast on-system demand to determine the OFO
                  Tolerance Band (set as a percentage of usage). The remaining
                  imbalance is the volume of needed supply and/or demand relief
                  for the pipeline to stay within its Inventory Limits.

             (3)  Next, PG&E prepares an internal imbalance report forecasting
                  the OFO Day imbalance for each entity responsible for managing
                  imbalances. These "balancing entities" are: (a) Noncore
                  Balancing Aggregation Agreement (NBAA) agents; (b) Core
                  Procurement Groups (CPGs); and (c) Individual end-users who do
                  not have an NBAA agent.

             (4)  These balancing entity forecasts are composed of the same
                  individual end-use customer demand forecasts that are used to
                  forecast OFO compliance on INSIDEtracc. No change is proposed
                  in these methods.

             (5)  PG&E then reviews the internal imbalance report and identifies
                  those balancing entities with forecast imbalances exceeding
                  both the calculated OFO Tolerance Band percentage and an
                  imbalance volume of 5,000 Dth.

             (6)  Customer-specific OFOs will be issued, if (i) there are no
                  more than 10 balancing entities, and (ii) the total forecast
                  imbalance relief they would provide in aggregate, multiplied
                  by a Performance Factor, exceeds the volume relief needed for
                  the pipeline, as calculated in Section C.3.b.(2), above.

             (7)  The customer-specific OFO Performance Factor is a measure of
                  the historic effectiveness of these OFOs. Experience shows
                  that balancing entities issued an OFO may trade gas to get
                  within the tolerance band. However, such traded gas is still
                  on the system and does not help offset pipeline inventory
                  levels, since there is usually not an accompanying change in
                  demand under these circumstances. Therefore, the resulting
                  pipeline inventory relief provided may be less than forecast.
                  The Performance Factor is the system relief actually achieved
                  by customer-specific OFOs divided by the forecast relief
                  calculated per Section C.3.b.(6) above. Adjustments may be
                  made to the calculation to reflect experience over several
                  customer-specific OFOs and to normalize for such factors as
                  temperature differences between the forecast and actual data.
                  The Performance Factor may differ depending on whether it is a
                  high or low inventory OFO situation. The Performance Factor is
                  set initially at 100% for both high and low inventory
                  conditions. PG&E may adjust the Performance Factor. The
                  Performance Factor will not be adjusted to a percentage which
                  is less than the average of the actual performance for all
                  customer-specific OFOs since the effective date of this
                  Settlement. However, unless required by operational
                  conditions, PG&E will not reduce the Performance Factor below
                  50% without the prior consent of the Forum. PG&E will post the
                  changes to the Performance Factor, along with supporting data
                  and explanation within 14 days of each customer-specific OFO.
                  If a customer-specific OFO is issued within this 14-day
                  period, the Performance Factor currently in effect will be

    =======================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure.
    Rule 601 et seq. of the FERC Rules of Practice. Rule 408 of the Federal
             -- ---
      Rules of Evidence, and Section 1152 of the California Evidence Code
    =======================================================================

October 20, 1999                                                          Page 8
<PAGE>

CPCU Promising Gas Option OII 99-07-003
OFO Settlement Agreement
------------------------

                  used. This information will be evaluated by the Gas OFO Forum
                  on an ongoing basis.

             (8)  In the event the conditions of Section C.3.b.(6) are not met,
                  a system-wide OFO will be issued.

             (9)  On occasion, even if the conditions of Section C.3.b.(6) are
                  met, operating experience or market conditions may indicate to
                  PG&E that customer-specific OFOs will not be effective in
                  achieving needed pipeline inventory relief. In these
                  instances, a system-wide OFO will be issued. If the conditions
                  of Section C.3.b.(6) are met, yet PG&E calls a system-wide
                  OFO, PG&E will post an explanation of the factors causing PG&E
                  to determine not to call a customer-specific OFO on its Pipe
                  Ranger Web site, and will include such information in its
                  quarterly OFO reports.

         c.  PG&E will post a general market notification of customer-specific
             OFOs on its Pipe Ranger Web site by 7:30 a.m. PT on the day before
             Gas Day, or as soon as possible thereafter, and will notify the
             affected balancing entities by 8:00 a.m. PT, or as soon as possible
             thereafter.

         d.  No tariff revisions are needed to reflect the operating guidelines
             set forth above for issuing customer-specific OFOs.

     4.  Cashout Prices

         a.  The Gas Accord Settlement provides that: "The intent of imbalance
             cashouts is to create an economic disincentive for incurring
             cashout imbalances. PG&E will file to revise the imbalance charges
             and cashout options if the Gas Accord provisions do not accomplish
             this." (D.97-08-055, Appendix 1, E.13.d.vii, page 26) At least
             three times since the beginning of the Gas Accord, the
             underdelivery cashout price was lower than the spot price,
             providing the market with an incentive to cash-out rather than
             avoiding or trading imbalances. This has occurred only for Tier I
             commodity cashouts where the cashout price is either 95% or 105% of
             the weighted market price. In these cases, certain marketers
             arbitraged this cashout price by buying the gas from PG&E as
             provided in Schedule G-BAL.

         b.  The commodity cashout price will be changed for Tier I Cashouts in
             Schedule G-BAL to 75% (from 95%) of the Weighted Overdelivery Index
             and to 125% (from 105%) of the Weighted Underdelivery Index.

         c.  Commodity cashout transactions will continue to be recorded in the
             Balancing Charge Account (BCA).

    ========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure,
    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
       Rules of Evidence, and Section 1152 of the California Evidence Code
    ========================================================================

October 20, 1999                                                          Page 9

<PAGE>

CPCU Promising Gas Option OII 99-07-003
OFO Settlement Agreement
------------------------

     5.  Core Procurement Group Imbalances

         a.  Core Procurement Groups (CPGs), which include PG&E's Core
             Procurement Department, serve residential and small commercial
             customers whose meters do not generally provide daily usage data.
             Their cumulative usage over a "cycle" period is read at the meter
             and recorded in a PG&E data base. They are also billed on this
             cycle basis, not on a calendar month. Since cycles overlap months,
             two cycles of meter data are needed to calculate a given calendar
             month's meter use for these customers.

         b.  Recognizing these data limitations, certain provisions were
             implemented as part of the Gas Accord so that CPGs could manage
             their daily and monthly imbalances like the other marketers,
             shippers and noncore customers. One of these provisions was the
             Core Load Forecasting and Determination Service, which forecasts
             the upcoming Gas Day usage for each CPG 24 hours and 48 hours prior
             to the Gas Day, as well as provides a usage estimate on the morning
             of the Gas Day. The CPG usage estimate provided on the Gas Day
             itself is called the Determined Usage. The Determined Usage is used
             by PG&E to determine two monthly imbalances for each CPG: the
             Cumulative Imbalance and the Operating Imbalance.

             (1)  Cumulative Imbalances are the monthly accumulation of each
                  day's scheduled supply less Determined Usage. Cumulative
                  Imbalances are calculated at the end of each month and may be
                  traded, cashed-out or carried over to the subsequent month.

             (2)  Operating Imbalances are the difference between calendar month
                  Determined Usage and metered usage. Metered usage for a
                  calendar month is calculated by the appropriate weighting of
                  the measured cycle usage. An Operating Imbalance Statement for
                  a particular month is normally provided to customers two
                  months following the processing of the Cumulative Imbalance
                  Statement for the same month. This added time is necessary to
                  collect and process the billing cycle usage data needed to
                  calculate the indicated calendar month usage. These Operating
                  Imbalances may be traded into or out of storage, traded with
                  other customer Operating Imbalances for the same calendar
                  month, or under current provisions, carried over to the month
                  following the date on which the Operating Imbalance Statement
                  is issued.

         c.  To allow more flexibility in managing their total imbalances, CPGs
             will now be able to trade Operating Imbalances with any Cumulative
             Imbalances issued in the same month. The trading between Cumulative
             and Operating Imbalances is subject to the following rules:

             (1) Trades must occur in the regular monthly Cumulative Imbalance
                 trading period.

             (2) Trades must move the total Operating Imbalance towards, but not
                 past, zero.

         d.  Accounting adjustments for CPGs as provided in Schedule G-BAL will
             be included in their Operating Imbalance Carryover.

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    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
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    ========================================================================

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<PAGE>

CPCU Promising Gas Option OII 99-07-003
OFO Settlement Agreement
------------------------


         e.  Currently, any Operating Imbalance remaining after the Trading
             Period normally becomes the first gas through the meter in the
             month following the trading period. Since an imbalance repayment
             has no offsetting demand and can be relatively large, it is
             important to spread these deliveries out over a longer period of
             time so the impact on pipeline balancing and the possible need to
             issue OFOs is minimized. This also allows positive and negative
             Operating Imbalances to offset each other over time. Therefore, the
             following process is adopted for CPGs to repay untraded Operating
             Imbalances over approximately a one-year period: (1) An Operating
             Imbalance Carryover account is established to accumulate (credit)
             and repay

                  (debit) the untraded monthly Operating Imbalances.
             (2)  Each month, following the trading period, the untraded
                  Operating Imbalance is credited to the Operating Imbalance
                  Carryover.

             (3)  Each month, one-twelfth (1/12) of the Operating Imbalance
                  Carryover at the end of the prior month will be considered the
                  first transaction for that CPG and will be debited to its
                  Operating Imbalance Carryover.

             (4)  A CPG may also make a monthly election to clear its entire
                  Operating Imbalance Carryover if it is less than 5,000 Dth.
                  This will be considered the first transaction during the
                  calendar month following PG&E's receipt of written
                  notification, and will set the Operating Imbalance Carryover
                  to zero.

         f.  PG&E will continue to provide customers with information on the
             basic assumptions and methods used to develop demand forecasts for
             Core Procurement Groups. PG&E will also continue to assess and
             implement appropriate and cost-effective modifications to its
             forecasting processes, with the objective of reducing Operating
             Imbalances.

     6.  Storage Allocation to Balancing

         a.  Settlement Parties agree that no additional storage assets will be
             allocated to balancing at this time. Parties may agree in a future
             settlement to either add or reduce the amount of PG&E storage
             assets allocated to system balancing.

         b.  PG&E will provide the Settlement Parties, no later than the date
             initial testimony is due in I.99-07-003, with a report which
             describes the cost of adding and/or allocating additional storage
             assets to system balancing. This storage report will include the
             cost of each component (inventory and compressors), the anticipated
             effect on operations and OFOs, and the effect on rates.

    ========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure,
    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
       Rules of Evidence, and Section 1152 of the California Evidence Code
    ========================================================================

October 20, 1999                                                         Page 11
<PAGE>

CPCU Promising Gas Option OII 99-07-003
OFO Settlement Agreement
------------------------

D.   Provisions Designed to Reduce the Impact of OFOs
     ------------------------------------------------

     1.  OFO Notification

         a.  PG&E will continue to notify the market of system-wide and
             customer-specific OFOs as soon as practically possible. Primary
             notice will continue to be posted on INSIDEtracc. Notice will also
             continue to be provided on PG&E's Pipe Ranger Web site. In addition
             to electronic mail and/or a FAX for OFO notification, customers may
             now also sign up to receive an alpha page, which replaces the less
             effective "blast-paging."

         b.  PG&E currently provides the following information to the market for
             system-wide OFOs:

             (1)  Date of the OFO.

             (2)  Tolerance Band in percent.

             (3)  Stage (i.e., 1, 2, 3, or 4) as established in this Agreement.

             (4)  Noncompliance Charge in $ per therm.

             (5)  Reason (i.e., High or Low pipeline inventory).

         c.  No tariff changes are needed to reflect these adjustments to PG&E's
             OFO notification options or procedures.

     2.  Noncompliance Charges During an OFO

         a.  Experience with OFOs has indicated that some customers tend to
             over-adjust their supply (and sometimes demand) in order to
             minimize the risk of being outside the tolerance band and subject
             to an OFO noncompliance charge. The objective in issuing an OFO is
             to match the market reaction to the system need for imbalance
             relief, and thereby permit the system to stay within operating
             limits. A lower noncompliance charge which is closer to the
             movement of commodity prices in the market should encourage parties
             to more accurately adjust their supplies to their expected demand
             under most OFO conditions.

         b.  PG&E still retains the option under the tariffs of commencing an
             OFO at a higher stage and noncompliance charge, or even increasing
             the stage later in the day.

         c.  The noncompliance charge for a Stage 1 OFO will be reduced from
             $0.10 to $0.025 per therm. Another stage will be added after Stage
             1 with a noncompliance charge of $0.10 per therm and a tolerance
             range up to +/-20%. The table currently included in the Gas Rule
             14, Section E, will be revised to the following:

                                   Tolerance Band        Noncompliance Charge
                                   As a % of Usage         Dollars Per Therm

               Stage 1:             up to +/-25%                $0.025
               Stage 2:             up to +/-20%                 $0.10
               Stage 3:             up to +/-15%                 $0.50
               Stage 4:              up to +/-5%                 $2.50

    ========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure,
    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
       Rules of Evidence, and Section 1152 of the California Evidence Code
    ========================================================================

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<PAGE>

CPCU Promising Gas Option OII 99-07-003
OFO Settlement Agreement
------------------------

          3.  OFO Noncompliance Charge Exemption

              a.  Currently, some customers have difficulty in complying with
                  OFOs because the gas market generally requires gas commodity
                  purchases in packages of at least 5,000 Dth per transaction,
                  or charges a premium for "small or odd lot" deals.

              b.  All balancing entities will be exempt from OFO noncompliance
                  charges if their total monthly OFO noncompliance charges are
                  equal to or less than $1,000. This noncompliance charge
                  exemption will allow those customers with small imbalances to
                  avoid making supply or demand adjustments during an OFO, even
                  if their imbalance as a percent of their demand is outside the
                  allowable OFO tolerance band.

              c.  PG&E may prospectively withdraw this exemption or reduce the
                  exemption level if in PG&E's sole judgment this provision
                  contributes to an increase in OFOs. PG&E will provide notice
                  to, and will consult with, the Gas OFO Forum prior to making
                  such a change.

              d.  There shall be no exemptions from noncompliance charges during
                  EFOs or Involuntary Diversions.

    ========================================================================
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    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
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    ========================================================================

October 20, 1999                                                          Page13
<PAGE>

                          CPUC Promising Gas Options
                                  I.99-07-003


                             Comprehensive Gas OII
                             Settlement Agreement


                               January 28, 2000


    =======================================================================
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    Rule 601 et seq. of the FERC Rules or Practice, Rule 408 of the Federal
             -- ---
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    =======================================================================
<PAGE>

                     CPUC Promising Gas Options I.99-07-003
                   Comprehensive Gas OII Settlement Agreement

                               Table of Contents
                               -----------------

<TABLE>
<CAPTION>
<S>   <C>                                                                                  <C>
1.    INTRODUCTION........................................................................  1
2.    PROMISING OPTIONS WHICH ARE PUT IN PLACE BY THIS SETTLEMENT AGREEMENT...............  4
   2.1  Cost and Rate Separation for Balancing Services [Self-Balancing Options]..........  4
   2.2  Electronic Trading of Imbalances [Including Rights]...............................  8
   2.3  Re-examine Utility Role in Core Procurement Once a Specified Competitor Market
         Share Has Been Achieved.......................................................... 13
   2.4  Eliminate Core Aggregation Transportation Thresholds After Adoption of Consumer
         Protection Measures.............................................................. 14
   2.5  Unbundle Utility Storage Costs for Core Customers [Served by CTAs]................ 14
   2.6  Separate Costs and Rates for Core Utility [Procurement] Services.  Treat Utility
         Core Procurement Departments as Any Other Utility Customer....................... 18
   2.7  Provide Details of Completed Transactions......................................... 19
   2.8  Establish a Secondary Market [Trading System] via a Utility Electronic  Bulletin
         Board............................................................................ 19
   2.9  Provide Real-Time, Customer-Specific Usage Data................................... 20
   2.10 Provide Competitive Metering Technologies......................................... 22
   2.11 Provide Competitive Billing Options to Customers Similar to Those Offered in the
         Electric Industry................................................................ 25
3.    PROMISING OPTIONS ALREADY IN PLACE FOR PG&E......................................... 27
   3.1  Create Firm Tradable Intrastate Transmission Rights............................... 27
   3.2  Establish a Secondary Market for Intrastate Transmission Capacity................. 27
   3.3  Place the Utility At Risk for Unused [Transmission] Resources..................... 27
   3.4  Create Firm, Tradable Storage Rights.............................................. 28
   3.5  Establish a Secondary Market For Intrastate Storage Capacity...................... 28
   3.6  Place the Utility At-Risk for Unused [Storage] Resources.......................... 28
   3.7  Separate Utility Hub Services From Procurement Functions.......................... 29
   3.8  Unbundle Utility Interstate Capacity Costs for Core Customers..................... 29
   3.9  Eliminate Core Subscription Service............................................... 29
</TABLE>

                                       i

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    =======================================================================
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    Rule 601 et seq. of the FERC Rules or Practice, Rule 408 of the Federal
             -- ---
       Rule of Evidence and Section 1152 of the California Evidence Code
    =======================================================================
<PAGE>

                     CPUC Promising Gas Options I.99-07-003
                   Comprehensive Gas OII Settlement Agreement

                         Table of Contents (continued)
                         -----------------------------

<TABLE>
<S>   <C>                                                                                  <C>
4.    PROMISING OPTIONS AND OTHER ISSUES WHICH ARE NOT TO BE LITIGATED PENDING FURTHER
      SETTLEMENT DISCUSSIONS.............................................................  30
   4.1  Develop Clear Procedures for Allocating [Firm] Capacity..........................  30
   4.2  Revise PG&E's Transmission Interconnection Policy, Terms and Conditions  (Not an
         Appendix C Item)................................................................  30
   4.3  Revise PG&E's Electric Generation Rate Design (Not an
         Appendix C Item)................................................................  30
   4.4. Review PG&E's Local Transmission Reliability, Design Standards and Curtailment
         Provisions (Not an Appendix C Item).............................................  30
   4.5  Investigate Mechanisms to Reduce the Costs of Transmission Service for Noncore
         Customers Connecting To or Located Close To PG&E's Backbone Transmission
         Facilities  (Not an Appendix C Item)............................................  31
5.    PROMISING OPTIONS WHICH WERE SETTLED IN THE OFO SETTLEMENT AGREEMENT...............  31
   5.1  Examine Strategies for Devoting More Assets to PG&E Balancing....................  31
   5.2  Implement Targeted Operational Flow Orders.......................................  31
   5.3  Provide Pipeline Operator Demand Forecasts Broken Down by
         Customer Class..................................................................  32
6.    NO ISSUES REMAIN TO BE LITIGATED IN I.99-07-003....................................  32
</TABLE>

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<PAGE>

                     CPUC Promising Gas Options I.99-07-003
                   Comprehensive Gas OII Settlement Agreement
                   ------------------------------------------

1.  INTRODUCTION

    1.1   Purpose: The purpose of this Comprehensive Gas OII Settlement
          Agreement ("Settlement Agreement") is to address the most promising
          options and other issues presented in Investigation (I.)99-07-003.
          Specifically, the goal of this Settlement Agreement is to resolve all
          PG&E issues that would otherwise be litigated in I.99-07-003.

    1.2   Parties: This Settlement Agreement is entered into by the Settlement
          Parties ("Parties"), as identified by their attached signatures.
          Parties agree to actively support this Settlement Agreement in
          I.99-07-003 and to not oppose any provision of this Settlement
          Agreement in any regulatory, legislative or judicial forum. Parties
          agree that this Settlement Agreement is consistent with the provisions
          of AB 1421.

    1.3   Background: In Decision (D.)99-07-015, the California Public Utilities
          Commission ("CPUC" or "Commission") identified a number of promising
          options for continued restructuring of the California natural gas
          industry. These options were summarized in Appendix C of that
          decision. This Settlement Agreement uses the Appendix C notation for
          reference.

    1.4   Commission Directive: In her ruling of November 5, 1999,
          Administrative Law Judge Andrea L. Biren directed parties to file a
          settlement of all or some of the issues in this docket by January 28,
          2000. In the absence of a complete settlement, Parties were directed
          to file prepared testimony on all non-settled issues by March 7, 2000.

    1.5   Summary of Agreement and Conditions: This Settlement Agreement settles
          all of the issues raised by the most promising options being
          investigated in I.99-07-003. No issues require further litigation in
          this proceeding for PG&E. This Settlement Agreement distinguishes
          between promising options being put in place, those already in place
          on the PG&E system, those being negotiated elsewhere, and those
          addressed in the OFO Settlement filed with the Commission on October
          22, 1999.
          The Gas Accord, as approved by the Commission in D.97-08-055, will
          continue through December 31, 2002, and is only modified as
          specifically agreed to in this Settlement Agreement, subject to future
          decisions by the CPUC. PG&E agrees to initiate post-Gas Accord
          settlement discussions promptly following the Commission's approval of
          this Settlement Agreement.
          This Settlement Agreement is a negotiated compromise and is broadly
          supported by parties who are marketers, gas suppliers, shippers,
          wholesale and retail end-use customers, storage operators and
          regulatory representatives, as well as the Coalition of California
          Utility Employees. Nothing contained herein shall be deemed to
          constitute an admission or an acceptance by any party of any fact,
          principle, or position contained herein, except to the extent that
          Parties, by signing this Settlement Agreement, acknowledge that they
          pledge support for Commission approval and subsequent implementation
          of all these provisions.

    =======================================================================
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             -- ---
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    =======================================================================

Page 1
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<PAGE>

CPUC Promising Gas Options I.99-07-003
Comprehensive Gas OII Settlement Agreement
------------------------------------------

          This Settlement Agreement is to be treated as a complete package and
          not as a collection of separate agreements on discrete issues or
          proceedings. To accommodate the interests of different parties on
          diverse issues, the Parties acknowledge that changes, concessions, or
          compromises by a party or parties in one section of this Settlement
          Agreement necessitated changes, concessions, or compromises by other
          parties in other sections.

          All Parties' obligations under this Settlement Agreement are
          conditioned upon the CPUC issuing a decision approving this Settlement
          Agreement without modification. If the CPUC modifies the Settlement
          Agreement, each party reserves the right to withdraw its support for
          the Settlement Agreement.

    1.6   Cost Recovery: PG&E will recover $700,000 in costs from
          customers/ratepayers to implement and maintain the following
          provisions of this Settlement Agreement. If costs exceed this amount,
          they will be borne by PG&E.

               Section 2.1    Cost and Rate Separation for Balancing Services
                              [Self-Balancing]
               Section 2.2.2  Anonymous Monthly Imbalance Trading
               Section 2.2.3  Trading OFO Day Imbalance Rights
               Section 2.8    Secondary Market Electronic Trading System

          Upon approval of this Settlement Agreement, PG&E will debit the
          specified amount of $700,000 to the Balancing Charge Account (BCA).
          This debited amount will not be subject to a reasonableness review by
          the Commission. Also as provided in Sections 2.2.2.3.6, 2.2.3.5 and
          2.8.4 below, PG&E will credit the BCA with a portion of the
          transaction fees received from certain trading activities.

    1.7   Implementation and Term: Within 60 days of a Commission decision
          approving this Settlement Agreement without modification, PG&E shall
          file an advice letter in compliance with that decision. In order to
          facilitate the implementation of the Settlement Agreement and to
          enable parties to promptly respond to the compliance advice letter,
          PG&E agrees to serve the parties in I.99-07-003 with pro forma tariff
          sheets reflecting the provisions of the Settlement Agreement within 60
          days of the filing of this Settlement Agreement. Unless stated
          otherwise, those provisions of this Settlement Agreement which do not
          require tariff changes shall become effective upon approval by the
          Commission. Those provisions requiring tariff changes shall become
          effective at such time as indicated in a Commission decision,
          resolution, or letter of approval. This Settlement Agreement shall
          continue in effect through December 31, 2002, or until such other
          dates as specified in this Settlement Agreement.

    1.8   Implementation Date For Changes Put In Place By This Settlement
          Agreement Which Affect Core Transportation Agents (CTAs):

        1.8.1  PG&E is not be able to provide PG&E-consolidated gas billing for
               gas-only customers until its billing system replacement project
               is completed ("Billing Availability Date"). PG&E commits to
               providing PG&E-consolidated billing for such customers upon
               completion of its billing system replacement project. Absent
               unforeseen circumstances, PG&E intends to provide this
               functionality by no later than the end of 2002 based on PG&E's
               current project plan. In the event of any unexpected delays, PG&E
               will notify the Parties of the possible delays as soon as

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CPUC Promising Gas Options I.99-07-003
Comprehensive Gas OII Settlement Agreement
------------------------------------------

               is reasonably practical. Parties agree that under AB 1421 and
               other relevant law, nothing in this Settlement Agreement will
               require PG&E to offer PG&E-consolidated gas billing for gas-only
               customers prior to the Billing Availability Date.

        1.8.2  The following sections of this Settlement Agreement will be
               implemented independent of the Billing Availability Date:

                  2.1      Cost and Rate Separation for Balancing Services
                           [Self-Balancing Option]
                  2.2.2    Anonymous Monthly Imbalance Trading
                  2.2.3    Trading OFO Day Imbalance Rights
                  2.5      Unbundle Utility Storage Costs for Core Customers
                           [Served by CTAs]
                  2.7      Provide Details of Completed Transactions
                  2.8      Establish a Secondary Market Electronic Trading
                           System
                  2.9      Provide Real-Time Customer-Specific Usage Data
                  2.10     Provide Competitive Metering Technologies
                  2.11.4   Terminate Information Bill Requirement
                  2.11.5   Provide Billing Credits For CTA Consolidated Billing

        1.8.4  This Settlement Agreement is contingent on a final decision by
               the CPUC that contains an express finding that under AB 1421 and
               any other relevant law, nothing in this Settlement Agreement
               requires PG&E to offer consolidated gas billing for gas-only
               customers prior to the Billing Availability Date.

        1.8.5  If, after approval of this Settlement Agreement, the CPUC or a
               court issues a decision finding that certain changes resulting
               from this Settlement Agreement require PG&E to offer consolidated
               gas billing for gas-only customers prior to the Billing
               Availability Date, then such changes shall not be made available
               until the Billing Availability Date, notwithstanding Section
               1.8.2 of this Settlement Agreement.

    =======================================================================
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    Rule 601 et seq. of the FERC Rules or Practice, Rule 408 of the Federal
             -- ---
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    =======================================================================

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CPUC Promising Gas Options I.99-07-003
Comprehensive Gas OII Settlement Agreement
------------------------------------------

2.   PROMISING OPTIONS WHICH ARE PUT IN PLACE BY THIS SETTLEMENT AGREEMENT

     2.1   Cost and Rate Separation for Balancing Services [Self-Balancing
           Options]

          2.1.1  Summary of D.99-07-015: The creation of separate, avoidable
                 rates for balancing services might facilitate the entry of
                 competitors who would provide balancing services along with
                 procurement, storage, as well as intrastate and interstate
                 transmission. Cost and rate separation for balancing services
                 might also facilitate the provision of a variety of balancing
                 services on the part of the utility as well as competitors.
                 Examples of such services would include daily balancing with
                 varying tolerance bands and penalties as well as more generous
                 monthly balancing tariffs, with costlier charges. The provision
                 of a daily balancing option may be necessary in order to
                 implement other reforms such as electronic trading of
                 imbalances as well as cost and rate separation for balancing
                 services. The costs and benefits of the daily balancing option
                 should be considered in the next phase of this inquiry. (pp.
                 38-40, Findings of Fact (FoF) 22, Conclusions of Law (CoL) 8,
                 Appendix C)

          2.1.2  Gas Accord Balancing Provisions:

               2.1.2.1   Currently, PG&E's pipeline (California Gas Transmission
                         or CGT) provides a limited amount of balancing for
                         customers to manage their differences between supplies
                         and usage caused by a variety of factors, including
                         end-user demand uncertainty, unplanned equipment
                         outages, and price arbitrage. PG&E's pipeline must also
                         manage other imbalances including shrinkage, pipeline-
                         to-pipeline imbalances, California gas production
                         imbalances and imbalances due to forecast error for
                         core loads on the day of gas flow.

               2.1.2.2   The resources used by the pipeline for balancing
                         include the gas in the pipelines (called pipeline
                         inventory or linepack) and the firm storage assets
                         assigned to balancing under the Gas Accord. If the
                         pipeline inventory is forecast to exceed operating
                         limits, Operational Flow Orders (OFOs) are issued,
                         which impose daily balancing limits and penalties for
                         that day. If conditions warrant, Emergency Flow Orders
                         (EFOs), involuntary diversions or trimming receipt
                         point deliveries can also be implemented to protect the
                         integrity of the pipeline.

               2.1.2.3   Balancing entities are limited to a monthly imbalance
                         of +/-5 percent. After the end of the month, they can
                         trade imbalances outside this range. Following trading,
                         amounts outside +/-5 percent are cashed-out. There are
                         no specific daily balancing limits, except on OFO or
                         EFO days, although customers have daily nomination
                         limits.

    ========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure,
    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
       Rules of Evidence, and Section 1152 of the California Evidence Code
    ========================================================================

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        2.1.3  Self-Balancing Option Provisions: As part of this Settlement
               Agreement, PG&E will develop and implement an unbundled daily
               balancing option, which is called the Self-Balancing option. This
               option allows customers to receive a credit for a portion of the
               balancing costs currently bundled in the backbone rate, and is
               designed to reduce the need for PG&E to make systems changes for
               accounting, operations and tracking of daily imbalances for a
               significant number of customers. The following provisions will
               apply to Self-Balancing.

           2.1.3.1   Bundled Balancing: Bundled monthly balancing provided by
                     -----------------
                     PG&E remains the default balancing service for any customer
                     who does not elect the Self-Balancing option. The intent of
                     the Parties is that the offering by PG&E and the election
                     by customers of the Self-Balancing option will not
                     adversely affect the availability, reliability or cost of
                     bundled balancing, nor will it cause an increase in the
                     frequency of OFOs or EFOs. As provided in Section 2.1.3.8
                     below, the OFO Forum will monitor these effects, and meet
                     to discuss and resolve concerns if such adverse effects
                     occur.

           2.1.3.2   Availability and Election of Self-Balancing Option:  The
                     --------------------------------------------------
                     Self-Balancing option is available to noncore customers,
                     wholesale customers, and core procurement groups (CPGs).
                     For CPGs, a daily forecast of demand will continue to be
                     used to measure daily imbalances, similar to how OFOs are
                     done. PG&E's Core Procurement Department agrees that for
                     the term of this Settlement Agreement it will not elect the
                     Self-Balancing option. Noncore Balancing Aggregation
                     Agreements (NBAAs) may contain either Self-Balancing
                     customers or monthly balancing customers, but not combine
                     Self-Balancing and monthly balancing customers (since the
                     balancing rules which apply to each are quite different).

           2.1.3.3   Transmission Rates: All of the costs agreed to be included
                     ------------------
                     in rates for system balancing in the Gas Accord will
                     continue to be included in backbone transmission rates.

           2.1.3.4   Allocation of Balancing Storage Assets: For purposes of
                     --------------------------------------
                     this Settlement Agreement, through March 31, 2003, eighty
                     percent (80%) of the balancing storage assets are unbundled
                     and made available to the self-balancing option. However,
                     all these storage assets remain with the pipeline unless a
                     customer elects the Self-Balancing option. For these
                     customers, their share of the balancing storage assets will
                     be assigned to and remarketed through PG&E's at-risk
                     unbundled storage program. If a customer elects to return
                     to monthly balancing from Self-Balancing during the annual
                     election period, then the same amount of storage is
                     reassigned back to pipeline balancing. The amount is
                     calculated as a pro rata share of the unbundled balancing
                     storage assets based on the customer's annual average usage
                     as a percentage of PG&E's average annual system usage.

           2.1.3.5   Limitations on Self-Balancing Option:  The elections for
                     ------------------------------------
                     Self-Balancing are limited to 50 percent of the total
                     storage balancing assets of 2.2 Bcf of inventory, 50 MMcf
                     per day of injection and 70 MMcf per day of

    ========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure,
    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
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                     withdrawal. Once this limit is neared or reached, the OFO
                     Forum will meet to consider lifting this cap and whether
                     other adjustments are needed to PG&E's operating parameters
                     to ensure both the integrity of pipeline operations and the
                     benefits to the market of the Self-Balancing option.

           2.1.3.6   Credit for Self-Balancing: Those customers and CPGs
                     -------------------------
                     electing Self-Balancing will receive a credit equal to
                     $0.0050 per decatherm times their actual monthly metered
                     usage.

           2.1.3.7   Analysis of Storage Balancing Assets: The Parties agree
                     ------------------------------------
                     that a first priority for the OFO Forum is to evaluate the
                     level of storage assets made available for pipeline
                     balancing. By February 1, 2001, the OFO Forum will
                     recommend to the Commission whether the amount of storage
                     capacity allocated to balancing service should be revised.
                     If the recommendation is for an increase, the OFO Forum
                     will also recommend the source of this additional firm
                     storage capacity. Possible sources include PG&E's at-risk
                     unbundled storage program, capacity rejected by CTAs
                     pursuant to the provisions of Section 2.5, non-PG&E on-
                     system storage, or some combination thereof. Additionally,
                     the OFO Forum will recommend rate treatment for the costs
                     associated with a recommended change in allocated balancing
                     storage capacity. Parties agree that there will be no
                     decrease in assets dedicated to system balancing (except as
                     provided herein for self-balancing elections), nor rate
                     decreases, during the term of this Settlement Agreement
                     Provision.

           2.1.3.8   Monitoring the Effect of Self-Balancing on OFOs: The
                     -----------------------------------------------
                     Parties, through the OFO Forum, will monitor the response
                     to the Self-Balancing option and the impact on OFOs. After
                     reviewing the data, the OFO Forum may recommend revising
                     the Self-Balancing option and/or pipeline operating
                     parameters.

        2.1.4  Self-Balancing Option Terms and Conditions: Customers electing
               the Self-Balancing option will be subject to the following terms
               and conditions.

           2.1.4.1   Election of the Self-Balancing option is made annually in
                     February and is effective for a minimum term of one year
                     from April 1 through March 31. After the initial year, a
                     customer who previously elected to Self-Balance, may elect
                     back to monthly balancing during the election period. A
                     multi-year election to Self-Balance may also be made, but
                     not extending beyond March 31, 2003. Circumstances may also
                     arise which would require a customer to change its self-
                     balancing election during the year.

           2.1.4.2   Customers will be responsible for tracking their own daily
                     imbalance position. PG&E will not be required to provide
                     warnings or other notice, even if a customer is falling
                     outside the prescribed Self-Balancing requirements.

           2.1.4.3   Noncore customers must have meters which record daily
                     usage, even if these meters are only read once per month.
                     The cost of adding daily usage recording devices and/or
                     data access is the responsibility of the customer.

    ========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure,
    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
       Rules of Evidence, and Section 1152 of the California Evidence Code
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                     Small meters (meter capacity less than 100 dth per day) at
                     a customer facility with large hourly recording meters are
                     exempted from the hourly recording requirement and will be
                     included in daily calculations using a forecast of daily
                     usage based on averages derived from monthly data.

           2.1.4.4   Daily usage for CPGs electing the Self-Balancing option
                     will be based on a forecast of their customers' gas usage.
                     For CPGs whose demand is smaller than three percent (3%) of
                     the core market (based on annual demand), daily usage will
                     be determined using the first 24-hour forecast available
                     each day. For CPGs whose demand is greater than or equal to
                     three percent (3%) of the core market, daily usage will be
                     determined using an end of the gas day forecast. For any
                     CPG electing Self-Balancing, the applicable daily usage
                     forecast will also be used to calculate its monthly
                     cumulative imbalance available for trading or carry forward
                     as described below in Section 2.1.4.9. If the annual demand
                     of CPGs electing Self-Balancing exceeds ten percent (10%)
                     of the total core market annual demand, then the largest
                     CPG(s) electing to self-balance will have their daily usage
                     determined based on the end of the gas day forecast, such
                     that the sum of the demands for the remaining self-
                     balancing CPGs continuing to use the 24-hour forecast does
                     not exceed the ten percent (10%) limit. The OFO Forum may
                     review and make recommendations to address impacts on OFOs
                     and/or EFOs that may arise due to CPGs electing Self-
                     Balancing.

           2.1.4.5   Customers electing the Self-Balancing option will be
                     subject to two imbalance limits each day.

               2.1.4.5.1  The daily imbalance cannot exceed plus or minus ten
                          percent (+/-10%) of that day's metered or forecast
                          usage, except on OFO or EFO days; and

               2.1.4.5.2  The accumulated daily imbalance cannot exceed plus or
                          minus one percent (+/-1%) of that month's usage. Each
                          month's usage for this purpose will be set prior to
                          the month based on historical usage and forecast
                          patterns.

           2.1.4.6   Each balancing entity subject to the Self-Balancing limits
                     specified above is still subject to system-wide and
                     customer-specific OFOs. On those days, the OFO or EFO
                     tolerance band requirements and associated noncompliance
                     charges will be imposed, and the +/-10 percent
                     Self-Balancing requirement will not apply for that OFO or
                     EFO day. However, the accumulated daily imbalance
                     requirement will still apply.

           2.1.4.7   PG&E will calculate the daily imbalances after the calendar
                     month for each noncore customer or balancing entity
                     electing this option after processing the applicable meter
                     data. Daily imbalances for CPGs will be based on their
                     daily usage as described in Section 2.1.4.4 above.

           2.1.4.8   Noncompliance charges will be calculated for customers
                     electing the Self-Balancing option as the sum of the
                     following, except as provided in Section 2.1.4.8.4, and
                     will be recorded in the Balancing Charge Account (BCA).

    ========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure,
    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
       Rules of Evidence, and Section 1152 of the California Evidence Code
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              2.1.4.8.1   For each non-OFO or non-EFO day, a noncompliance
                          charge equal to $1.00 per decatherm per day for each
                          day when the daily imbalance exceeds +/-10 percent of
                          the daily metered or determined usage.

               2.1.4.8.2  For each OFO or EFO day, a noncompliance charge is
                          calculated using the applicable OFO or EFO tolerance
                          level and noncompliance charge.

               2.1.4.8.3  For each day including OFO and EFO days, a
                          noncompliance charge equal to $1.00 per decatherm per
                          day for each day when the accumulated daily imbalance
                          exceeds +/-1 percent of the preset monthly usage.

               2.1.4.8.4  For each OFO day or EFO day on which a noncore
                          customer or balancing entity electing the
                          Self-Balancing option is exceeding its accumulated
                          imbalance limit in a direction opposite to that of the
                          OFO or EFO situation, there will be no noncompliance
                          charge under Section 2.1.4.8.3 above. For example,
                          under a high inventory OFO, a balancing entity with a
                          negative accumulated imbalance exceeding -1% of its
                          preset monthly usage would not receive a noncompliance
                          charge for this situation. However, if the accumulated
                          imbalance is not corrected to within the +/-1 percent
                          limit on the next non-OFO or non-EFO day,
                          noncompliance charges will apply.

           2.1.4.9   Monthly cumulative imbalance trading is allowed. Any gas
                     imbalances remaining after the trading period that are in
                     excess of plus or minus one percent (+/-1%) of the monthly
                     usage will be cashed out at the highest cash-out price
                     indicated in Schedule G-BAL for imbalances in excess of
                     10%. Any carry forward amount will set the beginning
                     accumulation level for the next month. No daily trading
                     during the month of imbalance position or rights is
                     allowed. However, trading of OFO day imbalance rights
                     (chips) will be allowed as provided in Section 2.2.3 below.

           2.1.4.10  Following each annual election period, PG&E will report
                     within 30 days on its Pipe Ranger Web site the percentage
                     (based on annual demands) of the core and noncore markets
                     electing to Self-Balance. Specific customers or entities
                     electing the Self-Balancing option will not be identified.

    2.2   Electronic Trading of Imbalances [Including Rights]

        2.2.1  Summary of D.99-07-015: The Commission provisionally finds that
               shippers should be allowed to trade or sell imbalance rights
               since they pay for a balancing tolerance as a component of their
               intrastate transmission rates and are entitled to have the plus
               or minus tolerance on a daily or monthly basis. The trading of
               imbalance rights would give shippers the ability to adapt to
               daily balancing rules, where they apply, during a given day's
               nomination cycles. The Commission finds the concept of imbalance
               trading to hold sufficient promise to merit further inquiry. The
               Commission also encourages parties to consider whether a
               mechanism could be developed to produce the hoped-for benefits
               versus its costs. (pp. 41-44, FoF 24-26, Appendix C)

    ========================================================================
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    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
       Rules of Evidence, and Section 1152 of the California Evidence Code
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        2.2.2  Anonymous Monthly Imbalance Trading

           2.2.2.1   Current PG&E Platform for Monthly Imbalance Trading: PG&E
                     currently provides a platform on its Pipe Ranger Web site
                     for entities to confirm trades of same month cumulative and
                     operating imbalances. This Internet-based platform allows
                     balancing entities who have negotiated imbalance trades
                     with another balancing entity to inform PG&E of the
                     imbalance trade using the Internet. Basically, one
                     balancing entity electronically enters the results of the
                     negotiated trade, and the other balancing entity confirms
                     the trade. This platform validates whether the confirmed
                     trade is in compliance with the current imbalance trading
                     rules set forth in PG&E's tariff Schedule G-BAL. If not,
                     the trade is rejected. this platform currently does not
                     provide for posting offers to buy or sell monthly
                     imbalances, or for facilitating trading such imbalances.
                     Entities contact each other directly to work out the trade
                     details, including price.

           2.2.2.2   Provider of Electronic Imbalance Trading System: PG&E will
                     contract with a Third Party Service Provider (TPSP) to
                     provide anonymous electronic trading of cumulative and
                     operating imbalances, i.e., the trading of actual imbalance
                     gas, not rights. PG&E intends to enter into a sole-source
                     contract with an affiliate of Altra Energy Technologies,
                     Inc. (ALTRA(R)) to provide the monthly imbalance trading
                     platform using their Altrade(R)product. The sole source
                     provision of this contract will be in effect through
                     December 31, 2002. Once PG&E finalizes its contract with
                     ALTRA, a copy of the contract will be provided to the
                     Parties, subject to a confidentiality agreement. At the end
                     of this sole-source period, any other TPSP may provide
                     service in competition with ALTRA. At that time, PG&E will
                     provide a customer service and data interface with all
                     interested TPSPs offering electronic imbalance trading.

           2.2.2.3   Principles for Imbalance Trading System: The following
                     principles are agreed to in order to mitigate concerns
                     about the market relying on a sole-source provider during
                     this market development period.

               2.2.2.3.1  PG&E will continue to provide its platform for
                          entities to post and confirm monthly imbalance trades
                          without charging transaction fees.

               2.2.2.3.2  Use of the anonymous trading platform is voluntary.

               2.2.2.3.3  ALTRA is a logical sole-source provider. ALTRA has
                          contracts with about 80% of the entities for gas
                          commodity trading, and is well recognized as an
                          industry leader in building and servicing electronic
                          trading platforms.

               2.2.2.3.4  Entities with currently-effective ALTRA contracts will
                          not have to pay added monthly subscription fees. A
                          smaller fixed subscription fee will be made available
                          for those entities who only want to use ALTRA for
                          imbalance trading, and not commodity trading. The
                          monthly subscription fee will be credited against
                          transaction fees up to that amount. Subscription fees
                          are needed in addition to transaction fees because
                          experience is that entities will use the price
                          discovery

    ========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure,
    Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
       Rules of Evidence, and Section 1152 of the California Evidence Code
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                     information available on the trading screens to do their
                     own deals outside the trading platform. These deals can
                     then be reported through PG&E's existing platform, thus
                     avoiding transaction fees.

          2.2.2.3.5  Each trade will be subject to buyer and to seller
                     transaction fees for each decatherm traded. The transaction
                     fee provides an incentive for ALTRA to encourage trading
                     volume which in turn improves liquidity and price
                     discovery. These fees will be charged in a non-
                     discriminatory manner, but could include tiered pricing.
                     The transaction fees will be capped during the sole-source
                     period.

          2.2.2.3.6  PG&E will retain a share of ALTRA's transaction fee which
                     offsets PG&E's transaction and credit costs, as well as
                     reflects the value PG&E brings to this service. The fee
                     sharing will also provide an incentive to PG&E to encourage
                     use of this trading service. The fee shall be established
                     by ALTRA with any revenues shared between ALTRA and PG&E
                     equally. One-half of the PG&E portion of these transaction
                     fees will be recorded as a credit to the BCA to help offset
                     the costs incurred to implement this trading system. PG&E
                     will include the specific fee provisions in its tariffs
                     pursuant to Section 1.7 above.

          2.2.2.3.7  ALTRA will operate the trading system and retain ownership
                     of all software. ALTRA will be responsible for all
                     maintenance and operation costs associated with operating
                     the Altrade trading platform.

          2.2.2.3.8  PG&E shall not influence, in any way, ALTRA's selection of
                     trading partners, business associations or contracts with
                     any third party operating on the PG&E system, other than in
                     matters of routine credit and nomination capacities
                     envisioned by this Settlement Agreement.

      2.2.2.4   System Features for Electronic Imbalance Trading System: The
                following provisions will be part of the monthly imbalance
                trading system limitations and features.

          2.2.2.4.1  The electronic trading platform will allow a balancing
                     agent to post either a bid to purchase imbalance gas or to
                     post an asking price to sell imbalance gas. Other parties
                     will be able to monitor these postings and accept the
                     posted offer or make a counter-offer. When two parties
                     agree on price, ALTRA will manage the transaction by adding
                     imbalance gas to the Purchaser's account and subtracting
                     imbalance gas from the Seller's account. The Purchaser is
                     then billed for the agreed upon price, and payment is made
                     to the Seller for the same amount.

          2.2.2.4.2  Anonymous trading on ALTRA platform will not be required to
                     abide by all the imbalance trading limitations in Schedule
                     G-BAL during the trading period. However, the final
                     summation of the imbalance trades completed on ALTRA's
                     trading platform and those posted on PG&E's platform will
                     be subject to the Schedule G-BAL limitations and cash-out
                     provisions. The limitations include: no trading across
                     months;

  ==========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure.
    Rule 601 et seq of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
      Rules of Evidence and Section 1152 of the California Evidence Code
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                     trading cumulative imbalances towards zero; trading results
                     in a cumulative imbalance that is within the range of plus
                     or minus three percent of usage past zero; and trading into
                     or out of on-system storage accounts which have documented
                     inventory gas or space available.

          2.2.2.4.3  PG&E and ALTRA will establish an electronic link to
                     transfer data on current account balances and to update
                     these accounts once the imbalance trading period ends.
                     ALTRA will send its trading results to PG&E. PG&E will add
                     additional trades that are confirmed through PG&E's current
                     platform and add trades between storage accounts. The final
                     ending imbalance position for each balancing entity will be
                     used to determine any cashout or carry forward amounts
                     based on the rules in Schedule G-BAL.

          2.2.2.4.4  Entities will be subject to trading limitations based on
                     individual credit limits and system operating limitations.
                     PG&E will revise its credit-worthiness requirements in its
                     tariffs to reflect these transactions. PG&E will be
                     responsible for providing ALTRA with these trading limits.
                     ALTRA will not allow an entity to complete a trade if their
                     limit would be exceeded by completing the trade.

          2.2.2.4.5  PG&E will accept the credit risk for entities which are
                     PG&E customers approved for this program, including
                     designated marketers, NBaas, and CTas. If a Purchaser
                     accepts a trade and fails to pay its trading position
                     (either buying or selling imbalance gas) when billed by
                     ALTRA, PG&E will guarantee payment to the Seller in the
                     transaction. PG&E will then take collection action against
                     the Purchaser, including late fees and, if appropriate,
                     cashouts in accordance with the G-BAL requirements.

          2.2.2.4.6  To encourage additional liquidity, ALTRA may allow market
                     makers that have no imbalances on the PG&E system to
                     participate in imbalance trading. ALTRA will be responsible
                     for credit approval and collection for these market makers,
                     pursuant to its agreement with PG&E. Market makers will be
                     required to have zero imbalances at the end of the trading
                     period. ALTRA may institute additional rules to enforce
                     this requirement and other conditions needed to conduct
                     business.

          2.2.2.4.7  On-system, non-PG&E storage facilities may participate
                     under the same terms and conditions applicable to imbalance
                     trading with PG&E's storage and/or market center.

  ==========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure.
    Rule 601 et seq of the FERC Rules of Practice.  Rule 408 of the Federal
             -- ---
      Rules of Evidence and Section 1152 of the California Evidence Code
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    2.2.3   Trading OFO Day Imbalance Rights

        2.2.3.1   Objectives: PG&E and ALTRA will implement a mechanism to allow
                  trading of imbalance rights for each OFO day using the same
                  electronic platform as for monthly imbalance trading. The
                  objective is to provide balancing entities the opportunity
                  after the fact to reduce or eliminate OFO noncompliance
                  charges, and to create value for those entities who are within
                  the specified OFO day tolerance band. Trading these rights
                  does not change the physical imbalance position of the entity
                  or the pipeline. Trading these OFO day rights also avoids the
                  problem of significant retroactive accounting adjustments
                  which would be needed if physical imbalances for the OFO day
                  were traded.

        2.2.3.2   Market Benefits: A daily balancing tolerance level is
                  specified for each day an OFO is called. This tolerance level
                  generally ranges from +/-2% to +/-16%. If a balancing entity
                  has an imbalance outside this tolerance level for that OFO
                  day, it is subject to noncompliance charges. If a balancing
                  entity has an imbalance that is within this tolerance level
                  for that OFO day, that entity receives no benefit for helping
                  the situation. With imbalance rights trading, there is an
                  opportunity for the balancing entity that is below the
                  tolerance level to gain value from this position, while
                  helping the balancing entity outside the tolerance band to
                  reduce their noncompliance charges.

        2.2.3.3   Establishing and Trading Imbalance Rights: The approach is to
                  establish imbalance rights, or chips, for each balancing
                  entity for each OFO day, and then to allow the trading of
                  these rights. The following describes this mechanism.

            2.2.3.3.1  The imbalance rights or chips are calculated as the
                       difference between the entities' imbalance and the
                       tolerance level on that OFO day. Chips are positive
                       (black) for those entities whose imbalances are within
                       the tolerance level, and negative (red) for those
                       entities that are outside the tolerance level and subject
                       to noncompliance charges. One chip is given for each
                       decatherm of difference.

            2.2.3.3.2  Each chip is dated corresponding to a specific OFO day.
                       Chips can only be traded with those of the same date. In
                       other words, imbalances and noncompliance charges cannot
                       be traded between OFO days. Unlike cumulative imbalance
                       trading, gas in storage accounts will not be eligible to
                       create positive chips or to offset a negative chip
                       position during the imbalance rights trading period.
                       Trading between different OFO days and using storage
                       after the gas day occurs would change the incentive of
                       balancing agents to comply with the OFO on that
                       particular day. Trading of chips does not change these
                       incentives to comply with the OFO order.

            2.2.3.3.3  Chips are cleared after the month is over. For example,
                       if there were five different OFO days during the previous
                       month, each balancing entity would have five separate
                       trading accounts and associated chips.

  ==========================================================================
        Subject to Rule 51 of the CPUC Rules of Practice and Procedure,
   Rule 601 et seq. of the FERC Rules of Practice.  Rule 408 of the Federal
            -- ---
      Rules of Evidence, and Section 1152 of the California Evidence Code
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            2.2.3.3.4  For each individual OFO day, entities with positive
                       (black) chips will be able to sell them at a mutually
                       agreed upon price to those entities needing to offset
                       their negative (red) chips. The market would establish
                       the price for positive chips. It is likely that the price
                       to buy positive chips would be much lower than the
                       noncompliance charge if a large number of entities are
                       below the tolerance band and are competing to sell their
                       positive chips. When only a few entities have positive
                       chips for sale, the price would likely be close to the
                       noncompliance charge, but should never exceed the
                       noncompliance charge.

            2.2.3.3.5  Those entities with net negative (red) chips remaining
                       after the trading period would be billed for the
                       commensurate noncompliance charges for the related OFO.
                       It is possible, although not likely, that an entity who
                       was physically in balance during the OFO could end up in
                       a negative chip position and pay noncompliance charges.

        2.2.3.4   Electronic Trading and Confirmation System: Electronic trading
                  and electronic confirmation of offline trades of OFO day
                  imbalance rights (chip) will be included as part of the sole-
                  source contract with ALTRA, and subject to the terms of that
                  contract. Under this contract, ALTRA and PG&E will establish
                  the necessary interfaces, and ALTRA will provide the necessary
                  screens and trading platform. PG&E will modify its GTS and
                  accounting systems to verify compliance with the trading
                  rules, to record the trades, and to adjust the payments of
                  noncompliance charges accordingly.

        2.2.3.5   Electronic Trading Fees: A monthly subscription fee will be
                  required if the customer does not already subscribe to ALTRA.
                  A smaller fixed subscription fee will be made available for
                  those entities who only want to use ALTRA for imbalance rights
                  trading, and not commodity trading. ALTRA will charge a
                  transaction fee to both the buyer and seller performing
                  electronic trading or electronic confirmation of offline
                  trades. This fee will be capped, and any discounts made
                  available on a nondiscriminatory basis. PG&E will receive
                  fifty percent (50%) of these fees, which will be recorded as a
                  credit to the BCA to help offset the costs for implementing
                  this trading system. PG&E will include the specific fee
                  provisions in its tariffs pursuant to Section 1.7 above.

   2.3  Re-examine Utility Role in Core Procurement Once a Specified Competitor
        Market Share Has Been Achieved

     2.3.1  Summary of D.99-07-015: The Commission recommends the re-examination
            of local distribution company core procurement and the default
            provider function if the market share exceeds 30% of the number of
            customers, but even at that point the Commission has seen no
            compelling reason to eliminate local distribution company
            procurement as an option for customers. (pp. 50-59, Appendix C)

     2.3.2  Resolution: Parties agree that there is no need to litigate nor for
            the Commission to further examine the utility role in core
            procurement in this proceeding.

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   2.4  Eliminate Core Aggregation Transportation Thresholds After Adoption of
        Consumer Protection Measures

      2.4.1  Summary of D.99-07-015: The Commission believes the lifting of the
             core aggregation threshold and core participation cap will expand
             the competitive options available to residential and small
             commercial customers. In Ordering Paragraph 11, the Commission
             recommends to the California Legislature that the consumer
             protection measures proposed by the Commission's Energy Division be
             immediately adopted by statute. The Commission also recommends that
             the Legislature provide an exception to Senate Bill 1602 to allow
             the Commission to remove the current restrictions that limit
             participation in the utilities' Core Aggregation Transportation
             programs. The exception would allow the limits to be removed before
             January 1, 2000, but after the Commission has implemented the
             appropriate consumer protection measures. (pp. 59-61, FoF 30,
             Ordering Paragraph (OP) #11, Appendix C)

      2.4.2  Market Threshold: Under the Gas Accord, PG&E eliminated the market
             limit threshold of 10 percent, and no further action is needed.

      2.4.3  CTA Participation Threshold: Under the Gas Accord, PG&E reduced the
             minimum size for core aggregation (CTA) participation from 250,000
             to 120,000 therms per year. Parties agree that no change to this
             threshold is necessary in this proceeding or during the term of
             this Settlement Agreement.

   2.5  Unbundle Utility Storage Costs for Core Customers [Served by CTAs]

      2.5.1  Summary of D.99-07-015: The Commission recommends exploration of
             the unbundling of storage costs for core customers. (p.49)

      2.5.2  Current CTA Storage Requirements: Under the Gas Accord, each Core
             Transportation Agent (CTA) is assigned a pro rata share of the
             total core allocated storage. This assignment is based on the total
             historical winter usage of their customers. PG&E's tariff Schedule
             G-CT requires that CTAs must fill and maintain their allocated
             storage inventory within specified limits to aid in customer cold
             weather system reliability.

      2.5.3  Unbundling Storage Costs for CTAs: Parties agree to unbundle core
             storage costs for CTAs during the remainder of the Gas Accord
             period pursuant to the provisions below. Any further unbundling of
             storage costs for all core customers will be considered only in the
             context of the post-Gas Accord structure.

      2.5.4  Basic Provisions: The following describes the structure and timing
             of the CTA storage choice. Final details will be included in the
             tariff changes needed to implement this program.

         2.5.4.1   Core Storage Rate Treatment: As of the effective date of the
                   ---------------------------
                   tariffs implementing this provision of the Settlement
                   Agreement, core storage costs will be recovered from PG&E's
                   Core Procurement Department customers through monthly core
                   procurement rates and from CTAs through monthly fees to the
                   extent they accept an allocation of core storage on

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                   behalf of their core transport customers, subject to
                   balancing account treatment up to the limits described below.
                   Cost shifts among core customers are to be minimized and no
                   costs are shifted to noncore customers.

         2.5.4.2   CTA Storage Allocations: An allocation of storage inventory,
                   -----------------------
                   injection and withdrawal capacity to CTAs will continue to be
                   calculated in the same manner as is currently provided for in
                   Schedule G-CT. This allocation is based upon the historical
                   total winter throughput of CTA customers and the BCAP-adopted
                   winter throughput of all core customers. A core storage
                   allocation will continue to be calculated each February,
                   based upon the CTA group contracted volumes for the
                   subsequent winter season using the Direct Access Service
                   Requests (DaSRs) that have been processed to date.

         2.5.4.3   CTA Option to Accept or Reject Storage Allocations: Each year
                   --------------------------------------------------
                   between about February 15 and March 1, CTAs will be given the
                   option to accept or reject their Annual Allocation of core
                   storage, for the storage year of April 1 through March 31, in
                   ten percent (10%) increments. CTAs will be able to make
                   adjustments to their annual election for increases or
                   decreases in loads during the Intra-Year Adjustment period
                   described below.

         2.5.4.4   Initial Partial Year Option: If tariffs to implement this
                   ---------------------------
                   provision are approved such that implementation can begin on
                   or before December 1, 2000, any CTA may reject all or a
                   portion of its current core storage allocation in ten percent
                   (10%) increments for the April 1, 2000 through March 31, 2001
                   storage season, subject to the Cap specified in Section
                   2.5.4.5 below. A CTA rejecting storage must sell the gas from
                   the portion of its storage account that it rejects to PG&E's
                   Core Procurement Department at a weighted average Core
                   Procurement price (Schedule G-CP) for the months that the
                   Core Procurement Department has injected gas during its
                   current or most recent injection season. A CTA must also
                   certify Alternate Resources pursuant to Section 2.5.4.11
                   below. The PG&E Core Procurement Department's Benchmark under
                   its Core Procurement Incentive Mechanism (CPIM) will be
                   adjusted by adding the costs associated with the purchase of
                   this CTA storage gas.

         2.5.4.5   Cap on Rejected Storage Allocations: During the term of this
                   -----------------------------------
                   Settlement Agreement, the total amount of core storage
                   allocations that can be rejected by all of the CTAs is capped
                   each storage season as follows for inventory, with
                   proportionate injection and withdrawal rights.

                       Storage Season       Cap On Rejected    Share of Total
                     April 1 - March 31)      CTa Storage       Core Storage
                     -------------------      -----------       ------------
                      2000-2001                1.64 Bcf             5%
                      2001-2002                3.28 Bcf            10%
                      2002-2003                4.92 Bcf            15%

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                     To the extent that rejected Annual CTA Allocations amount
                     to more than this Cap, the amounts that exceed the Cap will
                     be reassigned to CTAs in proportion to the amounts they
                     have rejected.

           2.5.4.6   Accepted and Assigned CTA Storage Allocations: For amounts
                     ---------------------------------------------
                     of capacity that a CTA may accept or have assigned, the CTA
                     will pay PG&E monthly, over the storage year, the revenue
                     requirement associated with accepted and assigned amounts
                     as a proportion of total core storage. CTAs must fill and
                     maintain accepted and assigned storage inventories on an
                     annual cycle as specified in the current tariff under
                     Schedule G-CT.

           2.5.4.7   Core Procurement Core Storage Assignment: Amounts of core
                     ----------------------------------------
                     storage not allocated to CTAs in accordance with Section
                     2.5.4.2 above, plus rejected CTA Core Storage Allocations
                     up to 1.64 Bcf, will be assigned to PG&E's Core Procurement
                     Department.

               2.5.4.7.1  The cost of storage assigned to the Core Procurement
                          Department will be recovered through the procurement
                          portion of core customer bundled rates, subject to
                          balancing account treatment. All storage allocations
                          to the Core Procurement Department are to be treated
                          in the same manner as current Core Procurement
                          Department storage allocations in the CPIM.

               2.5.4.7.2  The Core Procurement Department will fill and maintain
                          inventory for this assignment according to the terms
                          currently specified by the CPIM for amounts now
                          allocated to the Core Procurement Department.

           2.5.4.8   Disposition of Rejected Core Storage Allocations Above 1.64
                     -----------------------------------------------------------
                     Bcf: Core storage inventory allocations rejected by CTAs
                     ---
                     above 1.64 Bcf will be allocated to PG&E's at-risk
                     unbundled storage program.

           2.5.4.9   Intra-Year Rules - Increase In Load:  In August of each
                     -----------------------------------
                     year, based upon the CTA group contracted volumes for the
                     upcoming winter season using the Direct Access Service
                     Requests (DASRs) that have been processed to date, PG&E
                     will recalculate the pro rata CTA storage allocations and
                     compare this new calculation with the Annual Storage
                     Allocation calculated at the beginning of the current
                     storage season. If a CTA's allocated share of storage
                     inventory has increased by more than 100,000 therms, the
                     CTA must choose whether to accept an increased allocation
                     for any portion of the incremental change, in ten percent
                     (10%) increments. This election must be made between August
                     15 and September 1.
               2.5.4.9.1  For amounts that the CTA accepts of these incremental
                          storage rights, gas in the Core Procurement
                          Department's storage account will be transferred to
                          the CTA storage account at a price that reflects a
                          weighted average Core Procurement (Schedule G-CP)
                          price for the months of April through October times an
                          injection schedule for the Core Procurement Department
                          (Schedule G-CT will be modified in this way for all
                          gas-in-storage transactions). The CTA will also pay

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                          the total cost of this storage capacity for that year
                          in payments over the remainder of the storage year.

               2.5.4.9.2  For amounts that the CTA rejects of this offered
                          storage, Alternate Resources, in like amount, will be
                          required as described in Section 2.5.4.11 below.
                          Rejection of offered storage is subject to the Cap for
                          the current storage season. To the extent rejected
                          capacity exceeds the Cap during the intra-season
                          election, the right to reject storage will be pro
                          rated among those rejecting storage capacity at this
                          time.

           2.5.4.10  Intra-Year Rules - Decrease In Load: If the mid-year
                     -----------------------------------
                     evaluation, described in Section 2.5.4.9 above, results in
                     a decrease of more than 100,000 therms in the amount of
                     storage inventory that would be allocated to a CTA, and the
                     CTA has accepted a storage allocation, the CTA must
                     transfer to the Core Procurement Department a share of its
                     reduced allocation in a proportion equal to the percentage
                     of its Annual Allocation that it accepted for the year. For
                     instance, consider a CTA whose Annual Allocation was
                     400,000 therms, and it accepted 300,000 therms, or
                     three-quarters of its allocation. If this CTA's mid-year
                     Allocation was 250,000 therms, three-quarters, or 112,500
                     therms of the 150,000 therm reduced allocation would be
                     transferred to the Core Procurement Department. The gas in
                     storage will also be transferred to Core Procurement
                     Department, which will pay the CTA for the storage and gas
                     on the same terms described in Section 2.5.4.9 above, to
                     the extent that the total rejected capacity has been
                     reduced.

           2.5.4.11  CTA Certification of Alternate Resources: A CTA rejecting
                     ----------------------------------------
                     all or part of a PG&E core storage allocation, must certify
                     to PG&E no less than ten business days before each winter
                     month that it has sufficient Alternate Resources in amounts
                     equal to the amounts of withdrawal capacity associated with
                     rejected storage. The certification is that the CTA has
                     contracts for the following resources or combination of
                     these resources which provide peak-day gas supplies
                     equivalent to that which would have been available from the
                     PG&E-allocated storage that the CTA has rejected. The
                     resources used as alternates in this certification cannot
                     duplicate any resources offered as replacements for winter
                     intrastate transmission capacity that the CTA may be
                     required to hold.
               2.5.4.11.1 Contracted firm storage services from PG&E or from an
                          on-system CPUC-certificated independent storage
                          provider;
               2.5.4.11.2 Contracted firm PG&E backbone capacity matched with an
                          equivalent quantity of contracted upstream gas supply,
                          and any necessary firm upstream pipeline capacity
                          (upstream gas supply can include a gas producer
                          contract, or a contract with an off-system
                          CPUC-certificated gas utility or independent storage
                          provider); and/or
               2.5.4.11.3 Third-party peaking supply arrangements, where that
                          supply is backed up by contracts under Section
                          2.5.4.11.1 or 2.5.4.11.2 above.

           2.5.4.12  Release and Indemnification of PG&E: Any CTA that elects to
                     -----------------------------------
                     reject all or a portion of its core storage allocation
                     shall enter into an agreement with

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                     PG&E releasing PG&E from any and all liability associated
                     with that CTA's rejection of its core storage allocation.
                     In this agreement, the CTA shall be required to indemnify
                     PG&E for any and all losses, including direct and
                     consequential damages, that arise (i) from any
                     representation in that CTA's certification which turns out
                     to be inaccurate or (ii) from any failure of its Alternate
                     Resources to perform as compared to the resources which
                     would have been available from the PG&E-allocated core
                     storage had this storage not been rejected by the CTA.

        2.5.5  Term: This unbundling of core storage for CTAs will be effective
               upon the effective date of the tariffs implementing this
               Settlement Agreement provision. If this date is after December 1,
               2000, then no intra-year elections may be made for the April
               2000-March 2001 storage season as provided in Section 2.5.4.4.
               This program will continue for the April 2001-March 2002 and for
               the April 2002-March 2003 storage seasons. The provisions of this
               program will be reconsidered as part of the post-Gas Accord
               negotiations.

    2.6   Separate Costs and Rates for Core Utility [Procurement] Services.
          Treat Utility Core Procurement Departments as Any Other Utility
          Customer

        2.6.1  Summary of D.99-07-015: The Commission recommends, to the extent
               reasonable as determined in the cost-benefit phase, separating
               the costs and rates for core utility services including core
               procurement, transmission, storage, distribution, and balancing,
               and treating the local distribution company core procurement
               departments as a single customer for operational purposes, which
               is subject to the same terms and conditions of service as other
               customers. On PG&E's system, core customers are being treated
               like any other customer, are clearly liable for OFO penalties,
               and hub service revenues are not included in the CPIM. The
               Commission recognizes that it is important to ensure that all
               costs are assigned to the appropriate function. Additionally the
               Commission states that when they have determined whether and the
               extent to which various service components will be competitively
               provided, the utilities will be able to implement separate rates
               for those services, and to assure that no charges have been left
               in any functional category by default. (p. 49 [#8], p. 62, p. 86,
               Appendix C)

        2.6.2  Current Brokerage Fee: A core brokerage fee of 2.4 cents per
               decatherm was negotiated in the Gas Accord as a proxy for certain
               costs directly related to PG&E's Core Procurement Department
               functions and overheads. Under the Gas Accord, the brokerage fee
               is subject to balancing account recovery and can be re-examined
               if PG&E's market share drops to 80% (Gas Accord, ss.IV.H.1). The
               parties reserved the right to propose other cost-based core cost
               allocation and rate design changes in future BCAPs for
               distribution rates and rate design (Gas Accord, ss.III.C.6.d.).

        2.6.3  Resolution: The Parties agree the brokerage fee, and the method
               of separating PG&E's Core Procurement Department costs this fee
               addresses, will remain unchanged for the duration of this
               Settlement Agreement. PG&E agrees to

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               discuss this issue and to consider reevaluating the method of
               allocating all procurement-related costs as part of PG&E's post-
               Gas Accord negotiations.

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    2.7   Provide Details of Completed Transactions

        2.7.1  Summary of D.99-07-015: The Commission believes that disclosure
               of the transaction-specific details requested by parties is basic
               and fundamental to an efficient market. In Conclusion of Law 17,
               the Commission directs the utilities either to provide timely
               information along the lines of the specific requests outlined in
               this decision, or to find different ways to convey to shippers
               information that they need to function effectively in the
               marketplace without compromising confidentiality concerns. (pp.
               73- 78, FoF 17, CoL 17, Appendix C)

        2.7.2  Monthly Negotiated Contract Report: PG&E will continue to file a
               monthly negotiated contract capacity report with the CPUC. This
               reports lists the details, but not customer names, of all
               negotiated capacity transactions for firm transportation,
               as-available transportation, and storage. Negotiated arrangements
               with affiliates or other Company departments are identified.

        2.7.3  Resolution: Parties agree that the other provisions of this
               Settlement Agreement, including Sections 2.2.3, 2.2.4, 2.7 and
               2.8 of this Settlement Agreement, as well as the OFO Settlement
               Agreement (filed October 22, 1999), should provide sufficient
               information on transactions to the market and shippers to enhance
               market liquidity and efficiency. Parties also agree that no
               further litigation of this issue is needed in I.99-07-003.

    2.8   Establish a Secondary Market [Trading System] via a Utility Electronic
          Bulletin Board

        2.8.1  Summary of D.99-07-015: Participation in the secondary market
               transactions through a mandatory Electronic Bulletin Board is
               consistent with the Commission's goals of enhancing market
               efficiency, preventing anti-competitive behavior, and providing
               additional competitive tools to the marketplace. Considering that
               all secondary market transactions will need to be confirmed
               through the utility, the Commission believes the utility should
               be required to provide the electronic bulletin board. However,
               the Commission wants to understand the costs of providing such a
               service before determining whether to require its provision. (p.
               79, FoF 38, Appendix C)

        2.8.2  Current Secondary Market Trading: Secondary market capacity
               trading is currently done on a voluntary basis through private
               transactions. There is no facilitating electronic platform
               currently available to the northern California market, other than
               a posting section on PG&E's INSIDEtracc. If parties to a capacity
               transaction want to change billing and nomination responsibility,
               the assignment is reported to PG&E so the change can be made and
               a new authorized nomination number can be provided.

        2.8.3  Electronic Trading System Provisions: PG&E will facilitate a
               voluntary and anonymous secondary market trading system for firm
               backbone transmission

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               capacity as part of its sole-source contract with ALTRA, and
               subject to the terms of that contract. The following provisions
               will apply:

           2.8.3.1   Firm transmission capacity by path will be included on the
                     electronic trading platform.

           2.8.3.2   ALTRA and PG&E will establish the process for reporting
                     assignments, and ALTRA will provide the screens and trading
                     platform.

           2.8.3.3   ALTRA will notify PG&E of the capacity assignment upon
                     completion of a trade and PG&E will adjust its records
                     accordingly and issue a new authorized nomination number to
                     the assignee.

           2.8.3.4   ALTRA will post on its electronic trading platform a
                     summary of the completed transactions, listing the amount
                     of capacity, the path (for transmission), transaction price
                     and the term of the assignment. Customer names will not be
                     provided.

        2.8.4  Trading Fees: A monthly subscription fee is required if the
               customer does not already subscribe to ALTRA. A smaller fixed
               subscription fee will be made available for those entities who
               only want to use ALTRA for capacity trading, and not commodity
               trading. ALTRA will charge a transaction fee to both the buyer
               and seller. This fee will be capped, and any discounts made
               available on a nondiscriminatory basis. PG&E will receive fifty
               percent (50%) of the transaction fees to cover its ongoing costs
               and services, and will record one-half of these monies as a
               credit to the BCA to help offset the costs for implementing this
               trading system. PG&E will include the specific fee provisions in
               its tariffs pursuant to Section 1.7 above.

    2.9   Provide Real-Time, Customer-Specific Usage Data

        2.9.1  Summary of D.99-07-015: The Commission believes that customer
               access to real-time consumption data is consistent with its goals
               of increased market efficiency and providing competitive tools.
               Access to real-time data may help customers to better manage
               their pipeline flows. The Commission considers the most promising
               option going forward appears to be for the utilities to make
               available to any customer, at the customer's expense, the
               equipment, technology and training necessary for expanded
               customer access to timely consumption information. The Commission
               is interested in hearing from parties in the cost/benefit phase
               of this proceeding what it would cost on a per-customer basis to
               make such access generally available, as well as the specific
               impediments to providing real-time available capacity updates.
               (pp. 72-73, FoF 33 & 36, CoL 15-16, Appendix C)

        2.9.2  Customer Options to Access Meter Data: Currently, about 900 of
               the 1200 noncore customers have Automatic Meter Reading (AMR)
               equipment, which PG&E "polls" via conventional phone lines once
               per day in order to retrieve the customer's hourly usage for each
               of the prior 24 hours. Since it takes about four to five hours to
               gather this data from all the AMR-equipped meters, the cumulative
               24 hour data is not available to these customers until around
               7:00 a.m.

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               the following morning through PG&E's INSIDEtracc and Pipe Ranger.
               In addition, PG&E currently offers all customers options to
               access their gas usage data through pulses (which can be
               converted to usage), with the cost billed to the specific
               customer per the provisions contained in Gas Rule 2.C, Special
               Facilities.

        2.9.3  Dial-In Access to AMR Data: PG&E may, depending on interest from
               market participants, offer customers, or their agents, dial-in
               access to PG&E's AMR meters. PG&E will survey market
               representatives to determine this level of interest. Any such
               dial-in access program would be subject to the following
               provisions. This option would only be available for meters
               equipped with both Mercury ECAT and AMR equipment. Equipment
               upgrades would be provided at customer expense to allow this data
               access option. The number of customer calls per meter would be
               limited to two per day so that battery life is not severely
               reduced. Also, no customer calls would be allowed between the
               hours of midnight and 5:00 a.m., during which time PG&E is
               calling the meter and downloading data for its use. PG&E would
               establish a start-up fee and a monthly service fee, as well as
               fees for other requests, such as changing an access password.
               These fees will be estimated based on recovering the costs to
               implement and maintain this program.

        2.9.4  Internet Information on Meter Access Options: PG&E may, depending
               on interest from market participants, create an Internet
               accessible web page specifying customer options for accessing
               their own meter data or pulses. Each option would generally
               describe the types of meters involved, the type of data provided,
               the frequency of the data, an estimated cost range for typical
               installations, any related service fees, and other information
               which could help customers perform a rough evaluation of these
               options. PG&E contact phone numbers would be provided for
               responding to questions and to specific requests. These options
               should include:

                   .  AMR access for noncore customers,
                   .  Meter pulse data for all customers,
                   .  Dial-in access to the meter,
                   .  Pilot for noncore meter ownership for new facilities (per
                      Section 2.10.4 below), and
                   .  Pilot for meter add-on devices (per Section 2.10.5 below).

        2.9.5  Internet Access to Full AMR Data:  PG&E may, depending on
               interest from market participants, make available on its Pipe
               Ranger Web site the AMR usage data for each hour of the prior
               day's usage in addition to the 24-hour total now provided. Data
               would be available about 7:00 a.m. in the morning for the prior
               midnight to midnight period. PG&E does not consider this billing
               quality data since missing data is filled in using estimation
               processes. This option would only be available to those customers
               with AMR equipment. Fees may be charged for this service based on
               recovering the costs to implement and maintain this program.

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        2.9.6  Resolution: Parties agree that all issues in this proceeding with
               respect to the provision of real-time consumption data are
               resolved for the term of this Settlement Agreement and need not
               be litigated.

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    2.10       Provide Competitive Metering Technologies

        2.10.1 Summary of D.99-07-015: For safety implications, the Commission
               does not currently believe that it is an option to encourage the
               cost or rate separation of meter reading or servicing, or of what
               have been referred to as after-meter services. Distribution
               utilities should continue to provide these services as part of a
               bundled distribution service. The Commission views the
               competitive provision of meters to be a promising option,
               consistent with their goals of ensuring safe and reliable
               service, as well as their objective of removing unnecessary
               barriers to entry into various components of the natural gas
               service market. This inquiry can include consideration of whether
               or not the local distribution company should become the owner of
               any meter that it installs. Any meter would have to meet
               appropriate safety standards and utilize standardized information
               protocols. (pp. 84-85, Appendix C)

        2.10.2 Resolution: Consistent with obligations under existing law, PG&E
               will install, read, remove, service, and maintain all gas meters
               during the term of this agreement. As part of the pilot program
               described below, a limited number of noncore customers may own
               their own PG&E-approved meters, or may choose meters to be owned
               by PG&E, for new meter installations. Further, also as a pilot
               program, a limited number of customers may own an "add-on device"
               to the PG&E-owned meter that allows the customer to access (and
               thus read remotely) meter data at time intervals needed for the
               customer's own purposes, or allows the customer to provide this
               meter data to another party. The selection and installation of
               this add-on device must also comply with established standards
               and procedures.

        2.10.3 Principles for Ownership of Meters and Add-On Devices: The
               following principles provide the basis for the pilot ownership
               programs and to help guide implementation.

           2.10.3.1  All customer-owned meters and add-on devices will have to
                     meet appropriate standards of safety, accuracy and
                     reliability, as determined by PG&E.

           2.10.3.2  Customer ownership of any meter or add-on device will not
                     interfere with PG&E's right to obtain current or additional
                     data from the meter. PG&E also reserves the right to
                     reconfigure the meter to improve PG&E's ability to obtain
                     current or additional data. For example, if PG&E chooses to
                     install automated meter reading (AMR) technology for a new
                     class of customers or a given portion of its service area,
                     PG&E shall be free to install that capability for all
                     customers of that category, whether or not such customers
                     had previously installed a customer-owned meter or meter
                     add-on device incompatible with the AMR technology to be
                     employed by PG&E.

           2.10.3.3  Those customers that choose to own their own meters or
                     add-ons are responsible for the additional incremental
                     costs associated with such equipment.

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           2.10.3.4  Nothing in this Settlement Agreement prevents PG&E from
                     continuing to offer its currently available meter and
                     meter-related products and services, or to propose new
                     meter-related products and services. Furthermore, nothing
                     in this Settlement Agreement requires Parties to support
                     any PG&E proposals to offer any such new meter or
                     meter-related products and services during the term of this
                     Settlement Agreement.

        2.10.4 Pilot Program for Customer Meter Ownership and Meter Choice: The
               following provisions apply to this pilot program for limited
               meter ownership and choice of PG&E-owned meters.

           2.10.4.1  Participation Limit: The pilot program is limited to the
                     -------------------
                     installation of 500 customer-owned meters per year. The
                     pilot program applies only to new meter installations at
                     noncore customer facilities, and does not apply to the
                     replacement of an existing PG&E-owned meter. PG&E at its
                     sole discretion may increase the cap on the number of
                     meters which can be owned by customers.

           2.10.4.2  Limit on Meter Choice: The meter ownership pilot program is
                     ---------------------
                     limited to customer ownership of meters approved by PG&E.
                     Nothing in this program requires PG&E to evaluate and/or
                     approve additional meters that are not already approved as
                     of the date of a Commission order approving this Settlement
                     Agreement, nor does anything in this program prevent PG&E
                     from removing currently-approved meters from the approved
                     list.

           2.10.4.3  Cost Responsibility: Customers choosing to own their meter
                     -------------------
                     are responsible for incremental costs associated with their
                     meter that are incurred by PG&E. Incremental costs are
                     those costs beyond the costs that would have been incurred
                     by PG&E having installed and owned the most cost-effective
                     meter for that site. Costs for which customers may be
                     responsible could include, but are not limited to,
                     installation of the meter or additional equipment,
                     maintenance, call-out servicing, and any other incremental
                     transaction-based costs associated with their owning the
                     meter.

           2.10.4.4  PG&E Access to Meter Data: PG&E has the right to obtain or
                     -------------------------
                     directly access any data available from the customer-owned
                     meter. PG&E may also add-on devices to a customer-owned
                     meter which do not interfere with the customer's use of
                     that meter. PG&E would pay the cost of such add-ons.

           2.10.4.5  Advice Filing for Pilot: PG&E will prepare and submit an
                     -----------------------
                     advice filing to implement this pilot meter ownership
                     program, including tariff and fee provisions, consistent
                     with the terms of this Settlement Agreement. This filing
                     will be made as part of the submission discussed in Section
                     1.7 of this Settlement Agreement.

           2.10.4.6  Term of Pilot: This pilot program is effective when the
                     -------------
                     CPUC-approved tariffs implementing this program are
                     effective, and will continue for the term of this
                     Settlement Agreement.

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           2.10.4.7  Assessment of Pilot: One year prior to the completion of
                     -------------------
                     the program, PG&E will begin working with interested
                     parties to prepare a report assessing the pilot meter
                     ownership program. This assessment report, which will
                     include recommendations concerning the future of the
                     program, will be submitted to the CPUC six months prior to
                     the end of the pilot. The report will address, among other
                     things, whether the pilot program should be expanded, and
                     the disposition of all existing customer-owned meters if
                     the meter ownership pilot program is terminated.

        2.10.5  Pilot Program for Customer Ownership of Meter Add-Ons: Subject
                to the following terms and conditions, PG&E will allow a limited
                customer ownership of add-on devices to PG&E-owned meters for
                the purpose of accessing meter data at time intervals needed for
                the customer's internal purposes, or for providing such data to
                another party.

           2.10.5.1  Participation Limit:  This pilot program is limited to the
                     -------------------
                     installation of 1000 customer-owned meter add-on devices
                     per year. PG&E at its sole discretion may increase the cap
                     on the number of customer-owned meter add-on devices.

           2.10.5.2  Meter Responsibility: Add-on devices will not adversely
                     --------------------
                     affect the safety, reliability and accuracy of PG&E's gas
                     meters, nor PG&E's ability to obtain any meter data. PG&E
                     remains responsible for installation, removal, service and
                     maintenance of the meters and the add-on devices. Customer
                     ownership of an add-on device will not prevent or interfere
                     with PG&E's ability to replace or reconfigure the meter.

           2.10.5.3  Cost Responsibility: Customers will be responsible for the
                     -------------------
                     costs associated with add-on devices, including, but not
                     limited to, installation, maintenance, removal, and any
                     other transaction-based costs associated with that add-on
                     device.

           2.10.5.4  Advice Filing for Pilot: PG&E will prepare and submit an
                     -----------------------
                     advice filing to implement this pilot meter add-on program,
                     including tariff and fee provisions, consistent with the
                     terms of this Settlement Agreement. This filing will be
                     made as part of the submission discussed in Section 1.7 of
                     this Settlement Agreement.

           2.10.5.5  Term of Pilot: This pilot program is effective when the
                     -------------
                     CPUC-approved tariffs implementing this Settlement
                     Agreement are effective, and will continue for the term of
                     this Settlement Agreement.

           2.10.5.6  Assessment of Pilot Program: One year prior to the
                     ---------------------------
                     completion of the program, PG&E will begin working with
                     interested parties to prepare a report assessing the pilot
                     meter add-on program. This assessment report, which will
                     include recommendations for the future of the program, will
                     be submitted to the CPUC six months prior to the end of
                     this program. The report will address, among other things,
                     whether the pilot program should be expanded, and the
                     disposition of all existing customer-owned add-on devices
                     if the meter add-on pilot program is terminated.

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    2.11  Provide Competitive Billing Options to Customers Similar to Those
          Offered in the Electric Industry
        2.11.1 Summary of D.99-07-015: The Commission states that competing gas
               and electric providers should be able to choose to provide a
               consolidated bill for gas and electricity so that the customers
               of such providers will not face duplicative charges for the
               billing function. The Commission feels that it may be appropriate
               for the natural gas utilities to provide billing options similar
               to those currently offered on the electric side. The Commission
               states that it should be just as possible for an electricity
               provider to bill its customers for gas service as it would be for
               a gas provider to bill for electric service. The Commission
               includes this as a promising option for further study and wants
               to examine cost system conversion and potential labor impacts
               associated with providing competitive billing and other services
               in the cost/benefit phase. (pp. 85-86, FoF 43, CoL 19, Appendix
               C)

        2.11.2 Current Billing Options: Currently, CTAs who sell gas to
               residential and small commercial customers have three options
               open to them. The first option is for the CTA to bill for the gas
               commodity and have PG&E bill for gas transportation. This is
               called separate billing. The second option is for the CTA to bill
               for both their gas service and PG&E's transportation service.
               This option is called CTA consolidated billing. A third billing
               option, PG&E consolidated billing, where PG&E bills for both its
               transportation service and the CTA's commodity gas cost, is
               currently available only for dual-commodity customers who also
               participate in electric direct access. PG&E consolidated billing
               for gas-only customers (including those customers that receive
               separate gas and electric bills) will not be available until the
               Billing Availability Date as defined in Section 1.8 above.

        2.11.3 PG&E Consolidated Gas Billing: PG&E will provide a PG&E gas
               consolidated billing option for gas-only customers by the Billing
               Availability Date. This approach avoids unnecessary costs for
               programming and manual processes which would still take one to
               one-and-a-half years to complete, and then be disposed of once
               the new billing system is operational. Once implemented, PG&E
               reserves the right to charge CTAs for PG&E consolidated gas
               billing services based on a methodology consistent with the
               methodology then in effect for PG&E consolidated electric
               billing.

        2.11.4 Termination of Informational Bill Requirement: If a CTA performs
               CTA consolidated billing, PG&E is currently required to send the
               customer an informational bill. The Parties agree that the
               requirement for an informational bill should be removed upon
               implementation of this Settlement Agreement for those CTAs
               receiving PG&E billing information via Electronic Data
               Interchange (EDI) that agree in writing to present the requisite
               PG&E-provided charges, bill inserts and customer protection
               information in each end-user bill. CTAs also agree to provide a
               market-index commodity price (i.e., the Natural Gas Intelligence
               Weekly Gas Price Index, first of the month publication, PG&E
               Citygate, Bidweek) or the currently-required PG&E core
               procurement price in each end-user bill. The CTA shall annually
               elect which commodity price to provide. The requisite information
               to be presented in each end-user's bill will be addressed as

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               part of the tariff process described in Section 1.7 above. In the
               agreement between PG&E and the CTA, the CTA shall indemnify PG&E
               for all direct and consequential damages, and the CTA shall
               expressly agree to assume all liability associated with the CTA's
               modification of, or failure to provide a customer with, any PG&E-
               provided bill insert. Any disputes concerning the content of PG&E
               provided bill inserts will be resolved by the Energy Division of
               the CPUC. As part of its compliance filing set forth in Section
               1.7, PG&E will include provisions specifying compliance
               monitoring, cost responsibility, and enforcement measures. Any
               such CTA agreements will be in effect for the term of this
               Settlement Agreement, except that they will expire after (i) gas
               consumer protection legislation becomes effective which includes
               a provision authorizing the CPUC to enforce consumer protection
               rules, and (ii) the CPUC adopts such rules, including a CTA
               certification program.

        2.11.5 Billing Credits for CTA-Consolidated Billing: The customer of a
               CTA, which performs consolidated CTA billing, will get the
               following avoided cost credit off their transportation rate as
               long as PG&E no longer has to send them an informational bill per
               Section 2.11.4 above. These credits will apply for both gas-only
               customers and dual-commodity customers for the term of this
               Settlement Agreement. If an Energy Service Provider (ESP) is also
               a CTA and performs both gas and electric consolidated billing for
               a dual-commodity customer, then that customer will receive the
               CTA consolidated gas billing credit in addition to the applicable
               electric credit for a dual-commodity customer.

                                                 ($ per account per month)
                                        Residential        G-NR1          G-NR2
                                        -----------        -----          -----
                   Gas Billing Credit      $0.71           $1.00          $1.00

        2.11.6 Delivery of CTA Consolidated Gas Billing Credits: PG&E will
               deliver credits to those customers receiving consolidated billing
               services from their respective CTAs via checks sent to the
               respective CTAs in whatever manner PG&E deems most
               cost-effective, except that PG&E will deliver such checks on at
               least a semi-annual basis. This process will continue for the
               term of this Settlement Agreement, or until automation of the gas
               credit process in the new billing system. Upon automation of the
               gas credit process, credits will be included as a line item on
               PG&E's customer-specific billing data provided to CTAs and shown
               on their consolidated bill to these customers.


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3.  PROMISING OPTIONS ALREADY IN PLACE FOR PG&E

    Parties agree that the following promising options identified in D.99-07-015
    do not need to be litigated for the PG&E system in I.99-07-003, although
    they may be otherwise negotiated or litigated for the post-Gas Accord
    period. Through the Gas Accord, PG&E has already implemented these options
    for the Gas Accord period.

    3.1   Create Firm Tradable Intrastate Transmission Rights

        3.1.1  Summary of D.99-07-015: The Commission agrees that the creation
               of firm, tradable intrastate transmission rights offers the hope
               of improving efficiency through value-based pricing, as well as
               providing individual shippers with greater certainty as to their
               ability to move certain quantities of gas through the pipeline
               system.
               (pp. 12-14, FoF 1 & 2, CoL 1, 2, 5, Appendix C)

        3.1.2  Resolution: The path-based firm backbone transmission capacity
               rights established by the Gas Accord continue to apply for
               Northern California. These rights are fully tradable and
               assignable, subject to the creditworthiness of the assignee.

    3.2   Establish a Secondary Market for Intrastate Transmission Capacity

        3.2.1  Summary of D.99-07-015: Participation in the secondary market
               transactions through a mandatory Electronic Bulletin Board is
               consistent with the Commission's goals of enhancing market
               efficiency, preventing anti-competitive behavior, and providing
               additional competitive tools to the marketplace. The Commission
               wants to understand the costs of providing such a service before
               determining whether to require its provision. (p. 79, FoF 38,
               Appendix C)

        3.2.2  Resolution: A secondary market exists for PG&E's firm intrastate
               transmission capacity rights. This Settlement Agreement
               establishes an electronic trading platform for secondary market
               transmission transactions pursuant to Section 2.8 above.

    3.3   Place the Utility At Risk for Unused [Transmission] Resources

        3.3.1  Summary of D.99-07-015: The Commission refers to the fact that
               PG&E's shareholders are at risk for "stranded" costs associated
               with intrastate transmission in a table. (p. 12)

        3.3.2  Resolution: The Gas Accord places PG&E at risk for recovery of
               transmission facility costs, and the rates associated with these
               costs are fixed for the Gas Accord period. These at-risk
               provisions continue to apply. However, this Settlement Agreement
               does not predetermine how risk will be allocated following the
               Gas Accord.



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    3.4   Create Firm, Tradable Storage Rights

        3.4.1  Summary of D.99-07-015: The Commission believes there would be
               more efficient use of the hard-to-find gas storage resources if
               individual shippers and customers could bid for firm storage
               access rights. In addition, the local distribution company will
               be motivated to pursue more complete utilization of its storage
               assets if its shareholders bear the risk for cost recovery. If
               accompanied by an active secondary market, the bidding and
               trading of storage rights should lead to pricing that reflects
               demand. (pp. 23-24, FoF 9, CoL 4, Appendix C)

        3.4.2  Resolution: The Gas Accord assigned PG&E's existing firm gas
               storage capacity rights to core procurement, pipeline balancing
               and an unbundled storage program. Annual open seasons are held
               under the unbundled storage program, with negotiated deals at
               other times. The acquirers of firm storage capacity can sell that
               capacity on the secondary market, as can core procurement
               entities holding firm storage capacity, subject to the
               creditworthiness of the assignee.

    3.5   Establish a Secondary Market For Intrastate Storage Capacity

        3.5.1  Summary of D.99-07-015: The Commission anticipates that the
               existence of an active secondary market for storage would reduce
               a utility's ability to increase its storage revenues in an unfair
               manner. Shippers should be more willing to acquire storage rights
               when they know they are able to sell unused capacity on the
               secondary market. Participation in the secondary market
               transactions through a mandatory Electronic Bulletin Board is
               consistent with the Commission's goals of enhancing market
               efficiency, preventing anti-competitive behavior, and providing
               additional competitive tools to the marketplace. The Commission
               wants to understand the costs of providing such a service before
               determining whether to require its provision.
               (p. 24, FoF 38, Appendix C)

        3.5.2  Resolution: As with firm transmission capacity, firm storage
               rights are already tradable and assignable under the provisions
               of the Gas Accord, subject to the creditworthiness requirements.
               Parties agree that no further action is needed on the PG&E system
               for trading storage rights.

    3.6   Place the Utility At-Risk for Unused [Storage] Resources

        3.6.1  Summary of D.99-07-015: The Commission requests the parties to
               consider the costs and benefits related to creating a system of
               tradable storage rights in Southern California that places the
               utility at risk for unused resources and preserving such a market
               in Northern California beyond the period of the Gas Accord.
               (pp. 20-24, Appendix C)

        3.6.2  Gas Accord At-Risk Requirements: The Gas Accord places PG&E at
               risk for recovery of its storage facility costs. The major
               portion of the storage (32.8 Bcf) is assigned to core customers
               to ensure reliability of service. The core is obligated to pay
               these costs. However, this Settlement Agreement allows Core
               Transport


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               Agents (CTAs) to provide reliability through other means and
               avoid payment of their share of these costs. Another portion of
               storage (2.2 Bcf) is assigned to pipeline balancing. These costs
               are included in the backbone transmission rates, which are at-
               risk for cost recovery. The feasibility of adding more storage
               assets to this service is one of the issues for the OFO Forum, as
               provided in the Gas OFO Settlement, filed October 22, 1999 in
               I.99-07-003.

               The remaining portion of storage (4.7 Bcf) is assigned to a fully
               at-risk unbundled storage program, where firm and negotiated
               storage services are offered by PG&E's Golden Gate Market Center.

        3.6.3  Resolution: These at-risk provisions for storage continue to
               apply, as modified by this Settlement Agreement. However, this
               Settlement Agreement does not predetermine how risk will be
               allocated following the Gas Accord period.

    3.7   Separate Utility Hub Services From Procurement Functions

        3.7.1  Summary of D.99-07-015: The Commission would like to separate hub
               services, where possible, from the procurement function to
               eliminate the possibility of a conflict of interest affecting the
               two functions. (pp. 48-49, CoL 10, Appendix C)

        3.7.2  Resolution: The current rules and protocols provide separation of
               PG&E's Core Procurement Department from PG&E's utility hub
               services for the term of the Gas Accord. This issue may be
               revisited during the post-Gas Accord negotiations.

    3.8   Unbundle Utility Interstate Capacity Costs for Core Customers

        3.8.1  Summary of D.99-07-015: The Commission recommends the unbundling
               of interstate capacity costs for SoCalGas, which may enhance the
               opportunities for competition for core customers, as marketers
               search for ways to beat SoCalGas' costs for inter-state
               transportation. PG&E and SDG&E have already unbundled such costs.
               (p. 49 [#4], pp. 60-61, FoF 31, Appendix C)

        3.8.2  Resolution: PG&E unbundled these costs as part of the Gas Accord.
               This unbundling was approved in D.97-12-032, dated December 4,
               1997.

    3.9   Eliminate Core Subscription Service

        3.9.1  Summary of D.99-07-015: The Commission recommends to eliminate
               the core subscription by April 1, 2001, and require that any
               noncore customer who prefers to continue procurement from local
               distribution companies after that date to take and pay for core
               service. (p. 49 [#7], pp. 63-64, Appendix C)

        3.9.2  Resolution: The Gas Accord, as approved in D.97-08-055, phases
               out core subscription by March 1, 2001. Parties agree that no
               further action is needed on the PG&E system.



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4.  PROMISING OPTIONS AND OTHER ISSUES WHICH ARE NOT TO BE LITIGATED PENDING
    FURTHER SETTLEMENT DISCUSSIONS

    4.1   Develop Clear Procedures for Allocating [Firm] Capacity

        4.1.1  Summary of D.99-11-053 issued November 18, 1999: This decision
               resolved the investigation into PG&E's bidding behavior in the
               Gas Accord open season auction. The Commission finds that PG&E
               abided by all the rules in place at that time and "that the UEG
               did not behave in an anti-competitive manner warranting penalty.
               The auction procedures should be reformed to further limit the
               ability of any single entity to unduly influence the market."
               (Mimeo, p. 22) The Commission also notes that "[F]urther
               discussion of potential reforms to auction rules for intrastate
               transmission capacity and for sales in the secondary market may
               take place within Investigation 99-07-003." (Mimeo, p. 25,
               Ordering Paragraph 2)

        4.1.2  Resolution: PG&E does not plan on conducting any firm capacity
               open seasons before the end of the Gas Accord period. PG&E and
               the Parties will re-examine the issue of open season rules in the
               process of negotiating a post-Gas Accord settlement. Parties
               agree that this issue does not need to be litigated or resolved
               as part of I.99-07-003 or the current Settlement Agreement.

    4.2   Revise PG&E's Transmission Interconnection Policy, Terms and
          Conditions (Not an Appendix C Item)

        4.2.1  Gas Rule 27 Committee: This issue, which includes PG&E's proposed
               Gas Rule 27, is under consideration by a committee of the
               Parties. The objective is to resolve this issue through
               settlement, and perhaps a separate application.

        4.2.2  Resolution: Parties agree that these issues do not need to be
               litigated or resolved as part of I.99-07-003 or the current
               Settlement Agreement.

    4.3   Revise PG&E's Electric Generation Rate Design (Not an Appendix C Item)

        4.3.1  Resolution: The Parties agree not to litigate issues related to
               Public Utilities Code Section 454.4 in I.99-07-003. The Parties
               also agree that PG&E's Biennial Cost Allocation Proceeding
               (BCAP), and not I.99-07-003, is an appropriate proceeding in
               which to address PG&E's electric generation cost allocation and
               rate design issues in I.99-07-003. PG&E commits to work with the
               BCAP parties to attempt to settle these issues.

    4.4.  Review PG&E's Local Transmission Reliability, Design Standards and
          Curtailment Provisions (Not an Appendix C Item)

        4.4.1  Resolution: Parties agree that issues related to PG&E's local
               transmission reliability, design standards and local curtailment
               provisions will be negotiated


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               separately, and will not be litigated with respect to PG&E as
               part of I.99-07-003 or resolved in this Settlement Agreement.

    4.5   Investigate Mechanisms to Reduce the Costs of Transmission Service for
          Noncore Customers Connecting To or Located Close To PG&E's Backbone
          Transmission Facilities (Not an Appendix C Item)

        4.5.1  Resolution: Parties agree that issues related to "direct
               connects," and/or limited use of PG&E's local transmission
               system, between a customer's facility and PG&E's backbone
               facilities will be negotiated separately, and will not be
               litigated with respect to PG&E as part of I.99-07-003 or resolved
               in this Settlement Agreement.

5.  PROMISING OPTIONS WHICH WERE SETTLED IN THE OFO SETTLEMENT AGREEMENT

    5.1   Examine Strategies for Devoting More Assets to PG&E Balancing

        5.1.1  Summary of D.99-07-015: The Commission states that it is clear
               that shippers need to be better-equipped to anticipate and
               respond to OFOs. It's logical to assume that if PG&E had more
               storage capacity set aside to support its balancing efforts, it
               would have greater ability to smooth out fluctuations in system
               balancing without calling OFOs or undertaking curtailments. The
               Commission considers asking PG&E to identify the incremental cost
               of expanding balancing services in the next phase and suggests
               all interested parties to address the economics of this step.
               (pp. 32-33, FoF 15, CoL 6, Appendix C

        5.1.2  OFO Forum: This issue will be considered by the OFO Forum in
               accordance with Section 2.1.3.7 above.

        5.1.3  Balancing Study: PG&E agrees to provide the balancing study to
               all parties participating in the OFO Forum no later than March 7,
               2000, even if the date for filing testimony is extended.

        5.1.4  Resolution: Parties agree that this issue does not need to be
               litigated in I.99-07-003 and that the Forum is open to all
               storage operators on the PG&E system, as well as customers,
               shippers and consumer representatives.

    5.2   Implement Targeted Operational Flow Orders

        5.2.1  Summary of D.99-07-015: The Commission wants to explore targeted
               OFOs along with other similar reforms in the cost/benefit phase.
               They believe even though it's possible that some customers might
               respond to a targeted request by shifting excess gas to other
               customers, it may also improve the system balance. (p. 41, p. 50
               [#10], FoF 23, CoL 9, Appendix C)


================================================================================
       Subject to Rule 51 of the CPUC Rules of Practice and Procedure.
    Rule 601 et seq of the FERC Rules of Practice. Rule 408 of the Federal
             -- ---
     Rules of Evidence and Section 1152 of the California Evidence Code
================================================================================

Page 33
January 28, 2000
<PAGE>

CPUC Promising Gas Options I.99-07-003
Comprehensive Gas OII Settlement Agreement
------------------------------------------


        5.2.2  Resolution: The OFO Settlement provides specific procedures for
               implementing customer-specific or targeted OFOs. No further
               litigation is needed.

    5.3   Provide Pipeline Operator Demand Forecasts Broken Down by Customer
          Class

        5.3.1  Summary of D.99-07-015:  The Commission is not persuaded that
               disaggregating demand forecast information will create a
               disadvantage for any customer, including the core. Furthermore,
               the Commission does not believe that any particular customer
               would have an incentive to lessen the reliability or precision of
               its communications with the pipeline operator if they were
               provided the demand forecasts. (pp. 79-84, FoF 41, Appendix C)

        5.3.2  Resolution: The OFO Settlement Agreement specifies that PG&E will
               provide customer class demand data with a three-day lag, as
               agreed to by those Parties. No further litigation is needed.


6.  NO ISSUES REMAIN TO BE LITIGATED IN I.99-07-003

     Parties agree that there are no issues of material fact or promising
     options which need litigating in I.99-07-003, provided the Commission
     approves this Settlement Agreement pursuant to its conditions. If
     Commission approval is conditional or modifies the Settlement Agreement,
     Parties reserve the right to seek hearings on any or all issues otherwise
     covered by this Settlement Agreement.


================================================================================
       Subject to Rule 51 of the CPUC Rules of Practice and Procedure.
    Rule 601 et seq of the FERC Rules of Practice. Rule 408 of the Federal
             -- ---
     Rules of Evidence and Section 1152 of the California Evidence Code
================================================================================

Page 34
January 28, 2000
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.2
<SEQUENCE>7
<FILENAME>dex102.txt
<DESCRIPTION>CREDIT AGREEMENT
<TEXT>

<PAGE>

                                                                    EXHIBIT 10.2


      ==================================================================


                                CREDIT AGREEMENT

                                     among

                                PG&E CORPORATION
                                  as Borrower,

                           the LENDERS party hereto,

                      GENERAL ELECTRIC CAPITAL CORPORATION
                                as Co-Arranger,

                          LEHMAN COMMERCIAL PAPER INC.
                            as Administrative Agent

                                      and

                              LEHMAN BROTHERS INC.

                       as Lead Arranger and Book Manager


                    _______________________________________

                           Dated as of March 1, 2001

                    _______________________________________


      ==================================================================
<PAGE>

                               TABLE OF CONTENTS
                               -----------------
<TABLE>
<CAPTION>
                                                                          Page
                                                                          ----
<S>                                                                       <C>
SECTION 1.  DEFINITIONS AND RULES OF INTERPRETATION...................       1

        1.1  Defined Terms............................................       1
        1.2  Rules of Interpretation..................................       1
        1.3  Accounting Principles....................................       1

SECTION 2.  AMOUNTS AND TERMS OF CREDIT FACILITY......................       1

        2.1  The Commitment...........................................       1
        2.2  Notice of Borrowing......................................       2
        2.3  Disbursement of Funds....................................       2
        2.4  Notes....................................................       2
        2.5  Interest.................................................       2
        2.6  Interest Periods.........................................       3
        2.7  Increased Costs, Illegality, etc.........................       5
        2.8  Compensation.............................................       6
        2.9  Extension of Maturity Date ..............................       7

SECTION 3.  PREPAYMENTS; PAYMENTS; TAXES..............................       7

        3.1  Voluntary Prepayments....................................       7
        3.2  Mandatory Repayments.....................................       7
        3.3  Method and Place of Payment..............................       9
        3.4  Net Payments.............................................      10
        3.5  Allocation...............................................      12
        3.6  Fee......................................................      12
        3.7  Application of Payments; Sharing.........................      12

SECTION 4.  CONDITIONS PRECEDENT......................................      13

        4.1  Conditions to Closing....................................      13

SECTION 5.  REPRESENTATIONS, WARRANTIES AND AGREEMENTS................      18

        5.1  Standing.................................................      19
        5.2  Requisite Authority; Etc.................................      19
        5.3  No Conflict..............................................      19
        5.4  Consents.................................................      19
        5.5  Compliance with Law......................................      20
        5.6  Litigation Claims........................................      20
        5.7  Contracts and Commitments................................      20
        5.8  Liens....................................................      21
        5.9  Insurance................................................      21
</TABLE>
<PAGE>

<TABLE>
<S>                                                                                        <C>
        5.10  Capitalization and Ownership................................................  21
        5.11  Financial Statements; Absence of Certain Changes............................  22
        5.12  Taxes.......................................................................  23
        5.13  Disclosure..................................................................  24
        5.14  Environmental Matters.......................................................  24
        5.15  Brokers' or Finders' Fees...................................................  24
        5.16  Certain Regulatory Matters..................................................  24
        5.17  Transactions With Affiliates................................................  26
        5.18  Use of Proceeds.............................................................  26
        5.19  Compliance with ERISA.......................................................  26
        5.20  Investment Company Act......................................................  27
        5.21  Regulation..................................................................  27
        5.22  Security Documents..........................................................  27
        5.23  Certain Scheduled Projects..................................................  27
        5.24  Environmental Matters.......................................................  28
        5.25  Intellectual Property.......................................................  28
        5.26  No Default..................................................................  29
        5.27  Single-Purpose Entity.......................................................  29
        5.28  Trust Indenture Act.........................................................  29
        5.29  [OMITTED]...................................................................  29
        5.30  Ratings Letter..............................................................  29
        5.31  Certain Indebtedness........................................................  29

SECTION 6.  AFFIRMATIVE COVENANTS.........................................................  30

        6.1   Information Covenants.......................................................  30
        6.2   Books, Records and Inspections..............................................  33
        6.3   Maintenance of Property; Insurance..........................................  33
        6.4   Corporate Franchises........................................................  34
        6.5   Compliance with Statutes, etc...............................................  34
        6.6   Compliance with Environmental Laws..........................................  34
        6.7   ERISA.......................................................................  35
        6.8   End of Fiscal Years; Fiscal Quarters........................................  36
        6.9   Payment of Taxes............................................................  36
        6.10  [OMITTED....................................................................  36
        6.11  Performance of Obligations..................................................  37
        6.12  Use of Proceeds.............................................................  37
        6.13  Regulatory Compliance.......................................................  37
        6.14  Financial Covenants.........................................................  37
        6.15  Charter Documents...........................................................  37
        6.16  Further Assurances; etc.....................................................  37
        6.17  Tax Refund..................................................................  38

SECTION 7.  NEGATIVE COVENANTS............................................................  38

        7.1  Liens........................................................................  38
        7.2  Consolidation, Merger, Purchase or Sale of Assets, etc.......................  40
</TABLE>

                                      ii
<PAGE>

<TABLE>
<S>                                                                                           <C>
        7.3    Dividends....................................................................  41
        7.4    Indebtedness.................................................................  41
        7.5    Advances, Investments and Loans..............................................  42
        7.6    Transactions with Affiliates.................................................  43
        7.7    Capital Expenditures.........................................................  43
        7.8    Limitations on Liens on Collateral; Modifications of Certain Indebtedness;
                 Modifications of Certificate of Incorporation, By-Laws and Certain Other
                 Agreements, etc............................................................  43
        7.9    Limitation on Issuance of Capital Stock......................................  44
        7.10   Business.....................................................................  45
        7.11   Regulatory Compliance........................................................  45

SECTION 8.      EVENTS OF DEFAULT AND REMEDIES..............................................  45

        8.1    Events of Default............................................................  45
        8.2    Acceleration.................................................................  48
        8.3    Other Remedies...............................................................  48

SECTION 9.      MISCELLANEOUS...............................................................  48

        9.1    Costs and Expenses...........................................................  48
        9.2    Indemnity....................................................................  49
        9.3    Notices......................................................................  51
        9.4    Benefit of Agreement.........................................................  51
        9.5    No Waiver; Remedies Cumulative...............................................  51
        9.6    No Third Party Beneficiaries.................................................  52
        9.7    Reinstatement................................................................  52
        9.8    No Immunity..................................................................  52
        9.9    Counterparts.................................................................  52
        9.10   Amendment or Waiver..........................................................  52
        9.11   Assignments, Participations, etc.............................................  53
        9.12   Survival.....................................................................  55
        9.13   WAIVER OF JURY TRIAL.........................................................  55
        9.14   Right of Set-off.............................................................  55
        9.15   Severability.................................................................  55
        9.16   Governing Law; Submission to Jurisdiction....................................  56
        9.17   Waiver by Borrower...........................................................  57
        9.18   Recourse.....................................................................  57
        9.19   Complete Agreement...........................................................  57
        9.20   Publicity....................................................................  57
        9.21   Effectiveness................................................................  57
        9.22   Certain Representations and Warranties.......................................  57
        9.23   Confidentiality..............................................................  57
</TABLE>

                                     iii
<PAGE>

<TABLE>
<S>                                                                                         <C>
SECTION 10.   THE ADMINISTRATIVE AGENT; THE LEAD ARRANGER, THE CO-
              ARRANGER AND THE BOOK MANAGER.................................................58

        10.1   Appointment..................................................................58
        10.2   Nature of Duties.............................................................58
        10.3   Lack of Reliance on the Agent................................................58
        10.4   Certain Rights of the Administrative Agent...................................59
        10.5   Reliance.....................................................................59
        10.6   Indemnification..............................................................59
        10.7   The Administrative Agent in its Individual Capacity..........................60
        10.8   Holders......................................................................60
        10.9   Resignation by the Administrative Agent......................................60
        10.10  The Lead Arranger, Co-Arranger and Book Manager..............................61
</TABLE>

                                      iv
<PAGE>

APPENDICES:
----------

        Appendix A           Defined Terms and Rules of Interpretation

EXHIBITS:
--------

        Exhibit A            Form of Notice of Borrowing
        Exhibit B            Form of Note
        Exhibit C            Form of Section 3.4(b)(ii) Certificate
        Exhibit D            Form of Process Agent Letter

SCHEDULES:
---------

        Schedule 3.5         Allocation - Investment Unit
        Schedule 4.1(k)      SEC Filings
        Schedule 5.6         Litigation
        Schedule 5.7         Covered Contracts
        Schedule 5.8         Liens
        Schedule 5.9         Insurance
        Schedule 5.10(e)     Warrants, etc.
        Schedule 5.10(f)     Ownership
        Schedule 5.14        Environmental Matters
        Schedule 5.15        Brokers
        Schedule 5.16(e)     Regulated Entities
        Schedule 5.17        Transactions with Affiliates
        Schedule 5.19        ERISA
        Schedule 5.23        Scheduled Projects
        Schedule 7.1         Certain Liens
        Schedule 9.3         Notices

ANNEXES
-------

        Annex A              Section 13 of the LLC Agreement

                                       v
<PAGE>

          CREDIT AGREEMENT (this "Agreement"), dated as of March 1, 2001, among
                                  ---------
PG&E Corporation, a California corporation, as the Borrower, the Lenders party
hereto, General Electric Capital Corporation, a New York corporation, as Co-
Arranger, Lehman Commercial Paper Inc., a New York corporation, as
Administrative Agent, and Lehman Brothers Inc., a Delaware corporation, as Lead
Arranger and Book Manager.

                              W I T N E S S E T H:
                              -------------------

          WHEREAS, the Lenders party hereto are willing to provide the credit
facility described herein upon the terms and conditions herein set forth;

          NOW, THEREFORE, in consideration of the premises and mutual agreements
hereinafter contained, the parties hereto agree as follows:

          SECTION 1.  DEFINITIONS AND RULES OF INTERPRETATION.
                      ---------------------------------------

          1.1  Defined Terms.  Except as otherwise expressly provided herein,
               -------------
capitalized terms used in this Agreement and its Schedules and Exhibits shall
have the respective meanings assigned to such terms in Appendix A hereto.

          1.2  Rules of Interpretation.  Except as otherwise expressly provided
               -----------------------
herein, the rules of interpretation set forth in Appendix A hereto shall apply
to this Agreement.

          1.3  Accounting Principles.  Except as otherwise provided in this
               ---------------------
Agreement, all computations and determinations as to financial matters, and all
financial statements to be delivered under this Agreement shall be made or
prepared in accordance with U.S. GAAP (including principles of consolidation
where appropriate) applied on a consistent basis (except to the extent approved
or required by the independent public accountants certifying such statements and
disclosed therein).

          SECTION 2.  AMOUNTS AND TERMS OF CREDIT FACILITY.
                      ------------------------------------

          2.1  The Commitment.  (a)  Subject to and upon the terms and
               --------------
conditions set forth herein, each Lender agrees to make a term loan to the
Borrower, which term loans (i) shall be incurred pursuant to a single drawing on
the Closing Date, (ii) shall be denominated in Dollars, (iii) shall be incurred
and maintained as Eurodollar Loans, except as otherwise specifically provided in
Section 2.7(b), (iv) shall be made on the Closing Date in an aggregate principal
amount which (x) in the case of the Tranche A Loan, equals the Tranche A
Commitment and (y) in the case of the Tranche B Loan, equals the Tranche B
Commitment, and (v) shall mature on the earlier of (A) the date of a Spin-Off of
NEG, Inc. and (B) the Date Certain.

          (b) If the Closing Date has not occurred on or prior to March 30,
2001, then, in such event, the Lenders shall have no further obligations or
liabilities under any of the Financing Documents and the Financing Documents
shall have no further force or effect with respect to the Lenders, but the
Borrower's obligation to pay the Commitment Fees and other costs, fees and
<PAGE>

expenses as provided herein and to indemnify the other parties to the Financing
Documents shall not be terminated, modified or diminished in any respect.

          (c) The Loans are available only on the terms and conditions specified
hereunder, and once repaid, in whole or in part, at maturity or by prepayment,
may not be reborrowed in whole or in part.

          2.2  Notice of Borrowing.  The Borrower shall give the Lenders prior
               -------------------
notice of the Eurodollar Loan to be incurred hereunder, provided that any such
                                                        --------
notice shall be deemed to have been given on a certain day only if given before
1:00 P.M. (New York time) on such day.  Such notice (the "Notice of Borrowing")
                                                          -------------------
shall be irrevocable and shall be in writing, or by telephone promptly confirmed
in writing, in the form of Exhibit A, appropriately completed to specify:  (i)
the aggregate principal amount of the Loans to be incurred on the Closing Date
(which shall be a Business Day), (ii) the Selected Interest Period for the
period beginning on the Closing Date pursuant to Section 2.6(b), and (iii) the
account information for disbursement of the Loans.

          2.3  Disbursement of Funds.  No later than 1:00 P.M. (New York time)
               ---------------------
on the Closing Date, each Lender will make available such Lender's pro rata
                                                                   --- ----
share of the amount of Borrowing requested to be made on such date.  All such
amounts will be made available in Dollars and in immediately available funds and
disbursed in accordance with the provisions of the Escrow Agreement.

          2.4  Notes.  (a)  The Borrower's obligation to pay the principal of,
               -----
and interest on, any Loan made by a Lender shall be evidenced by a promissory
note duly executed and delivered by the Borrower substantially in the form of
Exhibit B, with blanks appropriately completed in conformity herewith (each, a
"Note").
 ----

          (b) The Note issued to a Lender shall (i) be executed by the Borrower,
(ii) be payable to such Lender or its Assignee and be dated the Closing Date
(or, if issued after the Closing Date, be dated the date of issuance thereof),
(iii) be in a stated principal amount equal to the Loan made by, or assigned to,
such Lender, as the case may be, and be payable in the outstanding principal
amount of the Loan evidenced thereby, (iv) mature on the earlier of (A) the date
of a Spin-Off of NEG, Inc. and (B) the Date Certain, (v) bear interest as
provided in the appropriate clause of Section 2.5 in respect of a Base Rate Loan
(if converted pursuant to Section 2.7(b)) or a Eurodollar Loan, as the case may
be, evidenced thereby, (vi) be subject to voluntary prepayment as provided in
Section 3.1, and mandatory repayment as provided in Section 3.2, and (vii) be
entitled to the benefits of this Agreement and the other Financing Documents.

          (c) Each Lender will note on its internal records the amount of the
Loan made by it and each payment in respect thereof and will prior to any
transfer of its Note endorse on the reverse side thereof the outstanding
principal amount of the Loan evidenced thereby.  Failure to make any such
notation or any error in such notation shall not affect the Borrower's
obligations in respect of such Loan.

          2.5  Interest.  (a)  The Borrower agrees to pay interest in respect of
               --------
the unpaid principal amount of any Base Rate Loan from the date of conversion
thereof pursuant to Section

                                      -2-
<PAGE>

2.7(b) until the maturity thereof (whether by acceleration or otherwise) at a
rate per annum which shall be equal to the sum of the Applicable Margin plus the
Base Rate each as in effect from time to time.

          (b) The Borrower agrees to pay interest in respect of the unpaid
principal amount of each Eurodollar Loan from the date of Borrowing thereof
until the earlier of (i) the maturity thereof (whether by acceleration or
otherwise) and (ii) the conversion of such Eurodollar Loan to a Base Rate Loan
pursuant to Section 2.7(b) at a rate per annum which shall, during each Interest
Period applicable thereto, be equal to the sum of the Applicable Margin as in
effect from time to time during such Interest Period plus the Eurodollar Rate
for such Interest Period.

          (c) Overdue principal and, to the extent permitted by law, overdue
interest in respect of each Loan and any other overdue amount payable by the
Borrower shall, in each case, bear interest at a rate per annum equal to the
rate which is 2% in excess of the rate then borne by such Loan.  Interest which
accrues under this Section 2.5(c) shall be payable on demand.

          (d) Accrued (and theretofore unpaid) interest shall be payable (i) in
respect of each Base Rate Loan, (x) quarterly in arrears on each Quarterly Date,
(y) on the date of any repayment or prepayment in full of the outstanding
principal amount of such Base Rate Loan, and (z) at maturity (whether by
acceleration or otherwise) and, after such maturity, on demand, and (ii) in
respect of each Eurodollar Loan, (x) on the last day of each Interest Period
applicable thereto and, in the case of an Interest Period in excess of three
months, on each date occurring at three month intervals after the first day of
such Interest Period, and (y) on the date of any repayment or prepayment (on the
amount repaid or prepaid), at maturity (whether by acceleration or otherwise)
and, after such maturity, on demand; provided that the first interest payment
                                     --------
shall be due and payable in advance on the Closing Date in an amount equal to
the Interest Prepaid Amount and the first Interest Period shall be a one year
period (the "First Interest Period").

          (e) Upon each Interest Determination Date with respect to any
Eurodollar Loan, the Administrative Agent shall determine the Eurodollar Rate
for the relevant Interest Period applicable to such Eurodollar Loan and shall
promptly notify the Borrower thereof.  Each such determination shall, absent
manifest error, be final and conclusive and binding on all parties hereto.

          2.6  Interest Periods.  (a)  At the time the Borrower gives the Notice
               ----------------
of Borrowing or prior to 1:00 P.M. (New York time) on the third Business Day
prior to the expiration of an Interest Period applicable to a Eurodollar Loan
(in the case of any subsequent Interest Period), the Borrower shall have the
right to elect the interest period (each an "Interest Period") applicable to
                                             ---------------
such Eurodollar Loan, which Interest Period shall, at the option of the
Borrower, be a one, two, three or six-month period; provided that (in each
                                                    --------
case):

          (i)  the initial Interest Period for any Eurodollar Loan shall
     commence on the date of Borrowing of such Eurodollar Loan and each Interest
     Period occurring thereafter in respect of such Eurodollar Loan shall
     commence on the day on which the next preceding Interest Period applicable
     thereto expires;

                                      -3-
<PAGE>

           (ii)  if any Interest Period for a Eurodollar Loan begins on a day
     for which there is no numerically corresponding day in the calendar month
     at the end of such Interest Period, such Interest Period shall end on the
     last Business Day of such calendar month;

           (iii) if any Interest Period for a Eurodollar Loan would otherwise
     expire on a day which is not a Business Day, such Interest Period shall
     expire on the next succeeding Business Day; provided, however, that if any
                                                 --------  -------
     Interest Period for such Eurodollar Loan would otherwise expire on a day
     which is not a Business Day but is a day of the month after which no
     further Business Day occurs in such month, such Interest Period shall
     expire on the next preceding Business Day;

           (iv)  no Interest Period may be selected at any time when a Default
     or an Event of Default is then in existence; and

           (v)   no Interest Period in respect of any Borrowing of any
     Eurodollar Loan shall be selected which extends beyond the Date Certain.

          If upon the expiration of any Interest Period applicable to any
Eurodollar Loan, the Borrower has failed to elect, or is not permitted to elect,
a new Interest Period to be applicable to such Eurodollar Loan as provided
above, the Borrower shall be deemed to have elected a one-month Interest Period
effective as of the expiration date of such current Interest Period.

          (b) During the First Interest Period, the Borrower shall have the
right, at the times indicated and following the procedure set forth in Section
2.6(a), to deliver notice to the Administrative Agent to indicate Interest
Periods of one, two, three or six months (each such Interest Period, with
respect to any Eurodollar Loan, a "Selected Interest Period") for purposes of
                                   ------------------------
comparing the interest rates.  The Administrative Agent shall determine the
Eurodollar Rate for each such Selected Interest Period applicable to a
Eurodollar Loan and the amount of accrued interest (such amount, the "Selected
                                                                      --------
Interest Amount") which would be payable in respect of such Eurodollar Loan for
---------------
each such Selected Interest Period, which determination shall, absent manifest
error, be final, conclusive and binding on all parties hereto.  On the date
which is the earlier of the date of prepayment of all the Loans by the Borrower
pursuant to the terms hereof and the first anniversary of the Closing Date (x)
the Borrower shall pay to the Administrative Agent the amount by which the sum
of the aggregate Selected Interest Amounts (discounted to present value as of
the Closing Date using a discount factor of 4.25%) plus any amounts due and
payable under Section 2.8 with respect to a Selected Interest Period exceeds the
Interest Prepaid Amount or (y) each Lender shall credit to the Borrower the
amount by which the Interest Prepaid Amount with respect to the Loan of such
Lender exceeds the sum of the aggregate Selected Interest Amounts (discounted to
present value as of the Closing Date using a discount factor of 4.25%) with
respect to the Loan of such Lender plus any amounts due and payable to such
Lender under Section 2.8 or otherwise under this Agreement.  In no event shall a
Selected Interest Period extend beyond the last day of the First Interest
Period.

          2.7  Increased Costs, Illegality, etc.  (a)  In the event that a
               ---------------------------------
Lender shall have determined (which determination shall, absent manifest error,
be final and conclusive and binding upon all parties hereto):

                                      -4-
<PAGE>

           (i)   on any Interest Determination Date that, by reason of any
     changes arising after the date of this Agreement affecting the interbank
     Eurodollar market, adequate and fair means do not exist for ascertaining
     the applicable interest rate on the basis provided for in the definition of
     Eurodollar Rate; or

           (ii)  at any time, that such Lender shall incur increased costs or
     reductions in the amounts received or receivable hereunder with respect to
     any Eurodollar Loan of such Lender because of (x) any change since the
     Closing Date in any applicable law or governmental rule, regulation, order,
     guideline or request (whether or not having the force of law) or in the
     interpretation or administration thereof and including the introduction of
     any new law or governmental rule, regulation, order, guideline or request,
     such as, for example, but not limited to:  (A) a change in the basis of
     taxation of payment to such Lender of the principal of or interest on such
     Lender's Loan or Note or any other amounts payable to such Lender hereunder
     (except for changes in the rate of tax on, or determined by reference to,
     the net income or net profits of such Lender pursuant to the laws of the
     jurisdiction in which it is doing business, organized or in which its
     principal office or applicable lending office is located or any subdivision
     thereof or therein) or (B) a change in official reserve requirements, but,
     in all events, excluding reserves required under Regulation D to the extent
     included in the computation of the Eurodollar Rate and/or (y) other
     circumstances (other than with respect to taxes) arising since the Closing
     Date affecting such Lender (or its Source), the interbank Eurodollar market
     or the position of such Lender in such market; or

           (iii) at any time, that the making or continuance of any Eurodollar
     Loan has been made (x) unlawful by any law or governmental rule, regulation
     or order, (y) impossible by compliance by such Lender in good faith with
     any governmental request (whether or not having force of law) or (z)
     impracticable as a result of a contingency occurring after the Closing Date
     which materially and adversely affects the interbank Eurodollar market;

then, and in any such event, such Lender shall promptly give notice (by
telephone promptly confirmed in writing) to the Borrower of such determination.
Thereafter (x) in the case of clause (i) above, Eurodollar Loans shall no longer
be available until such time as such Lender notifies the Borrower that the
circumstances giving rise to such notice by the Lender no longer exist, (y) in
the case of clause (ii) above, the Borrower agrees to pay to such Lender, upon
such Lender's written request therefor, such additional amounts (in the form of
an increased rate of, or a different method of calculating, interest or
otherwise as such Lender in its sole discretion shall determine) as shall be
required to compensate such Lender for such increased costs or reductions in
amounts received or receivable hereunder (a written notice as to the additional
amounts owed to such Lender, showing in reasonable detail the basis for the
calculation thereof, submitted to the Borrower by such Lender shall, absent
manifest error, be final and conclusive and binding on all the parties hereto)
and (z) in the case of clause (iii) above, the Borrower shall take one of the
actions specified in Section 2.7(b) as promptly as possible and, in any event,
within the time period required by Law.

           Each Lender, at the sole cost and expense of the Borrower (including,
but not limited to, such Lender's internal costs for use of its personnel and
resources), will use its reason-

                                      -5-
<PAGE>

able efforts to minimize taxes indemnifiable by the Borrower under this Section
2.7(a), including by complying with reasonable requests by the Borrower to do or
to refrain from doing any act (including the execution of any certificates or
similar documents required to establish an exemption or relief from any tax), if
such efforts or any such compliance is, in the good faith discretion of such
Lender, of a purely ministerial nature and has no adverse impact on such Lender
or any Affiliate or on the business or operations of the foregoing (unless such
adverse impact is one of a nature and quality such that it is subject to
indemnification and the Borrower has indemnified such Lender against such
adverse impact in a manner satisfactory to such Lender determined in its sole
discretion). The Borrower shall indemnify such Lender for any taxes that may be
imposed on it as a consequence of such compliance.

          (b) At any time that any Eurodollar Loan is affected by the
circumstances described in Section 2.7(a)(i) or (ii), the Borrower may, and in
the case of a Eurodollar Loan affected by the circumstances described in Section
2.7(a)(iii), the Borrower shall, upon at least three Business Days' written
notice to such Lender, require the affected Lender to convert such Eurodollar
Loan into a Base Rate Loan.

          (c) If a Lender determines that after the Closing Date the
introduction of or any change in any applicable law or governmental rule,
regulation, order, guideline, directive or request (whether or not having the
force of law) concerning capital adequacy, or any change in interpretation or
administration thereof by the NAIC or any governmental authority, central bank
or comparable agency, will have the effect of increasing the amount of capital
required or expected to be maintained by such Lender (or its Source) or any
corporation controlling such Lender based on the existence of such Lender's
Commitment hereunder or its obligations hereunder, then the Borrower agrees to
pay to such Lender, upon its written demand therefor, such additional amounts as
shall be required to compensate such Lender or such other corporation for the
increased cost to such Lender or such other corporation or the reduction in the
rate of return to such Lender or such other corporation as a result of such
increase of capital.  In determining such additional amounts, each Lender will
act reasonably and in good faith and will use averaging and attribution methods
which are reasonable, provided that such Lender's determination of compensation
                      --------
owing under this Section 2.7(c) shall, absent manifest error, be final and
conclusive and binding on all the parties hereto.  Such Lender, upon determining
that any additional amounts will be payable pursuant to this Section 2.7(c),
will give prompt written notice thereof to the Borrower, which notice shall show
in reasonable detail the basis for calculation of such additional amounts.

          2.8  Compensation.  The Borrower agrees to compensate each Lender,
               ------------
upon its written request (which request shall set forth in reasonable detail the
basis for requesting such compensation), for all losses, expenses and
liabilities (including, without limitation, any loss, expense or liability
incurred by reason of the liquidation or reemployment of deposits or other funds
required by such Lender to fund its Eurodollar Loan but excluding loss of
anticipated profits) which such Lender may sustain:  (i) if any prepayment or
repayment (including any prepayment or repayment made pursuant to Section 3.1,
Section 3.2 or as a result of an acceleration of the Loans pursuant to Section
8.2) or conversion of any Eurodollar Loan is made on a date other than the last
day of the Interest Period (or during the First Interest Period, any Selected
Interest Period) applicable thereto; or (ii) as a consequence of (x) any other
default by the

                                      -6-
<PAGE>

Borrower to repay such Eurodollar Loan when required by the terms of this
Agreement or any Note held by such Lender or (y) any election made pursuant to
Section 2.7(b).

          2.9  Extension of Maturity Date   The Borrower may by notice to the
               --------------------------
Administrative Agent and the holders of the Loans not later than thirty (30)
days prior to the Initial Date Certain or the Extended Date Certain occurring
six months after the Initial Date Certain (if the maturity date of the Loans was
extended on the Initial Date Certain to such Extended Date Certain), and upon
payment of the Extension Fees relating to such extension pursuant to the Fee
Letter and the Lehman Fee Letter, extend the maturity date of the Loans to the
earlier of (i) the date of a Spin-Off of NEG, Inc. and (ii) the Extended Date
Certain, but in no event shall the Date Certain be beyond the third anniversary
of the Closing Date; provided, that there shall be no extension of the maturity
                     --------
date of the Loans if on the date of such extension, (a) a Default or an Event of
Default shall be continuing or (b) the aggregate outstanding principal amount of
the Loans at such time shall be more than $692,000,000.

          SECTION 3.  Prepayments; Payments; Taxes.
                      ----------------------------

          3.1  Voluntary Prepayments.  The Borrower shall have the right to
               ---------------------
prepay the Tranche A Loan and the Tranche B Loan, on a pro rata basis, without
                                                       --- ----
premium or penalty, in whole or in part at any time and from time to time on the
following terms and conditions:  the Borrower shall give each Lender prior to
12:00 Noon (New York time) (x) at least one Business Day's prior written notice
(or telephonic notice promptly confirmed in writing) of its intent to prepay a
Base Rate Loan and (y) at least three Business Days' prior written notice (or
telephonic notice promptly confirmed in writing) of its intent to prepay a
Eurodollar Loan, which notice (in each case) shall specify the amount of such
prepayment which shall be in an aggregate principal amount of at least
$10,000,000, and minimum increments of $1,000,000 in excess thereof.

          3.2  Mandatory Repayments.  (a)  The principal amount of each Loan, to
               --------------------
the extent then outstanding, shall be repaid at its maturity (whether by
acceleration or otherwise).

          (b) In addition to any other mandatory repayments pursuant to this
Section 3.2, on each date on or after the Closing Date upon which LLC, NEG, Inc.
or any NEG Subsidiary receives any cash proceeds from any incurrence by LLC,
NEG, Inc. or any NEG Subsidiary of Indebtedness for borrowed money, an amount
equal to 100% of the Net Debt Proceeds of the respective incurrence of
Indebtedness shall be applied on such date in accordance with the requirements
of Section 3.2(h); provided that such Net Debt Proceeds shall not be required to
                   --------
be so applied to the extent such Net Debt Proceeds are (i) retained as cash or
Cash Equivalents by LLC, NEG, Inc. or any NEG Subsidiary or (ii) applied to
repay Indebtedness for borrowed money of NEG, Inc. or any NEG Subsidiary or
(iii) reinvested in the business of NEG, Inc. or any NEG Subsidiary within the
scope of business as described by the Business Plan; provided, further, that if
                                                     --------  -------
a Default or Event of Default shall have occurred and be continuing, such
reinvestment may only be made to the extent specified in Part II of the Business
Plan.

          (c) In addition to any other mandatory repayments pursuant to this
Section 3.2, on each date on or after the Closing Date upon which LLC, NEG, Inc.
or any NEG Subsidiary receives any cash proceeds from any sale or issuance of
its equity (other than cash

                                      -7-
<PAGE>

proceeds received as part of an IPO which shall be applied pursuant to clause
(d) below) an amount equal to 100% of the Net Equity Proceeds of such sale or
issuance of equity, whether common or preferred, shall be applied on such date
in accordance with the requirements of Section 3.2(h); provided that such Net
                                                       --------
Equity Proceeds shall not be required to be so applied to the extent such Net
Equity Proceeds are (i) retained as cash or Cash Equivalents by LLC, NEG, Inc.
or the NEG Subsidiaries or (ii) applied to repay Indebtedness for borrowed money
of NEG, Inc. or any NEG Subsidiary or (iii) reinvested in the business of NEG,
Inc. or any NEG Subsidiary within the scope of business as described by the
Business Plan; provided, further, that if a Default or Event of Default shall
               --------  -------
have occurred and be continuing, such reinvestment may only be made to the
extent specified in Part II of the Business Plan.

          (d) In addition to any other mandatory repayments required pursuant to
this Section 3.2, on the date of an IPO upon which the Borrower, LLC or NEG,
Inc. receives any proceeds from such IPO, (i) so long as no Default or Event of
Default shall have occurred and be continuing (both before and after giving
effect to such IPO), an amount sufficient to reduce the outstanding principal
amount of the Loans to no more than $500,000,000, or (ii) if a Default or an
Event of Default shall have occurred and be continuing (either before or after
giving effect to such IPO), then (A) in the event such Default or Event of
Default may be cured by the payment of money, an aggregate amount sufficient to
cure such Default or Event of Default and to reduce the aggregate outstanding
principal amount of the Loans to no more than $500,000,000, or (B) in the event
such Default or Event of Default is not subject to cure by the payment of money,
an amount equal to the greater of (x) the amount specified in clause (i) above
or (y) 100% of such proceeds, in each case shall be applied on such date in
accordance with the requirements of Section 3.2(h).

          (e) In addition to any other mandatory repayments pursuant to this
Section 3.2, on each date on or after the Closing Date upon which  LLC, NEG,
Inc. or any NEG Subsidiary receives any cash proceeds from any Asset Sale by
LLC, NEG, Inc. or any NEG Subsidiary, an amount equal to 100% of the Net Sale
Proceeds therefrom shall be applied in accordance with the requirements of
Section 3.2(h); provided that such Net Sale Proceeds shall not be required to be
                --------
so applied to the extent such Net Sale Proceeds are (i) retained as cash or Cash
Equivalents by LLC, NEG, Inc. or the NEG Subsidiaries or (ii) applied to repay
Indebtedness for borrowed money of NEG, Inc. or any NEG Subsidiary or (iii)
reinvested in the business of NEG, Inc. or any NEG Subsidiary within the scope
of business as described by the Business Plan; provided, further, that if a
                                               --------  -------
Default or Event of Default shall have occurred and be continuing, such
reinvestment may only be made to the extent specified in Part II of the Business
Plan.

          (f) In addition to any other mandatory repayments pursuant to this
Section 3.2, on each date on or after the Closing Date upon which LLC, NEG, Inc.
or any NEG Subsidiary receives any cash proceeds from any Recovery Event, an
amount equal to 100% of the Net Insurance Proceeds from such Recovery Event
shall be applied in accordance with the requirements of Section 3.2(h); provided
                                                                        --------
that such Net Insurance Proceeds shall not be required to be so applied to the
extent such Net Insurance Proceeds are (i) applied to repay Indebtedness for
borrowed money of NEG, Inc. or any NEG Subsidiary or (ii) reinvested in the
business of NEG, Inc. or any NEG Subsidiary within the scope of business as
described by the Business Plan within eighteen (18) months of the Recovery
Event; provided, further, that if a Default or Event
       --------  -------

                                      -8-
<PAGE>

of Default shall have occurred and be continuing, such reinvestment may only be
made to the extent specified in Part II of the Business Plan.

          (g) In addition to any other mandatory repayments pursuant to this
Section 3.2, on each date on or after the Closing Date upon which the Borrower
receives a distribution, Dividend or payment of any sort from LLC (other than
the proceeds of an IPO which shall be applied pursuant to clause (d) above and
issuance of the note from NEG, Inc. to LLC or the Borrower or from LLC to the
Borrower, solely in connection with the IPO (but not payments thereunder)), an
amount equal to 100% of such proceeds (net of any amount thereof used to
reimburse the Borrower for (i) any expense related to any income or franchise
Taxes of NEG, Inc. or any NEG Subsidiary (computed as if NEG, Inc. and each of
its Subsidiaries filed a consolidated federal income Tax return and state
consolidated or combined income or franchise Tax returns, where applicable,
separate from the Borrower, PG&E Utility and Subsidiaries of PG&E Utility, for
all taxable periods), (ii) any expenses then due and payable under the Expense
Sharing Agreement or (iii) any amount then due and payable under the note from
NEG, Inc. and payable to LLC or the Borrower solely in connection with the IPO)
shall be applied in accordance with the requirements of Section 3.2(h).

          (h) Each amount required to be applied pursuant to this Section 3.2(h)
shall be first paid to the Lenders ratably according to the respective
outstanding principal amounts of Loans held by the Lenders and shall be applied
by each Lender to payment of any amount owing to such Lender under Section 2.8,
then to payment of any interest then due and payable to such Lender, and then to
reduce ratably the remaining principal balance of the Loans of such Lender.

          (i) In addition to any other mandatory repayments pursuant to this
Section 3.2, all the then outstanding Loans shall be repaid in full on the
earlier of (x) the date of a Spin-Off of NEG, Inc. and (y) the Date Certain.

          (j) The application of any proceeds received by LLC to be applied for
mandatory repayment under Sections 3.2(b), (c), (e) and (f) shall be subject to
Compliance by LLC with the requirements for Distribution under Section 13 of the
LLC Agreement.

          (k) Nothing in this Section 3.2 shall limit any other rights or
remedies a Lender may have under Article 8 of this Agreement or under applicable
law in connection with any Event of Default.

          3.3  Method and Place of Payment.  Except as otherwise specifically
               ---------------------------
provided herein, all payments under this Agreement and under any Note shall be
made to the Administrative Agent for the account of the Lenders entitled thereto
not later than 12:00 Noon (New York time) on the date when due and shall be made
in Dollars in immediately available funds at the Payment Office or pursuant to
such other instruction as the Administrative Agent shall designate to the
Borrower in writing.  Except as otherwise provided herein, whenever any payment
to be made hereunder or under any Note shall be stated to be due on a day which
is not a Business Day, the due date thereof shall be extended to the next
succeeding Business Day and, with respect to payments of principal, interest
shall be payable at the applicable rate during such extension.

                                      -9-
<PAGE>

          3.4  Net Payments.  (a)  All payments made by the Borrower to the
               ------------
Administrative Agent or any Lender hereunder and under any Note will be made
without setoff, counterclaim or other defense.  Except as provided in Section
3.4(b), all such payments will be made free and clear of, and without deduction
or withholding for, any present or future taxes, levies, imposts, duties, fees,
assessments or other charges of whatever nature now or hereafter imposed by any
jurisdiction or by any political subdivision or taxing authority thereof or
therein with respect to such payments (but excluding, except as provided in the
second succeeding sentence, any tax imposed on or measured by the net income or
net profits of a Lender pursuant to the laws of the jurisdiction in which it is
doing business, organized or the jurisdiction in which the principal office or
applicable lending office of such Lender is located or any subdivision thereof
or therein) and all interest, penalties or similar liabilities with respect to
such non-excluded taxes, levies, imposts, duties, fees, assessments or other
charges (all such non-excluded taxes, levies, imposts, duties, fees, assessments
or other charges being referred to collectively as "Taxes").  If any Taxes are
                                                    -----
so levied or imposed, the Borrower agrees to pay the full amount of such Taxes,
and such additional amounts as may be necessary so that every payment of all
amounts due under this Agreement or under any Note, after withholding or
deduction for or on account of any Taxes, will not be less than the amount
provided for herein or in such Note.  If any amounts are payable in respect of
Taxes pursuant to the preceding sentence, the Borrower agrees to reimburse each
Lender, upon the written request of such Lender, for taxes imposed on or
measured by the net income or net profits of such Lender pursuant to the laws of
the jurisdiction in which such Lender is doing business, organized or in which
the principal office or applicable lending office of such Lender is located or
under the laws of any political subdivision or taxing authority of any such
jurisdiction in which such Lender is doing business, organized or in which the
principal office or applicable lending office of such Lender is located and for
any withholding of taxes as such Lender shall reasonably determine are payable
by, or withheld from, such Lender, in respect of such amounts so paid to or on
behalf of such Lender pursuant to the preceding sentence and in respect of any
amounts paid to or on behalf of such Lender pursuant to this sentence.  The
Borrower will furnish to such Lender within 45 days after the date the payment
of any Taxes is due pursuant to applicable law certified copies of tax receipts
evidencing such payment by such Borrower.  The Borrower agrees to indemnify and
hold harmless each Lender, and reimburse such Lender upon its written request,
for the amount of any Taxes so levied or imposed and paid by such Lender.

          (b) Any Lender that is not a United States person (as such term is
defined in Section 7701(a)(30) of the Code) for U.S. Federal income tax purposes
agrees to deliver to the Administrative Agent and the Borrower on or prior to
the Closing Date or, in the case of a Lender that is an assignee or transferee
of an interest under this Agreement pursuant to Section 9.11(a) (unless such
Assignee was already a Lender hereunder immediately prior to such assignment in
which case such assignee shall reaffirm its ability to deliver the forms set
forth below in clause (i) or (ii), as applicable), on the date of the assignment
to such Assignee, (i) two accurate and complete original signed copies of
Internal Revenue Service Form W-8ECI or Form W-8BEN (with respect to a complete
exemption under an income tax treaty) (or successor forms) certifying to such
Lender's entitlement as of such date to a complete exemption from United States
withholding tax with respect to payments to be made under this Agreement and
under any Note, or (ii) if any such Lender is not a "bank" within the meaning of
Section 881(c)(3)(A) of the Code and cannot deliver either Internal Revenue
Service Form W-8ECI or

                                      -10-
<PAGE>

Form W-8BEN (with respect to a complete exemption under an income tax treaty)
(or any successor forms) pursuant to clause (i) above, (x) a certificate
substantially in the form of Exhibit C (any such certificate, a "Section
3.4(b)(ii) Certificate") and (y) two accurate and complete original signed
copies of Internal Revenue Service Form W-8BEN (with respect to the portfolio
interest exemption) (or successor form) certifying to such Lender's entitlement
as of such date to a complete exemption from United States withholding tax with
respect to payments of interest to be made under this Agreement and under any
Note. In addition, each such Lender agrees that from time to time after the
Closing Date, when a lapse in time or change in circumstances renders the
previous certification obsolete or inaccurate in any material respect, such
Lender will deliver to the Administrative Agent and the Borrower two new
accurate and complete original signed copies of Internal Revenue Service Form W-
8ECI, Form W-8BEN (with respect to the benefits of any income tax treaty), or
Form W-8BEN (with respect to the portfolio interest exemption) and a Section
3.4(b)(ii) Certificate, as the case may be, and such other forms as may be
required in order to confirm or establish the entitlement of such Lender to a
continued exemption from or reduction in United States withholding tax with
respect to payments under this Agreement and any Note, or such Lender shall
immediately notify the Administrative Agent and the Borrower of its inability to
deliver any such Form or Certificate, in which case such Lender shall not be
required to deliver any such Form or Certificate pursuant to this Section
3.4(b). Notwithstanding anything to the contrary contained in Section 3.4(a) and
the immediately succeeding sentence, (x) the Borrower shall be entitled, to the
extent it is required to do so by law, to deduct or withhold income or similar
taxes imposed by the United States (or any political subdivision or taxing
authority thereof or therein) from interest, fees or other amounts payable
hereunder for the account of any Lender which is not a United States person (as
such term is defined in Section 7701(a)(30) of the Code) for U.S. Federal income
tax purposes to the extent that such Lender has not provided to the
Administrative Agent and the Borrower U.S. Internal Revenue Service Forms that
establish a complete exemption from such deduction or withholding and (y) the
Borrower shall not be obligated pursuant to Section 3.4(a) to gross-up payments
to be made to a Lender in respect of income or similar taxes imposed by the
United States if (I) such Lender has not provided to the Administrative Agent
and the Borrower the Internal Revenue Service Forms required to be provided to
the Administrative Agent and the Borrower pursuant to this Section 3.4(b) or
(II) in the case of a payment, other than interest, to a Lender described in
clause (ii) above, to the extent that such Forms do not establish a complete
exemption from withholding of such taxes. Notwithstanding anything to the
contrary contained in the preceding sentence or elsewhere in this Section 3.4,
the Borrower agrees to pay any additional amounts and to indemnify each Lender
in the manner set forth in Section 3.4(a) (without regard to the identity of the
jurisdiction requiring the deduction or withholding) in respect of any amounts
deducted or withheld by it as described in the immediately preceding sentence as
a result of any changes that are effective after the Closing Date in any
applicable law, treaty, governmental rule, regulation, guideline or order, or in
the interpretation thereof, relating to the deducting or withholding of such
Taxes. The sole consequence of any Lender failing to comply with the requirement
to deliver the Internal Revenue Service Forms or the Section 3.4(b)(ii)
Certificate shall be that the Borrower shall not be obligated pursuant to
Section 3.4(a) to gross-up payments to be made to such Lender in respect of any
resulting U.S. income or similar taxes.

                                      -11-
<PAGE>

          (c) Any Lender that is (i) an Assignee pursuant to Section 9.11(a) and
(ii) not a United States person (as such term is defined in Section 7701(a)(30)
of the Code) for U.S. Federal income tax purposes will certify to the Borrower
on or prior to the date of the assignment to such Lender that payments to such
Lender hereunder and under any Note are, as of the date of such assignment, not
subject to any withholding tax imposed by any taxing jurisdiction located
outside of the United States.

          (d) Each Lender, at the sole cost and expense of the Borrower
(including, but not limited to, the Lender's internal costs for use of its
personnel and resources), will use its reasonable efforts to minimize taxes
indemnifiable by the Borrower under this Section 3.4, including by complying
with reasonable requests by the Borrower to do or to refrain from doing any act
(including the execution of any certificates or similar documents required to
establish an exemption or relief from any tax), if such efforts or any such
compliance is, in the good faith discretion of such Lender, of a purely
ministerial nature and has no adverse impact on such Lender or any Affiliate or
on the business or operations of the foregoing (unless such adverse impact is
one of a nature and quality such that it is subject to indemnification and the
Borrower has indemnified such Lender against such adverse impact in a manner
satisfactory to such Lender determined in its sole discretion).  The Borrower
shall indemnify such Lender for any taxes that may be imposed on it as a
consequence of such compliance.  No Lender shall be required to disclose any tax
return or filing or any related information it deems confidential and all
positions taken by each Lender in any tax return, filing or proceeding shall be
within the sole control of such Lender.

          3.5  Allocation.  The parties agree that the Notes issued by the
               ----------
Borrower under this Agreement and the Options issued by LLC under the Option
Agreement, will for federal tax purposes, be treated as an "investment unit" as
such term is defined under Section 1273(c)(2) of the Code and the parties agree
that the consideration paid by each Lender for its Note and Option shall be
allocated as set forth on Schedule 3.5.

          3.6  Fee.  The Borrower shall pay to (a) the Tranche A Lender the
               ---
Commitment Fee payable to it pursuant to the terms of the Fee Letter and (b) the
Tranche B Lender the Commitment Fee payable to it pursuant to the Lehman Fee
Letter.

          3.7  Application of Payments; Sharing.
               --------------------------------

          (a) Subject to the provisions of this Section 3.7, the Administrative
Agent agrees that promptly after its receipt of each payment from or on behalf
of the Borrower in respect of any Obligations of the Borrower hereunder, it
shall promptly distribute such payment to the Lenders pro rata based upon their
                                                      --- ----
respective shares, if any, of the Obligations with respect to which such payment
was received.

          (b) Each of the Lenders agrees that, if it should receive any amount
hereunder (whether by voluntary payment, by realization upon security, by the
exercise of the right of setoff or banker's lien, by counterclaim or cross
action, by the enforcement of any right under the Financing Documents, or
otherwise), which, in any such case, is in excess of its ratable share of
payments on account of the Obligations obtained by all Lenders, then such Lender
receiving such excess payment shall purchase for cash without recourse or
warranty from the other Lenders an

                                      -12-
<PAGE>

interest in the Obligations of the Borrower to such Lenders in such amount as
shall result in a proportional participation by all the Lenders in such amount;
provided, however, that if all or any portion of such excess amount is
--------  -------
thereafter recovered from such Lender, such purchase shall be rescinded and the
purchase price restored to the extent of such recovery, but without interest.

          SECTION 4.  CONDITIONS PRECEDENT.
                      --------------------

          4.1  Conditions to Closing.  The obligation of any Lender to make its
               ---------------------
Loan shall be subject to the conditions precedent that such Lender shall have
received, or shall have waived receipt of, the following, each of which shall be
in form and substance satisfactory to such Lender, and that the other conditions
set forth below shall have been satisfied or waived by such Lender:

          (a) Financing Documents.  Each of the Financing Documents (including
              -------------------
the LLC Pledge Agreement, the Stock Pledge Agreement and the Option Agreement)
shall have been duly authorized, executed and delivered by each party thereto.
Such Lender shall have received an original of each Financing Document executed
by all parties thereto.

          (b) Notes.  The Borrower shall have duly authorized, executed and
              -----
delivered a Note for the account of such Lender.  Each Note shall be
appropriately completed with the name of the payee, the maximum principal amount
thereof and the date of issuance (which shall be the Closing Date) inserted
therein.

          (c) Charter Documents.  Such Lender shall have received the following
              -----------------
documents, each certified as indicated below:

          (i) a copy of the Charter Documents of the Borrower, LLC, NEG, Inc.,
     the Significant Subsidiaries and the Specified Subsidiaries, as in effect
     on the Closing Date, certified by the Secretary of State of the State of
     such Person's organization, as applicable, and a certificate, where
     available, as to the good standing of and payment of franchise taxes by the
     Borrower, LLC, NEG, Inc., the Significant Subsidiaries and the Specified
     Subsidiaries from the Secretary of State of the State of such Person's
     organization, dated as of a date no earlier than 5 days prior to the
     Closing Date;

          (ii) a certificate of an Authorized Officer of each of the Borrower,
     LLC and NEG, Inc., dated the Closing Date, certifying (A) that attached
     thereto is a true and complete copy of the Charter Documents of such
     Person, as in effect at all times from the date on which the resolutions
     referred to in clause (B) below were adopted to and including the date of
     such certificate, (B) that attached thereto is a true and complete copy of
     resolutions duly adopted by the board of directors (or other equivalent
     body) or evidence of all corporate, partnership or limited liability
     company action, as the case may be, of such Person, authorizing the
     execution, delivery and performance of the Financing Documents to which
     such Person is or is intended to be a party, and that such resolutions have
     not been modified, rescinded or amended and are in full force and effect,
     and (C) as to the name, incumbency and specimen signature of each officer
     of such Person executing the Financing Documents to which such Person is
     intended to be a party and each other document to be delivered by such
     Person from time to time in connection therewith; and

                                      -13-
<PAGE>

          (iii)  a certificate of another Authorized Officer of each of the
     Borrower, LLC and NEG, Inc., as to the name, incumbency and specimen
     signature of the Authorized Officer of such Person that signed the
     certificate referred to in clause (ii) above.

          (d) Filings, Registrations, Recordings; Other Perfection Actions.  (i)
              ------------------------------------------------------------
On or prior to the Closing Date, such Lender shall have received certified
copies of Requests for Information or Copies (Form UCC-11), or equivalent
reports, each of a recent date listing all effective financing statements that
name the Borrower, LLC or NEG, Inc., as debtor, together with copies of such
financing statements.

          (ii) Any document required to be filed, registered, notarized or
recorded in order to create and perfect the security interest of the Collateral
Agent under the Security Documents as a first priority Lien shall have been
properly filed, registered, notarized or recorded in each office in each
jurisdiction in which such filings, registrations, notarizations and
recordations are required, and any other action required in the judgment of any
Lender to perfect such security interest as such first priority Lien shall have
been effected, and such Lender shall have received acknowledgment copies or
other evidence satisfactory to it that all necessary filing, notarization,
recording and other fees and all taxes and expenses related to such filings,
notarizations, registrations and recordings have been paid in full.

          (iii)  The Collateral Agent shall have received the stock certificates
representing 100% of the capital stock of NEG, Inc., together with related
appropriate stock powers, duly executed in blank.

          (iv) The Collateral Agent shall have received the certificates
representing 100% of the Pledged Interest of the Borrower being pledged pursuant
to the LLC Pledge Agreement, together with related powers, duly executed in
blank.

          (e) Borrower's Certificate.  Such Lender shall have received an
              ----------------------
original counterpart of a certificate of an Authorized Officer of the Borrower,
dated the Closing Date, to the effect that:  (i) the representations and
warranties of the Borrower contained in Section 5 hereof and the representations
and warranties of the Borrower contained in each of the other Financing
Documents to which the Borrower is a party are true and correct in all material
respects (or in the event any such representation or warranty shall be qualified
by a "Material Adverse Effect" or a materiality threshold, in all respects) on
and as of the Closing Date (or, if stated to have been made solely as of an
earlier date, were true and correct as of such earlier date), (ii) all covenants
required to be performed by the Borrower contained in any Financing Document to
which it is a party prior to the Closing Date have been performed in all
material respects, (iii) all Financing Documents are in full force and effect
under the terms and conditions set forth in such Financing Documents, and (iv)
no Default or Event of Default has occurred and is continuing.

          (f) Other Officer Certificates.  (i)  Such Lender shall have received
              --------------------------
a certificate signed by an Authorized Officer of LLC, dated the Closing Date, to
the effect that (i) the representations and warranties of LLC set forth in each
of the Financing Documents to which it is a party are true and correct in all
material respects (or in the event any such representation or warranty shall be
qualified by a "Material Adverse Effect" or a materiality threshold, in all
respects)

                                      -14-
<PAGE>

on and as of such date as if made on and as of the Closing Date (or, if stated
to have been made solely as of an earlier date, were true and correct as of such
earlier date) and (ii) all covenants required to be performed by LLC contained
in any Financing Document to which it is a party prior to the Closing Date have
been performed in all material respects.

          (ii) Such Lender shall have received a certificate signed by an
Authorized Officer of NEG, Inc., dated the Closing Date, to the effect that (i)
the representations and warranties of NEG, Inc. set forth in each of the
Financing Documents to which it is a party are true and correct in all material
respects (or in the event any such representation or warranty shall be qualified
by a "Material Adverse Effect" or a materiality threshold, in all respects) on
and as of such date as if made on and as of such date (or, if stated to have
been made solely as of an earlier date, were true and correct as of such earlier
date) and on and as of the Closing Date, and (ii) all covenants required to be
performed by NEG, Inc. contained in any Financing Document to which it is a
party prior to the Closing Date have been performed in all material respects.

          (g) Financial Information, etc.  (i)  Such Lender shall have received
              --------------------------
copies of the most recent audited and unaudited (x) consolidated financial
statements from each of the Borrower and NEG, Inc. and (y) financial statements
or information from each of the FI Subsidiaries, in each case, in form and
substance satisfactory to such Lender together with a certificate from the Chief
Financial Officer or other Authorized Officer of such Person, dated the Closing
Date, to the effect that, to the best of such officer's knowledge, (A) such
financial statements or information are true, complete and correct in all
material respects and (B) there has been no material adverse change in the
condition (financial or otherwise), results of operations, business, Properties,
liabilities, management or prospects of such Person since the date of the most
recent financial statements or information of such Person; provided that for
                                                           --------
purposes of this clause (g), defaults or events of default in respect of the
Indebtedness of the Borrower which is to be Refinanced by the proceeds of the
Loan or other defaults or events of default with respect to the Borrower which
are described in the SEC Filings by the Borrower since December 31, 2000 but
prior to the Closing Date, and any Utility Event shall not be deemed a Material
Adverse Change to such Person.

          (ii) Such Lender shall have received such other financial, business
and other information regarding any other Subsidiary of the Borrower as such
Lender shall have reasonably requested.

          (h) Process Agent.  Such Lender shall have received a copy of a letter
              -------------
from CT Corporation System accepting its appointment as process agent in New
York for the Borrower, LLC and NEG, Inc., in substantially the form of Exhibit D
hereto.

          (i) Legal Opinions.  Such Lender shall have received original
              --------------
counterparts of the legal opinions of counsel to the Borrower, LLC and NEG,
Inc., which legal opinions shall be dated the Closing Date, addressed to such
Lender, and in form, scope and substance satisfactory to such Lender.

          (j) Due Diligence.  Such Lender shall have (i) completed its due
              -------------
diligence investigation of the organization and capital structure of the
Borrower and its Subsidiaries and all

                                      -15-
<PAGE>

documents and instruments relating thereto, and other matters related to or in
connection with the transactions contemplated hereby, in scope, and with
results, satisfactory to such Lender in all respects, and (ii) been given such
access to the management, records, books of account, contracts, concessions, and
other documents relating to the business, regulatory framework and Property of
the Borrower and its Subsidiaries as such Lender shall have reasonably
requested.

          (k) Material Adverse Change.  Since December 31, 2000, and except as
              -----------------------
disclosed in the SEC Filings by the Borrower since December 31, 2000 but prior
to the Closing Date, there shall not have occurred and be continuing any
Material Adverse Change of the Borrower or of LLC, NEG, Inc. and the Significant
Subsidiaries, taken as a whole; provided that for purposes of this clause (k),
                                --------
defaults or events of default in respect of the Indebtedness of the Borrower
which is to be Refinanced by the proceeds of the Loan and a Utility Event shall
not be deemed a Material Adverse Change to the Borrower.

          (l) Fees; Interest; Expenses.  Such Lender shall have received the
              ------------------------
Commitment Fee pursuant to the Fee Letter or the Lehman Fee Letter, as the case
may be, and all other fees, costs and charges due and owing under the Financing
Documents on or prior to the Closing Date and shall have received its pro rata
                                                                      --- ----
share of the Interest Prepaid Amount required to be paid pursuant to Section
2.5. The Collateral Agent shall have received the CA Fee for payment of its
services as Collateral Agent under the Financing Documents. Such Lender shall
have received payment of all out-of-pocket expenses payable by the Borrower to
such Lender pursuant to Section 9.1 (including reasonable fees and expenses and
disbursements of legal counsel).

          (m) Notice of Borrowing.  Such Lender shall have received a Notice of
              -------------------
Borrowing pursuant to and in compliance with Section 2.

          (n) Governmental Approvals, etc.  (i) All Governmental Approvals and
              ----------------------------
consents or approvals from any third party which under applicable Law or any
agreement, contract or document are required to be obtained by the Borrower or
its Subsidiaries with respect to the transactions contemplated by the Financing
Documents prior to the Closing Date shall have been duly obtained and shall be
final, non-appealable and in full force and effect; (ii) there shall have been
no change in any applicable Law, and no issuance of any order, writ, injunction
or decree of any Governmental Authority or arbitral tribunal, which, in either
such case, could reasonably be expected to have a Material Adverse Effect; and
(iii) there shall have been no proposed change in or modification of any
applicable Law which could reasonably be expected to be enacted and which if
enacted could reasonably be expected to have a Material Adverse Effect.

          (o) Material Adverse Effect.  There shall exist no circumstance, event
              -----------------------
or condition which has had or could reasonably be expected to have a Material
Adverse Effect.

          (p) Litigation.  No legal or arbitral proceedings or investigations,
              ----------
or any proceedings by or before any Governmental Authority or any Person, shall
be pending or threatened against the transactions contemplated by the Financing
Documents or any document executed in connection therewith which, if adversely
determined, could reasonably be expected to have a Material Adverse Effect, and
no other legal or arbitral proceedings or investigations, or any pro

                                      -16-
<PAGE>

ceedings by or before any Governmental Authority or any Person, shall be pending
in respect of the Borrower, LLC, NEG, Inc. or the Significant Subsidiaries
which, if adversely determined, could reasonably be expected to result in a
Material Adverse Change to the Borrower, or a Material Adverse Change to LLC,
NEG, Inc. and the Significant Subsidiaries, taken as a whole.

          (q) Solvency Certificate.  On or before the Closing Date, the Borrower
              --------------------
shall cause to be delivered to such Lender a solvency certificate from the Chief
Financial Officer of the Borrower in form, scope and substance satisfactory to
such Lender, dated the Closing Date, setting forth the conclusion that, after
giving effect to the transaction contemplated by the Financing Documents and the
incurrence of all the financings contemplated herein, the Borrower (on a stand-
alone basis), the Borrower and its Subsidiaries (on a consolidated basis) and
LLC (on a stand-alone basis), in each case, are not insolvent and will not be
rendered insolvent by the indebtedness incurred in connection therewith, and
will not be left with unreasonably small capital with which to engage in its or
their businesses and will not have incurred debts beyond its or their ability to
pay debts as they mature and become due.

          (r) No Breach.  Immediately prior to and after giving effect to the
              ---------
transactions contemplated by the Financing Documents, except as disclosed in
Part E of the Disclosure Letter, there shall exist no default or event of
default under any material agreement or contract to which the Borrower, LLC,
NEG, Inc. or any Significant Subsidiary is a party which would result in a
Material Adverse Change to the Borrower, or a Material Adverse Change to LLC,
NEG, Inc. and the Significant Subsidiaries, taken as a whole.

          (s) Refinancing; Existing Indebtedness.  (i)  On the Closing Date (but
              ----------------------------------
concurrently with the consummation of the transactions contemplated by the
Financing Documents), all Indebtedness to be Refinanced shall have been repaid
in full in the manner set forth in Part C of the Disclosure Letter by the
Borrower by applying  thereto the proceeds of the Loans, and all commitments in
respect thereof shall have been terminated and all Liens and guaranties in
connection therewith shall have been terminated (and all appropriate releases,
termination statements or other instruments of assignment with respect thereto
shall have been obtained) to the reasonable satisfaction of such Lender.
Without limiting the foregoing, there shall have been delivered to such Lender
(x) proper termination statements (Form UCC-3 or the appropriate equivalent) for
filing under the UCC of each jurisdiction where a financing statement (Form UCC-
1 or the appropriate equivalent) was filed with respect to the Borrower or any
of its Subsidiaries in connection with the security interest created with
respect to the Indebtedness to be Refinanced and the documentation related
thereto and (y) terminations of all mortgages, leasehold mortgages and deeds of
trust created with respect to property of the Borrower or any of its
Subsidiaries, in each case, to secure the obligations under the Indebtedness to
be Refinanced, all of which shall be in form and substance satisfactory to such
Lender.

          (ii) On the Closing Date and after giving effect to the transactions
contemplated by the Financing Documents, the Borrower and LLC shall have no
Indebtedness or preferred stock outstanding other than the Loan and certain
other indebtedness existing on the Closing Date acceptable to such Lender as
listed on Part B of the Disclosure Letter.  On and as of the Closing Date, all
of the existing Indebtedness under the Existing Indebtedness Agreements shall
remain outstanding after giving effect to the transactions contemplated hereby
without any

                                      -17-
<PAGE>

default or event of default existing thereunder or arising as a result of the
transaction contemplated hereby (except to the extent amended or waived by the
parties thereto on terms and conditions reasonably satisfactory to such Lender).

          (iii)  On the Closing Date, such Lender shall have received evidence
in form and substance reasonably satisfactory to such Lender that the matters
set forth in this Section 4.1(s) have been satisfied.

          (t)  [OMITTED].
                -------

          (u) Finality of FERC Orders.  FERC shall have (i) issued final binding
              -----------------------
orders not subject to rehearing in Docket Nos. EC01-49-000 and EC01-41-000, and
(ii) denied all motions to intervene, requests for rehearing, requests to vacate
or any other relief requested in pleadings other than those by LLC or any member
of NEG Group which were filed subsequent to the FERC orders in Docket Nos. EC01-
49-000 and EC01-41-000.

          (v) Letter.  Such Lender shall have received a copy of letters
              ------
addressed to the Borrower from third parties, confirming the amount and type of
Indebtedness of the Borrower with respect to items B and C of Part A(IV) of the
Disclosure Letter to be Refinanced hereunder.

          (w) Business Plan.  Such Lender shall have received a true and
              -------------
complete copy of the Business Plan, certified by an Authorized Officer of each
of the Borrower, LLC and NEG, Inc.

          (x) Disclosure Letter.  Such Lender shall have received the Disclosure
              -----------------
Letter.

          (y) Proceedings.  All corporate and other proceedings, and all Charter
              -----------
Documents, other documents, instruments and other legal matters in connection
with the transactions contemplated hereby and the other Financing Documents
shall be satisfactory in form and substance to such Lender and such Lender shall
have received such other documents, certificates and instruments relating to the
Financing Documents or the transactions contemplated thereby as it shall have
reasonably requested, in each case, in form and substance satisfactory to it.

          SECTION 5.  REPRESENTATIONS, WARRANTIES AND AGREEMENTS.
                      ------------------------------------------

          In order to induce the Administrative Agent and each Lender to enter
into this Agreement, and to induce each Lender to make its Loan, the Borrower
makes the following representations, warranties and agreements as of the date
hereof, all of which shall survive the execution and delivery of this Agreement
and the Notes and the making and continuance of the Loans:

          5.1  Standing.  (a)  Each of the Borrower, LLC, NEG, Inc. and each
               --------
Significant Subsidiary (collectively, the "Covered Parties") is a corporation,
limited partnership or limited liability company duly formed, validly existing
and in good standing under the laws of its jurisdiction of organization and has
the requisite power and authority to own, lease and operate its Properties and
to carry on its business as now being conducted.

                                      -18-
<PAGE>

          (b) Each Covered Party is duly qualified or licensed to do business as
a foreign entity and is in good standing in each jurisdiction in which the use
and ownership of its Property or the conduct of its business requires such
license or qualification, except where the failure to be so qualified or
licensed would not have a Material Adverse Effect.

          5.2  Requisite Authority; Etc.  Each Covered Party has all requisite
               -------------------------
power and authority to enter into the Financing Documents to which it is a
party.  All necessary action on the part of each Covered Party has been taken to
authorize the execution and delivery of the Financing Documents to which it is a
party, the performance of its obligations under such Financing Documents and the
consummation of the transactions contemplated hereby and thereby.  Each of the
Financing Documents has been duly and validly executed and delivered by each
Covered Party that is a party thereto, and constitutes valid and binding
agreements of each such Covered Party, enforceable in accordance with their
respective terms, except as the enforceability thereof may be limited by
bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and
similar laws of general application relating to or affecting creditors' rights
generally and to general principles of equity (regardless of whether such
enforceability is considered in an proceeding in equity or at law).

          5.3  No Conflict.  Neither the execution and delivery of the Financing
               -----------
Documents nor the consummation of the transactions contemplated by such
Financing Documents nor compliance by any Covered Party with any of the
provisions of such Financing Documents to which it is a party will (i) violate
or conflict with any provision of the charter, certificate of formation, by-laws
or limited liability company agreement or other governing documents of such
Covered Party, or any Law, judgment, order, writ, decree or injunction
applicable to such Covered Party, or (ii) except as set forth in Part F of the
Disclosure Letter, violate, or conflict with, or result in a breach of any
provision of, or constitute a default (or any event which, with or without due
notice or lapse of time, or both, would constitute a default) under, or result
in the termination of, accelerate the performance required by, or, except for
the Liens created by the Financing Documents, result in the creation of any Lien
upon any of the Properties or assets of such Covered Party, under any contract,
note, bond, mortgage, indenture, deed of trust, license, lease, agreement,
permit or other instrument or obligation of which such Covered Party is a party
or by which it or any of its assets are bound.

          5.4  Consents.  (a)  No permit, application, notice, transfer,
               --------
consent, approval, order, qualification, waiver from or authorization of, or
declaration, filing or registration with, any Governmental Authority or any
third party is currently required to be made or obtained by any Covered Party or
any of its Subsidiaries in connection with (i) the execution, delivery and
performance of the Financing Documents or the consummation of the transactions
contemplated by such Financing Documents, (ii) the grant by the Borrower or LLC,
or the perfection and maintenance, of the Liens contemplated by the Financing
Documents (including the first priority nature thereof) or (iii) the exercise by
any party to the Financing Documents of any of its rights under any such
Financing Document or any remedies pursuant to the Financing Documents, other
than with respect to the exercise by any Holder of its right to convert the
Option to Option Shares under the Option Agreement which may require filing
under the HSR Act or with FERC or the exercise of the foreclosure rights with
respect to the stock of NEG, Inc. or the LLC Interests which may require filing
with FERC and certain state regulatory agencies.

                                      -19-
<PAGE>

          (b) No right of first refusal, preemptive right, right of first offer
or other similar rights to acquire (each a "Preferential Right") are required to
                                            ------------------
be complied with by any Covered Party or any of its Subsidiaries in connection
with the execution, delivery or performance of the Financing Documents or the
consummation of the transactions contemplated by the Financing Documents.

          5.5  Compliance with Law.  Each of the Borrower and each member of the
               -------------------
NEG Group and each Scheduled Project has been and on the Closing Date is in
compliance in all material respects with all Laws, Governmental Approvals,
orders, writs, injunctions or decrees or its Charter Documents applicable to or
otherwise concerning such Person and such Scheduled Project.

          5.6  Litigation Claims.  Except as set forth on Schedule 5.6, there
               -----------------
are no legal or arbitral proceedings or investigations, or any proceedings by or
before any Governmental Authority or any Person, pending or threatened against
the transactions contemplated by the Financing Documents or any document
executed in connection therewith which could reasonably be expected to have a
Material Adverse Effect, and there are no other legal or arbitral proceedings or
investigations, or any proceedings by or before any Governmental Authority or
any Person pending against the Borrower, LLC, NEG, Inc. or the Significant
Subsidiaries which could reasonably be expected to result in a Material Adverse
Change to the Borrower, or a Material Adverse Change to LLC, NEG, Inc. and the
Significant Subsidiaries, taken as a whole.

          5.7  Contracts and Commitments.  (a)  Schedule 5.7 reflects a complete
               -------------------------
and accurate list of all material contracts, agreements or letters of intent or
written understandings (including all amendments and supplements thereto)
entered into by any Covered Party (collectively, the "Covered Contracts") (it
being understood that any contract, agreement or letter of intent or written
understanding (i) entered in the ordinary course of business of the Covered
Parties, or (ii) with respect to Indebtedness of any such Covered Party that is
non-recourse to such Covered Party, or (iii) requiring aggregate payments of
less than $10,000,000 or (iv) with a fixed term of less than three hundred and
sixty-four (364) days shall not be deemed to be a "material" contract, agreement
or letter of intent or written understanding).

          (b) Except as otherwise set forth on Part E of the Disclosure Letter,
(i) each of the Covered Contracts is a valid and binding obligation of the
Covered Party which is a party thereto and enforceable by the Covered Parties
(as applicable) in accordance with its terms, except as enforcement may be
limited by bankruptcy, insolvency, reorganization or similar laws or equitable
principles relating to creditors' rights generally; (ii) none of the Covered
Parties party to any Covered Contract is in default or alleged to be in default
under any Covered Contract, and no other asserted or, to the best knowledge of
the Borrower, LLC and NEG, Inc., unasserted claim or dispute under any Covered
Contract exists; and (iv) to the best knowledge of the Borrower, there exists no
event, condition or occurrence that, after notice or lapse of time, or both,
would constitute such a default, claim or dispute by the Covered Parties or, to
the best knowledge of the Borrower, any other party to any such Covered
Contract.

                                      -20-
<PAGE>

          5.8  Liens.  Except as set forth on Schedule 5.8, none of the
               -----
Properties of the Borrower, LLC or NEG, Inc. are subject to any Lien, other than
the Liens created by this Agreement and the Security Documents.

          5.9  Insurance.  All insurance policies and fidelity bonds relating to
               ---------
the Covered Parties and their Properties, including summary descriptions and the
termination dates thereof, in force as of the date of this Agreement are set
forth on Schedule 5.9.  The insurance coverage provided by such policies will
not terminate or lapse as a result of the transactions contemplated by this
Agreement or the other Financing Documents.  Except as set forth on Schedule
5.9, all such insurance policies and fidelity bonds are in the name of the
Borrower, LLC, NEG, Inc. or a NEG Subsidiary (as indicated on Schedule 5.9).
None of the Covered Parties or, to the best knowledge of the Borrower, any other
party to any such policy or bond is in breach, violation or default (including
with respect to the payment of premiums or the giving of notices), and, to the
best knowledge of the Borrower, no event has occurred that, with notice or the
lapse of time or both, could constitute such a breach, violation or default by
the Covered Parties or any other party, or permit termination, modification or
acceleration, under such policy or bond, except where any such breach,
violation, default, termination, modification or acceleration could not
reasonably be expected to have a Material Adverse Effect.

          5.10  Capitalization and Ownership.  (a)  As of the Closing Date, the
                ----------------------------
Borrower and Energy NEG Corp. are the sole members of LLC, with the Borrower
owning all of the Class A membership interests of the LLC, which entitle the
Borrower to 100% of the economic interest in LLC, and Energy NEG Corp. owning
all of the Class B membership interests of LLC, which entitle Energy NEG Corp.
to vote solely on certain bankruptcy matters of LLC as provided for in the LLC
Agreement.  The Borrower is (and at all times prior to the Closing Date from and
after January 12, 2001, was) the owner of 100% of the Class A membership
interests in LLC and is (and at all times prior to the Closing Date from and
after January 12, 2001, was) the indirect owner (through the Limited Liability
Company Interests) of 100% of NEG, Inc. and the NEG Subsidiaries.

          (b) LLC is (and at all times prior to the Closing Date from and after
January 12, 2001,was) the sole direct owner of all of the outstanding Capital
Stock of NEG, Inc., free and clear of all Liens and adverse claims, other than
the Liens in favor of the Collateral Agent created by the Security Documents.

          (c) NEG, Inc. is (and at all times prior to the Closing Date from and
after January 1, 1999, was) the ultimate sole parent other than companies owning
NEG, Inc. directly or indirectly, of all Significant Subsidiaries and other NEG
Subsidiaries.

          (d)  (i)  All of the Limited Liability Company Interests have been
duly authorized and, at the Closing Date, are and will be validly issued, free
and clear of all Liens and adverse claims, other than the Liens in favor of the
Collateral Agent created by the Security Documents.

          (ii) All shares of the Capital Stock of NEG, Inc. have been duly
authorized and, at the Closing Date, are and will be validly issued and fully
paid and nonassessable and are

                                      -21-
<PAGE>

owned by LLC, free and clear of all Liens and adverse claims, other than the
Liens in favor of the Collateral Agent created by the Security Documents.

          (e) Except as set forth in Schedule 5.10(e), no Person other than a
member of the NEG Group owns (i) any outstanding option, warrant, purchase
right, subscription right, conversion right, exchange right or other contract,
commitment, arrangement or understanding relating to the issuance by or purchase
from the Borrower of its LLC Interests, LLC, NEG, Inc. or any Significant
Subsidiary of its Equity Interests (as defined below), or (ii) any outstanding
stock appreciation, phantom stock, profit participation or similar rights with
respect to LLC, NEG, Inc. or any Significant Subsidiary, and there are no voting
trusts, proxies or other agreements or understandings with respect to the voting
of LLC Interests or Equity Interests to which the Borrower, LLC, NEG, Inc. or
any Significant Subsidiary is party.

          (f) Schedule 5.10(f) sets forth for each of the Borrower, LLC, NEG,
Inc. and the NEG Subsidiaries a complete and accurate listing of (i) its name
and jurisdiction of organization, (ii) its form of organization and (iii) the
percentage (and, where applicable, the amount) of capital stock, partnership
interests (general and limited), membership interests or other equity interests
("Equity Interests") held directly or indirectly by the Borrower.

          5.11  Financial Statements; Absence of Certain Changes. (a) Prior to
                ------------------------------------------------
the execution of this Agreement, the Borrower has delivered to the
Administrative Agent and each Lender the following financial statements, each of
which has been certified by the Chief Financial Officer of the relevant Person
specified below:

          (i) (x) the audited consolidated financial statements of the Borrower
     as at December 31, 1999, and (y) the unaudited consolidated financial
     statements of the Borrower as at June 30, 2000 and September 30, 2000, and
     the unaudited consolidating balance sheet and income statement of the
     Borrower as at November 30, 2000, which statement has been prepared on a
     management basis and does not include accompanying notes;

          (ii) (x) the audited financial statements of each of the FI
     Subsidiaries as at December 31, 1999, and (y) the unaudited financial
     statements of each of the FI Subsidiaries as at June 30, 2000 and September
     30, 2000, and the unaudited draft financial statements of each such FI
     Subsidiary as at December 31, 2000;

          (iii)  the unaudited consolidated balance sheet and income statements
     of NEG, Inc. as at December 31, 1999 and the estimated unaudited financial
     statements of NEG, Inc. as at December 31, 2000.

Any audited financial statements (the "Audited Financial Statements") described
in this Section 5.11(a) (complete with any appropriate footnote disclosures)
present fairly the financial position of the relevant Person as at December 31,
1999, and were prepared in accordance with GAAP, consistently applied.  Any
unaudited financial statements (the "Unaudited Financial Statements") described
in this Section 5.11(a) present fairly the financial position of the relevant
Person as at

                                      -22-
<PAGE>

such dates. Such Audited Financial Statements and Unaudited Financial Statements
have been prepared from the books of account and financial records of the
relevant Person.

     (b)  Since December 31, 2000 and except as disclosed in the SEC Filings by
the Borrower since December 31, 2000 but prior to the Closing Date, the Borrower
and all members of the NEG Group have conducted their business only in the
ordinary course of business, and there has not been (i) any event or development
that could, individually or in the aggregate, reasonably be expected to have a
Material Adverse Effect or (ii) any damage, destruction or loss, whether or not
covered by insurance, that could, individually or in the aggregate, reasonably
be expected to have a Material Adverse Effect. Except as set forth in the
Audited Financial Statements or otherwise disclosed in writing to each Lender in
the Disclosure Letter or incurred in the ordinary course of business, none of
the Covered Parties or any other NEG Subsidiary has any outstanding claims,
liabilities or indebtedness, contingent or otherwise.

     5.12 Taxes. (a) Each of the Covered Parties and its Subsidiaries has filed
          -----
or caused to be filed with the appropriate taxing authorities all material
federal, state and local tax returns ("Returns") which are required to be filed
by or with respect to each such Covered Party, its Subsidiaries, or any assets
thereof. The Returns accurately reflect (or will accurately reflect) all
liabilities for Taxes of each such Covered Party or Subsidiary for the periods
covered thereby in all material respects. All material Taxes due by or with
respect to each such Covered Party or Subsidiary, or any assets thereof, whether
or not shown on any Return, have been or will be timely paid in full on or prior
to the Closing Date or accrued and provided for on the books and records of each
such Person, as applicable, in accordance with GAAP. There is no dispute or
claim concerning any liability for Taxes of each of the Covered Parties, its
Subsidiaries, or any assets thereof that has been claimed or raised by any
Governmental Authority, except for disputes or claims for Taxes that have been
provided for on the books and records of each such Person, as applicable, in
accordance with GAAP. No Return of any of the Covered Parties, their
Subsidiaries, or the affiliated group of the Borrower is currently, or has been,
the subject of an audit by any taxing authority and no notice of such an audit
has been received, except for audits with respect to Taxes that have been
provided for on the books and records of each such Covered Party and its
Subsidiaries, as applicable, in accordance with GAAP. None of the Covered
Parties or any of their Subsidiaries have waived any statute of limitations in
respect of Taxes or agreed to any extension of time with respect to a Tax
assessment or deficiency, except with respect to Taxes that have been provided
for on the books and records of each such Covered Party and its Subsidiaries, as
applicable, in accordance with GAAP.

     (b)  All material Taxes which a Covered Party or any of its Subsidiaries is
(or was) required by Law to withhold or collect with respect to any payments
made in connection with its Property have been duly withheld or collected, and
have been timely paid over to the appropriate authorities to the extent due and
payable.

     5.13 Disclosure. All documents, reports or other written information
          ----------
pertaining to the Covered Parties or its Affiliates that have been furnished to
the Lenders by or on behalf of the Covered Parties, taken as a whole, are true
and correct in all material respects and do not contain any untrue statement of
a material fact or omit to state any material fact necessary to make the
statements contained therein not misleading. There is no fact, event or
circumstance

                                      -23-
<PAGE>

that has not been disclosed to the Lenders in writing, the existence of which
could reasonably be expected to have a Material Adverse Effect or a Material
Adverse Change of NEG, Inc. and the NEG Subsidiaries, taken as a whole.

     5.14 Environmental Matters. Except as set forth in Schedule 5.14, (a) each
          ---------------------
of the Borrower and the members of the NEG Group is in compliance in all
material respects with all applicable Environmental Laws, (b) there is no
Environmental Claim outstanding or pending against the Borrower or any member of
the NEG Group or, to the best knowledge of the Borrower, threatened against the
Borrower or any member of the NEG Group, which, individually or in the
aggregate, could reasonably be expected to have a Material Adverse Effect or to
result in a Material Adverse Change to NEG, Inc. and the NEG Subsidiaries, taken
as a whole, and (c) to the best knowledge of the Borrower, LLC and NEG, Inc.,
none of the Covered Parties or other NEG Subsidiary has made any past or present
releases, emissions, discharges or disposals of any Hazardous Material in
violation of any Environmental Laws or that would give rise to any liability
which, individually or in the aggregate, could reasonably be expected to have a
Material Adverse Effect or a Material Adverse Change to NEG, Inc. and the NEG
Subsidiaries, taken as a whole.

     5.15 Brokers' or Finders' Fees. Except as set forth in Schedule 5.15 (as to
          -------------------------
which the Borrower is solely responsible for the payment of any such investment
banker's, brokers' or finders' fee or other commission or similar fee), no
agent, broker, investment banker, Person or firm acting on behalf of the Covered
Parties or any of their Affiliates or under the authority of the Borrower or any
of its Affiliates is or will be entitled to any brokers' or finders' fee or any
other commission or similar fee directly or indirectly from any of the parties
hereto in connection with any of the transactions contemplated hereby.

     5.16 Certain Regulatory Matters. (a) Neither Borrower nor any Subsidiary of
          --------------------------
Borrower is a "registered holding company" or a "subsidiary company" or an
"affiliate" of a "registered holding company" or a company which is required to
be registered as a "holding company" as such terms are defined under PUHCA.

     (b)  Each member of the NEG Group that owns assets subject to the
jurisdiction of FERC pursuant to the FPA or sells power at wholesale in the
United States is and at all relevant times has been either: (i) a QF; (ii)
certified by FERC as an EWG, has been granted by FERC the waivers from
regulation under the FPA typically granted to EWGs with market rate authority,
and has been granted by FERC market rate authority without qualifications,
conditions or restrictions other than those typically imposed on utility
affiliates; or (iii) a power marketer which owns no physical assets used for the
generation, transmission or distribution of electric energy as such terms are
used in PUHCA, has been granted by FERC the waivers from regulation under the
FPA typically granted to power marketers, and has been granted by FERC market
rate authority without qualifications, conditions or restrictions other than
those typically imposed on utility affiliates. The applications and additional
information submitted in connection with the certifications for QF status,
applications for EWG certification, applications for power marketer status, and
applications for market rate authority were accurate and complete in all
material respects when made and, as amended or supplemented from time-to-time,
remained at all relevant times and currently remain accurate and complete in all
respects affecting the eligibility for QF

                                      -24-
<PAGE>

status, EWG status, power marketer status, or market rate authority as
applicable, and each such FERC authorization or certification is in full force
and effect.

     (c)  Each member of the NEG Group (other than a QF during the period during
which it was a QF) that owns assets subject to the jurisdiction of FERC pursuant
to the FPA or sells power at wholesale in the United States has charged rates or
provided services only pursuant to either: (i) one or more rate schedules on
file with FERC; or (ii) market rate contracts in compliance with such entity's
market rate authority from FERC. Each QF during the period it was a QF has sold
power only in a manner consistent with its status as a QF.

     (d)  Each member of the NEG Group which owns natural gas assets, sells
natural gas or provides services subject to the jurisdiction of FERC pursuant to
the Natural Gas Act, as amended, or the Natural Gas Policy Act of 1978, as
amended, (i) has a rate schedule on file with FERC; (ii) has charged rates and
provided services only pursuant to such filed rates; and (iii) has complied and
complies in all material respects with the requirements of FERC orders
applicable to such member of the NEG Group.

     (e)  No member of the NEG Group is subject to Utility Regulation other than
as set forth in Schedule 5.16(e).

     (f)  Neither the Borrower nor LLC directly owns any assets subject to the
jurisdiction of FERC pursuant to the FPA.

     (g)  Except with respect to material licenses issued for the Brayton Point
and Salem Harbor Stations for monitoring equipment used to measure coal supply,
no member of the NEG Group is subject to regulation under the Atomic Energy Act
of 1954.

     (h)  The Borrower and each of its Subsidiaries is in material compliance
with all orders of the CPUC applicable to it, including without limitation, the
conditions set forth in the orders setting forth the conditions for the creation
of the Borrower and any subsequent CPUC proceedings, Pacific Gas and Electric
                                                     ------------------------
Company, 69 CPUC2nd 167 (Nov. 6, 1996), Pacific Gas and Electric Company, 194
-------                                 --------------------------------
PUR4th 1 (April 22, 1999), and all other CPUC orders purporting to apply to the
Borrower or its Subsidiaries regardless of whether the CPUC had jurisdiction.

     (i)  The Borrower and each of its Subsidiaries subject to Utility
Regulations is in material compliance with the requirements of Utility
Regulation applicable to it.

     (j)  None of the Borrower or any member of the NEG Group is subject to any
statute or regulation which would prohibit or require approval of the
transactions contemplated under this Agreement and the other Financing
Documents, including any Utility Regulation.

     5.17 Transactions With Affiliates. Except as set forth on Schedule 5.17,
          ----------------------------
neither the Borrower nor any of its Subsidiaries is a party to any material
contract (i) with PGE Utility on the one hand and Borrower or any member of the
NEG Group on the other, or (ii) with the Borrower on the one hand and any member
of the NEG Group on the other.

                                      -25-
<PAGE>

     5.18 Use of Proceeds. The proceeds of the Loans will be used for the
          ---------------
Refinancing in accordance with the provisions of this Agreement. The Borrower is
not engaged principally, or as one of its important activities, in the business
of extending credit for the purpose, whether immediate, incidental or ultimate,
of buying or carrying Margin Stock and no part of the proceeds of the Loans will
be used to purchase or carry any Margin Stock. Neither the making of the Loans
nor the use of the proceeds thereof will violate or be inconsistent with the
provisions of Regulation U or Regulation X.

     5.19 Compliance with ERISA. (i) Schedule 5.19 sets forth each Plan; each
          ---------------------
Plan (and each related trust, insurance contract or fund) is in substantial
compliance with its terms and with all applicable laws, including without
limitation ERISA and the Code; each Plan (and each related trust, if any) which
is intended to be qualified under Section 401(a) of the Code has received a
determination letter from the Internal Revenue Service to the effect that it
meets the requirements of Sections 401(a) and 501(a) of the Code; no Reportable
Event has occurred; no Plan which is a multiemployer plan (as defined in Section
4001(a)(3) of ERISA) is insolvent or in reorganization; no Plan has an Unfunded
Current Liability; no Plan which is subject to Section 412 of the Code or
Section 302 of ERISA has an accumulated funding deficiency, within the meaning
of such sections of the Code or ERISA, or has applied for or received a waiver
of an accumulated funding deficiency or an extension of any amortization period,
within the meaning of Section 412 of the Code or Section 303 or 304 of ERISA;
all contributions required to be made with respect to a Plan have been timely
made; neither the Borrower nor any Subsidiary of the Borrower nor any ERISA
Affiliate has incurred any material liability (including any indirect,
contingent or secondary liability) to or on account of a Plan pursuant to
Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201, 4204 or 4212 of
ERISA or Section 401(a)(29), 4971 or 4975 of the Code or expects to incur any
such liability under any of the foregoing sections with respect to any Plan; no
condition exists which presents a material risk to the Borrower or any
Subsidiary of the Borrower or any ERISA Affiliate of incurring a liability to or
on account of a Plan pursuant to the foregoing provisions of ERISA and the Code;
no proceedings have been instituted to terminate or appoint a trustee to
administer any Plan which is subject to Title IV of ERISA; no action, suit,
proceeding, hearing, audit or investigation with respect to the administration,
operation or the investment of assets of any Plan (other than routine claims for
benefits) is pending, expected or threatened; using actuarial assumptions and
computation methods consistent with Part 1 of subtitle E of Title IV of ERISA,
the aggregate liabilities of the Borrower and its Subsidiaries and its ERISA
Affiliates to all Plans which are multiemployer plans (as defined in Section
4001(a)(3) of ERISA) in the event of a complete withdrawal therefrom, as of the
close of the most recent fiscal year of each such Plan ended prior to the date
of the most recent Credit Event, would not exceed $100,000; each group health
plan (as defined in Section 607(1) of ERISA or Section 4980B(g)(2) of the Code)
which covers or has covered employees or former employees of the Borrower, any
Subsidiary of the Borrower, or any ERISA Affiliate has at all times been
operated in compliance with the provisions of Part 6 of subtitle B of Title I of
ERISA and Section 4980B of the Code; no lien imposed under the Code or ERISA on
the assets of the Borrower or any Subsidiary of the Borrower or any ERISA
Affiliate exists or is likely to arise on account of any Plan; and the Borrower
and its Subsidiaries may cease contributions to or terminate any employee
benefit plan maintained by any of them without incurring any material liability.

                                      -26-
<PAGE>

     (ii) Each Foreign Pension Plan has been maintained in substantial
compliance with its terms and with the requirements of any and all applicable
laws, statutes, rules, regulations and orders and has been maintained, where
required, in good standing with applicable regulatory authorities. All
contributions required to be made with respect to a Foreign Pension Plan have
been timely made. Neither the Borrower nor any of its Subsidiaries has incurred
any obligation in connection with the termination of, or withdrawal from, any
Foreign Pension Plan. The present value of the accrued benefit liabilities
(whether or not vested) under each Foreign Pension Plan, determined as of the
end of the Borrower's most recently ended fiscal year on the basis of actuarial
assumptions, each of which is reasonable, did not exceed the current value of
the assets of such Foreign Pension Plan allocable to such benefit liabilities.

     5.20 Investment Company Act. 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. Neither the making of any Loan, nor the application of the
proceeds or repayment thereof by the Borrower, nor the consummation of the other
transactions contemplated hereby will violate any provisions of such Act or any
rule, regulation or order of the SEC thereunder.

     5.21 Regulation.  Solely by virtue of the execution, delivery and
          ----------
performance of, or the consummation of the transactions contemplated by the
Financing Documents (including, without limitation, the assignment of or
transfer into any trust, or any realization or foreclosure upon, any of the LLC
Interests pledged under the LLC Pledge Agreement or any of the collateral
pledged under the Stock Pledge Agreement, or the exercise of any right under the
Option Agreement), neither any Holder nor any Lender shall be or become subject
to regulation (i) as a "holding company," or an "affiliate" of a "holding
company" or a "subsidiary company" of a "holding company," within the meaning of
the Public Utility Holding Company Act of 1935, (ii) under the Federal Power Act
of 1920, or (iii) as a "public utility" or "public service corporation" or the
equivalent under the applicable Law of any Governmental Authority, except with
respect to the exercise of the foreclosure rights with respect to the stock of
NEG, Inc. or the LLC Interests which may require filing with FERC and certain
state regulatory agencies.

     5.22 Security Documents. The provisions of the Security Documents are
          ------------------
effective to create, in favor of the Collateral Agent, for the benefit of the
Lenders, legal, valid and enforceable Liens on or in all of the collateral
intended to be covered thereby, and all necessary recordings and filings have
been made in all necessary public offices and all other necessary and
appropriate action has been taken so that the Liens created by each Security
Document constitute perfected Liens on or in the collateral intended to be
covered thereby, prior and superior to all other Liens, and all necessary
consents to the creation, effectiveness, priority and perfection of each such
Lien have been obtained. No mortgage or financing statement or other instrument
or recordation covering all or any part of the collateral is on file in any
recording office, except such as may have been filed in favor of the Collateral
Agent, for the benefit of the Lenders.

     5.23 Certain Scheduled Projects. Schedule 5.23 sets forth a complete list
          --------------------------
of all projects owned directly or indirectly by the Borrower, LLC, NEG, Inc. and
the NEG Subsidiaries ("Scheduled Projects") and a summary of material
                       ------------------
information with respect thereto, including the name, location, capacity and
classification of each Scheduled Project as a QF, EWG or otherwise,

                                      -27-
<PAGE>

the equity structure, and the amount of Indebtedness, with respect to each
Scheduled Project and such other information requested by the Lenders.

     5.24 Environmental Matters. (a) The Borrower, LLC, NEG, Inc. and the NEG
          ---------------------
Subsidiaries have complied and are now complying in all material respects with
(i) all Environmental Laws applicable to the Scheduled Projects and (ii) the
requirements of any Governmental Approvals issued under such Environmental Laws
with respect to the Scheduled Projects.

     (b)  Except as set forth in Schedule 5.14, there are no facts,
circumstances, conditions or occurrences regarding any of the Scheduled Projects
that (i) to the best knowledge of the Borrower, could reasonably be anticipated
to form the basis of an Environmental Claim against such Scheduled Project, the
Borrower, LLC, NEG, Inc. or any NEG Subsidiary or, to the best knowledge of the
Borrower, or any other Person occupying or conducting operations on or about
such Scheduled Project which if adversely determined could reasonably be
expected to have a Material Adverse Effect or a Material Adverse Change to NEG,
Inc. and the NEG Subsidiaries, taken as a whole, (ii) could reasonably be
anticipated to cause such Scheduled Project to be subject to any material
restrictions on its ownership, occupancy, use or transferability under any
Environmental Law or (iii) could be reasonably anticipated to require the filing
or recording of any material notice, registration, permit or disclosure document
under any Environmental Law.

     (c)  Except as set forth in Schedule 5.14, there are no past, pending, or,
to the best knowledge of the Borrower, threatened, Environmental Claims against
the Borrower, LLC, NEG, Inc., or any of the Scheduled Projects, which if
adversely determined could reasonably be expected to have a Material Adverse
Effect or a Material Adverse Change to NEG, Inc. and the NEG Subsidiaries, taken
as a whole.

     (d)  Hazardous Materials have not at any time been generated, used,
treated, recycled, stored on, or transported to or from, or Released, deposited
or disposed of on all or any portion of any Scheduled Project other than in
compliance at all times with all applicable Environmental Laws, except to the
extent such non-compliance, individually or in the aggregate, could not
reasonably be expected to have a Material Adverse Effect or a Material Adverse
Change to NEG, Inc., and the NEG Subsidiaries, taken as a whole.

     (e)  There are not now and, to the best knowledge of the Borrower, never
have been any underground storage tanks located on the Scheduled Projects and
there is no asbestos contained in, forming part of, or contaminating, any part
of the Scheduled Projects, and no polychlorinated biphenyls (PCBs) are used,
stored, located at or contaminate any part of the Scheduled Projects, the
existence of which, individually or in the aggregate, could reasonably be
expected to have a Material Adverse Effect or a Material Adverse Change to NEG,
Inc. and the NEG Subsidiaries, taken as a whole.

     5.25 Intellectual Property. Each of the Covered Parties owns or has the
          ---------------------
right to use all patents, trademarks, permits, service marks, trade names,
copyrights, franchises, formulas, licenses and other rights with respect
thereto, and has obtained assignment of all licenses and other rights of
whatsoever nature necessary for the operation of its business as currently
contem-

                                      -28-
<PAGE>

plated without any conflict with the rights of others. To the best knowledge of
the Borrower, no product, process, method, substance, part or other material
sold or employed or presently contemplated to be sold by or employed by any of
the Covered Parties in connection with its business infringes or will infringe
any patent, trademark, permit, service mark, trade name, copyright, franchise,
formula, license or other intellectual property right.

     5.26 No Default. No Default or Event of Default has occurred and is
          ----------
continuing.

     5.27 Single-Purpose Entity. LLC has not engaged in any business other than
          ---------------------
the ownership of 100% of the capital stock of NEG, Inc. LLC has established
offices at 7500 Old Georgetown Road, Bethesda, MD 20814-6161, and does not have
a place of business at any other location. LLC has no Indebtedness and no
significant assets other than the common stock of NEG, Inc.

     5.28 Trust Indenture Act. The offering, issuance, sale and delivery of the
          -------------------
Notes under the circumstances contemplated by this Agreement and the other
Financing Documents will not require this Agreement to be qualified under the
Trust Indenture Act of 1939, as amended.

     5.29 [OMITTED]

     5.30 Ratings Letter. Since January 19, 2001, none of NEG, Inc. or any
          --------------
Significant Subsidiary has knowledge of or received any notice of a downgrade of
the credit rating of its long-term senior unsecured indebtedness or its being
placed on "credit watch" by Moody's or Standard & Poor's.

     5.31 Certain Indebtedness. Part A of the Disclosure Letter sets forth a
          --------------------
true and complete list of all Indebtedness of the Borrower and the amount
thereof immediately prior to the Closing Date. Part B of the Disclosure Letter
sets forth a true and complete list of all agreements with respect to the
Indebtedness of the Borrower and the amount thereof existing on the Closing Date
which, subject to Section 7.4, is to remain outstanding after the Closing Date
(the "Existing Indebtedness Agreements"). Except as set forth on Part B, C and D
      --------------------------------
of the Disclosure Letter, all Indebtedness of the Borrower will be Refinanced
and repaid in full as at the Closing Date and all commitments in respect thereof
and all Liens and guaranties in connection therewith are terminated, and no
Person shall have any claim against the Borrower and the Borrower shall have no
further obligations with respect thereto. NEG, Inc. has made all reasonable
efforts to offer to repay, refinance or otherwise release the obligations of the
Borrower under such Indebtedness listed on Clauses I, II and III of Part B of
the Disclosure Letter, including the obligations of the Borrower under the
Equity Infusion Agreement and the Trading Contracts. Except as set forth in Part
B of the Disclosure Letter, none of the obligations of the Borrower under the
Existing Indebtedness Agreements are due and payable as of the Closing Date, and
there has been no demand on the Borrower, and the Borrower is not currently
liable, for any payment under such Existing Indebtedness Agreements.

                                      -29-
<PAGE>

     SECTION 6.  AFFIRMATIVE COVENANTS.
                 ---------------------

     The Borrower hereby covenants and agrees that in the case of the covenants
described below on and after the Closing Date and until the Loans and the Notes
together with interest, fees and all other Obligations incurred hereunder and
thereunder are paid in full (other than any indemnity, not then due and payable,
which by its terms shall survive such termination and payment):

          6.1  Information Covenants. The Borrower will, or will cause the
               ---------------------
Covered Parties to, furnish to each Lender:

          (a)  Quarterly Financial Statements. Within 45 days after the close of
               ------------------------------
     the first three quarterly accounting periods in each fiscal year of the
     relevant Person specified below, (i) the consolidated and consolidating
     balance sheets of each of (x) the Borrower and its consolidated
     subsidiaries, (y) NEG, Inc. and its consolidated subsidiaries, and (ii) the
     condensed consolidated balance sheets of the Significant Subsidiaries and
     their consolidated subsidiaries, as at the end of such quarterly accounting
     period and the related consolidated and consolidating statements of income
     and cash flows, in each case for such quarterly accounting period and for
     the elapsed portion of the fiscal year ended with the last day of such
     quarterly accounting period, and in each case, setting forth comparative
     figures for the related periods in the prior fiscal year, all of which
     shall be certified by the Chief Financial Officer of the relevant Person,
     subject to normal year-end audit adjustments.

          (b)  Annual Financial Statements.  Within 90 days after the close of
               ---------------------------
     each fiscal year commencing with the fiscal year 2001, and within 110 days
     after the close of the fiscal year 2000, of the relevant Person specified
     below, (i) the consolidated balance sheets of each of (x) the Borrower and
     its consolidated subsidiaries, (y) NEG, Inc. and its consolidated
     subsidiaries, and (ii) the balance sheets of each of the FI Subsidiaries as
     at the end of such fiscal year and in each case, the related statements of
     income and retained earnings and of cash flows for such fiscal year,
     consolidated or otherwise, as applicable, setting forth comparative figures
     for the preceding fiscal year and in the case of all such balance sheets
     certified by Deloitte & Touche LLP, or such other independent certified
     public accountants of recognized national standing reasonably acceptable to
     the Lenders, together with a report of such accounting firm stating that in
     the course of its regular audit of the financial statements of any of (A)
     the Borrower and its consolidated subsidiaries, or (B) NEG, Inc. or any of
     its consolidated subsidiaries or (C) any of the FI Subsidiaries, as the
     case may be, which audit was conducted in accordance with generally
     accepted auditing standards, such accounting firm obtained no knowledge of
     any Default or Event of Default which has occurred and is continuing or, if
     in the opinion of such accounting firm such a Default or Event of Default
     has occurred and is continuing, a statement as to the nature thereof, and
     (iii) management's discussion and analysis of the Borrower of the important
     operational and financial developments during such fiscal year.

                                      -30-
<PAGE>

          (c)  Management Letters.  Promptly after the receipt thereof by the
               ------------------
     Borrower or any of its Subsidiaries, a copy of any "management letter"
     received by any such Person from its certified public accountants and the
     management's responses thereto.

          (d)  [OMITTED]
                -------

          (e)  Officer's Certificates.  At the time of the delivery of the
               ----------------------
     financial statements provided for in Section 6.1(a) and (b), a certificate
     of the Chairman of the Board, the President or Chief Financial Officer of
     the Borrower to the effect that, to the best of such officer's knowledge,
     no Default or Event of Default has occurred and is continuing or, if any
     Default or Event of Default has occurred and is continuing, specifying the
     nature and extent thereof.

          (f)  Notice of Default or Litigation, etc.  Promptly, and in any event
               ------------------------------------
     within three (3) Business Days after an officer of the Borrower or any
     other Covered Party obtains knowledge thereof, notice of (i) the occurrence
     of any event which constitutes a Default or Event of Default, (ii) any
     litigation or governmental investigation or proceeding pending or
     threatened (x) against the Borrower or any of its Subsidiaries which would
     reasonably be expected to have a Material Adverse Effect or result in a
     Material Adverse Change to LLC, NEG, Inc. and the Significant Subsidiaries,
     taken as a whole, (y) with respect to any Indebtedness in excess of
     $10,000,000 of the Borrower or any of its Subsidiaries or (z) with respect
     to any Financing Document, (iii) downgrade of the credit rating of the
     long-term senior unsecured indebtedness of the Borrower or any other
     Covered Party or "negative watch" by Moody's or Standard & Poor's, and (iv)
     demand for satisfaction of any guaranty or other Contingent Obligations of
     the Borrower or any other Covered Party.

          (g)  Other Reports and Filings.  Promptly, copies of all financial
               -------------------------
     information, proxy materials and other information and reports, if any,
     which the Borrower or any of its Subsidiaries shall receive from FERC, CPUC
     or SEC or file with FERC, CPUC or SEC, which could reasonably be expected
     to have a Material Adverse Effect or result in a Material Adverse Change to
     LLC, NEG, Inc. and the Significant Subsidiaries, taken as a whole, or
     deliver to holders of its material Indebtedness pursuant to the terms of
     the documentation governing such Indebtedness (or any trustee, agent or
     other representative therefor) and holders of their capital stock in their
     capacity as such.

          (h)  Environmental Matters.  Promptly upon, and in any event within
               ---------------------
     thirty (30) days after, an officer of the Borrower or any other Covered
     Party obtains knowledge thereof, notice of one or more of the following
     environmental matters which occurs after the Closing Date, unless such
     environmental matters would not, individually or when aggregated with all
     other such environmental matters, be reasonably expected to have a Material
     Adverse Effect or result in a Material Adverse Change to LLC, NEG, Inc. and
     the Significant Subsidiaries, taken as a whole:

                                      -31-
<PAGE>

               (i)    any Environmental Claim pending or threatened in writing
          against the Borrower or any of its Subsidiaries or any Real Estate
          owned or operated or occupied by the Borrower or any of its
          Subsidiaries;

               (ii)   any condition or occurrence on or arising from any Real
          Estate owned or operated or occupied by the Borrower or any of its
          Subsidiaries that (a) results in noncompliance by the Borrower or any
          of its Subsidiaries with any applicable Environmental Law or (b) would
          reasonably be expected to form the basis of an Environmental Claim
          against the Borrower or any of its Subsidiaries or any such Real
          Estate;

               (iii)  any condition or occurrence on any Real Estate owned or
          operated or occupied by the Borrower or any of its Subsidiaries that
          would reasonably be expected to cause such Real Estate to be subject
          to any restrictions on the ownership, occupancy, use or
          transferability by the Borrower or any of its Subsidiaries of such
          Real Estate under any Environmental Law; and

               (iv)   the taking of any removal or remedial action in response
          to the actual or alleged presence of any Hazardous Material on any
          Real Estate owned or operated or occupied by the Borrower or any of
          its Subsidiaries as required by any Environmental Law or any
          governmental or other administrative agency; provided that in any
                                                       --------
          event the Borrower shall deliver to each Lender all material notices
          received by it or any of its Subsidiaries from any government or
          governmental agency under, or pursuant to, CERCLA.

     All such notices shall describe in reasonable detail the nature of the
     claim, investigation, condition, occurrence or removal or remedial action
     and the Borrower's or such Subsidiary's response thereto. In addition, the
     Borrower will provide each Lender, from time to time, with copies of
     periodic environmental audit and associated final closeout reports audited
     by the environmental management system of any member of the NEG Group and
     annual environmental compliance report prepared by any member of the NEG
     Group, and copies of all material communications with any government or
     governmental agency and all material communications with any Person
     relating to any Environmental Claim as to which notice is required to be
     given pursuant to this Section 6.1(h), and such detailed reports of any
     such Environmental Claim as to which notice is required, as may reasonably
     be requested by any Lender.

          (i)  [OMITTED]
                -------

          (j)  Intercompany Transaction. From time to time, such information or
               ------------------------
     document with respect to any commitment, memorandum of understanding or
     agreement, whether in writing or not, with respect to material transactions
     between (i) any of the Borrower and any member of the NEG Group or (ii)
     between or among any of the Borrower and any member of the NEG Group, on
     one hand and PGE Utility and any of its Subsidiaries, on the other hand.

                                      -32-
<PAGE>

          (k)  Certain Other Information.  Concurrently therewith, any financial
               -------------------------
     information provided by NEG, Inc. to its lenders, noteholders or
     bondholders  pursuant to the terms of the credit agreement, loan agreement
     or other equivalent instrument.

          (l)  Quarterly Meetings with Lender.  At the request of the
               ------------------------------
     Administrative Agent, within 50 days after the close of each fiscal quarter
     the Borrower shall hold a meeting at a reasonable time and place selected
     by the Borrower and acceptable to each Lender at which meeting shall be
     reviewed the financial results of the previous fiscal quarter and the
     financial condition of the Borrower and its Subsidiaries and the budgets
     presented for the current fiscal quarter of the Borrower and its
     Subsidiaries.

          (m)  Cash Reserve Certificate.  At the time of delivery of the
               ------------------------
     quarterly financial statements pursuant to clause (a) above, a certificate
     of an officer of the Borrower certifying that it is in compliance with
     Section 6.18 and setting forth in reasonable detail the calculation and the
     amount of cash and Cash Equivalents held by the Borrower with respect to
     such compliance at such time.

          (n)  Other Information.  From time to time, such other information or
               -----------------
     documents (financial or otherwise) with respect to the Borrower or its
     Subsidiaries as the Administrative Agent or any Lender may reasonably
     request in writing.

          6.2  Books, Records and Inspections.  The Borrower will, and will
               ------------------------------
cause all members of the NEG Group to, keep proper books of record and account
in which are made full, true and correct entries in conformity with generally
accepted accounting principles and all requirements of law.  The Borrower will,
and will cause the other Covered Parties to, permit officers and designated
representatives of any Lender to visit and inspect, during regular business
hours and under guidance of officers of the Borrower, any of the properties of
the Borrower and the other Covered Parties in whomsoever's possession, and to
examine the books of account of the Borrower and the other Covered Parties and
discuss the affairs (including environmental matters), finances and accounts of
the Borrower and the other Covered Parties with, and be advised as to the same
by, its and their officers and independent accountants, all upon reasonable
advance notice and at such reasonable times and intervals and to such reasonable
extent as such Lender may request, provided, that so long as no Default or Event
                                   --------
of Default has occurred and is continuing, the Borrower shall have the right to
participate in any discussions of the Lender with any independent accountants of
the Borrower.

          6.3  Maintenance of Property; Insurance.  The Borrower will, and will
               ----------------------------------
cause all members of the NEG Group to, (i) keep all material properties and
equipment used in its business in good working order and condition (ordinary
wear and tear and loss or damage by casualty or condemnation excepted), (ii)
maintain in full force and effect  insurance with reputable and solvent
insurance carriers on all its property in at least such amounts, against at
least such risks and with such deductibles or self-insured retentions as is
consistent and in accordance with industry practice and (iii) furnish to each
Lender, upon written request, full information as to the insurance carried.  In
addition to the requirements to the immediately preceding sentence, the Borrower
will at all time cause insurance of the types described in Schedule 5.9 to be
maintained with no less scope of coverage or greater deductibles as are
described in Schedule 5.9 unless Borrower can

                                      -33-
<PAGE>

show that such insurance is no longer available to the Borrower at a
commercially reasonable cost. Such insurance shall include physical damage
insurance on all real and personal property (whether now or hereafter acquired)
on an all risk basis and business interruption insurance.

          6.4  Corporate Franchises.  The Borrower will, and will cause all
               --------------------
members of the NEG Group, to do or cause to be done, all things necessary to
preserve and keep in full force and effect its existence and its material
rights, franchises, licenses and patents used in its business.

          6.5  Compliance with Statutes, etc.  The Borrower will, and will cause
               -----------------------------
all members of the NEG Group to, comply with all applicable Law, in respect of
the conduct of its business and the ownership of its Property, except such
noncompliances as could not, individually or in the aggregate, reasonably be
expected to have a Material Adverse Effect or result in a Material Adverse
Change to LLC, NEG, Inc. and the Significant  Subsidiaries, taken as a whole.

          6.6  Compliance with Environmental Laws.  (a)  The Borrower will
               ----------------------------------
comply, and will cause all members of the NEG Group to comply, in all material
respects with all Environmental Laws applicable to the operation of its business
or to the ownership or use of Real Estate now or hereafter owned or operated by
the Borrower and the other Covered Parties, will within a reasonable time period
pay or cause to be paid all costs and expenses incurred in connection with such
compliance (except to the extent being contested in good faith), and will
undertake all reasonable efforts to keep or cause to be kept all such Real
Estate free and clear of any Liens imposed pursuant to such Environmental Laws,
except such noncompliances as could not, individually or in the aggregate,
reasonably be expected to have a Material Adverse Effect or a Material Adverse
Change of LLC, NEG, Inc. and the Significant  Subsidiaries, taken as a whole.
The Borrower will not and will cause the other Covered Parties not to generate,
use, treat, store, release or dispose of, or permit the generation, use,
treatment, storage, release or disposal of Hazardous Materials on any Real
Estate now or hereafter owned or operated or occupied by the Borrower or any of
the other Covered Parties, or transport or permit the transportation of
Hazardous Materials to or from any such Real Estate except in compliance with
all applicable Environmental Laws (except such noncompliances as could not,
individually or in the aggregate, reasonably be expected to have a Material
Adverse Effect or result in a Material Adverse Change to LLC, NEG, Inc. and the
Significant  Subsidiaries, taken as a whole) and reasonably required in
connection with the operation, use and maintenance of any such Real Estate or
otherwise in connection with their businesses.

          (b)  At the written request of any Lender upon a reasonable belief by
such Lender that the Borrower or any of its Subsidiaries has breached any
representation or covenant contained herein relating to environmental matters,
which request shall specify in reasonable detail the basis therefor, the
Borrower will provide, at the Borrower's sole cost and expense, an environmental
audit, reasonable in scope, concerning the subject matter of such representation
or covenant and any Real Estate now or hereafter owned, operated or occupied by
the Borrower or any of its Subsidiaries, prepared by an environmental consulting
firm reasonably acceptable to such Lender, indicating (if relevant to such
breach) the presence or absence of Hazardous Materials and the potential cost of
any removal or remedial action in connection with any Hazardous Materials on
such Real Estate; provided, that such request may be made only if (i) there has
                  --------
occurred and is continuing a Default, (ii) such Lender reasonably believes that
the

                                      -34-
<PAGE>

Borrower or any such Real Estate is not in compliance with Environmental Law and
such circumstances would reasonably be expected to have a Material Adverse
Effect or result in a Material Adverse Change to LLC, NEG, Inc. and the
Significant Subsidiaries, taken as a whole, or (iii) circumstances exist that
reasonably could be expected to form the basis of a material Environmental Claim
against the Borrower or any of its Subsidiaries or any such Real Estate. If the
Borrower fails to provide the same within a reasonable period, not to exceed 90
days, after such request was made, a Lender may order the same, and the Borrower
shall grant and hereby grants to such Lender and its agents access to such Real
Estate and specifically grants such Lender an irrevocable non-exclusive license,
subject to the rights of tenants, to undertake such an assessment, all at the
Borrower's expense.

          6.7  ERISA.  As soon as possible and, in any event, within ten (10)
               -----
days after the Borrower, any Subsidiary of the Borrower or any ERISA Affiliate
knows or has reason to know of the occurrence of any of the following, the
Borrower will deliver to each Lender a certificate of the Chief Financial
Officer of the Borrower setting forth the full details as to such occurrence and
the action, if any, that the Borrower, such Subsidiary or such ERISA Affiliate
is required or proposes to take, together with any notices required or proposed
to be given or filed by such Borrower, such Subsidiary, the Plan administrator
or such ERISA Affiliate to or with the PBGC or any other government agency, or a
Plan participant and any notices received by such Borrower, such Subsidiary or
ERISA Affiliate from the PBGC or any other government agency, or a Plan
participant with respect thereto:  that a Reportable Event has occurred (except
to the extent that the Borrower has previously delivered to each Lender a
certificate and notices (if any) concerning such event pursuant to the next
clause hereof); that a contributing sponsor (as defined in Section 4001(a)(13)
of ERISA) of a Plan subject to Title IV of ERISA is subject to the advance
reporting requirement of PBGC Regulation Section 4043.61 (without regard to
subparagraph (b)(1) thereof), and an event described in subsection .62, .63,
 .64, .65, .66, .67 or .68 of PBGC Regulation Section 4043 is reasonably expected
to occur with respect to such Plan within the following 30 days; that an
accumulated funding deficiency, within the meaning of Section 412 of the Code or
Section 302 of ERISA, has been incurred or an application may be or has been
made for a waiver or modification of the minimum funding standard (including any
required installment payments) or an extension of any amortization period under
Section 412 of the Code or Section 303 or 304 of ERISA with respect to a Plan;
that any contribution required to be made with respect to a Plan or Foreign
Pension Plan has not been timely made; that a Plan has been or may be
terminated, reorganized, partitioned or declared insolvent under Title IV of
ERISA; that a Plan has an Unfunded Current Liability; that proceedings may be or
have been instituted to terminate or appoint a trustee to administer a Plan
which is subject to Title IV of ERISA; that a proceeding has been instituted
pursuant to Section 515 of ERISA to collect a delinquent contribution to a Plan;
that the Borrower, any Subsidiary of the Borrower or any ERISA Affiliate will or
may incur any liability (including any indirect, contingent, or secondary
liability) to or on account of the termination of or withdrawal from a Plan
under Section 4062, 4063, 4064, 4069, 4201, 4204 or 4212 of ERISA or with
respect to a Plan under Section 401(a)(29), 4971, 4975 or 4980 of the Code or
Section 409, 502(i) or 502(l) of ERISA or with respect to a group health plan
(as defined in Section 607(1) of ERISA or Section 4980B(g)(2) of the Code) under
Section 4980B of the Code; or that the Borrower or any Subsidiary of the
Borrower may incur any material liability pursuant to any employee welfare
benefit plan (as defined in Section 3(1) of ERISA) that provides

                                      -35-
<PAGE>

benefits to retired employees or other former employees (other than as required
by Section 601 of ERISA) or any Plan or any Foreign Pension Plan. The Borrower
will deliver to each Lender copies of any records, documents or other
information that must be furnished to the PBGC with respect to any Plan pursuant
to Section 4010 of ERISA. Upon the reasonable request of the Required Waiver
Lenders, the Borrower will also deliver to each Lender a complete copy of the
annual report (on Internal Revenue Service Form 5500-series) of each Plan
(including, to the extent required, the related financial and actuarial
statements and opinions and other supporting statements, certifications,
schedules and information) required to be filed with the Internal Revenue
Service. In addition to any certificates or notices delivered to each Lender
pursuant to the first sentence hereof, copies of annual reports and any records,
documents or other information required to be furnished to the PBGC or any other
government agency, and any material notices received by the Borrower, any
Subsidiary of the Borrower or any ERISA Affiliate with respect to any Plan or
Foreign Pension Plan shall be delivered to each Lender no later than ten (10)
days after the date such annual report has been filed with the Internal Revenue
Service or such records, documents and/or information has been furnished to the
PBGC or any other government agency or such notice has been received by the
Borrower, the Subsidiary or the ERISA Affiliate, as applicable. The Borrower and
each of its applicable Subsidiaries shall ensure that all Foreign Pension Plans
administered by it or into which it makes payments obtains or retains (as
applicable) registered status under and as required by applicable law and is
administered in a timely manner in all respects in compliance with all
applicable laws except where the failure to do any of the foregoing would not be
reasonably likely to result in a material adverse effect upon the business,
operations, condition (financial or otherwise) or prospects of the Borrower or
any Subsidiary of the Borrower.

          6.8  End of Fiscal Years; Fiscal Quarters.  The Borrower shall cause
               ------------------------------------
(i) each of its, and each of the other Covered Party's, fiscal years to end on
December 31 and (ii) its fiscal quarters to end on March 31, June 30, September
30 and December 31.

          6.9  Payment of Taxes.  The Borrower (a) will pay and discharge, and
               ----------------
will cause each of its Subsidiaries to pay and discharge, all material federal
and state income and franchise taxes imposed upon it or upon its income or
profits, or upon any properties belonging to it, prior to the date on which
penalties attach thereto, and all lawful claims for sums related thereto that
have become due and payable which, if unpaid, might become a Lien not otherwise
permitted hereunder, and (b) will pay and discharge, and will cause each
Subsidiary to pay and discharge, all other material taxes, assessments and
governmental charges or levies imposed upon it or upon its income or profits, or
upon any properties belonging to it, prior to the date on which penalties attach
thereto, and all lawful claims for sums that have become due and payable which,
if unpaid, might become a Lien not otherwise permitted hereunder, provided that
                                                                  --------
neither the Borrower nor any of its Subsidiaries shall be required to pay any
such tax, assessment, charge, levy or claim which is being contested in good
faith and by proper proceedings if it has maintained adequate reserves with
respect thereto in accordance with GAAP, and provided, further, that this
                                             --------  -------
section 6.9 shall not apply with respect to any taxes of PG&E Utility or any
Subsidiary of PG&E Utility for which Borrower has no liability under applicable
law.

          6.10 [OMITTED]
                -------

                                      -36-
<PAGE>

          6.11  Performance of Obligations.  The Borrower will, and will cause
                --------------------------
each member of the NEG Group to, perform all of its obligations under the terms
of each mortgage, indenture, security agreement, loan agreement or credit
agreement and each other material agreement, contract or instrument by which it
is bound, except such non-performances as could not, either individually or in
the aggregate, reasonably be expected to have a Material Adverse Effect or
result in a Material Adverse Change to LLC, NEG, Inc. and the NEG Subsidiaries
taken as a whole.

          6.12  Use of Proceeds.  The Borrower will use the proceeds of the
                ---------------
Loans only as provided in Section 4.1(s).

          6.13  Regulatory Compliance.  Borrower will take all actions and cause
                ---------------------
its Subsidiaries to take all actions reasonably required to comply in all
material respects with applicable Utility Regulations and each order issued
pursuant thereto; provided that, the foregoing shall not prevent Borrower or a
                  --------
Subsidiary from challenging the validity or effect of any Utility Regulation or
order in any proceeding provided the manner of such challenge could not
reasonably be expected to cause a Material Adverse Effect.

          6.14  Financial Covenants.  (a)  The long-term unsecured debt
                -------------------
obligations of NEG, Inc. shall be rated at least BBB- by Standard & Poor's or
Baa3 by Moody's.

          (b)   The ratio of the Fair Market Value of NEG, Inc. to the aggregate
amount of principal then outstanding under the Loan (the "Required FMV Ratio")
                                                          ------------------
shall be at least 2:1.  The Required FMV Ratio may be determined in accordance
with the procedure set forth in the succeeding paragraph at any time at the
request and expense of the requesting Lender by delivering a notice to the
Borrower no more frequently than once per fiscal quarter of the Borrower.

          For purposes hereof, the "Fair Market Value" of NEG, Inc. shall mean
the price at which a willing buyer would buy and a willing seller would sell the
Pledged Interests having full knowledge of the facts, and assuming each party
acts on an arm's-length basis with the expectation of concluding the purchase or
sale within a reasonable time, which determination shall be made by an Approved
Appraiser selected by the Tranche A Lender and the Tranche B Lender (the
"Appraiser").  The Borrower will cooperate and deliver such document and provide
 ---------
such information as may be reasonably requested by the Tranche A Lender, the
Tranche B Lender or the Appraiser with respect to the determination of the
Required FMV Ratio.

          6.15  Charter Documents.  The Borrower will, and will cause LLC and
                -----------------
the other Specified Subsidiaries to, comply with their respective Charter
Documents in all material respects.

          6.16  Further Assurances; etc.  The Borrower will, and will cause the
                -----------------------
other Covered Parties, at the expense of the Borrower, make, execute, endorse,
acknowledge, file and/or deliver to each Lender from time to time such
confirmatory assignments, conveyances, financing statements, transfer
endorsements, powers of attorney, certificates, reports, and other assurances or
instruments and take such further steps as are necessary or desirable in order
to carry out the intent, purpose, provisions of this Agreement and the other
Financing Document, including any assignment or syndication by any Lender of its
Loan.  Furthermore, the Borrower

                                      -37-
<PAGE>

will deliver to each Lender such opinions of counsel and other related documents
as may be reasonably requested by any Lender to assure itself that this Section
6.16 has been complied with.

          6.17  Tax Refund.  The Borrower shall upon receipt of the tax refund
                ----------
for the fiscal year 2000 use such refund in the manner set forth in Part G of
the Disclosure Letter.

          6.18  Cash Reserve.  The Borrower shall at all times commencing after
                ------------
the first anniversary of the Closing Date and until the Loans are repaid in full
own cash or Cash Equivalents in its name in an amount no less than 15% of the
total principal amount of Loans then outstanding, free and clear of all Liens .

          SECTION 7.  NEGATIVE COVENANTS.
                      ------------------

          The Borrower covenants and agrees that on and after the Closing Date
and until the Loans and the Notes, together with interest, fees and all other
obligations incurred hereunder and thereunder, are paid in full (other than any
indemnity, not then due and payable, which by its terms shall survive such
termination and payment):

          7.1   Liens.  The Borrower will not, and will not permit any of the
                -----
other Covered Parties to, create, incur, assume or suffer to exist any Lien upon
or with respect to any Property or assets (real or personal, tangible or
intangible) of the Borrower or any of the other Covered Parties, whether now
owned or hereafter acquired, or sell any such Property or assets subject to an
understanding or agreement, contingent or otherwise, to repurchase such Property
or assets (including sales of accounts receivable with recourse to the Borrower
or any of the other Covered Parties), or assign any right to receive income or
permit the filing of any financing statement under the UCC or any other similar
notice of Lien under any similar recording or notice statute; provided that the
                                                              --------
provisions of this Section 7.1 shall not prevent the creation, incurrence,
assumption or existence of the following (Liens described below are herein
referred to as "Permitted Liens"):
                ---------------

           (i)  inchoate Liens for taxes, assessments or governmental charges or
     levies not yet due and payable or Liens for taxes, assessments or
     governmental charges or levies being contested in good faith and by
     appropriate proceedings for which adequate reserves have been established
     in accordance with generally accepted accounting principles in the United
     States;

           (ii) Liens in respect of Property or assets of the Covered Parties
     imposed by law, which arise or were incurred in the ordinary course of
     business and do not secure Indebtedness for borrowed money, such as
     carriers', workmen's, repairmen's, warehousemen's, materialmen's and
     mechanics' liens, collecting bank's liens, charge back rights of depository
     banks for uncollected items and other similar Liens arising or incurred in
     the ordinary course of business, and (x) which do not in the aggregate
     materially detract from the value of the property or assets of the Borrower
     or the other Covered Parties and do not materially impair the use thereof
     in the operation of the business of the Borrower or the other Covered
     Parties or (y) which are being contested in good faith by appropriate
     proceedings, which proceedings (or orders entered in connection with such
     proceedings)

                                      -38-
<PAGE>

     have the effect of preventing the forfeiture or sale of the property or
     assets subject to any such Lien;

          (iii)   Subject to Section 7.4(ii), Liens in existence on the Closing
     Date which are listed, and the Property subject thereto described, in
     Schedule 7.1;

          (iv)    Liens created pursuant to this Agreement and the Security
     Documents;

          (v)     licenses, leases or subleases granted to other Persons in the
     ordinary course of business not materially interfering with the conduct of
     the business of the Borrower and the other Covered Parties, taken as a
     whole;

          (vi)    easements, rights-of-way, restrictions (including zoning
     restrictions), covenants, encroachments, protrusions and other similar
     charges or encumbrances, and minor title deficiencies, in each case whether
     now or hereafter in existence, not securing Indebtedness and not materially
     interfering with the conduct of the business of the Borrower and the other
     Covered Parties, taken as a whole;

          (vii)   statutory, contractual and common law landlords' liens under
     leases or subleases permitted by this Agreement;

          (viii)  Liens (other than any Lien imposed by ERISA) (x) incurred or
     deposits made in the ordinary course of business in connection with
     workers' compensation, unemployment insurance and other types of social
     security, (y) to secure the performance of tenders, statutory obligations
     (other than excise taxes), surety, stay, customs and appeal bonds,
     statutory bonds, bids, leases, government contracts, trade contracts,
     performance and return of money bonds and other similar obligations
     (exclusive of obligations for the payment of borrowed money) or (z) arising
     by virtue of deposits made in the ordinary course of business to secure
     liability for premiums to insurance carriers, provided that the aggregate
                                                   --------
     amount of deposits at any time pursuant to sub-clauses (y) and (z) shall
     not exceed $25,000,000 in the aggregate;

          (ix)    any interest or title of a lessor, sublessor, licensee or
     licensor under any lease or license agreement permitted by this Agreement;

          (x)     attachment or judgment Liens in an aggregate amount
     outstanding at any one time not in excess of the amount of $1,000,000;

           (xi)   attachment or judgment Liens paid or fully covered by
     insurance which are not outstanding for more than sixty (60) days;

          (xii)  Liens arising from precautionary Uniform Commercial Code
     financing statement filings with respect to operating leases or consignment
     arrangements entered into by the Borrower or any of the other Covered
     Parties in the ordinary course of business; and

                                      -39-
<PAGE>

          (xiii) other than by LLC, any Lien attendant to transactions
     described by the Business Plan.

          7.2  Consolidation, Merger, Purchase or Sale of Assets, etc.  The
               -------------------------------------------------------
Borrower will not, and will not permit any member of the NEG Group to, wind up,
liquidate or dissolve its affairs or enter into any transaction of merger or
consolidation, or convey, sell, lease or otherwise dispose of (or agree to do
any of the foregoing at any future time) all or any part of its Property or
assets, or enter into any sale-leaseback transactions, or purchase or otherwise
acquire (in one or a series of related transactions) any part of the Property or
assets (other than purchases or other acquisitions of inventory in the ordinary
course of business) of any Person (or agree to do any of the foregoing at any
future time), except to the extent attendant to transactions described by the
Business Plan and except that:

          (i)    any NEG Subsidiary may in the ordinary course of business,
     sell, lease or otherwise dispose of any assets which, in the reasonable
     judgment of such Person, are obsolete, worn out or otherwise no longer
     useful in the conduct of such Person's business;

          (ii)   each of the Borrower and any member of the NEG Group may lease
     (as lessee) real or personal property in the ordinary course of business
     (so long as any such lease does not create a Capital Lease Obligation);

          (iii)  any NEG Subsidiary may make sales or transfers of inventory,
     energy and related products in the ordinary course of business and
     consistent with past practices;

          (iv)   any NEG Subsidiary may sell or discount, in each case without
     recourse and in the ordinary course of business, overdue accounts
     receivable arising in the ordinary course of business, but only in
     connection with the compromise or collection thereof consistent with
     customary industry practice (and not as part of any bulk sale);

          (v)    each of the Borrower and any member of the NEG Group may
     license or sublicense software, trademarks and other intellectual property
     in the ordinary course of business which do not materially interfere with
     the business of the Borrower, LLC, NEG, Inc. and the NEG Subsidiaries,
     taken as a whole;

          (vi)   each of the Borrower, LLC, NEG, Inc. or any NEG Subsidiary may
     transfer assets or lease to or acquire or lease assets from the Borrower,
     LLC, NEG, Inc. or any other NEG Subsidiary and LLC, NEG, Inc. or any NEG
     Subsidiary may be merged into LLC, NEG, Inc. or any other NEG Subsidiary;

          (vii)  any NEG Subsidiary may sell or otherwise dispose of additional
     assets, provided that (x) each such sale or disposition shall be for an
             --------
     amount at least equal to the fair market value thereof (as determined in
     good faith by the senior management of such Person), (y) each such sale
     (other than any like-kind exchange) results in consideration at least 75%
     of which shall be in the form of cash (for such purpose, taking into
     account the amount of cash, the principal amount of any promissory notes
     and the fair market value, as determined in good faith by the senior
     management of the Borrower, of any other

                                      -40-
<PAGE>

     consideration), and (z) the Net Sale Proceeds therefrom shall be applied
     pursuant to Section 3.2;

          (viii) subject to Section 3.2(f), each of the Borrower and any
     member of the NEG Group may make transfers of any proceeds of insurance
     resulting from any casualty or condemnation of property or assets; and

          (ix)   the Borrower may sell or otherwise dispose of any assets other
     than assets owned by any member of the NEG Group.

          7.3  Dividends.  The Borrower will not, and will not permit any of the
               ---------
other Covered Parties to, authorize, declare or pay any Dividends (other than
the Dividend being Refinanced hereunder), except that any Subsidiary of the
Borrower may pay cash Dividends to the Borrower or to LLC, NEG, Inc. or any NEG
Subsidiary and NEG, Inc. may distribute a note to LLC or the Borrower, and LLC
may distribute any such note to the Borrower, solely in connection with the IPO
or LLC may authorize, declare and pay Dividends to the Borrower in connection
with a Spin-Off of NEG, Inc.

          7.4  Indebtedness.  The Borrower will not, and will not permit any
               ------------
member of the NEG Group to, contract, create, incur, assume or suffer to exist
any Indebtedness, except:

          (i)    Indebtedness incurred pursuant to this Agreement and the other
     Financing Documents;

          (ii)   Existing Indebtedness outstanding on the Closing Date and
     listed on Schedule 5.23 or with respect to the Borrower, Part B (I) and
     (II) of the Disclosure Letter and with respect to the Covered Parties
     (other than the Borrower), Part B (III) of the Disclosure Letter (as
     reduced by any repayments of principal thereof), without giving effect to
     any subsequent extension, renewal or refinancing thereof; provided that no
                                                               --------
     later than four (4) months from the Closing Date, the obligations of the
     Borrower under the Equity Infusion Agreements shall be fully released and
     terminated and no Person shall have any claim against the Borrower and the
     Borrower shall have no further obligations with respect thereto, and the
     Contingent Obligations of the Borrower to the Trading Counterparties under
     the Trading Contracts shall not exceed $50,000,000 in the aggregate and the
     amount of such Indebtedness shall not be extended, renewed or refinanced;

          (iii)  Indebtedness resulting from the endorsement of negotiable
     instruments in the ordinary course of business;

          (iv)   Indebtedness among Borrower or any member of the NEG Group
     (other than LLC) and any other NEG Subsidiary from intercompany transfers
     of assets made in the ordinary course of business or to the extent
     permitted under Sections 7.2 and 7.5;

          (v)    Indebtedness of a Covered Party (other than LLC) secured by
     Liens permitted under Sections 7.1(i), (ii), (vii) and (viii);

          (vi)   in the case of the Borrower, Specified Rated Indebtedness; and

                                      -41-
<PAGE>

          (vii)   in the case of any member of the NEG Group (other than LLC),
     to the extent described by the Business Plan.

          7.5  Advances, Investments and Loans.  The Borrower will not, and will
               -------------------------------
not permit any member of the NEG Group to, directly or indirectly, lend money or
credit or make advances to any other Person, or purchase or acquire any stock,
obligations or securities of, or any other interest in, or make any capital
contribution to, any other Person, or purchase or own a futures contract or
otherwise become liable for the purchase or sale of currency or other
commodities at a future date in the nature of a futures contract, or hold any
cash or Cash Equivalents (each of the foregoing an "Investment" and,
                                                    ----------
collectively, "Investments"), except that the following shall be permitted:
               -----------

           (i)    the Borrower and the other Covered Parties may acquire and
     hold accounts receivables owing to any of them, if created or acquired in
     the ordinary course of business and payable or dischargeable in accordance
     with customary trade terms of the Borrower or such other Covered Parties;

           (ii)   the Borrower and the other Covered Parties may acquire and
     hold cash and Cash Equivalents;

           (iii)  the Borrower and the other Covered Parties may acquire and own
     investments (including debt obligations) received in connection with the
     bankruptcy or reorganization of suppliers and customers and in good faith
     settlement of delinquent obligations of, and other disputes with, customers
     and suppliers arising in the ordinary course of business;

           (iv)   any Investment by a Covered Party (other than LLC) to the
     extent described by the Business Plan;

           (v)    any Investment by the Borrower in PGE Utility if the Borrower
     reasonably determines that such Investment is required by applicable Law;

           (vi)   any Investment by the Borrower in PGE Utility if the Borrower
     reasonably determines that such Investment is required by the Holding
     Company Conditions;

           (vii)  loans and advances by the Covered Parties (other than LLC) to
     their respective directors, officers and employees in a principal amount
     not exceeding the amount of $100,000, on an individual basis, and
     $1,000,000, on an aggregate basis, at any one time outstanding;

           (viii) any NEG Subsidiary and NEG, Inc. may distribute a note to LLC
     or the Borrower, and LLC may distribute any such note to the Borrower,
     solely in connection with the IPO;

           (ix)   any Investment made by any of LLC, NEG, Inc. or any NEG
     Subsidiary pursuant to Section 3.2(b)(iii), 3.2(c)(iii), 3.2(e)(iii) or
     3.2(f)(ii);

                                      -42-
<PAGE>

           (x)  any Investment made by the Borrower or any member of the NEG
     Group in a wholly-owned Subsidiary; and

           (xi) in addition to the Investments permitted by clauses (i)-(x)
     above, the Borrower may make other Investments for operations of the
     Borrower or its Subsidiaries not otherwise related to PGE Utility or any of
     its Subsidiaries in an amount not to exceed $15,000,000 in the aggregate
     for the period commencing March 1, 2001 and ending December 31, 2001, and
     $10,000,000 in the aggregate for any subsequent fiscal year.

Notwithstanding anything provided herein or in the Business Plan to the
contrary, no investment may be made by the Borrower or any member of the NEG
Group in the nuclear generation business.

          7.6  Transactions with Affiliates.  Except as disclosed on Schedule
               ----------------------------
5.17, the Borrower will not, and will not permit any member of the NEG Group and
any other NEG Subsidiaries to, enter into any transaction or series of related
transactions with any Affiliate of the Borrower or any of its Subsidiaries,
other than (a) in the ordinary course of business and on terms and conditions
substantially as favorable to the Borrower or such Subsidiary as would
reasonably be obtained by the Borrower or such Subsidiary at that time in a
comparable arm's-length transaction with a Person other than an Affiliate,
except for provision of cash, credit or other financial assistance or support by
the Borrower or any member of the NEG Group to PGE Utility or any of its
Subsidiaries (unless such assistance or support is made to the extent provided
in the Business Plan), (b) as reasonably determined by the Borrower that such
transaction is required by applicable Law or the Holding Company Conditions, (c)
among the Borrower and the other Covered Parties and any other NEG Subsidiaries
and among the NEG Group, (d) any other transactions with Affiliates provided at
cost where the difference between the arms-length price and cost is less than
$5,000,000 in the aggregate, (e) the payment of reasonable and customary fees
and reimbursements of expenses payable to directors of any member of the NEG
Group or (f) the employment arrangements with respect to the procurement of
services of directors, officers and employees of any member of the NEG Group in
the ordinary course of business and payment of reasonable and customary fees in
connection therewith.

          7.7  Capital Expenditures.  The Borrower will not, and will not permit
               --------------------
any member of the NEG Group to, make any Capital Expenditures, except to the
extent (a) the Borrower reasonably determines that such Capital Expenditures by
the Borrower in PGE Utility is required by applicable Law, (b) the Borrower
reasonably determines that such Capital Expenditures by the Borrower in PGE
Utility is required by the Holding Company Conditions, (c) that such Capital
Expenditures are made by a Covered Party (other than LLC) attendant to
transactions described by the Business Plan, (d) related to Investment made by
any of LLC, NEG, Inc. or any NEG Subsidiary pursuant to Section 3.2(b)(iii),
3.2(c)(iii), 3.2(e) (iii) or 3.2(f)(ii) or (e) provided in the cash-flow
forecast of the Borrower attached to the solvency certificate of the Borrower
delivered on the Closing Date.

          7.8  Limitations on Liens on Collateral; Modifications of Certain
               ------------------------------------------------------------
Indebtedness; Modifications of Certificate of Incorporation, By-Laws and Certain
--------------------------------------------------------------------------------
Other Agreements, etc.  (a)
----------------------

                                      -43-
<PAGE>

The Borrower will not, and will not permit any of the Covered Parties and the
Specified Subsidiaries to:

          (i)   create or suffer to exist any Lien on any of the Collateral;

          (ii)  amend or modify, or permit the amendment or modification of, any
     provision of any Existing Indebtedness Agreements which could reasonably be
     expected to have a Material Adverse Effect or result in a Material Adverse
     Change to LLC, NEG, Inc. and the NEG Subsidiaries, taken as a whole;

          (iii) except as provided in the Business Plan with respect to the IPO
     or the Spin-Off of NEG, Inc., (w) except to the extent it would not cause
     an adverse effect on any Lender, amend, modify or change any material
     provision of its certificate or articles of incorporation (including,
     without limitation, by the filing or modification of any certificate or
     articles of designation), certificate of formation, limited liability
     company agreement or by-laws (or the equivalent organizational documents),
     as applicable, or (x) amend, modify or change any agreement entered into by
     it with respect to its capital stock or other equity interests (including
     any shareholders' agreement), or (y) enter into any new agreement with
     respect to its capital stock or other equity interests or (z) amend the
     Business Plan;

          (iv)  terminate, cancel or suspend any license, contract or material
     franchise agreements which would result in a Material Adverse Effect or a
     Material Adverse Change to LLC, NEG, Inc. and the NEG Subsidiaries, taken
     as a whole; or

          (v)  create any Subsidiary of the Borrower which will be a direct or
     indirect parent of LLC or create any Subsidiary of LLC which will be a
     direct or indirect parent of NEG, Inc. or create any Subsidiary of NEG,
     Inc. which would own, directly or indirectly, all or substantially all of
     the assets or shares of the NEG Subsidiaries.

          7.9  Limitation on Issuance of Capital Stock.  (a)  Except as
               ---------------------------------------
otherwise permitted by Sections 7.3 and 7.5 or to the extent attendant to
transactions described by the Business Plan, the Borrower will not permit any of
the Covered Parties (other than the Borrower) to issue (i) any participating
preferred stock or other participating preferred equity interests or preferred
stock or other preferred equity interests convertible to common stock or common
equity interest or (ii) any redeemable common stock or other redeemable common
equity interest other than common stock or other redeemable common equity
interest that is redeemable at the sole option of the Borrower or such Covered
Party, as the case may be.

          (b)  Except as otherwise permitted by Sections 7.3 and 7.5, the
Borrower will not permit any of the Covered Parties (other than the Borrower) to
issue any capital stock or other equity interests (including by way of sales of
treasury stock) or any options (other than the Option) or warrants to purchase,
or securities convertible into, capital stock or other equity interests, except
(other than LLC) (i) for transfers and replacements of then outstanding shares
of capital stock or other equity interests, (ii) for stock splits, stock
dividends and issuances which do not decrease the percentage ownership of any of
the Covered Parties in any class of the capital stock or other equity interests
of such other Covered Parties, (iii) pursuant to employee stock

                                      -44-
<PAGE>

option plans, (iv) to the extent the Borrower reasonably determines that such
issuance is required by applicable Law, or (v) to the extent attendant to
transactions described by the Business Plan.

          7.10 Business.  The Borrower will not, and will not permit any of the
               --------
other Covered Parties to, engage in any business other than the current
businesses engaged in by the Borrower and the other Covered Parties as of the
date hereof or to the extent within the scope of business described by the
Business Plan.

          7.11 Regulatory Compliance.  The Borrower will not take any actions or
               ---------------------
allow any of its Subsidiaries to take any action which would materially violate
any applicable Utility Regulations or order issued pursuant thereto; provided
                                                                     --------
that, the foregoing shall not prevent the Borrower or a Subsidiary from
----
challenging the validity or effect of any Utility Regulation or order in any
proceeding provided the manner of such challenge could not reasonably be
expected to cause a Material Adverse Effect.  The Borrower will not take any
actions or allow any of its Subsidiaries to take any actions that would prevent
Borrower from reaffirming the representations of Sections 5.16(b), (c), (d), (e)
and (g) as of any date prior to repayment of the Loans in full.

          SECTION 8.  EVENTS OF DEFAULT AND REMEDIES.
                      ------------------------------

          8.1  Events of Default.  The occurrence of any of the following events
               -----------------
or circumstances shall constitute an "Event of Default" hereunder:
                                      ----------------

          (a)  The Borrower shall (i) default in the payment when due of any
     principal of any Loan or any Note or (ii) default, and such default shall
     continue unremedied for three or more Business Days, in the payment when
     due of any interest on any Loan or Note or any fees or any other amounts
     owing hereunder or under any other Financing Document; or

          (b)  Any representation, warranty or statement made or deemed made by
     the Borrower or any other Covered Party herein or in any other Financing
     Document or in the Disclosure Letter or in any certificate delivered to the
     Administrative Agent or any Lender pursuant hereto or thereto shall prove
     to be untrue in any material respect on the date as of which made or deemed
     made; or

          (c)  The Borrower or any of the other Covered Parties shall (i)
     default in the due performance or observance by it of any term, covenant or
     agreement contained in Section 6 (other than Sections 6.1 and 6.2) or
     Section 7; provided, however that a Default under Section 6.14(b) shall not
     constitute an Event of Default hereunder unless such Default shall continue
     unremedied for sixty (60) days and the Appraiser, at the Required
     Acceleration Lenders' request, again reaffirms that the Required FMV Ratio
     is below 2:1 after such sixty (60) day period or (ii) except as set forth
     in clause (iii) and Section 8.1(g), default in the due performance or
     observance by it of any other term, covenant or agreement contained in this
     Agreement or in any other Financing Document (other than those set forth in
     clauses (a) and (b) of this Section 8.1) and such default shall continue
     unremedied for a period of 30 days after written notice thereof to the
     defaulting party by

                                      -45-
<PAGE>

     any Lender or (iii) default in the due performance or observance by it of
     any term, covenant or agreement contained in the Option Agreement; or

          (d)  (i)  Any of the Covered Parties shall default in any payment of
     any Indebtedness when due, or (ii) any of the Covered Parties shall default
     in the observance or performance of any agreement or condition relating to
     any Indebtedness or any other event or condition shall occur or exist, the
     effect of which event or condition is to cause, or permit the holder or
     holders of such Indebtedness to cause any such Indebtedness to become due
     prior to its stated maturity, or (iii) any Indebtedness of any of the
     Covered Parties shall be declared to be (or shall become) due and payable,
     or required to be prepaid other than by regularly scheduled prepayment,
     prior to the stated maturity thereof, provided it shall not be a Default or
                                           --------
     an Event of Default under this clause (d) unless the aggregate principal
     amount of all Indebtedness as described in preceding subclauses (i), (ii)
     and (iii) is at least $100,000,000; or

          (e)  The Borrower or any of the other Covered Parties shall commence a
     voluntary case concerning itself under Title 11 of the United States Code
     entitled "Bankruptcy," as now or hereafter in effect, or any successor
     thereto (the "Bankruptcy Code"); or an involuntary case is commenced
                   ---------------
     against the Borrower or any of the other Covered Parties, and the petition
     is not controverted within 10 days, or is not dismissed within 45 days,
     after commencement of the case; or a custodian (as defined in the
     Bankruptcy Code) is appointed for, or takes charge of, all or substantially
     all of the property of the Borrower or any of the other Covered Parties; or
     the Borrower or any of the other Covered Parties commences any other
     proceeding under any reorganization, arrangement, adjustment of debt,
     relief of debtors, dissolution, insolvency or liquidation or similar law of
     any jurisdiction whether now or hereafter in effect relating to the
     Borrower or any of the other Covered Parties; or there is commenced against
     the Borrower or any of the other Covered Parties any such proceeding which
     remains undismissed for a period of 60 days; or the Borrower or any of the
     other Covered Parties is adjudicated insolvent or bankrupt; or any order of
     relief or other order approving any such case or proceeding is entered; or
     the Borrower or any of the other Covered Parties suffers any appointment of
     any custodian or the like for it or any substantial part of its property to
     continue undischarged or unstayed for a period of 45 days; or the Borrower
     or any of the other Covered Parties makes a general assignment for the
     benefit of creditors; or any corporate, limited liability company or
     similar action is taken by the Borrower or any of the other Covered Parties
     for the purpose of effecting any of the foregoing; or

          (f)  (i) Any Plan shall fail to satisfy the minimum funding standard
     required for any plan year or part thereof under Section 412 of the Code or
     Section 302 of ERISA or a waiver of such standard or extension of any
     amortization period is sought or granted under Section 412 of the Code or
     Section 303 or 304 of ERISA, a Reportable Event shall have occurred, a
     contributing sponsor (as defined in Section 4001(a)(13) of ERISA) of a Plan
     subject to Title IV of ERISA shall be subject to the advance reporting
     requirement of PBGC Regulation Section 4043.61 (without regard to
     subparagraph (b)(1) thereof) and an event described in subsection .62, .63,
     .64, .65, .66, .67 or .68 of PBGC Regulation Section 4043 shall be
     reasonably expected to occur with respect to such Plan within the

                                      -46-
<PAGE>

     following 30 days, any Plan which is subject to Title IV of ERISA shall
     have had or is likely to have a trustee appointed to administer such Plan,
     any Plan which is subject to Title IV of ERISA is, shall have been or is
     likely to be terminated or to be the subject of termination proceedings
     under ERISA, any Plan shall have an Unfunded Current Liability, a
     contribution required to be made with respect to a Plan or a Foreign
     Pension Plan has not been timely made, the Borrower or any Subsidiary of
     the Borrower or any ERISA Affiliate has incurred or is likely to incur any
     liability to or on account of a Plan under Section 409, 502(i), 502(l),
     515, 4062, 4063, 4064, 4069, 4201, 4204 or 4212 of ERISA or Section
     401(a)(29), 4971 or 4975 of the Code or on account of a group health plan
     (as defined in Section 607(1) of ERISA or Section 4980B(g)(2) of the Code)
     under Section 4980B of the Code, or the Borrower or any Subsidiary of the
     Borrower has incurred or is likely to incur liabilities pursuant to one or
     more employee welfare benefit plans (as defined in Section 3(1) of ERISA)
     that provide benefits to retired employees or other former employees (other
     than as required by Section 601 of ERISA) or Plans or Foreign Pension
     Plans, a "default" within the meaning of Section 4219(c)(5) of ERISA shall
     occur with respect to any Plan, any applicable law, rule or regulation is
     adopted, changed or interpreted, or the interpretation or administration
     thereof is changed, in each case after the date hereof, by any governmental
     authority or agency or by any court (a "Change in Law"), or, as a result of
     a Change in Law, an event occurs following a Change in Law, with respect to
       -------------
     or otherwise affecting any Plan; (ii) there shall result from any such
     event or events the imposition of a lien, the granting of a security
     interest, or a liability or a material risk of incurring a liability; and
     (iii) such lien, security interest or liability, either individually and/or
     in the aggregate, has had, or could reasonably be expected to have, a
     Material Adverse Effect; or

          (g)  Any of the Security Documents or the Option Agreement shall cease
     to be in full force and effect, or shall cease to give the Collateral Agent
     and each Lender or the Holders the Liens, rights, powers and privileges
     purported to be created thereby (including, without limitation, a perfected
     security interest in, and Lien on, all of the Collateral, in favor of the
     Collateral Agent and each Lender, superior to and prior to the rights of
     all third Persons and subject to no other Liens), or any Covered Party
     shall default in the due performance or observance of any term, covenant or
     agreement on its part to be performed or observed pursuant to any Security
     Document and such default shall continue beyond the period of grace, if
     any, specifically applicable thereto pursuant to the terms of such Security
     Document; or

          (h)  One or more judgments or decrees shall be entered against the
     Borrower or any other Covered Party involving in the aggregate for the
     Borrower and the other Covered Parties a liability (not paid or fully
     covered by a reputable and solvent insurance company) of $100,000,000 or
     more and such judgments and decrees either shall be final and non-
     appealable or shall not be vacated, discharged or stayed or bonded pending
     appeal for any period of 60 consecutive days; or

          (i)  Any final and non-appealable order shall be issued by FERC, CPUC
     or other Governmental Authority that could reasonably be expected to have a
     Material

                                      -47-
<PAGE>

     Adverse Effect or result in a Material Adverse Change to the Borrower, LLC,
     or NEG, Inc. and the Significant Subsidiaries, taken as a whole; or

          (j)  The Required FMV Ratio is below 1.25:1 on any date, unless,
     within five (5) Business days after such date, the Required Acceleration
     Lenders shall have determined and shall have advised the Administrative
     Agent that, there shall not be an acceleration of the Loans and other
     amounts owing under the Financing Documents.

          8.2  Acceleration.  (a)  If an Event of Default specified in Section
               ------------
8.1(e) with respect to the Borrower or 8.1(j) shall occur, automatically the
Loans (with accrued interest thereon) and all other amounts owing under the
Financing Documents shall immediately become due and payable.

          (b)  If any Event of Default (other than an Event of Default referred
to in Section 8.1(e) or 8.1(j)) shall occur, then the Administrative Agent
(acting upon the instructions of the Required Acceleration Lenders) may by
notice to the Borrower either declare the Loans, all accrued and unpaid interest
thereon and all other amounts owing to the Lenders under the Financing Documents
to be due and payable, whereupon the same shall become immediately due and
payable.

          (c)  Except as expressly provided above in this Section 8.2,
presentment, demand, protest and all other notices and other formalities of any
kind are hereby expressly waived by the Borrower.

          8.3  Other Remedies.  Upon the occurrence and during the continuation
               --------------
of an Event of Default, the Administrative Agent (acting upon the instructions
of the Required Acceleration Lenders) may exercise any or all rights and
remedies at law or in equity (in any combination or order that the
Administrative Agent may elect), including without limitation or prejudice to
any Lender's other rights and remedies, any and all rights and remedies
available under any of the Financing Documents; provided that any Lender may
                                                --------
exercise any or all rights and remedies at law or in equity as provided
hereunder upon the occurrence and during the continuation of an Event of Default
described in Section 8.1(a) or 8.1(e) above.

          SECTION 9.  MISCELLANEOUS.
                      -------------

          9.1  Costs and Expenses.  The Borrower shall, whether or not the
               ------------------
transactions contemplated hereby are consummated and whether or not any of the
following are incurred before or after the Closing Date, pay, within five
Business Days after demand, all reasonable costs and expenses (including
reasonable fees and expenses of counsel and consultants) of the Administrative
Agent, the Lead Arranger, the Co-Arranger, the Book Manager, each Lender, the
Collateral Agent and each Holder in connection with the preparation, issuance,
delivery, filing, recording and administration of this Agreement, the other
Financing Documents, and any other documents which may be delivered in
connection herewith or therewith, including, without limitation, (a) any and all
amounts which the Administrative Agent, each Lender, the Collateral Agent and
each Holder has paid relative to curing any Event of Default resulting from the
acts or omissions of the Borrower under this Agreement or any other Financing
Document, (b) the

                                      -48-
<PAGE>

exercise, enforcement or attempted exercise, enforcement of, or the
investigation or preservation of any rights or remedies under, this Agreement or
any other Financing Document, or (c) any amendment, waiver or consent with
respect to any provision contained in this Agreement or any other Financing
Document. In addition, the Borrower shall pay any and all stamp and other taxes
and fees payable or determined to be payable in connection with the execution,
delivery, filing and recording of this Agreement or any other Financing
Document, or any other document which may be delivered in connection with this
Agreement, and agrees to save the Administrative Agent, the Lead Arranger, the
Co-Arranger, the Book Manager, each Lender, the Collateral Agent and each Holder
harmless from and against any and all liabilities with respect to or resulting
from any delay in paying or omission to pay such taxes and fees.

          9.2  Indemnity.  Whether or not the transactions contemplated hereby
               ---------
are consummated:

          (a)  The Borrower shall pay, indemnify, and hold each of the
Administrative Agent, the Lead Arranger, the Co-Arranger, the Book Manager, each
Lender, the Collateral Agent and each Holder and each of their respective
officers, directors, employees, counsel, agents and attorneys-in-fact and
Affiliates (each, an "Indemnified Person") harmless from and against any and all
                      ------------------
liabilities, obligations, losses, damages, penalties, claims, actions,
judgments, suits, costs, charges, expenses or disbursements (including
reasonable legal fees and expenses and reasonable fees and expenses of
consultants) of any kind or nature whatsoever which may at any time (including
at any time following repayment of the Loan or the termination, resignation or
replacement of any Administrative Agent, Lead Arranger, Co-Arranger, Book
Manager, Lender, Collateral Agent or Holder) be imposed on, incurred by or
asserted against any such Person in any way relating to or arising out of this
Agreement or any other Financing Document, including the Security Documents and
any other document or instrument contemplated by or referred to herein or
therein, or the transactions contemplated hereby and thereby, or any action
taken or omitted by any such Person under or in connection with any of the
foregoing, including with respect to the exercise by the Administrative Agent,
the Lead Arranger, the Co-Arranger, the Book Manager, any Lender, the Collateral
Agent and any Holder of any of its respective rights or remedies under any of
the Financing Documents, and any investigation, litigation or proceeding
(including any bankruptcy, insolvency, reorganization or other similar
proceeding or appellate proceeding) related to this Agreement or any other
Financing Document or the Loan, or the use of the proceeds thereof, whether or
not any Indemnified Person is a party thereto (all the foregoing, collectively,
the "Indemnified Liabilities"); provided, that the Borrower shall have no
     -----------------------    --------
obligation hereunder to any Indemnified Person with respect to Indemnified
Liabilities arising from the gross negligence or willful misconduct of such
Indemnified Person.

          (b)  Environmental Indemnity.
               -----------------------

          (i)  Without in any way limiting the generality of the other
     provisions contained in this Section 9.2, the Borrower agrees to defend,
     protect, indemnify, save and hold harmless each Indemnified Person, whether
     as beneficiary of any of the Security Documents, as a mortgagee in
     possession, or as successor-in-interest to the Borrower by foreclosure deed
     or deed in lieu of foreclosure, or otherwise, from and against any and all
     liabilities, obligations, losses, damages (including foreseeable and
     unforeseeable conse-

                                      -49-
<PAGE>

     quential damages and punitive claims), penalties, fees, claims, actions,
     judgments, suits, costs, disbursements (including, without limitation,
     reasonable legal fees and expenses and consultants' fees and disbursements)
     and expenses (collectively, "Losses") of any kind or nature whatsoever that
                                  ------
     may at any time be incurred by, imposed on, asserted or awarded against any
     such Indemnified Person directly or indirectly based on, or arising out of
     or resulting from, (A) the actual or alleged presence of Hazardous
     Materials on, in, under or affecting all or any portion of any Property of
     the Borrower or any member of the NEG Group whether or not the same
     originates or emanates from any such Property or any property adjoining or
     adjacent to any such Property or from properties at which any Hazardous
     Materials generated, stored or handled by the Borrower were Released or
     disposed of, (B) any Environmental Claim relating to any such Property or
     (C) the exercise of any Secured Party's rights under any of the provisions
     of the Security Documents (the "Indemnified Matters"), whether any of the
                                     -------------------
     Indemnified Matters arise before or after foreclosure of any of the
     security interests or other taking of title to all or any portion of the
     Collateral by the Collateral Agent or any Lender, including, without
     limitation, (x) the costs of removal of any and all Hazardous Materials
     from all or any portion of any such Property or any property adjoining or
     adjacent to any such Property, (y) additional costs required to take
     reasonable precautions to protect against the Release of Hazardous
     Materials on, in, under or affecting any such Property into the air, any
     body of water, any other public domain or any surrounding areas, and (z)
     costs incurred to comply, in connection with all or any portion of any such
     Property or any surrounding areas, with all applicable Environmental Laws
     with respect to Hazardous Materials, except to the extent that any such
     Indemnified Matter arises from the gross negligence or willful misconduct
     of such Indemnified Person.

          (ii) In no event shall any site visit, observation, or testing by any
     Indemnified Person (or any representative of any such Person) be deemed to
     be a representation or warranty that Hazardous Materials are or are not
     present in, on, or under, any Property of the Borrower or any member of the
     NEG Group, or that there has been or shall be compliance with any
     Environmental Law.  Neither the Borrower nor any other Person is entitled
     to rely on any site visit, observation, or testing by any Indemnified
     Person.  No Indemnified Person owes any duty of care to protect the
     Borrower or any other Person against, or to inform the Borrower or any
     other Person of, any Hazardous Materials or any other adverse condition
     affecting any such Property.  No Indemnified Person shall be obligated to
     disclose to the Borrower or any other Person any report or findings made as
     a result of, or in connection with, any site visit, observation, or testing
     by any Indemnified Person.

          (c)  Survival; Defense.  The obligations in this Section 9.2 shall
               -----------------
survive payment of the Loans and all other obligations hereunder.  At the
election of any Indemnified Person, the Borrower's indemnification obligations
under this Section 9.2 shall include the obligation to defend such Indemnified
Person using legal counsel satisfactory to such Indemnified Person, at the sole
cost and expense of the Borrower.  All amounts owing under this Section 9.2
shall be paid within 30 days after demand.

                                      -50-
<PAGE>

          (d)  Contribution. To the extent that any undertaking in the preceding
               ------------
paragraphs of this Section 9.2 may be unenforceable because it is violative of
any law or public policy, the Borrower will contribute the maximum portion that
it is permitted to pay and satisfy under applicable Law to the payment and
satisfaction of such undertaking.

          (e)  Settlement.  So long as the Borrower is in compliance with its
               ----------
obligations under this Section 9.2, the Borrower shall not be liable to any
Indemnified Person under this Section 9.2 for any settlement made by such
Indemnified Person without the Borrower's consent.

          9.3  Notices.  (a)  All notices, requests and other communications
               -------
provided for hereunder shall be in writing (including, unless the context
expressly otherwise provides, by facsimile transmission, provided that any
                                                         --------
matter transmitted by the Borrower by facsimile (i) shall be immediately
confirmed by a telephone call to the recipient at the number specified on
Schedule 9.3, and (ii) shall be followed promptly by a hard copy original
thereof by express courier) and faxed or delivered, to the address or facsimile
number specified for notices on Schedule 9.3 or to such other address as shall
be designated by such party in a written notice to the other parties hereto.

          (b)  All such notices, requests and communications (i) sent by express
courier will be effective upon delivery to or refusal to accept delivery by the
addressee, and (ii) transmitted by facsimile will be effective when sent and
facsimile confirmation received; except that all notices and other
communications to the Administrative Agent or any Lender shall not be effective
until actually received.

          (c)  The Borrower acknowledges and agrees that any agreement of the
Administrative Agent or any Lender to receive certain notices by telephone and
facsimile is solely for the convenience and at the request of the Borrower.  The
Administrative Agent and each Lender shall be entitled to rely on the authority
of any Person purporting to be a Person authorized by the Borrower to give such
notice and the Administrative Agent and each Lender shall not have any liability
to the Borrower or other Person on account of any action taken or not taken by
any of the Administrative Agent or such Lender in reliance upon such telephonic
or facsimile notice.

          9.4  Benefit of Agreement.  This Agreement shall be binding upon and
               --------------------
inure to the benefit of and be enforceable by the respective successors and
permitted assigns of the parties hereto.  The Borrower may not assign or
otherwise transfer any of its rights under this Agreement or any of the other
Financing Documents.

          9.5  No Waiver; Remedies Cumulative.  No failure or delay on the part
               ------------------------------
of the Administrative Agent or any Lender or the holder of any Note in
exercising any right, power or privilege hereunder or under any other Financing
Document and no course of dealing between the Borrower and the Administrative
Agent or any Lender or the holder of any Note shall operate as a waiver thereof,
nor shall any single or partial exercise of any right, power or privilege
hereunder or under any other Financing Document preclude any other or further
exercise thereof or the exercise of any other right, power or privilege
hereunder or thereunder.  No notice to or demand on the Borrower in any case
shall entitle the Borrower to any other or further notice or demand in

                                      -51-
<PAGE>

similar or other circumstances or constitute a waiver of the rights of the
Administrative Agent or any Lender or the holder of any Note to take any other
or further action in any circumstances without notice or demand. All remedies,
either under this Agreement or any other Financing Document or pursuant to any
applicable Law or otherwise afforded to the Administrative Agent or any Lender
shall be cumulative and not alternative.

          9.6  No Third Party Beneficiaries.  The agreement of any Lender to
               ----------------------------
make extensions of credit to the Borrower on the terms and conditions set forth
in this Agreement and the other Financing Documents is solely for the benefit of
the Borrower, and no other Person shall have any rights hereunder against such
Lender with respect to the Loans, the proceeds thereof or otherwise.

          9.7  Reinstatement.  To the extent that the Administrative Agent or
               -------------
any Lender receives any payment by or on behalf of the Borrower, which payment
or any part thereof is subsequently invalidated, declared to be fraudulent or
preferential, set aside or required to be repaid to the Borrower or to its
estate, trustee, receiver, custodian or any other party under any Bankruptcy Law
or otherwise, then to the extent of the amount so required to be repaid, the
obligation or part thereof which has been paid, reduced or satisfied by the
amount so repaid shall be reinstated by the amount so repaid and shall be
included within the Obligations as of the date such initial payment, reduction
or satisfaction occurred.

          9.8  No Immunity.  To the extent that the Borrower may be entitled, in
               -----------
any jurisdiction in which judicial proceedings may at any time be commenced with
respect to this Agreement or any other Financing Document, to claim for itself
or its revenues, assets or Properties any immunity from suit, the jurisdiction
of any court, attachment prior to judgment, attachment in aid of execution of
judgment, set-off, execution of a judgment or any other legal process, and to
the extent that in any such jurisdiction there may be attributed to such Person
such an immunity (whether or not claimed), the Borrower hereby irrevocably
agrees not to claim and hereby irrevocably waives such immunity to the fullest
extent permitted by the Law of the applicable jurisdiction.

          9.9  Counterparts.  This Agreement may be executed in any number of
               ------------
counterparts and by the different parties hereto on separate counterparts, each
of which when so executed and delivered by facsimile or otherwise shall be an
original, but all of which shall together constitute one and the same
instrument.

          9.10 Amendment or Waiver.  (a)  No provision of this Agreement or any
               -------------------
other Financing Document may be amended, supplemented, modified or waived,
except by a written instrument signed by the Required Waiver Lenders and the
Borrower and each Covered Party that is a party thereto, and, to the extent that
its rights or obligations may be affected thereby, the Administrative Agent.
Notwithstanding the foregoing provisions, no such waiver and no such amendment,
supplement or modification shall (i) increase or extend the Commitment of any
Lender (it being understood that waivers or modifications after the Closing Date
of covenants, Defaults or Events of Default shall not constitute a change in the
terms of any Commitment of any Lender), without the prior written consent of
such Lender, (ii) postpone or delay any date fixed by this Agreement or any
other Financing Document for any payment of principal, interest, fees or

                                      -52-
<PAGE>

other amounts due to any Lender hereunder or under any other Financing Document
(it being understood that waivers or modifications after the Closing Date of
covenants, Defaults or Events of Default shall not constitute a postponement or
delay in any date fixed by this Agreement or any other Financing Document for
any payment of principal, interest, fees or other amounts due to any Lender
hereunder or under any other Financing Document), without the prior written
consent of such Lender, (iii) reduce the principal of, or the rate of interest
specified in any Financing Document on, any Loan of any Lender, without the
prior written consent of such Lender, (iv) release all or substantially all of
the Collateral except as shall be otherwise provided in any Security Document or
other Financing Document or consent to the assignment or transfer by the
Borrower of any of its respective obligations under this Agreement or any other
Financing Document, without the prior written consent of each Lender, (v) amend,
modify or waive any provision of this Section 9.10 or Section 9.1 or 9.2,
without the prior written consent of each Lender, or (vi) reduce the percentage
specified in or otherwise amend the definition of Required Waiver Lenders or
Required Acceleration Lenders, without the prior written consent of each Lender.

          (b)   Any waiver and any amendment, supplement or modification made or
entered into in accordance with Section 9.10(a) shall be binding upon the
Borrower, the Administrative Agent, the Lenders and their successors and
assigns.

          9.11  Assignments, Participations, etc.  (a)  Each Lender may, without
                ---------------------------------
the consent of the Borrower, but with prior notice to the Administrative Agent,
sell or assign any part of the Loan of such Lender and the other rights and
obligations of such Lender to any Person or any assignee thereof (an "Assignee")
unless the sale or assignment of the Loan and such other rights and obligations
of such Lender would reasonably put the business of the Borrower at a
competitive disadvantage, then such sale or assignment shall require the consent
of the Borrower. The assigning Lender and the Assignee shall enter into an
assignment agreement, in form and substance satisfactory to the Administrative
Agent (an "Assignment and Acceptance"), with respect to the sale or assignment
           -------------------------
of the Loan to be assigned and, subject to paragraphs (e) and (f) of this
Section 9.11, upon execution and delivery of 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, shall have the rights and obligations of a Lender hereunder and
under the other Financing Documents, and this Agreement shall be deemed to be
amended to the extent, but only to the extent, necessary to effect the addition
of the Assignee, and any reference to the assigning Lender hereunder or under
the other Financing Documents shall thereafter refer to such Lender and to the
Assignee to the extent of their respective interests, and (ii) the assigning
Lender shall, to the extent that rights and obligations hereunder and under the
other Financing Documents have been assigned by it pursuant to such assignment
agreement, relinquish its rights and be released from its obligations under the
Financing Documents.

          (b)   Each Lender may sell participations to one or more banks or
other entities (other than the Borrower or any of its Affiliates) in or to all
or a portion of its rights and obligations under this Agreement and such
Lender's Note; provided, however, that (i) such Lender's obligations under this
               --------  -------
Agreement shall remain unchanged, (ii) such Lender shall remain solely
responsible to the other parties hereto for the performance of such obligations,
(iii) such Lender

                                      -53-
<PAGE>

shall remain the holder of any such Note for all purposes of this Agreement,
(iv) the Borrower 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 this Agreement or any Note, or any consent to any departure by the
Borrower therefrom, except to the extent that such amendment, waiver or consent
would reduce the principal of, or interest on, the Note or any fees or other
amounts payable hereunder, or release of all or substantially all of the
Collateral, in each case to the extent subject to such participation, or
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.

          (c)  A Lender may, in connection with any assignment or participation
or proposed assignment or participation pursuant to this Section 9.11, disclose
to the assignee or participant or proposed assignee or 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 to preserve the
confidentiality of any confidential information relating to the Borrower
received by it from such Lender.

          (d)  Notwithstanding any other provision contained in this Agreement
or any other Financing Document to the contrary, any Lender may assign all or
any portion of the Loan held by it as collateral security, provided that any
                                                           --------
payment in respect of such assigned Loan or Note made by the Borrower to or for
the account of the assigning or pledging Lender in accordance with the terms of
this Agreement shall satisfy the Borrower's obligations hereunder in respect to
such assigned Loan or Note to the extent of such payment. No such assignment
shall release the assigning Lender from its obligations hereunder.

          (e)  The Borrower hereby designates the Administrative Agent to serve
as the Borrower's agent, solely for purposes of this Section 9.11, to maintain a
register (the "Register") on which it will record the Loans made by each of the
Lenders and each repayment in respect of the principal amount of the Loans of
each Lender.  Failure to make any such recordation, or any error in such
recordation shall not affect the Borrower's obligations in respect of such
Loans.  With respect to any Lender, the transfer of the rights to the principal
of, and interest on, any Loan shall not be effective until such transfer is
recorded on the Register maintained by the Administrative Agent with respect to
ownership of such Loans and prior to such recordation all amounts owing to the
transferor with respect to such Loans shall remain owing to the transferor.  The
registration of assignment or transfer of all or part of any Loans shall be
recorded by the Administrative Agent on the Register only upon the acceptance by
the Administrative Agent of a properly executed and delivered Assignment and
Acceptance pursuant to Section 9.11(a).  The Borrower agrees to indemnify the
Administrative Agent from and against any and all losses, claims, damages and
liabilities of whatsoever nature which may be imposed on, asserted against or
incurred by the Administrative Agent in performing its duties under this Section
9.11(e).

          (f)  Upon its receipt of an Assignment and Acceptance executed by an
assigning Lender and an Assignee (and, in any case where the consent of the
Borrower is required by this Section, by the Borrower) together with payment to
the Administrative Agent of a registration and processing fee of $3,500, the
Administrative Agent shall (i) promptly accept such

                                      -54-
<PAGE>

Assignment and Acceptance and (ii) on the effective date determined pursuant
thereto record the information contained therein in the Register and give notice
of such acceptance and recordation to the Borrower. On or prior to such
effective date, the Borrower, at its own expense, upon request, shall execute
and deliver to the Administrative Agent (in exchange for the Note of the
assigning Lender) a new Note to the order of such Assignee in an amount equal to
the Loan acquired by it pursuant to such Assignment and Acceptance and, if such
assigning Lender has retained a Loan, a new Note to the order of such assigning
Lender in an amount equal to the Loan retained by it hereunder.

          9.12  Survival.  All indemnities set forth herein, including, without
                --------
limitation, Section 9.2, shall survive the execution and delivery of this
Agreement and the Notes and the making and repayment of the Loans.  In addition,
each representation and warranty made or deemed to be made pursuant hereto shall
survive the making of such representation and warranty, and no Lender shall be
deemed to have waived, by reason of making any extension of credit, any Default
or Event of Default which may arise by reason of such representation or warranty
proving to have been false or misleading, notwithstanding that such Lender may
have had notice or knowledge or reason to believe that such representation or
warranty was false or misleading at the time such extension of credit was made.

          9.13  WAIVER OF JURY TRIAL.  EACH OF THE PARTIES HERETO HEREBY
                --------------------
KNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVES THE RIGHT ANY OF THEM MAY HAVE
TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION BASED ON, OR ARISING OUT OF,
UNDER OR IN CONNECTION WITH, THIS AGREEMENT, THE NOTES OR ANY OTHER FINANCING
DOCUMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER
VERBAL OR WRITTEN) OR ACTIONS OF ANY PARTY RELATING HERETO OR THERETO.  THIS
PROVISION IS A MATERIAL INDUCEMENT FOR THE LENDERS TO ENTER INTO THIS AGREEMENT.

          9.14  Right of Set-off.  In addition to any rights now or hereafter
                ----------------
granted under applicable Law or otherwise, and not by way of limitation of any
such rights, upon the occurrence of an Event of Default, each Lender is hereby
authorized at any time or from time to time, without presentment, demand,
protest or other notice of any kind to the Borrower or to any other Person, any
such notice being hereby expressly waived, to set off and to appropriate and
apply any and all deposits (general or special) and any other Indebtedness at
any time held or owing by such Lender (including without limitation by branches
and agencies of such Lender wherever located), to or for the credit or the
account of the Borrower against and on account of the Obligations or liabilities
of the Borrower to such Lender under this Agreement or any of the other
Financing Documents, including all claims of any nature or description arising
out of or connected with this Agreement or any other Financing Document,
irrespective of whether such Lender shall have made any demand hereunder and
although said Obligations, liabilities or claims, or any of them, shall be
contingent or unmatured.

          9.15  Severability.  Any provision hereof which is prohibited or
                ------------
unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective
to the extent of such prohibition or

                                      -55-
<PAGE>

unenforceability without invalidating the remaining provisions hereof and
without affecting the validity or enforceability of any provision in any other
jurisdiction.

          9.16  Governing Law; Submission to Jurisdiction.  (a)  THIS AGREEMENT
                -----------------------------------------
AND EACH OF THE OTHER FINANCING DOCUMENTS (UNLESS SUCH DOCUMENT EXPRESSLY STATES
OTHERWISE THEREIN) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE
LAW OF THE STATE OF NEW YORK WITHOUT REGARD TO THE CONFLICT OF LAW RULES THEREOF
(OTHER THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW).

          (b)  The Borrower hereby submits to the nonexclusive jurisdiction of
the United States District Court for the Southern District of New York and of
any New York State court sitting in New York City for the purposes of all legal
proceedings arising out of or relating to this Agreement, any other Financing
Document or the transactions contemplated hereby or thereby. The Borrower hereby
irrevocably waives, to the fullest extent permitted by applicable Law, any
objection which it may now or hereafter have to the laying of the venue of any
such proceeding brought in such a court and any claim that any such proceeding
brought in such a court has been brought in an inconvenient forum. The Borrower
hereby irrevocably appoints CT Corporation System (the "Process Agent"), with
                                                        -------------
an office on the date hereof at 111 Eighth Avenue, New York, New York 10011, as
its agent to receive on its behalf and on behalf of its Property, service of
copies of the summons and complaint and any other process that may be served in
any such action or proceeding. Service upon the Process Agent shall be deemed to
be personal service on the Borrower and shall be legal and binding upon the
Borrower for all purposes notwithstanding any failure to mail copies of such
legal process to the Borrower, or any failure on the part of the Borrower to
receive the same. Nothing herein shall affect the right to serve process in any
other manner permitted by applicable Law or any right to bring legal action or
proceedings in any other competent jurisdiction, including judicial or non-
judicial foreclosure of real property interests which are part of the
Collateral. The Borrower further agrees that the aforesaid courts of the State
of New York and of the United States of America for the Southern District of New
York shall have exclusive jurisdiction with respect to any claim or counterclaim
of the Borrower based upon the assertion that the rate of interest charged by or
under this Agreement or under the other Financing Documents is usurious. To the
extent permitted by applicable Law, the Borrower further irrevocably agrees to
the service of process of any of the aforementioned courts in any suit, action
or proceeding by the mailing of copies thereof by certified mail, postage
prepaid, return receipt requested, to the Borrower at the address referenced in
Section 9.3, such service to be effective upon the date indicated on the postal
receipt returned from the Borrower.

          (c)  The Borrower agrees that it will at all times continuously
maintain an agent to receive service of process in the State of New York on
behalf of itself and its Properties, and, in the event that for any reason the
agent mentioned above shall not serve as agent for the Borrower to receive
service of process in the State of New York on its behalf, the Borrower shall
promptly appoint a successor satisfactory to the Administrative Agent so to
serve, advise the Administrative Agent thereof, and deliver to the
Administrative Agent evidence in writing of the successor agent's acceptance of
such appointment. The foregoing provisions constitute, among other things, a
special arrangement for service among the parties to this Agreement for the
purposes of 28 U.S.C. (S) 1608.

                                      -56-
<PAGE>

          9.17  Waiver by Borrower.  The Borrower waives any claim it may now or
                ------------------
hereafter have against the Administrative Agent, the Collateral Agent, any
Lender and any Holder for any consequential, exemplary or punitive damage under
or in connection with or relating to this Agreement or any of the Financing
Documents.

          9.18  Recourse.  This Agreement is made with full recourse to the
                --------
Borrower and pursuant to and upon all the representations, warranties, covenants
and agreements on the part of the Borrower contained herein and in the other
Financing Documents to which the Borrower is a party and otherwise in writing in
connection herewith and therewith.

          9.19  Complete Agreement.   THIS AGREEMENT, THE OTHER FINANCING
                ------------------
DOCUMENTS, THE FEE LETTER AND THE LEHMAN FEE LETTER REPRESENT THE FINAL AND
COMPLETE AGREEMENT OF THE PARTIES HERETO AND THERETO WITH RESPECT TO THE LOANS,
AND ALL PRIOR NEGOTIATIONS, REPRESENTATIONS, UNDERSTANDINGS, WRITINGS AND
STATEMENTS OF ANY NATURE WITH RESPECT TO THE LOANS ARE HEREBY SUPERSEDED IN
THEIR ENTIRETY BY THE TERMS OF THIS AGREEMENT AND THE OTHER FINANCING DOCUMENTS.

          9.20  Publicity.  Except as otherwise required by law, none of the
                ---------
parties hereto shall issue any press release relating to, connected with or
arising out of this Agreement and the other Financing Documents or the matters
contained herein or therein, without obtaining the prior approval of each other
party hereto to the contents and the manner of presentation and publication
thereof.  No references to any party hereto shall be made by any party hereto in
any public statement without its consent except as otherwise required by Law.

          9.21  Effectiveness.  This Agreement and the other Financing Documents
                -------------
shall be effective as of the Effective Date.

          9.22  Certain Representations and Warranties.  Each of the Tranche A
                --------------------------------------
Lender and the Tranche B Lender by reason of its business or financial
experience, has the capacity to protect its own interests (within the meaning of
Section 25102(f)(2) of the California Corporations Code) in connection with the
transactions contemplated by the Financing Documents.

          9.23  Confidentiality.  Each Lender agrees to keep confidential in
                ---------------
accordance with such Lender's customary practices (and in any event in
compliance with applicable law respecting material non-public information) all
information obtained by it pursuant hereto and the other Financing Documents
identified as confidential in writing at the time of delivery and agrees that it
will only use such information in connection with the transactions contemplated
by this Agreement and the other Financing Documents and not disclose any of such
information other than (a) to such Lender's employees, representatives,
directors, attorneys, auditors, agents, professional advisors, trustees or
indirect contractual counterparty in swap agreements or such contractual
counterparty's professional advisor (so long as such contractual counterparty or
professional advisor to such contractual counterparty agrees to be bound by the
provision of this Section 9.23 or is bound by a confidentiality agreement
containing substantially equivalent provisions), (b) to the extent such
information presently is or hereafter becomes available to such

                                      -57-
<PAGE>

Lender on a non-confidential basis from any source or such information that is
in the public domain at the time of disclosure, (c) to the extent disclosure is
required by law (including applicable securities laws), regulations, subpoena or
judicial order or process (provided that notice of such requirement or order
                           --------
shall be promptly furnished to the Borrower unless such notice is legally
prohibited) or requested or required by bank, securities, insurance or
investment company regulations or auditors or any administrative body or
commission (including the Securities Valuation Office of the National
Association of Insurance Commissioners) to whose jurisdiction such Lender may be
subject, (d) to any rating agency to the extent required in connection with any
rating to be assigned to such Lender, (e) to Assignees or prospective Assignees
or participants or prospective participants who agree to be bound by the
provisions of this Section 9.23 or who are subject to confidentiality agreements
containing substantially equivalent provisions, (f) to the extent required in
connection with any litigation between any party hereto or thereto and any
Lender with respect to the Loans or this Agreement and the other Financing
Documents or (g) with the Borrower's prior written consent. The agreements in
this Section 9.23 shall survive repayment of the Loans and all other amounts
payable hereunder.

          SECTION 10.   THE ADMINISTRATIVE AGENT; THE LEAD ARRANGER, THE CO-
                        ---------------------------------------------------
ARRANGER AND THE BOOK MANAGER.
-----------------------------

          10.1  Appointment.  Lehman Commercial Paper Inc. shall be the
                -----------
Administrative Agent and shall act as specified herein and in the other
Financing Documents.  Each Lender hereby irrevocably authorizes, and the holder
of any Note by the acceptance of such Note shall be deemed irrevocably to
authorize, the Administrative Agent to take such action on its behalf under the
provisions of this Agreement, the other Financing Documents and any other
instruments and agreements referred to herein or therein and to exercise such
powers and to perform such duties hereunder and thereunder as are specifically
delegated to or required of the Administrative Agent by the terms hereof and
thereof and such other powers as are reasonably incidental thereto.  The
Administrative Agent may perform any of its duties hereunder by or through its
officers, directors, agents or employees.

          10.2  Nature of Duties.  The Administrative Agent shall have no duties
                ----------------
or responsibilities except those expressly set forth in this Agreement and the
Security Documents.  Neither the Administrative Agent nor any of its officers,
directors, agents or employees shall be liable for any action taken or omitted
by it or them hereunder or under any other Financing Document or in connection
herewith or therewith, unless caused by its or their gross negligence or willful
misconduct.  The duties of the Administrative Agent shall be mechanical and
administrative in nature; the Administrative Agent shall not have by reason of
this Agreement or any other Financing Document, or by reason of the use of the
term "agent" with reference to the Administrative Agent, a fiduciary
relationship in respect of any Lender or the holder of any Note; and nothing in
this Agreement or any other Financing Document, expressed or implied, is
intended to or shall be so construed as to impose upon the Administrative Agent
any obligations in respect of this Agreement or any other Financing Document
except as expressly set forth herein.

          10.3  Lack of Reliance on the Administrative Agent.  Independently and
                --------------------------------------------
without reliance upon the Administrative Agent, each Lender and each holder of
any Note, to the extent it

                                      -58-
<PAGE>

deems appropriate, has made and shall continue to make (i) its own independent
investigation of the financial condition and affairs of the Borrower in
connection with the making and the continuance of the Loans and the taking or
not taking of any action in connection herewith and (ii) its own appraisal of
the creditworthiness of the Borrower, except as expressly provided in this
Agreement, the Administrative Agent shall have no duty or responsibility, either
initially or on a continuing basis, to provide any Lender or the holder of any
Note with any credit or other information with respect thereto, whether coming
into its possession before the making of the Loans or at any time or times
thereafter. The Administrative Agent shall not be responsible to any Lender or
the holder of any Note for any recitals, statements, information,
representations or warranties herein or in any document, certificate or other
writing delivered in connection herewith or for the execution, effectiveness,
genuineness, validity, enforceability, perfection, collectibility, priority or
sufficiency of this Agreement or any other Financing Document or the financial
condition of the Borrower or be required to make any inquiry concerning either
the performance or observance of any of the terms, provisions or conditions of
this Agreement or any other Financing Document, or the financial condition of
the Borrower or the existence or possible existence of any Default or Event of
Default.

          10.4  Certain Rights of the Administrative Agent.  If the
                ------------------------------------------
Administrative Agent shall request instructions from the Required Waiver Lenders
or Required Acceleration Lenders, as the case may be, with respect to any act or
action (including failure to act) in connection with this Agreement or any other
Financing Document, the Administrative Agent shall be entitled to refrain from
such act or taking such action unless and until the Administrative Agent shall
have received instructions from the Required Waiver Lenders or Required
Acceleration Lenders, as the case may be, and the Administrative Agent shall not
incur liability to any Person by reason of so refraining. Without limiting the
foregoing, no Lender or the holder of any Note shall have any right of action
whatsoever against the Administrative Agent as a result of the Administrative
Agent acting or refraining from acting hereunder or under any other Financing
Document in accordance with the instructions of the Required Waiver Lenders or
Required Acceleration Lenders, as the case may be.

          10.5  Reliance.  The Administrative Agent shall be entitled to rely,
                --------
and shall be fully protected in relying, upon any note, writing, resolution,
notice, statement, certificate, telex, teletype or telecopier message,
cablegram, radiogram, order or other document or telephone message signed, sent
or made by any Person that the Administrative Agent believed to be the proper
Person, and, with respect to all legal matters pertaining to this Agreement and
any other Financing Document its duties hereunder and thereunder, upon advice of
counsel selected by it.

          10.6  Indemnification.  To the extent the Administrative Agent is not
                ---------------
reimbursed and indemnified by the Borrower, each Lender will reimburse and
indemnify the Administrative Agent, in proportion to its respective Loan, for
and against any and all liabilities, obligations, losses, damages, penalties,
claims, actions, judgments, suits, costs, expenses or disbursements of
whatsoever kind or nature which may be imposed on, asserted against or incurred
by the Administrative Agent in performing its duties hereunder or under any
other Financing Document, or in any way relating to or arising out of this
Agreement or any other Financing Document; provided, however, that no Lender
shall be liable for any portion of such liabilities, obligations,

                                      -59-
<PAGE>

losses, damages, penalties, actions, judgments, suits, costs, expenses or
disbursements resulting from the Administrative Agent's gross negligence or
willful misconduct.

          10.7   The Administrative Agent in its Individual Capacity.  With
                 ---------------------------------------------------
respect to its obligation to make Loans under this Agreement, and with respect
to any Loan held by it or made by it, the Administrative Agent shall have the
rights and powers specified herein for a "Lender" and may exercise the same
rights and powers as though it were not performing the duties specified herein;
and the term "Lender," "Required Waiver Lenders", "Required Acceleration
Lenders", "holder of Note" or any similar terms shall, unless the context
clearly otherwise indicates, include the Administrative Agent in its individual
capacity. The Administrative Agent may accept deposits from, lend money to, and
generally engage in any kind of banking, trust or other business with the
Borrower or any Affiliate of the Borrower as if it were not performing the
duties specified herein, and may accept fees and other consideration from the
Borrower for services in connection with this Agreement and otherwise without
having to account for the same to the Lenders.

          10.8   Holders.  The Administrative Agent may deem and treat the payee
                 -------
of any Note as the owner thereof for all purposes hereof unless and until a
written notice of the assignment, transfer or endorsement thereof, as the case
may be, shall have been filed with the Administrative Agent.  Any request,
authority or consent of any Person who, at the time of making such request or
giving such authority or consent, is the holder of any Note shall be conclusive
and binding on any subsequent holder, transferee, assignee or indorsee, as the
case may be, of such Note or of any Note or Notes issued in exchange therefor.

          10.9   Resignation by the Administrative Agent.  (a)  The
                 ---------------------------------------
Administrative Agent may resign from the performance of all its functions and
duties hereunder and/or under the other Financing Documents at any time by
giving 15 Business Days' prior written notice to the Borrower and each Lender.
Such resignation shall take effect upon the appointment of a successor
Administrative Agent pursuant to clauses (b) and (c) below or as otherwise
provided below.

          (b)    Upon any such notice of resignation, the Required Waiver
Lenders shall appoint a successor Administrative Agent hereunder or thereunder
who shall be a commercial bank, trust company or other financial institution
which is a Lender and which (unless an Event of Default shall be continuing)
shall be subject to the reasonable approval of the Borrower.

          (c)    If a successor Administrative Agent shall not have been so
appointed within such 15 Business Day period, the Administrative Agent, with the
consent of the Borrower, may then appoint a successor Administrative Agent who
shall serve as Administrative Agent hereunder or thereunder until such time, if
any, as the Required Waiver Lenders appoint a successor Administrative Agent as
provided above.

          (d)    If no successor Administrative Agent has been appointed
pursuant to clause (b) or (c) above by the 20th Business Day after the date such
notice of resignation was given by the Administrative Agent, the Administrative
Agent's resignation shall become effective and the Required Waiver Lenders shall
thereafter perform all the duties of the Administrative

                                      -60-
<PAGE>

Agent hereunder and/or under any other Financing Document until such time, if
any, as the Required Waiver Lenders appoint a successor Administrative Agent as
provided above.

          10.10  The Lead Arranger, Co-Arranger and Book Manager.  None of the
                 -----------------------------------------------
Lead Arranger, the Co-Arranger and the Book Manager, in such respective
capacities, shall have any duties or responsibilities under this Agreement or
any other Financing Document, nor shall any of such Persons, in such respective
capacities, have any obligations or liabilities hereunder or under any other
Financing Document.

                  *                    *                    *

                                      -61-
<PAGE>

          IN WITNESS WHEREOF, the parties hereto have caused their duly
authorized officers to execute and deliver this Agreement as of the date first
above written.

                                 PG&E CORPORATION



                                 By:   /s/ [ILLEGIBLE]^^
                                     ------------------------------------
                                     Name:
                                     Title:
<PAGE>

                                 GENERAL ELECTRIC CAPITAL
                                  CORPORATION, as a Lender and
                                  Co-Arranger

                                 By:  /s/ Mark T Mellana
                                     ------------------------------------
                                     Name:  Mark T Mellana
                                     Title: Attorney-in-fact
<PAGE>

                                 LEHMAN COMMERCIAL PAPER INC., as
                                  a Lender and Administrative Agent

                                 By:  /s/ G. Andrew Keith
                                     ------------------------------------
                                 Name:  G. Andrew Keith
                                 Title: Authorized Signatory
<PAGE>

                                 LEHMAN BROTHERS INC., as Lead Arranger
                                  and Book Manager

                                 By:  /s/ G. Andrew Keith
                                     ------------------------------------
                                 Name:  G. Andrew Keith
                                 Title: Authorized Signatory


                                        G. Andrew Keith
                                        Senior Vice President
<PAGE>

                                                                      APPENDIX A
                                                                              to
                                                                Credit Agreement
                                                                ----------------



                   DEFINED TERMS AND RULES OF INTERPRETATION
                   -----------------------------------------

          1.   Defined Terms.
               -------------

          "Affiliate" shall mean, with respect to any Person, (a) any other
           ---------
Person that is directly or indirectly Controlled by, under common Control with
or Controls such Person; (b) any other Person owning beneficially or Controlling
five percent or more of the Voting Stock of such Person; or (c) any officer,
director or partner of such Person, except with respect to any officer or
director of the Borrower.

          "Administrative Agent" shall mean Lehman Commercial Paper Inc., acting
           --------------------
in its capacity as agent for the Lenders pursuant to the Credit Agreement, and
any successor in such capacity.

          "Applicable Margin" shall mean (a) as to the Base Rate Loan, (i)
           -----------------
during the period commencing on the Closing Date to but excluding the date
eighteen (18) months from the Closing Date, 2.50% per annum and (ii) during the
period commencing on the date eighteen (18) months from the Closing Date and
thereafter, 4.00% per annum, and (b) as to the Eurodollar Loan, (i) during the
period commencing on the Closing Date to but excluding the date eighteen (18)
months from the Closing Date, 2.50% and (ii) during the period commencing the
date eighteen (18) months from the Closing Date and thereafter, 4.00%.

          "Appraiser" shall have the meaning provided in Section 6.14 of the
           ---------
Credit Agreement.

          "Approved Appraiser" shall mean any independent nationally recognized
           ------------------
investment bank experienced in the valuation of equity interests of a company
similar to NEG, Inc. as may be reasonably proposed by the Borrower at the
request of any Lender; provided that the Borrower shall always propose at least
                       --------
two alternate investment banks.

          "Asset Sale" shall mean any sale, transfer or other disposition of any
           ----------
Property of the Borrower and any member of the NEG Group.

          "Assignee" shall have the meaning provided in Section 9.11 of the
           --------
Credit Agreement.

          "Audited Financial Statements" shall have the meaning provided in
           ----------------------------
Section 5.11 of the Credit Agreement.

          "Authorized Officer" shall mean (i) with respect to any Person that is
           ------------------
a corporation or a limited liability company, the Chairman, President, any Vice
President or Secretary of such Person and (ii) with respect to any Person that
is a partnership, the President, any Vice President or Secretary (or Assistant
Secretary) of a general partner or managing partner of such Person and
<PAGE>

                                                                      Appendix A
                                                                          Page 2

in each case whose name appears on a certificate of incumbency of such Person
delivered in accordance with the Credit Agreement, as such certificate may be
amended from time to time.

          "Bankruptcy Code" shall have the meaning provided in Section 8.1(e) of
           ---------------
the Credit Agreement.

          "Bankruptcy Law" shall mean the Bankruptcy Code and any other Law of
           --------------
any jurisdiction relating to bankruptcy, insolvency, liquidation,
reorganization, moratorium, winding-up or composition or readjustment of debts
or any similar Law.

          "Base Rate", for any day, shall mean the rate per annum equal to the
           ---------
higher of (a) the Federal Funds Rate for such day plus one-half of one percent
(.5%) and (b) the Prime Rate for such day.  Any changes in the Base Rate due to
a change in the Prime Rate or the Federal Funds Rate shall be effective on the
effective date of such change in the Prime Rate or Federal Funds Rate.

          "Base Rate Loans" shall mean the Loans or any portion thereof which
           ---------------
bears interest based upon the Base Rate.

          "Book Manager" shall mean Lehman Brothers Inc., a Delaware
           ------------
corporation.

          "Borrower" shall mean PG&E Corporation, a California corporation.
           --------

          "Borrowing" shall mean the borrowing of Loans of one Type from a
           ---------
Lender on a given date, provided that Base Rate Loans incurred pursuant to
                        --------
Section 2.7(b) shall be considered part of the related Borrowing of Eurodollar
Loans.

          "Business Day" shall mean (i) for all purposes other than as covered
           ------------
by clause (ii) below, any day except Saturday, Sunday and any day which shall be
in New York City, a legal holiday or a day on which banking institutions are
authorized or required by law or other government action to close in such city,
and (ii) with respect to all notices and determinations in connection with, and
payments of principal and interest on, any Eurodollar Loan, any day which is a
Business Day described in clause (i) above and which is also a day for trading
by and between banks in the London interbank eurodollar market.

          "Business Plan" shall mean the certified copy of the business plan of
           -------------
NEG, Inc., dated the Closing Date, as delivered to the Lenders.

          "CA Fee" shall mean the fees and expenses of the Collateral Agent set
           ------
forth in the Schedule of Fees with the Collateral Agent dated the Closing Date.

          "Capital Expenditure" shall mean, with respect to any Person, all
           -------------------
expenditures by such Person which should be capitalized in accordance with
generally accepted accounting principles, including all such expenditures with
respect to fixed or capital assets (including, without limitation, expenditures
for maintenance and repairs which should be capitalized in accordance with
generally accepted accounting principles) and the amount of Capital Lease
Obligations incurred by such Person.
<PAGE>

                                                                      Appendix A
                                                                          Page 3

          "Capital Lease Obligations" shall mean, for any Person, the
           -------------------------
obligations of such Person to pay rent or other amounts under a lease of (or
other agreement conveying the right to use) real or personal Property which
obligations are required to be classified and accounted for as a capital lease
on a balance sheet of such Person under U.S. GAAP (including Statement of
Financial Accounting Standards No. 13 of the Financial Accounting Standards
Board ("Statement No. 13")) and, for purposes of the Credit Agreement, the
amount of such obligations shall be the capitalized amount thereof, determined
in accordance with U.S. GAAP (including such Statement No. 13).

          "Capital Stock" shall mean, with respect to any Person, any and all
           -------------
shares, interests, participations and/or rights in or other equivalents (however
designated, whether voting or nonvoting, ordinary or preferred) in the equity or
capital of such Person, now or hereafter outstanding, and any and all rights,
warrants or options exchangeable for or convertible into any thereof.

          "Cash Equivalents" shall mean, as to any Person, (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
one year from the date of acquisition, (ii) time deposits and certificates of
deposit of any commercial bank having, or which is the principal banking
subsidiary of a bank holding company organized under the laws of the United
States, any State thereof or the District of Columbia having capital, surplus
and undivided profits aggregating in excess of $200,000,000, with maturities of
not more than one year from the date of acquisition by such Person, (iii)
repurchase obligations with a term of not more than 90 days for underlying
securities of the types described in clause (i) above entered into with any bank
meeting the qualifications specified in clause (ii) above, (iv) commercial paper
issued by any Person incorporated in the United States rated at least A-1 or the
equivalent thereof by Standard & Poor's or at least P-1 or the equivalent
thereof by Moody's and in each case maturing not more than one year after the
date of acquisition by such Person, and (v) investments in money market funds
substantially all of whose assets are comprised of securities of the types
described in clauses (i) through (iv) above.

          "CERCLA" shall mean the Comprehensive Environmental Response,
           ------
Compensation, and Liability Act of 1980, as the same may be amended from time to
time, 42 U.S.C. (S) 9601 et seq.
                         -- ----

          "Charter Documents" shall mean, with respect to any Person, (i) the
           -----------------
articles of incorporation or other similar organizational document of such
Person, (ii) the by-laws or other similar document of such Person, (iii) any
certificate of designation or instrument relating to the rights of preferred
shareholders or other holders of Capital Stock of such Person and (iv) any
shareholder rights agreement or other similar agreement.

          "Closing Date" shall mean the date upon which the conditions precedent
           ------------
set forth in Section 4.1 of the Credit Agreement have been satisfied (or waived
by all the Lenders).

          "Co-Arranger" shall mean General Electric Capital Corporation, a New
           -----------
York corporation.
<PAGE>

                                                                      Appendix A
                                                                          Page 4

          "Code" shall mean the Internal Revenue Code of 1986, as amended from
           ----
time to time, and the regulations promulgated and rulings issued thereunder.
Section references to the Code are to the Code as in effect at the date of the
Credit Agreement and any subsequent provisions of the Code, amendatory thereof,
supplemental thereto or substituted therefor.

          "Collateral" shall mean all Property that, in accordance with the
           ----------
terms of the Security Documents, is intended to be subject to any Lien in favor
of the Collateral Agent, for the benefit of each Lender.

          "Collateral Agent" shall mean Bankers Trust Company, acting as
           ----------------
collateral agent for the benefit of the Lenders.

          "Commitment" shall mean individually or collectively, as the context
           ----------
may require, the Tranche A Commitment or the Tranche B Commitment.

          "Commitment Fees" shall mean (i) the fee payable to the Tranche A
           ---------------
Lender pursuant to the Fee Letter and (ii) the commitment fees payable to the
Tranche B Lender pursuant to the Lehman Fee Letter.

          "Compliance" shall have the meaning provided in Section 13 of the LLC
           ----------
Agreement, attached hereto as Annex A.

          "Contingent Obligation" shall mean, as to any Person, any obligation
           ---------------------
of such Person guaranteeing or intending to guarantee any Indebtedness, leases,
dividends or other obligations ("primary obligations") of any other Person (the
"primary obligor") in any manner, whether directly or indirectly, including,
without limitation, any obligation of such Person, whether or not contingent,
(a) to purchase any such primary obligation or any property constituting direct
or indirect security therefor, (b) to advance or supply funds (i) for the
purchase or payment of any such primary obligation or (ii) to maintain working
capital or equity capital of the primary obligor or otherwise to maintain the
net worth or solvency of the primary obligor, (c) to purchase property,
securities or services primarily for the purpose of assuring the owner of any
such primary obligation of the ability of the primary obligor to make payment of
such primary obligation or (d) otherwise to assure or hold harmless the owner of
such primary obligation against loss in respect thereof.  The amount of any
Contingent Obligation shall be deemed to be an amount equal to the aggregate
current exposure pursuant to each applicable agreement net of the fair market
value of any posted collateral thereunder.

          "Control" shall mean possession, directly or indirectly, of the power
           -------
to direct or cause the direction of the management and policies of a Person,
whether through the ownership of partnership interests or voting securities, by
contract or otherwise.

          "Covered Contracts" shall have the meaning provided in Section 5.7 of
           -----------------
the Credit Agreement.

          "Covered Parties" shall have the meaning provided in Section 5.1 of
           ---------------
the Credit Agreement.
<PAGE>

                                                                      Appendix A
                                                                          Page 5

          "CPUC" shall mean the California Public Utilities Commission or its
           ----
successor.

          "Credit Agreement" shall mean the Credit Agreement, dated as of March
           ----------------
1, 2001 among the Borrower, the Lenders party thereto, General Electric Capital
Corporation, as Co-Arranger, Lehman Commercial Paper Inc., as Administrative
Agent and Lehman Brothers Inc., as Lead Arranger and Book Manager, as amended,
modified or supplemented from time to time.

          "Date Certain" shall mean the Initial Date Certain, as such date may
           ------------
be extended pursuant to Section 2.9 of the Credit Agreement.

          "Default" shall mean any event or circumstance which with notice or
           -------
lapse of time or both would become an Event of Default.

          "Dividend" shall mean, with respect to any Person, that such Person
           --------
has declared or paid a dividend, distribution or returned any equity capital to
its stockholders, partners or members or authorized or made any other
distribution, payment or delivery of property (other than common equity of such
Person) or cash to its stockholders, partners or members as such, or redeemed,
retired, purchased or otherwise acquired, directly or indirectly, for a
consideration any shares of any class of its capital stock or any partnership or
membership interests outstanding on or after the Closing Date (or any options or
warrants issued by such Person with respect to its capital stock or other equity
interests), or set aside any funds for any of the foregoing purposes, or shall
have permitted any of its Subsidiaries to purchase or otherwise acquire for a
consideration any shares of any class of the capital stock or any partnership or
membership interests of such Person outstanding on or after the Closing Date (or
any options or warrants issued by such Person with respect to its capital stock
or other equity interests).  Without limiting the foregoing, "Dividends" with
respect to any Person shall also include all payments made or required to be
made by such Person with respect to any stock appreciation rights, plans, equity
incentive or achievement plans or any similar plans or setting aside of any
funds for the foregoing purposes.

          "Disclosure Letter" shall mean the letter from the Borrower, addressed
           -----------------
to the Administrative Agent and the Lenders, dated the Closing Date, with
respect to certain disclosure of the Borrower.

          "Distribution" shall have the meaning provided in Section 13 of the
           ------------
LLC Agreement, attached hereto as Annex A.

          "Dollars" and the sign "$" shall each mean freely transferable, lawful
           -------                -
money of the United States.

          "Effective Date" shall mean March 1, 2001.
           --------------

          "Environmental Claim" shall mean, with respect to any Person, (i) any
           -------------------
notice, claim, administrative, regulatory or judicial or equitable action, suit,
Lien, judgment or demand by any other Person or (ii) any other written
communication by any Governmental Authority, in either case alleging or
asserting such Person's liability for investigatory costs, cleanup costs,
consultants' fees, governmental response costs, damages to natural resources
(including, without limitation, wetlands, wildlife, aquatic and terrestrial
species and vegetation) or other Property,
<PAGE>

                                                                      Appendix A
                                                                          Page 6

property damages, personal injuries, fines or penalties arising out of, based on
or resulting from (x) the presence, or Release into the environment, of any
Hazardous Material at any location, whether or not owned by such Person or (y)
circumstances forming the basis of any violation, or alleged violation, of any
Environmental Law or Governmental Approval issued under any Environmental Law.

          "Environmental Laws" shall mean any and all Laws, now or hereafter in
           ------------------
effect, and any judicial or administrative interpretation thereof, including any
judicial or administrative order, consent decree or judgment, relating to the
environment, human health or safety, or to emissions, discharges, releases or
threatened releases of pollutants, contaminants, chemicals, or toxic or
hazardous substances or wastes into the environment including, without
limitation, ambient air, surface water, groundwater, or land, or otherwise
relating to the manufacture, processing, distribution, use, treatment, storage,
disposal, transport, or handling of pollutants, contaminants, chemicals, or
toxic or hazardous substances or wastes.

          "Equity Infusion Agreements" shall mean the agreements identified as
           --------------------------
such on Part B of the Disclosure Letter.

          "Equity Interest" shall have the meaning provided in Section 5.10(f)
           ---------------
of the Credit Agreement.

          "ERISA" shall mean the Employee Retirement Income Security Act of
           -----
1974, as amended from time to time, and the regulations promulgated and rulings
issued thereunder.  Section references to ERISA are to ERISA, as in effect at
the date of the Credit Agreement and any subsequent provisions of ERISA,
amendatory thereof, supplemental thereto or substituted therefor.

          "ERISA Affiliate" shall mean each person (as defined in Section 3(9)
           ---------------
of ERISA) which together with the Borrower or a Subsidiary of the Borrower would
be deemed to be a "single employer" (i) within the meaning of Section
414(b),(c),(m) or (o) of the Code or (ii) as a result of the Borrower or a
Subsidiary of the Borrower being or having been a general partner of such
person.

          "Escrow Agreement" shall mean the Escrow Agreement, dated as of March
           ----------------
1, 2001, among the Borrower, the Lenders party thereto and Bankers Trust
Company, as escrow agent, setting forth the payment and account information in
connection with the Refinancing of the Indebtedness of the Borrower.

          "Eurodollar Loan" shall mean any Loan or any portion thereof which
           ---------------
bears interest based on the Eurodollar Rate.

          "Eurodollar Rate" shall mean, with respect to each Interest Period in
           ---------------
respect of a Eurodollar Loan, the rate per annum (rounded upwards, if necessary,
to the nearest 1/1000 of 1%) determined by the Administrative Agent to be equal
to the quotient obtained by dividing (a) the Eurorate for such Eurodollar Loan
for such Interest Period by (b) 1 minus the Reserve Requirement for such
Eurodollar Loan for such Interest Period.
<PAGE>

                                                                      Appendix A
                                                                          Page 7

          As used herein, "Eurorate" shall mean, with respect to each Interest
Period in respect of a Eurodollar Loan, as determined by the Administrative
Agent, the rate per annum (rounded upwards, if necessary, to the nearest 1/1000
of 1%) appearing on Telerate Page 3750 (or any successor page) as the London
interbank offered rate for deposits in Dollars at approximately 11:00 a.m.
(London time) two Business Days prior to the first day of such Interest Period
for a term comparable to such Interest Period.  If for any reason such rate is
not available, the term "Eurorate" shall mean, for any Eurodollar Loan for any
                         --------
Interest Period therefor, the rate per annum (rounded upwards, if necessary, to
the nearest 1/1000 of 1%) appearing on Reuters Screen LIBO Page as the London
interbank offered rate for deposits in Dollars at approximately 11:00 a.m.
(London time) two Business Days prior to the first day of such Interest Period
for a term comparable to such Interest Period; provided, however, if more than
                                               --------  -------
one rate is specified on Reuters Screen LIBO Page, the applicable rate shall be
the arithmetic mean of all such rates (rounded upwards, if necessary, to the
nearest 1/1000 of 1%).

          "Event of Default" shall have the meaning provided in Section 8.1 of
           ----------------
the Credit Agreement.

          "EWG" shall mean an "exempt wholesale generator" as defined under
           ---
PUHCA.

          "Existing Indebtedness Agreements" shall have the meaning provided in
           --------------------------------
Section 5.31 of the Credit Agreement.

          "Expense Sharing Agreement" shall mean each of the agreements entitled
           -------------------------
"Continuing Services Agreement" listed and marked with "*" on Schedule 5.17.

          "Extended Date Certain" shall mean each of (i) the date which is six
           ---------------------
months after the Initial Date Certain or (ii) the date which is twelve months
after the Initial Date Certain.

          "Extension Fee" shall have the meaning set forth in the Fee Letter or
           -------------
the Lehman Fee Letter.

          "Federal Funds Rate" shall mean, for any day, the rate per annum
           ------------------
(rounded upwards, if necessary, to the nearest 1/1000 of 1%) 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 Business Day
next succeeding such day; provided, that (i) if the day for which such rate is
                          --------
to be determined is not a Business Day, the Federal Funds Rate for such day
shall be such rate on such transactions on the next preceding Business Day as so
published on the next succeeding Business Day and (ii) if such rate is not so
published for any day, the Federal Funds Rate for such day shall be the average
rate charged to the Administrative Agent (in its individual capacity) on such
day on such transactions as determined by the Administrative Agent.

          "Fee Letter" shall mean the Fee Letter dated March 1, 2001 between the
           ----------
Borrower and the Tranche A Lender.

          "FERC" shall mean the Federal Energy Regulatory Commission or its
           ----
successor.
<PAGE>

                                                                      Appendix A
                                                                          Page 8

          "FI Subsidiaries" shall mean any of PG&E Energy Trading Holdings
           ---------------
Corp., a California corporation, PG&E Gas Transmission, Northwest Corporation, a
California corporation and PG&E Generating Company LLC, a Delaware limited
liability company.

          "Financing Documents" shall mean, collectively, the Credit Agreement,
           -------------------
the Note, the Fee Letter, the Lehman Fee Letter, the Escrow Agreement, the
Security Documents and the Option Agreement.

          "First Interest Period" shall have the meaning provided in Section
           ---------------------
2.5(d).

          "Foreign Pension Plan" shall mean any plan, fund (including, without
           --------------------
limitation, any superannuation fund) or other similar program established or
maintained outside the United States of America by the Borrower or any one or
more of its Subsidiaries primarily for the benefit of employees of the Borrower
or such Subsidiaries residing outside the United States of America, which plan,
fund or other similar program provides, or results in, retirement income, a
deferral of income in contemplation of retirement or payments to be made upon
termination of employment, and which plan is not subject to ERISA or the Code.

          "FPA" shall mean the Federal Power Act, as amended, and the rules and
           ---
regulations promulgated thereunder.

          "Governmental Approval" shall mean any authorization, consent,
           ---------------------
approval, license, ruling, permit, tariff, rate, certification, exemption,
filing, variance, claim, order, judgment, decree, publication, notice to,
declaration of or with, or registration by or with, any Governmental Authority.

          "Governmental Authority" shall mean any government, governmental
           ----------------------
department, commission, board, bureau, agency, regulatory authority,
instrumentality, judicial or administrative body, domestic or foreign, federal,
state or local having jurisdiction over the matter or matters in question.

          "Hazardous Material" shall mean any substance that is regulated or
           ------------------
could lead to liability under any Environmental Law, including, but not limited
to, any petroleum or petroleum product, asbestos in any form that is or could
become friable, transformers or other equipment that contain dielectric fluid
containing levels of polychlorinated biphenyls (PCB's), hazardous waste,
hazardous material, hazardous substance, toxic substance, contaminant or
pollutant, as defined or regulated as such under, any applicable Environmental
Law.

          "Hedging Agreement" means any agreement in respect of any interest
           -----------------
rate swap transaction, basis swap, forward rate transaction, commodity swap,
commodity option, equity or equity index swap, equity or equity index option,
bond option, interest rate option, foreign exchange transaction, cap
transaction, floor transaction, collar transaction, currency swap transaction,
cross-currency rate swap transaction, currency option or any other similar
transaction (including any option with respect to any of the foregoing
transactions) or any combination of the foregoing transactions entered into by
the Borrower.

          "Holder" shall have the meaning provided in the Option Agreement.
           ------
<PAGE>

                                                                      Appendix A
                                                                          Page 9

          "Holding Company Conditions" shall mean the conditions set forth by
           --------------------------
the CPUC in Decision 96-11-017 or Decision 99-04-068 and any decision of the
CPUC which imposes a requirement or condition on the Borrower affecting the
Borrower's relationship with PGE Utility.

          "HSR Act" shall mean the Hart-Scott-Rodino Antitrust Improvements Act
           -------
of 1976.

          "Indebtedness" of any Person shall mean (i) all indebtedness of such
           ------------
Person for borrowed money, (ii) the deferred purchase price of assets or
services which in accordance with U.S. GAAP would be shown on the liability side
of the balance sheet of such Person, (iii) the face amount of all letters of
credit issued for the account of such Person and, without duplication, all
drafts drawn thereunder, (iv) all Indebtedness of a second Person secured by any
Lien on any Property owned by such first Person, whether or not such
Indebtedness has been assumed, (v) all Capital Lease Obligations of such Person,
(vi) all obligations of such Person to pay a specified purchase price for goods
or services whether or not delivered or accepted, i.e., take-or-pay and similar
                                                  ----
obligations, (vii) all net obligations of such Person under Hedging Agreements
and (viii) all Contingent Obligations of such Person; provided that Indebtedness
                                                      --------
shall not include trade payables arising in the ordinary course of business so
long as such trade payables are payable within 90 days of the date the
respective goods are delivered or the respective services are rendered and are
not overdue.

          "Indemnified Liabilities" shall have the meaning provided in Section
           -----------------------
9.2(a) of the Credit Agreement.

          "Indemnified Matters" shall have the meaning provided in Section
           -------------------
9.2(b) of the Credit Agreement.

          "Indemnified Person" shall have the meaning provided in Section 9.2 of
           ------------------
the Credit Agreement.

          "Initial Date Certain" shall mean the second anniversary of the
           --------------------
Closing Date.

          "Insurance Proceeds" shall mean all amounts payable to the Borrower or
           ------------------
the Collateral Agent in respect of any insurance required to be maintained (or
caused to be maintained) by the Borrower pursuant to Section 5.9 of the Credit
Agreement (other than general liability insurance, delayed completion insurance
and business interruption insurance), regardless of whether such payments are
received from any insurer or from either EPC Contractor pursuant to the EPC
Contracts or otherwise.

          "Interest Determination Date" shall mean, with respect to any
           ---------------------------
Eurodollar Loan, the second Business Day prior to the commencement of any
Interest Period relating to such Eurodollar Loan.

          "Interest Period" shall have the meaning provided in Section 2.6 of
           ---------------
the Credit Agreement.
<PAGE>

                                                                      Appendix A
                                                                         Page 10

          "Interest Prepaid Amount" shall mean $73,500,000, which is the total
           -----------------------
amount of interest payable on the Loans based on a one-year Eurodollar Rate as
of the Closing Date discounted to present value as of the Closing Date using a
discount rate of 4.25%.

          "Investment" in any Person shall mean, without duplication: (a) the
           ----------
acquisition (whether for cash, securities, other Property, services or
otherwise) or holding of capital stock, bonds, notes, debentures, partnership or
other ownership interests or other securities of such Person, or any agreement
to make any such acquisition or to make any capital contribution to such Person;
or (b) the making of any deposit with, or advance, loan or other extension of
credit to, such Person.

          "Investments" shall have the meaning provided in Section 7.5 of the
           -----------
Credit Agreement.

          "IPO" shall mean the sale, in an initial underwritten offering,
           ---
registered under the Securities Act, of shares of NEG, Inc.'s common stock,
where after such offering, the common stock sold in such offering is traded on
the Nasdaq National Market or a national securities exchange.

          "Law" shall mean, with respect to any Person (i) any statute, law,
           ---
regulation, ordinance, rule, judgment, order, decree, permit, concession, grant,
franchise, license, agreement or other governmental restriction or any
interpretation or administration of any of the foregoing by any Governmental
Authority (including, without limitation, Governmental Approvals) applicable to
such Person and (ii) any directive, guideline, policy, requirement or any
similar form of decision of or determination by any Governmental Authority which
is binding on such Person, in each case, whether now or hereafter in effect
(including, without limitation, in each case, any Environmental Law).

          "Lead Arranger" shall mean Lehman Brothers Inc., a Delaware
           -------------
corporation.

          "Lehman Fee Letter" shall mean the Lehman Fee Letter dated March 1,
           -----------------
2001 among the Borrower, Lehman Brothers Inc. and Lehman Commercial Paper Inc.

          "Lender" shall mean, individually or collectively, as the context may
           ------
require, the Tranche A Lender or the Tranche B Lender and any Assignee thereof
pursuant to Section 9.11 of the Credit Agreement.

          "Lien" shall mean, with respect to any Property of any Person,  any
           ----
mortgage, lien, deed of trust, hypothecation, fiduciary transfer of title,
assignment by way of security, lien, pledge, charge, lease, sale and lease-back
arrangement, easement, servitude, trust arrangement, or security interest or
encumbrance of any kind in respect of such Property, or any preferential
arrangement having the practical effect of constituting a security interest with
respect to the payment of any obligation with, or from the proceeds of, any
Property of any kind (and a Person shall be deemed to own subject to a Lien any
Property that 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 Property).
<PAGE>

                                                                      Appendix A
                                                                         Page 11

          "Limited Liability Company Interest" shall have the meaning provided
           ----------------------------------
in the LLC Pledge Agreement.

          "LLC" shall mean PG&E National Energy Group, LLC, a Delaware limited
           ---
liability company.

          "LLC Agreement" shall mean the Amended and Restated Limited Liability
           -------------
Company Agreement dated as of March 1, 2001 of PG&E National Energy Group LLC.

          "LLC Interests" shall mean, as to LLC, any and all shares of the
           -------------
profits and losses of such Person, any and all rights to receive distributions
of such Person's assets, and any and all rights, benefits or privileges
pertaining to any of the foregoing, including, without limitation, voting rights
and the right to participate in management.

          "LLC Pledge Agreement" shall mean the LLC Pledge Agreement dated as of
           --------------------
March 1, 2001, among the Borrower, as pledgor, NEG, Inc., as issuer, the Lenders
and Bankers Trust Company, as pledgee, as Collateral Agent for the benefit of
the Lenders, as amended, modified or supplemented from time to time.

          "Loan" shall mean each of the Tranche A Loan and the Tranche B Loan,
           ----
and shall also mean, where the context requires, any portion of any such loan
held by a Lender or subject to a particular Interest Period or interest rate
option.

          "Losses" shall have the meaning provided in Section 9.2(b) of the
           ------
Credit Agreement.

          "Margin Stock" shall mean margin stock within the meaning of
           ------------
Regulation U and Regulation X.

          "Material Adverse Change" shall mean, with respect to any Person, a
           -----------------------
material adverse change in the condition (financial or otherwise), results of
operations, business, Properties, liabilities, management or prospects of such
Person.

          "Material Adverse Effect" shall mean a material adverse effect on (i)
           -----------------------
the condition (financial or otherwise), results of operations, business,
Properties, liabilities, management or prospects of the Borrower, (ii) the
ability of the Borrower, LLC or NEG, Inc. to timely perform any of its
obligations under any of the Financing Documents to which it is a party, (iii)
the legality, validity or enforceability of any material provision of any
Financing Document, (iv) the rights and remedies of the Collateral Agent, the
Administrative Agent, any Holder or any Lender under any of the Financing
Documents or (v) the security interests provided under the Security Documents or
the value thereof; provided that a Utility Event or defaults on Indebtedness to
                   --------
be Refinanced as of the Closing Date and other events of default described in
the SEC Filings of the Borrower since December 31, 2000 but prior to the Closing
Date, shall not constitute a Material Adverse Effect.

          "Material Agreements" shall have the meaning provided in Section
           -------------------
4.1(g)(iii) of the Credit Agreement.
<PAGE>

                                                                      Appendix A
                                                                         Page 12

          "Moody's" shall mean Moody's Investors Service, Inc.
           -------

          "NAIC" shall mean the National Association of Insurance Commissioners.
           ----

          "NEG Group" means LLC and each of its subsidiaries and each
           ----------
corporation, company or partnership in which any of the foregoing own a
Controlling equity interest.

          "NEG, Inc." shall mean PG&E National Energy Group, Inc., a Delaware
           ---------
corporation.

          "NEG Subsidiary" shall mean, as the context may require, any or all
           --------------
Subsidiaries of NEG, Inc.

          "Net Debt Proceeds" shall mean, with respect to any incurrence of
           -----------------
Indebtedness for borrowed money, the cash proceeds received by any Person (net
of any tax, underwriting discounts and commissions and reasonable costs paid by
such Person associated therewith) from the respective incurrence of such
Indebtedness for borrowed money.

          "Net Equity Proceeds" shall mean, with respect to each issuance or
           -------------------
sale of any equity by any Person or any capital contribution to such Person, the
cash proceeds received by any Person (net of any tax, underwriting discounts and
commissions and reasonable costs paid by such Person associated therewith) from
the respective sale or issuance of its equity or from the respective capital
contribution.

          "Net Insurance Proceeds" shall mean, with respect to any Recovery
           ----------------------
Event, the cash proceeds received by any Person (net of reasonable costs and
taxes paid by such Person associated therewith) in connection with such Recovery
Event.

          "Net IPO Proceeds" shall  mean, with respect to the IPO, the cash
           ----------------
proceeds received by the respective Person from such IPO (net of underwriting
discounts and commissions and other reasonable costs paid by such Person
associated therewith).

          "Net Sale Proceeds" shall mean, for any Asset Sale, the gross cash
           -----------------
proceeds (including any cash received by way of deferred payment pursuant to a
promissory note, receivable or otherwise, but only as and when received)
received by any Person from such sale of assets (net of the fees and commissions
and other reasonable costs paid by such Person associated therewith) relating to
the assets sold.

          "Note" shall have the meaning provided in Section 2.4 of the Credit
           ----
Agreement.

          "Notice of Borrowing" shall have the meaning provided in Section 2.2
           -------------------
of the Credit Agreement.

          "Obligations" shall mean, collectively, (i) all loans, advances,
           -----------
debts, liabilities, and obligations, howsoever arising, owed by the Borrower
under a Financing Document or otherwise to the Administrative Agent or any
Lender of every kind and description (whether or not evidenced by any note or
instrument and whether or not for the payment of money), direct or
<PAGE>

                                                                      Appendix A
                                                                         Page 13

indirect, absolute or contingent, due or to become due, now existing or
hereafter arising, including all interest, fees, charges, expenses, attorneys'
fees and consultants' fees chargeable to the Borrower; (ii) any and all sums
advanced by the Collateral Agent, the Administrative Agent or any Lender in
order to preserve the Collateral; and (iii) the reasonable expenses of retaking,
holding, preparing for sale or lease, selling or otherwise disposing of or
realizing on the Collateral, or of any exercise by the Collateral Agent, the
Administrative Agent or any Lender of its rights under the Security Documents,
together with reasonable attorneys' fees and court costs.

          "Officer's Certificate" shall mean an officer's certificate signed by
           ---------------------
an Authorized Officer of the Borrower.

          "Option" shall have the meaning provided in the Option Agreement.
           ------

          "Option Agreement" shall mean the Option Agreement dated as of March
           ----------------
1, 2001 among LLC, NEG, Inc., GPSF-F Inc., a Delaware corporation and LB I Group
Inc., a Delaware corporation.

          "Option Shares" shall have the meaning provided in the Option
           -------------
Agreement.

          "Payment Office" shall mean the office specified from time to time by
           --------------
the Administrative Agent as its payment office by notices to the Borrower and
the Lenders.

          "PBGC" shall mean the Pension Benefit Guaranty Corporation established
           ----
pursuant to Section 4002 of ERISA, or any successor thereto.

          "Permitted Lien" shall have the meaning provided in Section 7.1 of the
           --------------
Credit Agreement.

          "Person" shall mean any individual, corporation, limited liability
           ------
company, company, voluntary association, partnership, joint venture, trust, or
other enterprises or unincorporated organization or government (or any agency,
instrumentality or political subdivision thereof).

          "PGE Utility" shall mean Pacific Gas and Electric Company, a
           -----------
California corporation.

          "Plan" shall mean any pension plan as defined in Section 3(2) of
           ----
ERISA, which is maintained or contributed to by (or to which there is an
obligation to contribute of) the Borrower or a Subsidiary of the Borrower or an
ERISA Affiliate, and each such plan for the five-year period immediately
following the latest date on which the Borrower, or a Subsidiary of the Borrower
or an Affiliate maintained, contributed to or had an obligation to contribute to
such plan.

          "Pledged Interest" shall mean the Limited Liability Company Interests
           ----------------
pledged under the LLC Pledge Agreement.

          "Preferential Rights" shall have the meaning provided in Section
           -------------------
5.4(b) of the Credit Agreement.
<PAGE>

                                                                      Appendix A
                                                                         Page 14

          "Prime Rate" shall mean the per annum rate of interest established
           ----------
from time to time by Bankers Trust Company as its prime rate, which rate may not
be the lowest rate of interest charged by Bankers Trust Company to its
customers.

          "Process Agent" shall have the meaning provided in Section 9.16(b) of
           -------------
the Credit Agreement.

          "Property" shall mean any property or asset of any kind whatsoever,
           --------
whether real, personal or mixed and whether tangible or intangible, and any
right or interest therein.

          "PUHCA" shall mean the Public Utility Holding Company Act of 1935, as
           -----
amended, and rules and regulations promulgated thereunder.

          "QF" shall mean a "qualifying cogeneration facility" or a "qualifying
           --
small power production facility" as defined under the Public Utility Regulatory
Policies Act of 1978, as amended.

          "Quarterly Dates" shall mean the last Business Day of each of March,
           ---------------
June, September and December.

          "Real Estate" shall mean, with respect to any Person, all real estate
           -----------
assets, real property interests, including all easements, rights of way, feehold
interests, leasehold interests and any options with respect to any of the
foregoing, owned by such Person.

          "Recovery Event" shall mean the receipt by any Person of any cash
           --------------
insurance proceeds or condemnation awards payable (i) by reason of theft, loss,
physical destruction, damage, taking or any other similar event with respect to
any Property or assets of such Person or (ii) under any policy of insurance,
except in the case of the Borrower, excluding such proceeds or awards
attributable to PGE Utility or any Subsidiary of PGE Utility.

          "Refinance" or "Refinancing" shall mean the refinancing of the
           ---------      -----------
Indebtedness of the Borrower as set forth on Part A of the Disclosure Letter in
accordance with the requirements of Section 4.1(s) of the Credit Agreement.

          "Register" shall have the meaning provided in Section 9.11(e) of the
           --------
Credit Agreement.

          "Regulation D" shall mean Regulation D of the Board of Governors of
           ------------
the Federal Reserve system (or any successor).

          "Regulation U" shall mean Regulation U of the Board of Governors of
           ------------
the Federal Reserve system (or any successor).

          "Regulation X" shall mean Regulation X of the Board of Governors of
           ------------
the Federal Reserve system (or any successor).
<PAGE>

                                                                      Appendix A
                                                                         Page 15

          "Release" shall mean any spilling, leaking, pumping, pouring,
           -------
emitting, emptying, discharging, injecting, escaping, leaching, dumping, or
disposing into the environment (including the abandonment or discarding of
barrels, containers, and other closed receptacles containing any Hazardous
Material, but excluding (i) emissions from the engine exhaust of a motor vehicle
and (ii) the normal application of fertilizer).

          "Reportable Event" shall mean an event described in Section 4043(c) of
           ----------------
ERISA with respect to a Plan that is subject to Title IV of ERISA other than
those events as to which the 30-day notice period is waived under subsection
 .22, .23, .25, .27 or .28 of PBGC Regulation Section 4043.

          "Required Acceleration Lenders" shall mean, at any time, the holders
           -----------------------------
of at least 66 2/3% in principal amount of the Loans then outstanding.

          "Required FMV Ratio" shall have the meaning provided in Section 6.14
           ------------------
of the Credit Agreement.

          "Required Waiver Lenders" shall mean, at any time, at least two
           -----------------------
Lenders which (a) are not Affiliates of each other and (b) together hold, in the
aggregate, more than 66 2/3% in principal amount of the Loans then outstanding.

          "Reserve Requirement" shall mean, at any time, the maximum rate at
           -------------------
which reserves (including, without limitation, any marginal, special,
supplemental, or emergency reserves) are required to be maintained under
regulations issued from time to time by the Board of Governors of the Federal
Reserve System (or any successor) by member banks of the Federal Reserve System
against "Eurocurrency liabilities" (as such term is used in Regulation D).
Without limiting the effect of the foregoing, the Reserve Requirement shall
reflect any other reserves required to be maintained by such member banks with
respect to (i) any category of liabilities which includes deposits by reference
to which the Eurodollar Rate is to be determined, or (ii) any category of
extensions of credit or other assets which include Eurodollar Loans.  The
Eurodollar Rate shall be adjusted automatically on and as of the effective date
of any change in the Reserve Requirement.

          "Return" shall have the meaning provided in Section 5.12 of the Credit
           ------
Agreement.

          "Scheduled Project" shall have the meaning provided in Section 5.23 of
           -----------------
the Credit Agreement.

          "SEC" shall mean the Securities and Exchange Commission.
           ---

          "SEC Filings" shall mean the filings listed on Schedule 4.1(k).
           -----------

          "Securities Act" shall mean the Securities Act of 1933, as amended,
           --------------
and the rules and regulations promulgated by the SEC thereunder.

          "Security Documents" shall mean, collectively, the LLC Pledge
           ------------------
Agreement, the Stock Pledge Agreement and all Uniform Commercial Code financing
statements and other
<PAGE>

                                                                      Appendix A
                                                                         Page 16

filings, recordings or regulations required by the Credit Agreement or the LLC
Pledge Agreement or the Stock Pledge Agreement to be filed or made in respect of
any such Security Document.

          "Selected Interest Amount" shall have the meaning provided in Section
           ------------------------
2.6(b).

          "Selected Interest Period" shall have the meaning provided in Section
           ------------------------
2.6(b).

          "Significant Subsidiaries" shall mean any of PG&E Gas Transmission,
           ------------------------
Northwest Corporation, a California corporation, PG&E Energy Trading Holdings
Corporation, a California corporation, PG&E Generating Company, LLC, a Delaware
limited liability company and USGen New England, Inc., a Delaware corporation.

          "Source" of a Lender shall mean the source from which such Lender is
           ------
obtaining funds in connection with the funding or maintenance of its Eurodollar
Loan.

          "Specified Rated Indebtedness" shall mean any long-term unsecured
           ----------------------------
Indebtedness for borrowed money which (a) has a credit rating of no less than
BBB- by Standard & Poor's or Baa3 by Moody's, and (b) a maturity date no earlier
than the Date Certain and (c) such Indebtedness may not be accelerated or
prepaid prior to a repayment and satisfaction in full of all Obligations of the
Borrower under the Credit Agreement and the other Financing Documents.

          "Specified Subsidiaries" shall mean any of GTN Holdings LLC, a
           ----------------------
Delaware limited liability company and PG&E Energy Trading Holdings, LLC, a
Delaware limited liability company.

          "Spin-Off" of NEG, Inc. shall mean a spin-off, divestiture,
           --------
reorganization or other form of  restructuring that results in NEG, Inc. no
longer being a Subsidiary of LLC or the Borrower.

          "Standard & Poor's" shall mean Standard & Poor's Ratings Services, a
           -----------------
division of The McGraw-Hill Companies, Inc.

          "Stock Pledge Agreement" shall mean the Stock Pledge Agreement dated
           ----------------------
as of March 1, 2001, among the Borrower, the Lenders party thereto and Bankers
Trust Company, as pledgee, as Collateral Agent for the Lenders, as amended,
modified or supplemented from time to time.

          "Subsidiary" shall mean, for any Person, any corporation, partnership
           ----------
or other entity of which at least a majority of the securities or other
ownership interests having by the terms thereof ordinary voting power to elect a
majority of the board of directors or other persons performing similar functions
of such corporation, partnership or other entity (irrespective of whether or not
at the time securities or other ownership interests of any other class or
classes of such corporation, partnership or other entity shall have or might
have voting power by reason of the happening of any contingency) is at the time
directly or indirectly owned or controlled by such Person or one or more
Subsidiaries of such Person or by such Person and one or more Subsidiaries of
such Person.
<PAGE>

                                                                      Appendix A
                                                                         Page 17

          "Tax" shall have the meaning provided in Section 3.4 of the Credit
           ---
Agreement.

          "Trading Contracts" shall mean the agreements identified as such on
           -----------------
Part A of the Disclosure Letter.

          "Trading Counterparties" shall mean parties to the Trading Contracts
           ----------------------
identified as such on Part B of the Disclosure Letter.

          "Tranche A Commitment" shall mean $600,000,000.
           --------------------

          "Tranche A Lender" shall mean General Electric Capital Corporation, a
           ----------------
New York corporation.

          "Tranche A Loan" shall mean the Loan provided by the Tranche A Lender
           --------------
on the Closing Date.

          "Tranche B Commitment" shall mean $400,000,000.
           --------------------

          "Tranche B Lender" shall mean Lehman Commercial Paper Inc., a New York
           ----------------
corporation.

          "Tranche B Loan" shall mean the Loan provided by the Tranche B Lender
           --------------
on the Closing Date.

          "Type" shall mean the type of Loan determined with regard to the
           ----
interest option applicable thereto, i.e., whether a Base Rate Loan or a
Eurodollar Loan.

          "U.S. GAAP" shall mean generally accepted accounting principles and
           ---------
practices as in effect from time to time in the United States.

          "Unaudited Financial Statements" shall have the meaning provided in
           ------------------------------
Section 5.11 of the Credit Agreement.

          "Unfunded Current Liability" of any Plan shall mean the amount, if
           --------------------------
any, by which the value of the accumulated plan benefits under the Plan
determined on a plan termination basis in accordance with actuarial assumptions
at such time consistent with those prescribed by the PBGC for purposes of
Section 4044 of ERISA, exceeds the fair market value of all plan assets
allocable to such liabilities under Title IV of ERISA (excluding any accrued but
unpaid contributions).

          "United States" and "U.S." shall each mean the United States of
           -------------       ----
America.

          "Utility Event" shall mean any event, fact or circumstance which
           -------------
relates solely to and affects solely PGE Utility (including any voluntary filing
for bankruptcy or dissolution concerning PGE Utility or its Subsidiaries under
the Bankruptcy Code).

          "Utility Regulation" means any law, regulation or rule of the Federal
           ------------------
government, any state, or any agency or political subdivision of the foregoing
which is applicable to an entity
<PAGE>

                                                                      Appendix A
                                                                         Page 18

by virtue of (i) such entity's ownership or operation of assets used for the
generation, transmission, distribution or sale of electric energy, (ii) such
entity's transportation of natural or manufactured gas, gasoline, oil, or
similar fuels, steam, chilled water or other products resulting in regulation
similar to that imposed on the foregoing, (iii) such entity's engaging in the
sale or provision of electric energy, natural gas or similar fuels, steam,
water, chilled water, or telephone or other public utility services; provided
                                                                     --------
that, such term shall not include laws, regulations or rules of general
applicability with respect to protection of the environment, hazardous waste, or
public health or safety.

          "Voting Stock", with respect to any Person, shall mean Capital Stock
           ------------
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 a contingency.

          2.   Rules of Interpretation.  In each Financing Document, unless
               -----------------------
otherwise indicated:

          (a)  each reference to, and the definition of, any document (including
     any Financing Document) shall be deemed to refer to such document as it may
     be amended, supplemented, revised or modified from time to time in
     accordance with its terms and, to the extent applicable, the terms of the
     Credit Agreement;

          (b)  each reference to a Law or Governmental Approval shall be deemed
     to refer to such Law or Governmental Approval as the same may be amended,
     supplemented or otherwise modified from time to time;

          (c)  any reference to a Person in any capacity includes a reference to
     its permitted successors and assigns in such capacity and, in the case of
     any Governmental Authority, any Person succeeding to any of its functions
     and capacities;

          (d)  references to days shall refer to calendar days unless Business
     Days are specified; references to weeks, months or years shall be to
     calendar weeks, months or years, respectively;

          (e)  all references to a "Section," "Appendix," "Annex," "Schedule" or
     "Exhibit" are to a Section of such Financing Document or to an Appendix,
     Annex, Schedule or Exhibit attached thereto;

          (f)  the table of contents and Section headings and other captions
     therein are for the purpose of reference only and do not affect the
     interpretation of such Financing Document;

          (g)  defined terms in the singular shall include the plural and vice
     versa, and the masculine, feminine or neuter gender shall include all
     genders;
<PAGE>

                                                                      Appendix A
                                                                         Page 19

          (h)  the words "hereof", "herein" and "hereunder", and words of
     similar import, when used in any Financing Document, shall refer to such
     Financing Document as a whole and not to any particular provision of such
     Financing Document;

          (i)  the words "include," "includes" and "including" are deemed to be
     followed by the phrase "without limitation";

          (j)  where the terms of any Financing Document require that the
     approval, opinion, consent or other input of any Secured Party be obtained,
     such requirement shall be deemed satisfied only where the requisite
     approval, opinion, consent or other input is given by or on behalf of the
     relevant party in writing;

          (k)  where the terms of any Financing Document require or permit any
     action to be taken by the Collateral Agent, such action shall be taken
     strictly in accordance with the applicable provisions of the relevant
     Financing Documents;

          (l)  whenever the phrase "material compliance" is used, it shall be
     interpreted to mean that either the entity is in full compliance with the
     requirement or that any failure of the entity to be in compliance in all
     respects with the requirement could not reasonably be expected alone or
     together will all other such failures and all of the facts and
     circumstances to have a Material Adverse Effect; and

          (m)  all reference to "knowledge" of a Person shall mean the knowledge
     or actual awareness of such Person of the subject matter in question after
     due inquiry and investigation and "knowledge" of the Borrower shall mean
     and include knowledge of the other Covered Parties.
<PAGE>

                                                                       EXHIBIT A
                                                                       ---------

                          FORM OF NOTICE OF BORROWING

                                                                          [DATE]

[Address of Administrative Agent/Lender]
 --------------------------------------

          Attention:  __________________________

Gentlemen:

          The undersigned, PG&E Corporation, refers to the Credit Agreement,
dated as of March __, 2001 (as amended from time to time, the "Credit
Agreement," the terms defined therein being used herein as therein defined),
among the undersigned, the Lenders, [and you, as Administrative Agent for the
Lenders,] and hereby gives you notice, irrevocably, pursuant to Section 2.2 of
the Credit Agreement, that the undersigned hereby requests a Borrowing under the
Credit Agreement, and in that connection sets forth below the information
relating to such Borrowing (the "Proposed Borrowing") as required by Section 2.2
of the Credit Agreement:

          (i)    The Business Day of the Proposed Borrowing is March __, 2001.

          (ii)   The aggregate principal amount of the Proposed Borrowing is
[________].

          (iii)  The Proposed Borrowing is to consist of a Eurodollar Loan.

          (iv)   The initial Interest Period for the Proposed Borrowing is
[_________].

          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 Section 5 of
the Credit Agreement are correct, before and after giving effect to the Proposed
Borrowing and to the application of the proceeds thereof, as though made on and
as of such date; and

          (B)    no Default or Event of Default has occurred and is continuing,
or would result from such Proposed Borrowing or from the application of the
proceeds thereof.

                              Very truly yours,

                              PG&E Corporation

                              By_____________________________
                                 Title:
<PAGE>

                                                                       EXHIBIT B
                                                                       ---------



                                 FORM OF NOTE

                    THIS NOTE MAY NOT BE ASSIGNED EXCEPT IN
             ACCORDANCE WITH SECTION 9.11 OF THE CREDIT AGREEMENT

 $ _____________                                              New York, New York
                                                                  March __, 2001

          FOR VALUE RECEIVED, PG&E CORPORATION, a corporation organized and
existing under the laws of California (the "Borrower"), hereby promises to pay
to the order of [_____________________] (the "Lender") or its registered
assigns, in lawful money of the United States of America in immediately
available funds, at the Payment Office (as defined in the Agreement described
below) on the earlier of (a) the date of a Spin-Off of NEG, Inc. and (b) the
Date Certain, the principal sum of __________________ United States dollars or,
if less, the unpaid principal amount of all Loans (as defined in the Agreement)
made by the Lender pursuant to the Agreement.

          The Borrower promises also to pay interest on the unpaid principal
amount of the Loans in like money at said office from the date such Loans are
made until paid at the rates and at the times provided in the Agreement.

          This Note is one of the Notes referred to in the Credit Agreement,
dated as of March [__], 2001, among the Borrower, the Lenders party thereto,
General Electric Capital Corporation, as Co-Arranger, Lehman Commercial Paper
Inc., as Administrative Agent and Lehman Brothers Inc., as Lead Arranger and
Book Manager (as amended and as from time to time in effect, the "Agreement")
and is entitled to the benefits thereof. Capitalized terms used herein and not
defined shall have the meanings set forth in Appendix A to the Agreement. This
Note is secured by the Security Documents (as defined in the Agreement). As
provided in the Agreement, this Note is subject to voluntary and mandatory
prepayment, in whole or in part.

          In case an Event of Default (as defined in the Agreement) shall occur
and be continuing, the principal of and accrued interest on this Note may be
declared to be due and payable in the manner and with the effect provided in the
Agreement.

          The Borrower hereby waives presentment, demand, protest or notice of
any kind in connection with this Note.
<PAGE>

          THIS NOTE SHALL BE CONSTRUED IN ACCORDANCE WITH AND BE GOVERNED BY THE
LAW OF THE STATE OF NEW YORK.

                              PG&E Corporation

                              By_____________________________
                                Name:
                                Title:

                                     (ii)
<PAGE>

                                                                       EXHIBIT C
                                                                       ---------



                        Section 3.4(b)(ii) Certificate
                        ------------------------------

          Reference is hereby made to the Credit Agreement, dated as of March 1,
2001, among PG&E Corporation, a California corporation, as the Borrower, General
Electric Capital Corporation, a New York corporation, as a Lender and Co-
Arranger, Lehman Commercial Paper Inc., as a Lender and Administrative Agent and
Lehman Brothers Inc., as Lead Arranger and Book Manager (the "Credit
Agreement"). Pursuant to the provisions of Section 3.4(b)(ii) of the Credit
Agreement, the undersigned hereby certifies that it is not a "bank" as such term
is used in Section 881(c)(3)(A) of the Internal Revenue Code of 1986, as
amended.

                                    [NAME OF LENDER]

                                    By__________________________________
                                      Name:
                                      Title:
<PAGE>

                                                                       EXHIBIT D
                                                                       ---------

CT CORPORATION SYSTEM



                                                                   March 1, 2001

PG&E Corporation
One Market
Spear Street Tower, Suite 2400
San Francisco, CA 94105
Attention: Vice President and Corporate Secretary

PG&E National Energy Group, LLC
One Market
Spear Street Tower, Suite 2400
San Francisco, CA 94105
Attention: Secretary

PG&E National Energy Group, Inc.
One Market
Spear Street Tower, Suite 2400
San Francisco, CA 94105
Attention: Secretary

General Electric Capital Corporation
120 Long Ridge Road
Stamford, CT 06927

Lehman Commercial Paper Inc.
Three World Financial Center
200 Vesey Street
New York, NY 10285

Lehman Brothers Inc.
Three World Financial Center
200 Vesey Street
New York, NY 10285

Ladies and Gentlemen:

          Reference is made to the Credit Agreement, dated as of March 1, 2001
(the "Credit Agreement"), among PG&E Corporation, a California ("PG&E Corp."),
General Electric Capital Corporation, Lehman Commercial Paper Inc. and Lehman
Brothers Inc. Unless otherwise defined herein, terms defined in the Credit
Agreement are used herein as therein defined.

          Pursuant to Section 9.16(b) of the Credit Agreement and the other
Financing Documents, PG&E Corp., PG&E National Energy Group, LLC and PG&E
National Energy Group, Inc. have appointed CT Corporation System (with an office
on the date hereof at 111 Eighth Avenue, New York, New York 10011, U.S.A.) as
their agent in their name, place and stead to accept process on their behalf of
all writs, process and summonses in any action, suit or proceeding brought in
the State of New York arising out of or relating to the Credit Agreement, any
other Financing Documents or the transactions contemplated thereby.

     1350 Treat Boulevard, Suite 100
     Walnut Creek, CA 94596
     Tel. 800 874 5258
     Fax 925 287 9801


     A CCH LEGAL INFORMATION SERVICES COMPANY
<PAGE>

CT CORPORATION SYSTEM

          The undersigned hereby accepts each such appointment as agent and
agrees with you that (a) the undersigned will maintain an office in New York
City until such time as a successor agent shall be appointed by irrevocable
powers of attorney in form and substance acceptable to you and your counsel, and
such successor agent shall have delivered a letter to you accepting its
appointment, (b) the undersigned will perform its duties as agent in accordance
with the Credit Agreement and this letter, and (c) the undersigned will forward
forthwith copies of any writs, process or summonses which the undersigned
receives in connection with its appointment as agent to PG&E Corp., PG&E
National Energy Group, LLC and PG&E National Energy Group, Inc. at the following
addresses (or at such other address of which PG&E Corp., PG&E National Energy
Group, LLC and PG&E National Energy Group, Inc. shall hereafter notify us):

          PG&E Corporation
          One Market
          Spear Street Tower, Suite 2400
          San Francisco, CA 94105
          Attention: Leslie H. Everett, Vice President
                       and Corporate Secretary
          Fax: (415) 267-7260
          Phone: (415) 267-7010

          PG&E National Energy Group, LLC
          One Market
          Spear Street Tower, Suite 2400
          San Francisco, CA 94105
          Attention: Leslie H. Everett, Secretary
          Fax: (415) 267-7260
          Phone: (415) 267-7010

          PG&E National Energy Group, Inc.
          One Market
          Spear Street Tower, Suite 2400
          San Francisco, CA 94105
          Attention: Leslie H. Everett, Secretary
          Fax: (415) 267-7260
          Phone: (415) 267-7010

          This acceptance and agreement shall be binding upon the undersigned
and all successors of the undersigned.

                                        Very truly yours,

                                        CT CORPORATION SYSTEM

                                        By:  /s/ Naseem A. Conde
                                             -------------------------------
                                             Name:   Naseem A. Conde
                                             Title:  Special Asst. Secy.



     1350 Treat Boulevard, Suite 100
     Walnut Creek, CA 94596
     Tel. 800 874 5258
     Fax 925 287 9801
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.6
<SEQUENCE>8
<FILENAME>dex106.txt
<DESCRIPTION>LETTER REGARDING COMP. AGREEMENT - T. KING
<TEXT>

<PAGE>

                                                                  EXHIBIT 10.6

November 4, 1998


Mr. Thomas B. King



Dear Tom:

On behalf of PG&E Corporation, I am pleased to extend an invitation to you to
join our organization as President and COO - PG&E Gas Transmission and Sr. Vice
President PG&E Corporation, reporting to me.  We are unanimous in our view that
you are the right candidate for this position.  As we discussed, this position
would be physically located in our Houston office.

Below are the details of the compensation and benefit aspects of this offer.  It
you have any questions on compensation, please contact Brent Stanley at (415)
267-7136.  Your initial and 1999 target annual cash compensation is calculated
to be approximately $540,500.  You will also receive a one-time signing bonus of
$200,000.  In addition, you will participate in several short and long term
incentive plans and other plans, also described below.

1.   An annual base salary of $350,000 ($29,167 monthly) subject to possible
increases through our annual salary review plan.

2.   One-time bonus of $200,000 payable within 30 days of your hire, subject to
normal payroll withholdings, Should you decide to leave PG&E Corporation within
one year of your start date, a prorated amount of this bonus must be refunded to
the company.

3.   A target annual bonus of $175,000, which equals 50% of your base salary, in
an annual incentive plan under which your actual bonus dollars can reach from 0
to $350,000 based on your performance relative to established goals.

4.   An award of 10,000 performance units under our Performance Units Plan
(PUP), effective in December 1998.  The value of these units is tied to the
price of PG&E Corporation common stock.  The estimated target value of this
award is $333,000 based on a value of $33.00 per share.  In addition, you will
be awarded 11,000 performance units under the plan in January 1999 with an
estimated target value of $363,000 based on a value of $33.00 per share.

5.   Providing you meet general business goals for 1999 and 2000, the
Corporation will credit to your deferred compensation account, an amount equal
to $2,000,000 payable in two equal annual installments on January 1, 2000 and
January 1, 2001.  Should you terminate prior to the payment of an installment,
that installment as well as any remaining installment will be forfeited.  The
credited funds will be allocated to the PG&E Phantom Stock Fund.  Payment of
credited funds will occur in accordance with your selected payout option.

6.   A stock option grant of 50,000 shares of PG&E Corporation common stock.  In
addition, you will be granted an additional 100,000 stock options effective the
first business day of 1999.  The 50,000 options will be in effect and
<PAGE>

priced as of the day you are elected by the Board of Directors to your new
position. The remaining 100,000 options will be effective and priced on the
first business day of 1999.

7.   An annual perquisite allowance of $15,500.

8.   Participation in our health and welfare benefit plans.

9.   4 weeks of paid vacation per year.

10.  Executive relocation assistance package.

As we have discussed, a number of these compensation elements, as well as
election as an officer of PG&E Corporation, are subject to Board of Directors
approval.

Tom, I believe this position is a unique career opportunity.  PG&E Corporation
has the vision, the team, the resources, and the plan to be the premier energy
company in America.  We have the opportunity for great success and we all would
like you on our team.  I am interested in having you on board as soon as
possible.  We can mutually agree on a start date, which I hope would be no later
than December first.

Brent Stanley will be most helpful to you on any details of this offer, however,
I am ready and willing to discuss any aspect of it with you.

Sincerely



ROBERT D. GLYNN, JR.
Chairman, Chief Executive Officer and President


Accepted:

THOMAS B. KING
-------------------------

November 4, 1998
-------------------------
Date
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.7
<SEQUENCE>9
<FILENAME>dex107.txt
<DESCRIPTION>LETTER REGARDING COMP. AGREEMENT - L. MADDOX
<TEXT>

<PAGE>

                                                                  EXHIBIT 10.7


April 25, 1997

Mr. Lyn Maddox



Dear Lyn:

On behalf of PG&E Corporation, I am pleased to modify our previous offer for
you to join our organization as President and Chief Executive Officer of PG&E
Energy Trading and as Senior Vice President of PG&E Corporation reporting to me.

It is my understanding that these details are consistent with those described to
you by G. Brent Stanley and will form the basis for your acceptance of this
offer.

Your initial target annual total compensation plus a one-time signing bonus of
$50,000 is calculated to be approximately $935,000.  Listed below are
compensation and benefit details:

1.   An annual base salary of $300,000 ($25,000 monthly) subject to possible
increases through our merit review plan.

2.   One time bonus of $50,000 payable within 30 days of your hire, subject to
normal payroll withholdings.

3.   A target annual bonus of $135,000, which equals 45% of your base salary, in
an annual incentive plan under which your actual bonus dollars can reach from 0
to $270,000 based on your performance relative to established goals.  For 1997,
this bonus will be not less than $135,000.

4.   Annual award of 5,000 performance units under our Performance Units Plan
(PUP).  The value of these units is tied to the price of PG&E Corporation common
stock.  The estimated value of this award is $100,000 based on a value of $20
per share.

5.   A stock option grant of 120,000 shares of PG&E Corporation common stock.
The estimated value of this award is $333,600 based on a present value $2.78 per
share.

6.   An annual perquisite allowance of $15,500.

7.   Participation in our health and welfare benefit plans.

8.   Four weeks of paid vacation per year.

As we have discussed, a number of these compensation elements, as well as
election as an officer of PG&E Corporation, are subject to Board of Directors
approval.
<PAGE>

We are enthused that you are planning to join our team and working with us for
the success of PG&E Corporation.

I would appreciate receiving your written acceptance of this offer as soon as
possible.

Please call me at the office or at home (510) 933-9369 at any time.

Sincerely,

ROBERT D. GLYNN, JR.


Accepted:

L E MADDOX
--------------------

4/26/97
--------------------
Date
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.9
<SEQUENCE>10
<FILENAME>dex109.txt
<DESCRIPTION>DESCRIPTION OF RELOCATION ARRANGEMENT - L. MADDOX
<TEXT>

<PAGE>

                                                                  EXHIBIT 10.9

                         Description of Relocation Plan
                  Between PG&E Corporation and Lyn E. Maddox

Position:  Senior Vice President of PG&E Corporation and President and COO -
PG&E Energy Trading effective August 16, 2000.

1.   A moving allowance equal to one month's pay.

2.   Reimbursement for travel expenses incurred in finding a principal
residence, without a limitation on the number of trips required.  Mr. Maddox
will be reimbursed for the reasonable cost of temporary housing, which, subject
to the prior approval of the CEO of PG&E Corporation, can be extended beyond the
period provided under the plan.

3.   Reimbursement of all closing costs incurred in the sale of Mr. Maddox's
existing residence and the purchase of a new residence.  The relocation plan
also will indemnify him for any loss that he may suffer on the sale of his
existing residence.

4.   The plan will provide for the reimbursement of any tuition loss which Mr.
Maddox incurs as a result of his children changing schools, including enrollment
and application fees, testing, and school travel costs incurred in placing his
children in comparable schools in the Bethesda area.

5.   Mr. Maddox will be provided with a temporary mortgage buy-down of $3,500
per month, payable for four years, commencing with the first mortgage payment
for his new residence.  Should he voluntarily resign from employment with PG&E
Corporation or one of its subsidiaries or affiliates prior to December 31, 2004,
he will be required to repay all amounts provided to him under the temporary
mortgage buy-down.

Mr. Maddox's target bonus is 50 percent of his base pay of $400,000 with a
potential bonus of 100 percent. In addition to continuation of his current
compensation and benefit package, and in recognition of the additional expenses
associated with his relocation at PG&E Corporation's request to Bethesda, he
also will receive a one-time payment of $250,000, net of taxes, and a one-time
taxable payment of $75,000.  Should he voluntarily resign from his position and
no longer be employed by PG&E Corporation or one of its subsidiaries or
affiliates prior to December 31, 2004, he will be required to repay the gross
amount of these payments.  Inasmuch as these payments are considered to be
additional compensation, payment is conditioned on approval by PG&E
Corporation's Nominating and Compensation Committee.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10
<SEQUENCE>11
<FILENAME>dex1010.txt
<DESCRIPTION>PG&E SEO RETENTION PROGRAM
<TEXT>

<PAGE>

                                                                   EXHIBIT 10.10

                                                                PG&E Corporation
                                           Nominating and Compensation Committee
                                                               February 21, 2001



                           SENIOR EXECUTIVE RETENTION
                           --------------------------


Action Recommended
------------------

It is recommended that the Nominating and Compensation Committee approve Special
Senior Executive Retention Grants as a mechanism to retain a small group of key
executive officers.  The concept is outlined below.  Specific individual
recommendations will be presented for the Committee's approval at its meeting on
December 20, 2000.

Background
----------

We have built a very strong senior executive team.  Many of our key executives
are very attractive candidates for senior positions in other companies.  Our
goal is to retain individuals who are sought after to be CEOs or senior officers
in other companies that may have more attractive growth prospects.  Our ability
to retain these key individuals is critical to our success.  We must provide a
retention mechanism to make them less vulnerable to leaving by providing them
with a strong incentive to stay.

The eligible group excludes any key executives from the National Energy Group
(NEG) who might otherwise be eligible were it not for the Corporation's plan to
take that entity public in the near future.

The concept is a multi-year, cliff-vesting incentive award of phantom PG&E
Corporation restricted stock units.

Description
-----------

The phantom restricted stock units will provide an incentive equal three times
an eligible officer's base salary plus target short-term incentive award.
Grants will be made effective January 1, 2001, and will vest on December 31,
2004 subject to either one of the following conditions:

-    50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

-    if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.
<PAGE>

Eligible executives may elect to defer award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff vesting.  Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting.  Awards not deferred will
be paid either entirely in PG&E Corporation stock, or half in PG&E Corporation
stock and half in cash in January of the year following vesting.

Key Administrative Provisions
-----------------------------

The following provisions will apply to the early termination of an eligible
officer:

--------------------------------------------------------------------------------
            Circumstance                            Award Status
--------------------------------------------------------------------------------
          Death or disability                       Fully vested
--------------------------------------------------------------------------------
          Change in control                         Fully vested
--------------------------------------------------------------------------------
          Voluntary termination                       Forfeited
--------------------------------------------------------------------------------
          Termination for cause                       Forfeited
--------------------------------------------------------------------------------
     Involuntary termination (severed)        Full or prorated vesting at the
                                            discretion of the PG&E Corporation
                                            CEO or at the discretion of the
                                            Committee in the case of the PG&E
                                                       Corporation CEO
--------------------------------------------------------------------------------
               Retirement                      Forfeited subject to full or
                                            prorated vesting at the discretion
                                            of the PG&E Corporation CEO or at
                                            the discretion of the Committee in
                                            the case of the PG&E Corporation CEO
--------------------------------------------------------------------------------

Estimated Costs
---------------

The cost of the grants will depend on the specific amounts granted and the
actual stock price over the four-year period.  The estimated four-year cost
could range up to $15 million assuming a full payment at the current stock
price.  This cost will change over the four-year period with changes in the
stock price.

                                       2
<PAGE>

                                                                PG&E Corporation
                                           Nominating and Compensation Committee
                                                               February 21, 2001


                           SENIOR EXECUTIVE RETENTION
                           --------------------------


Action Recommended
------------------

It is recommended that the Nominating and Compensation Committee expand the
eligible officer population covered by the Senior Executive Retention program to
include additional officers of Pacific Gas and Electric Company as well as
several key officers of PG&E National Energy Group.  Specific individual
recommendations will be presented for the Committee's approval at its meeting on
February 21, 2001.

Background
----------

On December 20, 2000, the Nominating and Compensation Committee approved the
Senior Executive Retention program as a mechanism to retain a small group of key
executive officers.  The aim of the program is to provide certain key officers,
who are critical to our success and sought after by other companies, with a
retention mechanism to make them less vulnerable to leaving, by providing them
with a strong incentive to stay.

The number of shares needed to accommodate the addition of these officers to the
program will exceed the current number of authorized shares available under the
PG&E Corporation Long-Term Incentive Plan by approximately 700,000 shares.
Therefore, award payments under the program, if not deferred, will be paid
entirely in cash rather than half in cash and half in stock as provided for
under the program approved by the Committee at its meeting on December 20, 2000.

A general description of the program is attached (Attachment A).
<PAGE>

                                                                    ATTACHMENT A
                                                                    ------------

                       SENIOR EXECUTIVE RETENTION PROGRAM
                       ----------------------------------

The concept is a multi-year, cliff-vesting incentive award of phantom PG&E
Corporation restricted stock units.

Description
-----------

The incentive award will take the form of phantom restricted stock units to be
granted effective February 21, 2001, and will vest on December 31, 2004, subject
to either one of the following conditions:

-    50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004, only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

-    if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

Eligible executives may elect to defer award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff vesting.  Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting.  Awards not deferred will
be paid in cash in January of the year following vesting.

Key Administrative Provisions
-----------------------------

The following provisions will apply to the early termination of an eligible
officer:

--------------------------------------------------------------------------------
             Circumstance                               Award Status
--------------------------------------------------------------------------------
          Death or disability                           Fully vested
--------------------------------------------------------------------------------
          Change in control                             Fully vested
--------------------------------------------------------------------------------
         Voluntary termination                            Forfeited
--------------------------------------------------------------------------------
        Termination for cause                             Forfeited
--------------------------------------------------------------------------------
   Involuntary termination (severed)           Full or prorated vesting at the
                                              discretion of the PG&E Corporation
                                               CEO or at the discretion of the
                                               Committee in the case of the
                                                      PG&E Corporation CEO
--------------------------------------------------------------------------------
               Retirement                         Forfeited subject to full or
                                             prorated vesting at the discretion
                                              of the PG&E Corporation CEO or at
                                             the discretion of the Committee in
                                            the case of the PG&E Corporation CEO
--------------------------------------------------------------------------------
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.1
<SEQUENCE>12
<FILENAME>dex10101.txt
<DESCRIPTION>LETTER REGARDING RETENTION AWARD - R. D. GLYNN
<TEXT>

<PAGE>

                                                                 EXHIBIT 10.10.1

January 22, 2001

Mr. Robert D. Glynn, Jr., Chairman
CEO and President
PG&E Corporation
One Market, Spear Tower, Suite 2400
San Francisco, CA  94105

Dear Bob:

As you know, the Board of Directors recently approved a Senior Executive
Retention program for a small group of key senior officers.  You are included in
that group.  Under this program, you will receive a grant of phantom PG&E
Corporation restricted stock units granted under the PG&E Corporation Long-Term
Incentive Plan.  The amount of your grant is $6,000,000 and it translates into
615,385 units calculated at the closing price of PG&E Corporation common stock
on January 22, 2001, of $9.75 per share.

Your grant of phantom PG&E Corporation restricted stock units is effective
January 22, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting.  Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting.  Awards not deferred will
be paid either entirely in PG&E Corporation stock or half in PG&E Corporation
stock and half in cash in January of the year following vesting.

Sincerely,

BRENT G. STANLEY
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.2
<SEQUENCE>13
<FILENAME>dex10102.txt
<DESCRIPTION>LETTER REGARDING RETENTION AWARD - G. SMITH
<TEXT>

<PAGE>

                                                            EXHIBIT 10.10.2

January 22, 2001

Mr. Gordon R. Smith, President and CEO
Pacific Gas and Electric Company
77 Beale Street, M.C. B32
San Francisco, CA  94102

Dear Gordon:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you.  Under this program, you will receive a grant of phantom
PG&E Corporation restricted stock units granted under the PG&E Corporation Long-
Term Incentive Plan.  The amount of your grant is $3,500,000 and it translates
into 358,975 units calculated at the closing price of PG&E Corporation common
stock on January 22, 2001, of $9.75 per share.  An extremely small number of
individuals are included in this arrangement.  For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me or Brent
Stanley.

Your grant of phantom PG&E Corporation restricted stock units is effective
January 22, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting.  Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting.  Awards not deferred will
be paid either entirely in PG&E Corporation stock or half in PG&E Corporation
stock and half in cash in January of the year following vesting.

Gordon, I look forward to your continued strong contributions to PG&E
Corporation's success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.3
<SEQUENCE>14
<FILENAME>dex10103.txt
<DESCRIPTION>LETTER REGARDING RETENTION AWARD - P. DARBEE
<TEXT>

<PAGE>

                                                                 EXHIBIT 10.10.3

January 22, 2001

Mr. Peter A. Darbee, Sr. VP and CFO
PG&E Corporation
One Market, Spear Tower, Suite 2400
San Francisco, CA  94105

Dear Peter:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you.  Under this program, you will receive a grant of phantom
PG&E Corporation restricted stock units granted under the PG&E Corporation Long-
Term Incentive Plan.  The amount of your grant is $2,250,000 and it translates
into 230,770 units calculated at the closing price of PG&E Corporation common
stock on January 22, 2001, of $9.75 per share.  An extremely small number of
individuals are included in this arrangement.  For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me or Brent
Stanley.

Your grant of phantom PG&E Corporation restricted stock units is effective
January 22, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting.  Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting.  Awards not deferred will
be paid either entirely in PG&E Corporation stock or half in PG&E Corporation
stock and half in cash in January of the year following vesting.

Peter, I look forward to your continued strong contributions to PG&E
Corporation's success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.4
<SEQUENCE>15
<FILENAME>dex10104.txt
<DESCRIPTION>LETTER REGARDING RETENTION AWARD - G. B. STANLEY
<TEXT>

<PAGE>

                                                                 EXHIBIT 10.10.4

January 22, 2001

Bruce R. Worthington, Esq.
SVP and General Counsel
PG&E Corporation
One Market, Spear Tower, Suite 2400
San Francisco, CA  94105

Dear Bruce:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you.  Under this program, you will receive a grant of phantom
PG&E Corporation restricted stock units granted under the PG&E Corporation Long-
Term Incentive Plan.  The amount of your grant is $1,250,000 and it translates
into 128,205 units calculated at the closing price of PG&E Corporation common
stock on January 22, 2001, of $9.75 per share.  An extremely small number of
individuals are included in this arrangement.  For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me or Brent
Stanley.

Your grant of phantom PG&E Corporation restricted stock units is effective
January 22, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting.  Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting.  Awards not deferred will
be paid either entirely in PG&E Corporation stock or half in PG&E Corporation
stock and half in cash in January of the year following vesting.

Bruce, I look forward to your continued strong contributions to PG&E
Corporation's success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.5
<SEQUENCE>16
<FILENAME>dex10105.txt
<DESCRIPTION>LETTER RE: RETENTION AWARD - WORTHINGTON
<TEXT>

<PAGE>

                                                                 EXHIBIT 10.10.5

January 22, 2001

Mr. G. Brent Stanley
SVP - Human Resources
PG&E Corporation
One Market, Spear Tower, Suite 2400
San Francisco, CA  94105

Dear Brent:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you.  Under this program, you will receive a grant of phantom
PG&E Corporation restricted stock units granted under the PG&E Corporation Long-
Term Incentive Plan.  The amount of your grant is $1,250,000 and it translates
into 128,205 units calculated at the closing price of PG&E Corporation common
stock on January 22, 2001, of $9.75 per share.  An extremely small number of
individuals are included in this arrangement.  For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me.

Your grant of phantom PG&E Corporation restricted stock units is effective
January 22, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting.  Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting.  Awards not deferred will
be paid either entirely in PG&E Corporation stock or half in PG&E Corporation
stock and half in cash in January of the year following vesting.

Brent, I look forward to your continued strong contributions to PG&E
Corporation's success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.6
<SEQUENCE>17
<FILENAME>dex10106.txt
<DESCRIPTION>LETTER RE: RETENTION AWARD - D. D. RICHARD
<TEXT>

<PAGE>

                                                                 EXHIBIT 10.10.6

January 22, 2001

Mr. Daniel D. Richard Jr.
SVP - Public Affairs
PG&E Corporation
One Market, Spear Tower, Suite 2400
San Francisco, CA  94105

Dear Dan:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you.  Under this program, you will receive a grant of phantom
PG&E Corporation restricted stock units granted under the PG&E Corporation Long-
Term Incentive Plan.  The amount of your grant is $1,250,000 and it translates
into 128,205 units calculated at the closing price of PG&E Corporation common
stock on January 22, 2001, of $9.75 per share.  An extremely small number of
individuals are included in this arrangement.  For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me or Brent
Stanley.

Your grant of phantom PG&E Corporation restricted stock units is effective
January 22, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting.  Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting.  Awards not deferred will
be paid either entirely in PG&E Corporation stock or half in PG&E Corporation
stock and half in cash in January of the year following vesting.

Dan, I look forward to your continued strong contributions to PG&E Corporation's
success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.7
<SEQUENCE>18
<FILENAME>dex10107.txt
<DESCRIPTION>LETTER RE: RETENTION AWARD - J. K. RANDOLPH
<TEXT>

<PAGE>

                                                                 EXHIBIT 10.10.7


February 27, 2001

Mr. James K. Randolph, Sr. Vice President
Chief of Utility Operations
Pacific Gas and Electric Company
77 Beale Street, 32/nd/ Floor
San Francisco, CA  94105

Dear Jim:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you.  Under this program, you will receive a grant of phantom
PG&E Corporation restricted stock units granted under the PG&E Corporation Long-
Term Incentive Plan.  The amount of your grant is $1,250,000 and it translates
into 95,715 units calculated at the closing price of PG&E Corporation common
stock on February 21, 2001, of $13.06 per share.  An extremely small number of
individuals are included in this arrangement.  For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me, Brent
Stanley, or Gordon Smith.

Your grant of phantom PG&E Corporation restricted stock units is effective
February 21, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting.  Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting.  Awards not deferred will
be paid in cash in January of the year following vesting.

Jim, I look forward to your continued strong contributions to PG&E Corporation's
success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.8
<SEQUENCE>19
<FILENAME>dex10108.txt
<DESCRIPTION>LETTER RE: RETENTION AWARD - G. M. RUEGER
<TEXT>

<PAGE>

                                                            EXHIBIT 10.10.8

February 27, 2001

Mr. Gregory M. Rueger, Sr. Vice President
Generation & Chief Nuclear Officer
Pacific Gas and Electric Company
77 Beale Street, 32/nd/ Floor
San Francisco, CA 94105

Dear Greg:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you.  Under this program, you will receive a grant of phantom
PG&E Corporation restricted stock units granted under the PG&E Corporation Long-
Term Incentive Plan.  The amount of your grant is $1,250,000 and it translates
into 95,715 units calculated at the closing price of PG&E Corporation common
stock on February 21, 2001, of $13.06 per share.  An extremely small number of
individuals are included in this arrangement.  For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me, Brent
Stanley, or Gordon Smith.

Your grant of phantom PG&E Corporation restricted stock units is effective
February 21, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting.  Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting.  Awards not deferred will
be paid in cash in January of the year following vesting.

Greg, I look forward to your continued strong contributions to PG&E
Corporation's success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.9
<SEQUENCE>20
<FILENAME>dex10109.txt
<DESCRIPTION>LETTER RE: RETENTION AWARD - KENT HARVEY
<TEXT>

<PAGE>

                                                                 EXHIBIT 10.10.9

February 27, 2001

Mr. Kent Harvey, Sr. Vice President
Chief Financial Officer & Treasurer
Pacific Gas and Electric Company
77 Beale Street, 32/nd/ Floor
San Francisco, CA  94105

Dear Kent:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you. Under this program, you will receive a grant of phantom PG&E
Corporation restricted stock units granted under the PG&E Corporation Long-Term
Incentive Plan. The amount of your grant is $1,250,000 and it translates into
95,715 units calculated at the closing price of PG&E Corporation common stock on
February 21, 2001, of $13.06 per share. An extremely small number of individuals
are included in this arrangement. For this reason, it is absolutely necessary
for you to restrict any conversation on this subject to me, Brent Stanley, or
Gordon Smith.

Your grant of phantom PG&E Corporation restricted stock units is effective
February 21, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting. Awards not deferred will
be paid in cash in January of the year following vesting.

Kent, I look forward to your continued strong contributions to PG&E
Corporation's success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.10
<SEQUENCE>21
<FILENAME>dex101010.txt
<DESCRIPTION>LETTER RE: RETENTION AWARD - R. J. PETERS
<TEXT>

<PAGE>

                                                            EXHIBIT 10.10.10

February 27, 2001

Roger J. Peters, Esq.
Senior Vice President and General Counsel
Pacific Gas and Electric Company
77 Beale Street, 32/nd/ Floor
San Francisco, CA 94105

Dear Roger:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you. Under this program, you will receive a grant of phantom PG&E
Corporation restricted stock units granted under the PG&E Corporation Long-Term
Incentive Plan. The amount of your grant is $1,250,000 and it translates into
95,715 units calculated at the closing price of PG&E Corporation common stock on
February 21, 2001, of $13.06 per share. An extremely small number of individuals
are included in this arrangement. For this reason, it is absolutely necessary
for you to restrict any conversation on this subject to me, Brent Stanley, or
Gordon Smith.

Your grant of phantom PG&E Corporation restricted stock units is effective
February 21, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting. Awards not deferred will
be paid in cash in January of the year following vesting.

Roger, I look forward to your continued strong contributions to PG&E
Corporation's success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.11
<SEQUENCE>22
<FILENAME>dex101011.txt
<DESCRIPTION>LETTER RE: RETENTION AWARD - T. G. BOREN
<TEXT>

<PAGE>

                                                            EXHIBIT 10.10.11

February 27, 2001

Mr. Thomas G. Boren, Executive Vice President
President & CEO
PG&E National Energy Group
One Market, Spear Tower, Suite 2400
San Francisco, CA 94105

Dear Tom:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you. Under this program, you will receive a grant of phantom PG&E
Corporation restricted stock units granted under the PG&E Corporation Long-Term
Incentive Plan. The amount of your grant is $3,500,000 and it translates into
267,995 units calculated at the closing price of PG&E Corporation common stock
on February 21, 2001, of $13.06 per share. An extremely small number of
individuals are included in this arrangement. For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me or Brent
Stanley.

Your grant of phantom PG&E Corporation restricted stock units is effective
February 21, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting. Awards not deferred will
be paid in cash in January of the year following vesting.

If a monetizing event occurs (i.e., IPO or sale) which affects NEG, you will be
given the opportunity of exchanging your grant of phantom PG&E corporation stock
units under this program for an equity-type interest of comparable value in the
new entity.

Tom, I look forward to your continued strong contributions to PG&E Corporation's
success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.12
<SEQUENCE>23
<FILENAME>dex101012.txt
<DESCRIPTION>LETTER RE: RETENTION AWARD- LYN MADDOX
<TEXT>

<PAGE>

                                                            EXHIBIT 10.10.12

February 27, 2001

Mr. Lyn E. Maddox, Sr. Vice President
President & Chief Operating Officer
PG&E National Energy Group - Trading
7500 Old Georgetown Road
Bethesda, MD 20814-6161

Dear Lyn:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you. Under this program, you will receive a grant of phantom PG&E
Corporation restricted stock units granted under the PG&E Corporation Long-Term
Incentive Plan. The amount of your grant is $2,250,000 and it translates into
172,285 units calculated at the closing price of PG&E Corporation common stock
on February 21, 2001, of $13.06 per share. An extremely small number of
individuals are included in this arrangement. For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me, Brent
Stanley, or Tom Boren.

Your grant of phantom PG&E Corporation restricted stock units is effective
February 21, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting. Awards not deferred will
be paid in cash in January of the year following vesting.

If a monetizing event occurs (i.e., IPO or sale) which affects NEG, you will be
given the opportunity of exchanging your grant of phantom PG&E corporation stock
units under this program for an equity-type interest of comparable value in the
new entity.

Lyn, I look forward to your continued strong contributions to PG&E Corporation's
success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.13
<SEQUENCE>24
<FILENAME>dex101013.txt
<DESCRIPTION>LETTER RE: RETENTION AWARD - P. C. IRIBE
<TEXT>

<PAGE>

                                                            EXHIBIT 10.10.13

February 27, 2001

Mr. P. Chrisman Iribe, Sr. Vice President
President & Chief Operating Officer
PG&E National Energy Group - East Region
7500 Old Georgetown Road, 13/th/ Flr.
Bethesda, MD  20814-6161

Dear Chris:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you. Under this program, you will receive a grant of phantom PG&E
Corporation restricted stock units granted under the PG&E Corporation Long-Term
Incentive Plan. The amount of your grant is $2,250,000 and it translates into
172,285 units calculated at the closing price of PG&E Corporation common stock
on February 21, 2001, of $13.06 per share. An extremely small number of
individuals are included in this arrangement. For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me, Brent
Stanley, or Tom Boren.

Your grant of phantom PG&E Corporation restricted stock units is effective
February 21, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting. Awards not deferred will
be paid in cash in January of the year following vesting.

If a monetizing event occurs (i.e., IPO or sale) which affects NEG, you will be
given the opportunity of exchanging your grant of phantom PG&E corporation stock
units under this program for an equity-type interest of comparable value in the
new entity.

Chris, I look forward to your continued strong contributions to PG&E
Corporation's success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.10.14
<SEQUENCE>25
<FILENAME>dex101014.txt
<DESCRIPTION>LETTER RE: RETENTION AWARD - T. B. KING
<TEXT>

<PAGE>

                                                            EXHIBIT 10.10.14

February 27, 2001

Mr. Thomas B. King, Sr. Vice President
President & Chief Operating Officer
PG&E National Energy Group - West Region
7500 Old Georgetown Road, 13/th/ Floor
Bethesda, MD 20814-6161

Dear Tom:

You are an essential member of our senior executive team and I view your
contribution as vital to getting the Corporation through its current challenges,
achieving the Corporation's objectives, and providing strong returns to
shareholders.

The Board of Directors recently approved a Senior Executive Retention program
which includes you. Under this program, you will receive a grant of phantom PG&E
Corporation restricted stock units granted under the PG&E Corporation Long-Term
Incentive Plan. The amount of your grant is $2,250,000 and it translates into
172,285 units calculated at the closing price of PG&E Corporation common stock
on February 21, 2001, of $13.06 per share. An extremely small number of
individuals are included in this arrangement. For this reason, it is absolutely
necessary for you to restrict any conversation on this subject to me, Brent
Stanley, or Tom Boren.

Your grant of phantom PG&E Corporation restricted stock units is effective
February 21, 2001, and will vest on December 31, 2004, subject to either one of
the following conditions:

  -  50 percent will automatically vest on December 31, 2004. The remaining 50
     percent will vest on December 31, 2004 only if the Corporation's
     performance, as measured by relative Total Shareholder Return (TSR) on a
     cumulative basis over four years, is at or above the 55th percentile of its
     comparator group; or

  -  if, at the end of the third year of the grant, December 31, 2003, the
     Corporation's performance as measured by relative TSR on a cumulative
     basis, is at or above the 75th percentile of its comparator group, the
     entire grant will vest.

You may elect to defer your actual award payments under the PG&E Corporation
Supplemental Retirement Savings Plan prior to the award cliff-vesting. Such
deferrals will be made in PG&E Corporation phantom stock units on the first
business day of January of the year following vesting. Awards not deferred will
be paid in cash in January of the year following vesting.

If a monetizing event occurs (i.e., IPO or sale) which affects NEG, you will be
given the opportunity of exchanging your grant of phantom PG&E corporation stock
units under this program for an equity-type interest of comparable value in the
new entity.

Tom, I look forward to your continued strong contributions to PG&E Corporation's
success.

Sincerely,

ROBERT D. GLYNN, JR.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.11
<SEQUENCE>26
<FILENAME>dex1011.txt
<DESCRIPTION>AGMT BET PG&E CORP. & T. W. HIGH
<TEXT>

<PAGE>

                                                                   EXHIBIT 10.11

                                 AGREEMENT AND RELEASE


This Agreement and Release (hereafter "Agreement") is made and entered into by
and between THOMAS W. HIGH and PG&E CORPORATION (hereafter, PG&E Corp.)
(collectively referred to as "the parties") and sets forth the terms and
conditions of Mr. High's separation from PG&E Corp.

1.   Mr. High shall voluntarily resign from his employment with PG&E Corp. and
     from his position as SVP - Administration and External Relations of PG&E
     Corp. and as an officer and/or director of any and all subsidiary and
     affiliate companies of PG&E Corp., effective close of business April 30,
     2001.

2.   Beginning on May 1, 2001, and until the first of the month following the
     month in which Mr. High reaches age 55, PG&E Corp. shall pay to Mr. High an
     annual benefit under the Supplemental Executive Retirement Plan (SERP) of
     approximately Two Hundred and Ninety Seven Thousand, Two Hundred and Forty
     Four Dollars ($297,244.00), in equal monthly installments. Thereafter, and
     for the remainder of his life, PG&E Corp. shall pay Mr. High an annual
     benefit under the SERP of approximately Two Hundred Thirty Five Thousand,
     Five Hundred and Forty Six Dollars ($235,546.00), payable in equal monthly
     installments, which amount shall be in addition to any benefits to which
     Mr. High is otherwise entitled under the terms of the Retirement Plan for
     Employees of Pacific Gas and Electric Company. The benefits described in
     this paragraph are in the form of a single life annuity, and Mr. High shall
     be entitled to make any elections with respect to survivor benefits,
     payment options, or such other optional forms of benefits as are provided
     for in the SERP, consistent with the actuarial factors used by the SERP
     plan administrator.

3.   PG&E Corp. shall provide Mr. High executive career counseling and/or
     placement services from the firm of Spherion Corporation or, at his
     selection, another firm providing such services under contract with PG&E
     Corp.  If Mr. High becomes reemployed during the one year following the
     effective date of this Agreement, PG&E Corp.'s obligation to provide the
     service specified in this paragraph shall terminate at the time such
     employment commences.

4.   Effective May 1, 2001, all unvested performance unit grants, stock option
     grants, and special incentive stock ownership premiums provided to Mr. High
     under PG&E Corporation's Performance Unit Plan, Stock Option Plan, and
     Executive Stock Ownership Program shall vest under the provisions governing
     termination by reason of retirement contained in each respective plan or
     program.  The payment, exercise, and withdrawal of Mr. High's vested
     performance units, stock option grants, and stock ownership premiums shall
     be as provided under the terms of their respective plans or program.  Mr.
     High shall be considered to be a retired employee for purposes of the
     Postretirement Life Insurance Plan of Pacific Gas and Electric Company and
     shall be entitled to make any elections thereunder as provided to retired
     officers.

5.   PG&E Corp. shall provide to Mr. High legal representation and
     indemnification protection in any legal proceeding in which he is a party
     or is threatened to be made a party by reason of the fact that he
<PAGE>

     is or was a PG&E Corp. employee or officer, in accordance with the terms of
     the resolution of the Board of Directors of PG&E Corp. dated December 18,
     1996.

6.   Except as provided in paragraph 5 of this Agreement, in consideration of
     the payment and benefits PG&E Corp. is providing under this Agreement, Mr.
     High on behalf of himself and his representatives, agents, heirs and
     assigns, waives, releases, discharges and promises never to assert any and
     all claims, liabilities or obligations of every kind and nature, whether
     known or unknown, suspected or unsuspected that he ever had, now has or
     might have as of the effective date of this Agreement against PG&E Corp.,
     its predecessors, subsidiaries, related entities, officers, directors,
     shareholders, owners, agents, attorneys, employees, successors, or assigns.
     The released claims include, without limitation, any claims arising from or
     related to Mr. High's employment with PG&E Corp., his resignation from his
     position as an officer and/or director of PG&E Corp. or any of its
     subsidiaries or affiliate companies, the separation of his employment with
     PG&E Corp., or any of its subsidiaries or affiliate companies, and/or any
     of the conditions, events, transactions or series of transactions related
     thereto, and the execution of this Agreement.  The released claims also
     specifically include, without limitation, any claims arising under any
     federal, state and local statutory or common law, such as Title VII of the
     Civil Rights Act, the federal Age Discrimination in Employment Act, the
     California Fair Employment and Housing Act, the Americans With Disabilities
     Act, the Employee Retirement Income Security Act, the Fair Labor Standards
     Act, the California Labor Code (all as amended), the law of contract and
     tort, and any claim for attorneys' fees.  Mr. High further agrees that his
     violation of this paragraph shall constitute a material breach of this
     Agreement.

7.   Mr. High acknowledges that there may exist facts or claims in addition to
     or different from those which are now known or believed by him to exist.
     Nonetheless, except as provided for in paragraph 5 of this Agreement, Mr.
     High understands, intends, and agrees that this Agreement extends to all
     claims of every nature and kind whatsoever, whether known or unknown,
     suspected or unsuspected, past or present, and he specifically waives all
     rights under Section 1542 of the California Civil Code which provides that:

          A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES
          NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE
          RELEASE, WHICH IF KNOWN TO HIM MUST HAVE MATERIALLY AFFECTED HIS
          SETTLEMENT WITH THE DEBTOR.

     Mr. High further agrees that his violation of this paragraph shall
     constitute a material breach of this Agreement.

8.   Mr. High agrees that he will not initiate, maintain, or accept the benefits
     from any legal action or proceeding of any kind against PG&E Corp. or any
     of its predecessors, subsidiaries, related entities, officers, directors,
     shareholders, owners, agents, attorneys, employees, successors, or assigns
     as to any matter released in this Agreement, nor shall he assist or
     participate in any such proceedings, including any proceedings brought by
     any third parties, except as required by court order or law or to enforce
     this Agreement.  Mr. High further agrees that his violation of this
     paragraph shall constitute a material breach of this Agreement.

                                      -2-
<PAGE>

9.   Mr. High shall not seek any future re-employment with PG&E Corp.  This
     paragraph does not, however, preclude Mr. High from accepting an offer of
     future employment from PG&E Corp.

10.  Mr. High shall not disclose, publicize, or circulate to anyone in whole or
     in part, any information concerning the terms and/or conditions of this
     Agreement without the express written consent of the Chief Legal Officer of
     PG&E Corp. unless required by court order or law. Notwithstanding the
     preceding sentence, Mr. High may disclose the terms and conditions of this
     Agreement to his immediate family members, and any attorneys or tax
     advisors, if any, to whom there is a bona fide need for disclosure in order
     for them to render professional services to his, provided that Mr. High
     first instructs each affected family member, attorney, and tax advisor that
     he must keep the information confidential and may not make any disclosure
     of the terms and conditions of this Agreement, unless required by court
     order or law. Mr. High further agrees that his violation of this paragraph
     shall constitute a material breach of this Agreement.

11.  Mr. High agrees not to use, disclose, publicize, or circulate any
     confidential or proprietary information concerning PG&E Corp., its
     subsidiaries, or its affiliates, which has come to his attention during his
     employment with PG&E Corp., unless his doing so is expressly authorized in
     writing by the Chief Legal Officer of PG&E Corp., or is required by court
     order or law.  Before making any legally-required disclosure, Mr. High
     shall give PG&E Corp. notice at least ten (10) business days in advance.
     Mr. High further agrees that his violation of this paragraph shall
     constitute a material breach of this Agreement.

12.  Mr. High agrees not to engage in any unfair competition against PG&E Corp.
     For purposes of this Agreement, unfair competition shall be accorded the
     definition developed under the laws of the State of California, including
     section 17200, et seq., of the California Business and Professions Code.
     Mr. High agrees that his violation of this paragraph shall constitute a
     material breach of this Agreement.

13.  (a)  For a period of one year after the effective date of this Agreement as
          set forth in paragraph 17 below, Mr. High shall not, directly or
          indirectly, solicit or contact for the purpose of diverting or taking
          away or attempt to solicit or contact for the purpose of diverting or
          taking away any prospective customer of PG&E Corp. or its affiliates
          or subsidiaries about whom he acquired information as a result of any
          solicitation efforts by PG&E Corp., its subsidiaries, or affiliates,
          or the prospective customer during his employment with PG&E Corp. Mr.
          High further agrees that his violation of this paragraph shall
          constitute a material breach of this Agreement.

     (b)  For a period of one year after the effective date of this Agreement as
          set forth in paragraph 17 below, Mr. High shall not, directly or
          indirectly, solicit or contact for the purpose of diverting or taking
          away or attempt to solicit or contact for the purpose of diverting or
          taking away any existing customer of PG&E Corp. or its affiliates or
          subsidiaries.  Mr. High further agrees that his violation of this
          paragraph shall constitute a material breach of this Agreement.

     (c)  For a period of one year after the effective date of this Agreement as
          set forth in paragraph 17 below, Mr. High shall not, directly or
          indirectly, solicit or contact for the purpose of

                                      -3-
<PAGE>

          diverting or taking away or attempt to solicit or contact for the
          purpose of diverting or taking away any existing vendor of PG&E Corp.
          or its affiliates or subsidiaries. Mr. High further agrees that his
          violation of this paragraph shall constitute a material breach of this
          Agreement.

     (d)  For a period of one year after the effective date of this Agreement as
          set forth in paragraph 17 below, Mr. High shall not, directly or
          indirectly, solicit or contact for the purpose of diverting or taking
          away or attempt to solicit or contact for the purpose of diverting or
          taking away any prospective vendor of PG&E Corp. or its affiliates or
          subsidiaries, about whom he acquired information as a result of any
          solicitation efforts by PG&E Corp. or its affiliates or subsidiaries
          or the prospective vendor during his employment with PG&E Corp. Mr.
          High further agrees that his violation of this paragraph shall
          constitute a material breach of this Agreement.

     (e)  For a period of one year after the effective date of this Agreement as
          set forth in paragraph 17 below, Mr. High shall not, directly or
          indirectly, solicit, contact or induce, or attempt to solicit, contact
          or induce, any existing employees, agents or consultants of PG&E
          Corp., or of any of its subsidiaries or affiliates, to terminate or
          otherwise alter their employment, agency or consultant relationship
          with PG&E Corp. or any of its subsidiaries or affiliates. Mr. High
          further agrees that his violation of this paragraph shall constitute a
          material breach of this Agreement.

     (f)  For a period of one year after the effective date of this Agreement as
          set forth in paragraph 17 below, Mr. High shall not, directly or
          indirectly, solicit, contact or induce, any existing employees, agents
          or consultants of PG&E Corp., or of any of its subsidiaries or
          affiliates, to work in any capacity for or on behalf of any person,
          company or other business enterprise that is in competition with PG&E
          Corp. or any of its subsidiaries or affiliates. Mr. High further
          agrees that his violation of this paragraph shall constitute a
          material breach of this Agreement.

14.  Mr. High shall, upon reasonable notice from PG&E Corp., furnish information
     and proper assistance to PG&E Corp. (including truthful testimony and
     document production) as may reasonably be required by PG&E Corp. in
     connection with any legal, administrative or regulatory proceeding in which
     it or any of its subsidiaries or affiliates is, or may become, a party, or
     in connection with any filing or similar obligation of PG&E Corp. imposed
     by any taxing, administrative or regulatory authority having jurisdiction.
     Mr. High further agrees that his violation of this paragraph shall
     constitute a material breach of this Agreement.

15.  (a)  In the event that Mr. High breaches any material provision of this
          Agreement, PG&E Corp. shall have no further obligation to pay or
          provide to Mr. High any unpaid amounts or benefits specified in this
          Agreement. PG&E Corp. shall also be entitled to immediate return of
          any and all amounts or benefits previously paid or provided to Mr.
          High under this Agreement and to recalculate any future pension
          benefit entitlement without the additional credited service and/or age
          he received or would have received under this Agreement. Despite any
          breach by Mr. High his other duties and obligations under this
          Agreement, including his waivers and

                                      -4-
<PAGE>

          releases, shall remain in full force and effect. In the event of a
          breach or threatened breach by Mr. High of any of the provisions in
          paragraphs 6-8 and 10-14 of this Agreement, PG&E Corp. shall, in
          addition to any other remedies provided in this Agreement, be entitled
          to equitable and/or injunctive relief and, because the damages for
          such a breach or threatened breach will be difficult to determine and
          will not provide a full and adequate remedy, PG&E Corp. shall also be
          entitled to specific performance by Mr. High of his obligations under
          paragraphs 6-8 and 10-14 of this Agreement. Pursuant to paragraph 20
          herein, Mr. High shall also be liable for any litigation costs and
          expenses PG&E Corp. incurs in successfully seeking enforcement of its
          rights under this Agreement, including reasonable attorney's fees.

     (b)  Mr. High shall be entitled to recover actual damages in the event of
          any material breach of this Agreement by PG&E Corp., including any
          unexcused late or non-payment of any amounts owed under this
          Agreement, or any unexcused failure to provide any other benefits
          specified in this Agreement.  In the event of a breach or threatened
          breach by PG&E Corp. of any of its material obligations to Mr. High
          under this Agreement, Mr. High shall be entitled to seek, in addition
          to any other remedies provided in this Agreement, specific performance
          of PG&E Corp.'s obligations and any other applicable equitable or
          injunctive relief.  Pursuant to paragraph 20 herein, PG&E Corp. shall
          also be liable for any litigation costs and expenses Mr. High incurs
          in successfully seeking enforcement of his rights under this
          Agreement, including reasonable attorney's fees.  Despite any breach
          by PG&E Corp., its other duties and obligations under this Agreement
          shall remain in full force and effect.

16.  Mr. High acknowledges and agrees that this Agreement is not, and shall not
     be considered, an admission of liability or of a violation of any
     applicable contract, law, rule, regulation, or order of any kind.

17.  Pursuant to the Older Workers Benefit Protection Act, Mr. High acknowledges
     that he was provided up to 21 days to consider and accept the terms of this
     Agreement and that he was advised to consult with an attorney about the
     Agreement before signing it.
     Mr. High also understands that, after he signs the Agreement, he will have
     an additional seven (7) days in which to revoke his acceptance in writing,
     that to revoke, he must submit a signed statement to that effect to PG&E
     Corp.'s Senior Human Resources Officer before the close of business on the
     seventh day, and that, if he does not submit such a revocation, the
     Agreement will take effect on the eighth day after he signs it.

18.  This Agreement sets forth the entire agreement between the parties
     pertaining to the subject matter of this Agreement and fully supersedes any
     prior or contemporaneous negotiations, representations, agreements, or
     understandings between the parties with respect to any such matters,
     whether written or oral (including any that would have provided Mr. High
     any different severance arrangements). The parties acknowledge that they
     have not relied on any promise, representation or warranty, express or
     implied, not contained in this Agreement. Parol evidence will be
     inadmissible to show agreement by and among the parties to any term or
     condition contrary to or in addition to the terms and conditions contained
     in this Agreement.

19.  If any provision of this Agreement is determined to be invalid, void, or

                                      -5-
<PAGE>

     unenforceable, the remaining provisions shall remain in full force and
     effect except that, should paragraphs 6-8 and 10-14 be held invalid, void
     or unenforceable, either jointly or separately, PG&E Corp. shall be
     entitled to rescind the Agreement and/or recover from Mr. High any payments
     made and benefits provided to his under this Agreement.  Mr. High
     understands and agrees that before initiating any action to set aside all
     or any part of this Agreement, a mandatory condition precedent is his prior
     tender back to PG&E Corp. of the amounts of any payments previously made or
     benefits provided to his under this Agreement, including without
     limitation, any increased pension benefits he gained as a result of any
     additional credited service and/or age he received under this Agreement.

20.  With the exception of any request for specific performance, injunctive or
     other equitable relief, any dispute or controversy of any kind arising out
     of or related to this Agreement, Mr. High's employment with PG&E Corp. (or
     with the employing subsidiary), the separation thereof and from his
     positions as an officer and/or director of PG&E Corp. or any subsidiary or
     affiliate, or any claims for benefits shall be resolved exclusively by
     final and binding arbitration using a three member arbitration panel in
     accordance with the Commercial Arbitration Rules of the American
     Arbitration Association then in effect. Provided, however, that in making
     their determination, the arbitrators shall be limited to accepting the
     position of Mr. High or the position of PG&E Corp., as the case may be. The
     only claims not covered by this paragraph 20 are any non-waivable claims
     for benefits under workers' compensation or unemployment insurance laws,
     which will be resolved under those laws. Any arbitration pursuant to this
     paragraph 20 shall take place in San Francisco, California. Parties may be
     represented by legal counsel at the arbitration but must bear their own
     fees for such representation. The prevailing party in any dispute or
     controversy covered by this paragraph 20, or with respect to any request
     for specific performance, injunctive or other equitable relief, shall be
     entitled to recover, in addition to any other available remedies specified
     in this Agreement, all litigation expenses and costs, including any
     arbitrator, administrative or filing fees and reasonable attorneys' fees.
     Both Mr. High and PG&E Corp. specifically waive any right to a jury trial
     on any dispute or controversy covered by this paragraph 20. Judgment may be
     entered on the arbitrators' award in any court of competent jurisdiction.
     Subject to the arbitration provisions herein, the sole jurisdiction and
     venue for any action related to the subject matter of this Agreement shall
     be the California state and federal courts having within their jurisdiction
     the location of PG&E Corp.'s principal place of business in California at
     the time of such action. Both parties consent to the jurisdiction of such
     courts for any such action.

21.  This Agreement shall be governed by and construed under the laws of the
     United States and, to the extent not preempted by such laws, by the laws of
     the State of California, without regard to the conflicts of laws provisions
     thereof.

22.  The failure of either party to exercise or enforce, at any time, or for any
     period of time, any of the provisions of this Agreement shall not be
     construed as a waiver of such provision, or any portion thereof, and shall
     in no way affect that party's right to exercise or enforce such provisions.
     No waiver or default of any provision of this Agreement shall be deemed to
     be a waiver of any succeeding breach of the same or any other provisions of
     this Agreement.

                                      -6-
<PAGE>

23.  Mr. High acknowledges and agrees that he has read and understands the
     contents of this Agreement, that he has been afforded the opportunity to
     carefully review this Agreement with an attorney of his choice, that he has
     not relied on any oral or written representation not contained in this
     Agreement, that he has signed it knowingly and voluntarily, and that after
     this Agreement becomes effective he will be bound by all of its provisions.

     PLEASE READ CAREFULLY. THIS AGREEMENT INCLUDES A RELEASE OF ALL KNOWN AND
     UNKNOWN CLAIMS.


   THOMAS W. HIGH                            BRENT G. STANLEY
----------------------------------      ---------------------------------
   THOMAS W. HIGH                            PG&E CORPORATION


  December 8, 2000                           December 8, 2000
----------------------------------      ---------------------------------
         DATE                                       DATE

                                      -7-
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.14
<SEQUENCE>27
<FILENAME>dex1014.txt
<DESCRIPTION>DESCRIPTION OF STIP FOR OFFICERS OF PG&E CORP.
<TEXT>

<PAGE>

--------------------------------------------------------------------------------
                                                                   EXHIBIT 10.14

                                 CONFIDENTIAL



          ___________________________________________________________

                            2001 OFFICER SHORT-TERM
                           INCENTIVE PLAN FINANCIAL
                              PERFORMANCE MEASURE
          ___________________________________________________________


                          Nominating and Compensation
                      Committee of the Board of Directors


                               December 20, 2000


                                                         [LOGO] PG&E Corporation
                                                                ----------------
--------------------------------------------------------------------------------
<PAGE>

2001 Officer STIP Financial Performance Measure
================================================================================

                                  Background


Short-Term Incentive Plan Structure
-----------------------------------

 .    At its meeting on September 20, 2000, the Nominating and Compensation
     Committee reviewed and approved the 2001 STIP structure for officers of the
     Corporation and each subsidiary. The structure (see Appendix A) established
     the weighting of corporate EPS, subsidiary EPS, and other performance
     factors for officers. The structure requires an implementing methodology to
     link the EPS performance levels to threshold, minimum, and maximum
     incentive payout levels, which is contained in this document.
<PAGE>

2001 Officer STIP Financial Performance Measure                      Appendix B
================================================================================



                   2001 Short-Term Incentive Plan Structure

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
           Officer Group                      Award Component             Weight                   Performance Measures
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>                                 <C>       <C>
PG&E Corporation                     Corporate Financial Performance         100%  Corporate EPS from operations
-----------------------------------------------------------------------------------------------------------------------------------
President & CEO - PG&E               Corporate Financial Performance          50%  Corporate EPS from operations
National Energy Group                Subsidiary Performance                   50%  Respective subsidiary contribution to corporate
President & CEO - Pacific Gas and                                                  EPS from operations
Electric Company
-----------------------------------------------------------------------------------------------------------------------------------
Pacific Gas and Electric Co.         Corporate Financial Performance          25%  Corporate EPS from operations
PG&E National Energy Group           Subsidiary Financial Performance    50 - 75%  Respective subsidiary contribution to corporate
Pacific Venture Capital, LLC                                                       EPS from operations
PG&E Telecom, LLC                    Subsidiary Operational Performance   0 - 25%  Financial, operating, and service measures
                                                                                   determined by Subsidiary CEO

-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.20
<SEQUENCE>28
<FILENAME>dex1020.txt
<DESCRIPTION>PG&E CORP. EXECUTIVE STOCK OWNERSHIP PROGRAM
<TEXT>

<PAGE>

                                                                   EXHIBIT 10.20

                               PG&E CORPORATION
                       EXECUTIVE STOCK OWNERSHIP PROGRAM

                           Administrative Guidelines
                           -------------------------
                        (As amended September 19, 2000)

1.   Description. The Executive Stock Ownership Program ("Program") was approved
     -----------
     by the Nominating and Compensation Committee of the Board of Directors on
     October 15, 1997. The Program is an important element of the Committee's
     compensation policy of aligning executive interests with those of the
     Corporation's shareholders. As an integral part of the Program, the
     Committee also authorized the use of Special Incentive Stock Ownership
     Premiums ("SISOPs") which are designed to provide incentives to Eligible
     Executives to assist in achieving minimum stock ownership targets
     established by the Committee. These Guidelines were originally adopted by
     the Committee on November 19, 1997, amended by the Committee on July 22,
     1998, October 21, 1998, February 16, 2000, and September 19, 2000. These
     amended Guidelines, along with the written materials provided to the
     Committee on October 15, 1997, describe the Program which became effective
     on January 1, 1998. The Program is administered by the Corporation's Senior
     Human Resources Officer.

2.   Eligible Executives.  The Chief Executive Officer shall designate the
     -------------------
     officers of the Corporation and its affiliates who shall be Eligible
     Executives covered by the Program. The officers covered by the Guidelines
     and the applicable total stock ownership target ("Target") are:


     ---------------------------------------------------------------------------
       Officer Band                Position                    Total Stock
                                                             Ownership Target
     ---------------------------------------------------------------------------

            1                        CEO                       3 x base salary
     ---------------------------------------------------------------------------
            2               Heads of Business Lines,           2 x base salary
                            CFO, & General Counsel
     ---------------------------------------------------------------------------
            3               SVPs of Corp. & Utility            1.5 x base salary
     ---------------------------------------------------------------------------

3.   Annual Milestones.   Under the Guidelines, Targets are designed to be
     -----------------
     achieved by the end of the fifth calendar year following the calendar year
     in which an officer first becomes an Eligible Executive ("Target Date").
     Annual Milestones have been established as a means of measuring progress
     towards achieving Targets and of providing incentives for Eligible
     Executives to expeditiously meet their Targets. The Annual Milestone at the
     end of the first full calendar year is 20 percent of the Target, and the
     Annual Milestone for each succeeding year is an additional 20 percent of
     the Target. Annual Milestones shall be adjusted to reflect changes in base
     salary; provided, however, that in each instance any such modification
     shall be amortized over the remaining original five-year term. Following
     the Target Date, Targets also shall be modified to reflect changes in base
     salary.
<PAGE>

4.   Calculation of Stock Ownership Levels. Stock ownership level is the dollar
     -------------------------------------
     value of stock and stock equivalents owned by an Eligible Executive and
     calculated as of the last day of the calendar year ("Measurement Date").
     The purpose of this calculation is to determine the value of the stock or
     stock equivalents owned by the Eligible Executive as compared with the
     Annual Milestone or Target for that executive. For purposes of this
     calculation, the value per share of stock or stock equivalent ("Measurement
     Value") is the average closing price of PG&E Corporation common stock as
     traded on the New York Stock Exchange for the last thirty (30) trading days
     of the year.

     a)   The value of stock beneficially owned by the Eligible Executive is
          determined by multiplying the number of shares owned beneficially on
          the Measurement Date times the Measurement Value.

     b)   The value of PG&E Corporation phantom stock units credited to the
          Eligible Executive's account in the PG&E Corporation Supplemental
          Retirement Savings Plan ("SRSP") is determined by multiplying the
          number of phantom stock units credited to the Eligible Executive's
          SRSP account on the Measurement Date times the Measurement Value.

     c)   The value of stock held in the PG&E Corporation stock fund of any
          defined contribution plan maintained by PG&E Corporation or any of its
          subsidiaries is determined by multiplying the number of shares in such
          plan on the Measurement Date times the Measurement Value.

     d)   For Eligible Executive's whose Target Date is on or before 12/31/2004,
          the value of the frozen share-equivalent units of the vested "in the
          money" stock options as of 12/31/2000. The value of the frozen share-
          equivalent units of the vested "in the money" stock options is the
          difference between the number of options on 12/31/2000 multiplied by
          the Measurement Value on 12/31/2000 minus the number of options on
          12/31/2000 multiplied by the option exercise price (for purposes of
          this calculation, any value attributable to dividend equivalents is
          excluded).

5.   Award of SISOPs. SISOPs are awarded to Eligible Executives who achieve and
     ---------------
     maintain stock ownership levels prior to the end of the third year
     following the year in which an officer first became an Eligible Executive.
     For purposes of determining awards, the total stock ownership level is
     calculated as set forth under paragraph 4, on the Measurement Date. The
     amount of a SISOP award shall be equal to:

     a)   For the first year, 20 percent of the amount of the Eligible
          Executive's stock ownership level at the end of the year, up to the
          Annual Milestone, plus an additional 30 percent of the amount by which
          the stock ownership level exceeds the Annual Milestone up to the
          Target; and

     b)   For each of the second and third years, the current stock ownership
          level is reduced by the stock ownership level used to calculate
          previous SISOP awards to determine the new ownership then 20 percent
          of the amount up to the Annual Milestone by which the end of the year
          stock ownership level exceeds the beginning of the year stock
          ownership level, plus an additional 30 percent of the amount by which
          the end of the year balance exceeds the Annual Milestone, up to the
          Target.

                                       2
<PAGE>

     Each time a SISOP award calculation is made, a second calculation also is
     made to determine the minimum number of shares which must be retained by
     the Eligible Executive to avoid forfeiture of the SISOP award ("Minimum
     Ownership Level") as discussed below in paragraph 8. This calculation
     converts the dollar value of the stock ownership level used as the basis
     for qualifying for SISOPs into a number of shares of stock. It is
     calculated by dividing the stock ownership level by the Measurement Value.
     Thus, for example, if an Eligible Executive's stock ownership level was
     $250,000 and the Measurement Value was $25 per share, then the Minimum
     Ownership Level would be 10,000 shares.

     For purposes of this calculation, the maximum share ownership level used is
     the Eligible Executive's Target.  If an Eligible Executive has a share
     ownership level higher than his/her Target, the increment over the Target
     is not included.  Thus, for example, if an Eligible Executive has a Target
     of $750,000 and his/her share ownership level is $900,000, then only
     $750,000 is used to calculate the Minimum Ownership Level.

6.   SISOPs Credited to the SRSP. Upon award, SISOPs are credited to the
     ---------------------------
     Eligible Executive's SRSP account and converted into units of phantom stock
     each equal in value to a share of PG&E Corporation common stock ("SISOP
     units") as determined in accordance with the SRSP. The SISOP units
     constitute "incentive awards" authorized to be awarded by the Committee to
     Eligible Executives under the PG&E Corporation Long-Term Incentive Program
     ("LTIP"). Upon credit of SISOP units to an Eligible Executive's SRSP
     account, an equal number of shares of PG&E Corporation common stock shall
     be reserved for issuance from the pool of shares authorized for issuance
     under the LTIP. Once a SISOP unit is credited to the Eligible Executive's
     SRSP account, it shall be subject to all of the terms and conditions
     specifically applicable to SISOP units under the SRSP. Once vested in
     accordance with paragraph 7 below, SISOP units are distributed in the form
     of an equal number of shares of PG&E Corporation common stock as provided
     in the SRSP.

7.   Vesting. SISOPs vest only upon the expiration of three years after the date
     -------
     of award (provided the Eligible Executive continues to be employed on such
     date), or, if earlier, upon an Eligible Executive's death, disability,
     Retirement, upon a Change in Control, as defined in the LTIP, or upon a
     termination of employment coincident with the sale of all or substantially
     all of the assets of a subsidiary of PG&E Corporation. An Eligible
     Executive's unvested SISOPs will be forfeited upon termination of
     employment unless otherwise provided in the PG&E Corporation Officer
     Severance Policy or by another separation agreement

8.   Forfeiture of SISOP Units. So long as SISOP units remain unvested, such
     -------------------------
     units are subject to forfeiture if, on each Measurement Date, the Eligible
     Executive's stock ownership is less than the Minimum Ownership Level
     established when the SISOPs were granted (see paragraph 5). To determine
     forfeiture, the following steps are followed on each Measurement Date:

     a)   The total stock and stock equivalents owned by an Eligible Executive
          is determined as set forth under paragraph 4. This total ("Current
          Holdings") is compared with the Minimum Ownership Level determined
          when the SISOPs were granted. If the Current Holdings are equal to or
          greater than the Minimum Ownership Level, then no unvested SISOP units
          are forfeited. If the Current Holdings are less than the Minimum
          Ownership Level, then the unvested SISOP units are forfeited in the
          same proportion as the Current Holdings are less than Minimum
          Ownership Level (for

                                       3
<PAGE>

          example, if the Current Holdings are 20 percent less than the Minimum
          Ownership Level, then 20 percent of the SISOP units are forfeited).

9.   Failure to Achieve or Maintain Target. Failure to achieve stock ownership
     -------------------------------------
     levels at Target on the Target Date, or to maintain stock ownership levels
     at Target on any Measurement Date thereafter, will result in the deferral
     into the PG&E Corporation Phantom Stock Fund of the SRSP of annual awards
     from the Performance Unit Plan ("PUP") and the Short-Term Incentive Plan
     ("STIP"). As of any Measurement Date, to the extent that stock ownership
     levels are below Target, PUP awards shall be converted into PG&E
     Corporation Phantom Stock Units and held in the PG&E Corporation Phantom
     Stock Fund of the SRSP. If, with the addition of the phantom stock units
     attributable to the PUP award, the stock ownership level is still below
     Target for any Measurement Date, any STIP award above target STIP also
     shall be converted into phantom stock units, to the extent necessary to
     achieve the Target stock ownership level. Such conversion of PUP and STIP
     awards shall continue for successive Measurement Dates, if necessary, until
     Target is met. Phantom stock units attributable to PUP and STIP awards
     described in this paragraph 9 will be paid from the SRSP in a lump sum in
     January of the year following the year in which the Eligible Executive's
     employment terminates, or upon such earlier date as may have been elected
     by the Eligible Executive within thirty days after the date of mandatory
     deferral of PUP and/or STIP awards which date shall not be earlier than
     three (3) years after the date of mandatory deferral.

                                       4
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-11
<SEQUENCE>29
<FILENAME>dex11.txt
<DESCRIPTION>COMPUTATION OF EARNINGS PER COMMON SHARE
<TEXT>

<PAGE>

                                                                      EXHIBIT 11

                               PG&E CORPORATION
                   COMPUTATION OF EARNINGS PER COMMON SHARE

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------
                                            Three months ended  Twelve months ended
                                               December 31,         December 31,
                                             ----------------    ------------------
(in millions, except per share amounts)        2000     1999       2000      1999
-----------------------------------------------------------------------------------
<S>                                          <C>        <C>      <C>        <C>
BASIC EARNINGS PER SHARE (EPS)/1/

Earnings available for common stock          $(4,117)  $ (611)   $(3,364)   $  (73)
                                             =======   ======    =======    ======
Average common shares outstanding/2/             363      366        362       368
                                             =======   ======    =======    ======
Basic EPS                                    $ (1.34)  $(1.67)   $ (9.29)   $(0.20)
                                             =======   ======    =======    ======

DILUTED EARNINGS PER SHARE (EPS)/1/

Earnings available for common stock          $(4,117)  $ (611)   $(3,364)   $  (73)
                                             =======   ======    =======    ======

Average common shares outstanding                363      366        362       368
Add: outstanding options, reduced by the
 number of shares that could be
 repurchased with the proceeds from
 such exercise (at average market price)           3        -          2         1
                                             -------   ------    -------    ------

Average common shares outstanding as
 adjusted                                        366      366        364       369
                                             =======   ======    =======    ======
Diluted EPS                                  $(11.25)   (1.67)   $ (9.24)   $(0.20)
                                             =======   ======    =======    ======
-----------------------------------------------------------------------------------
</TABLE>

/1/   This presentation is submitted in accordance with Item 601(b)(11) of
      Regulation S-K and Statement of Financial Accounting Standards No. 128.

/2/   Average common shares outstanding exclude shares held by a subsidiary of
      PG&E Corporation (23,815,500 shares at December 31, 1999 and 2000,
      respectively) and shares held by the Company to secure deferred
      compensation obligations (281,985 shares at December 31, 1999 and 2000,
      respectively).
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-12.1
<SEQUENCE>30
<FILENAME>dex121.txt
<DESCRIPTION>COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<TEXT>

<PAGE>

                                                                    EXHIBIT 12.1

                        PACIFIC GAS AND ELECTRIC COMPANY
               COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                       Year ended December 31,
                                        -------------------------------------------------------
(dollars in millions)                       2000       1999        1998       1997        1996
-----------------------------------------------------------------------------------------------
<S>                                     <C>          <C>          <C>        <C>        <C>

Earnings:
 Net income (loss)                      $(3,483)     $   788     $   729     $   768    $   755
Adjustments for minority
  interests in losses of
  less than 100% owned
  affiliates and the
  Company's equity in
  undistributed losses
  (income) of less than
  50% owned affiliates                        -            -           -           -          3
Income tax expense                       (2,154)         648         629         609        555
 Net fixed charges                          648          637         673         628        683
                                        -------      -------     -------     -------    -------
    Total Earnings                      $(4,989)     $ 2,073     $ 2,031     $ 2,005    $ 1,996
                                        =======      =======     =======     =======    =======
Fixed Charges:
 Interest on long-
  term debt, net                        $   508      $   523     $   585     $   485    $   574
 Interest on short-
  term borrowings                           108           81          50         101         75
 Interest on capital leases                   2            3           2           2          3
 AFUDC debt                                   6            7          12          17          8
 Earnings required to
  cover the preferred stock
  dividend and preferred
  security distribution
  requirements of majority
  owned trust                                24           24          24          24         24
                                        -------      -------     -------     -------    -------
    Total Fixed Charges                 $   648      $   638     $   673     $   629    $   684
                                        =======      =======     =======     =======    =======
Ratios of Earnings to
 Fixed Charges                            (7.70)(1)     3.25        3.02        3.19       2.92
-----------------------------------------------------------------------------------------------
</TABLE>
Note:  For the purpose of computing Pacific Gas and Electric Company's ratios of
       earnings to fixed charges, "earnings" represent net income adjusted for
       the minority interest in losses of less than 100% owned affiliates, cash
       distributions from and equity in undistributed income or loss of Pacific
       Gas and Electric Company's less than 50% owned affiliates, income taxes
       and fixed charges (excluding capitalized interest). "Fixed charges"
       include interest on long-term debt and short-term borrowings (including a
       representative portion of rental expense), amortization of bond premium,
       discount and expense, interest of subordinated debentures held by trust,
       interest on capital leases, and earnings required to cover the preferred
       stock dividend requirements.

(1)    The ratio of earnings to fixed charges indicates a deficiency of less
       than one-to-one coverage aggregating $5,637 million.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-12.2
<SEQUENCE>31
<FILENAME>dex122.txt
<DESCRIPTION>COMPUTATION OF RATIOS OF EARNINGS - COMBINED
<TEXT>

<PAGE>


                                                                    EXHIBIT 12.2

                       PACIFIC GAS AND ELECTRIC COMPANY
       COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND
                           PREFERRED STOCK DIVIDENDS

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
                                                     Year ended December 31,
                              ------------------------------------------------------------
(dollars in millions)              2000          1999        1998         1997        1996
------------------------------------------------------------------------------------------
<S>                           <C>              <C>           <C>         <C>        <C>
Earnings:
  Net income (loss)           $  (3,483)     $    788    $    729    $     768   $     755
Adjustments for minority
    interests in losses of
    less than 100% owned
    affiliates and the
    Company's equity in
    undistributed losses
    (income) of less than
    50% owned affiliates              -             -           -            -           3
  Income tax expense             (2,154)          648         629          609         555
  Net fixed charges                 648           637         673          628         683
                              ---------      --------    --------    ---------   ---------
      Total Earnings          $  (4,989)     $  2,073    $  2,031    $   2,005   $   1,996
                              =========      ========    ========    =========   =========
Fixed Charges:
  Interest on long-
    term debt, net            $     508     $     523    $    585    $     485   $     574
  Interest on short-
    term borrowings                 108            81          50          101          75
  Interest on capital leases          2             3           2            2           3
  AFUDC debt                          6             7          12           17           8
  Earnings required to
    cover the preferred stock
    dividend and preferred
    security distribution
    requirements of majority
    owned trust                      24            24          24           24          24
                              ---------      --------    --------    ---------   ---------
      Total Fixed Charges     $     648      $    638    $    673    $     629   $     684
                              ---------      --------    --------    ---------   ---------
Preferred Stock Dividends:
  Tax deductible dividends    $       9      $      9    $      9    $      10   $      10
  Pretax earnings required
    to cover non-tax
    deductible preferred
    stock dividend
    requirements              $      27      $     27    $     31    $      39   $      39
                              ---------      --------    --------    ---------   ---------
    Total Preferred
     Stock Dividends          $      36      $     36    $     40    $      49   $      49
                              ---------      --------    --------    ---------   ---------
  Total Combined Fixed
    Charges and Preferred
    Stock Dividends           $     684      $    674    $    713    $     678   $     733
                              =========      ========    ========    =========   =========
Ratios of Earnings to
  Combined Fixed Charges and
  Preferred Stock Dividends       (7.29)(1)      3.08        2.85         2.96        2.72
---------------------------------------------------------------------------------------------
</TABLE>
Note:    For the purpose of computing Pacific Gas and Electric Company's ratios
         of earnings to combined fixed charges and preferred stock dividends,
         "earnings" represent net income adjusted for the minority interest in
         losses of less than 100% owned affiliates, cash distributions from and
         equity in undistributed income or loss of Pacific Gas and Electric
         Company's less than 50% owned affiliates, income taxes and fixed
         charges (excluding capitalized interest). "Fixed charges" include
         interest on long-term debt and short-term borrowings (including a
         representative portion of rental expense), amortization of bond
         premium, discount and expense, interest on capital leases, interest of
         subordinated debentures held by trust, and earnings required to cover
         the preferred stock dividend requirements of majority owned
         subsidiaries. "Preferred stock dividends" represent pretax earnings
         which would be required to cover such dividend requirements.

(1)      The ratio of earnings to combined fixed charges and preferred stock
         dividends indicates a deficiency of less than one-to-one coverage
         aggregating $5,673 million.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13
<SEQUENCE>32
<FILENAME>dex13.txt
<DESCRIPTION>ANNUAL REPORT TO SHAREHOLDERS OF PG&E CORP.
<TEXT>

<PAGE>

                                                                      EXHIBIT 13


                Portions of 2000 Annual Report to Shareholders


                            SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
(in millions, except per share amounts)                               2000         1999        1998        1997        1996
<S>                                                                <C>          <C>         <C>         <C>         <C>
PG&E Corporation/(1)/
For the Year
Operating revenues                                                 $26,232      $20,820     $19,577     $15,255     $ 9,610
Operating income (loss)                                             (4,807)         878       2,098       1,762       1,896
Income (Loss) from continuing operations                            (3,324)          13         771         745         722
Earnings (Loss) per common share from continuing operations,
basic and diluted                                                    (9.18)        0.04        2.02        1.82        1.75
Dividends declared per common share                                   1.20         1.20        1.20        1.20        1.77
At Year-End
Book value per common share                                        $  8.76      $ 19.13     $ 21.08     $ 21.30     $ 20.73
Common stock price per share                                         20.00        20.50       31.50       30.31       21.00
Total assets                                                        35,291       29,470      33,234      31,115      26,237
Long-term debt (excluding current portions)                          4,736        6,682       7,422       7,659       7,770
Rate reduction bonds (excluding current portions)                    1,740        2,031       2,321       2,611          --
Redeemable preferred stock and securities of subsidiaries
(excluding current portion)                                            635          635         635         750         694
Pacific Gas and Electric Company
For the Year
Operating revenues                                                 $ 9,637      $ 9,228     $ 8,924     $ 9,495     $ 9,610
Operating income (loss)                                             (5,201)       1,993       1,876       1,820       1,896
Income (Loss) available for common stock                            (3,508)         763         702         735         722
At Year-End
Total assets                                                       $21,988      $21,470     $22,950     $25,147     $26,237
Long-term debt (excluding current portion)                           3,342        4,877       5,444       6,218       7,770
Rate reduction bonds (excluding current portion)                     1,740        2,031       2,321       2,611          --
Redeemable preferred stock and securities (excluding current
portion)                                                               586          586         586         694         694
</TABLE>

(1)  PG&E Corporation became the holding company for Pacific Gas and Electric
     Company on January 1, 1997. The Selected Financial Data of PG&E Corporation
     and Pacific Gas and Electric Company (the Utility) for 1996 are identical
     because they reflect the accounts of the Utility as the predecessor of PG&E
     Corporation. Matters relating to certain data above, including the
     provision for loss on generation-related regulatory assets and
     undercollected purchased power costs, discontinued operations, and the
     cumulative effect of a change in accounting principle, are discussed in
     Management's Discussion and Analysis and in the Notes to the Consolidated
     Financial Statements.
<PAGE>

                     MANAGEMENT'S DISCUSSION AND ANALYSIS

     PG&E Corporation is an energy-based holding company headquartered in San
Francisco, California. PG&E Corporation's Northern and Central California energy
utility subsidiary, Pacific Gas and Electric Company (the Utility), delivers
electric service to approximately 4.6 million customers and natural gas service
to approximately 3.8 million customers. On April 6, 2001, the Utility filed a
voluntary petition for relief under the provisions of Chapter 11 of the U.S.
Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility
retains control of its assets and is authorized to operate its business as a
debtor in possession while being subject to the jurisdiction of the Bankruptcy
Court. The factors causing the Utility to take this action are discussed in this
Management's Discussion and Analysis (MD&A) and in Notes 2 and 3 of the Notes to
the Consolidated Financial Statements.

     PG&E Corporation's National Energy Group, Inc. (the NEG) is an integrated
energy company with a strategic focus on power generation, new power plant
development, natural gas transmission, and wholesale energy marketing and
trading in North America. The NEG businesses include its power plant development
and generation unit, PG&E Generating Company, LLC and its affiliates
(collectively, PG&E Gen); its natural gas transmission unit, PG&E Gas
Transmission Corporation (PG&E GT); and its wholesale energy and marketing
trading unit, PG&E Energy Trading Holdings Corporation, which owns PG&E Energy
Trading--Gas Corporation, and PG&E Energy Trading--Power, L.P. (collectively,
PG&E Energy Trading or PG&E ET). During 2000, the NEG sold its energy services
unit, PG&E Energy Services Corporation (PG&E ES). Also, during the fourth
quarter of 2000, the NEG sold its Texas natural gas and natural gas liquids
business carried on through PG&E Gas Transmission, Texas Corporation and PG&E
Gas Transmission Teco, Inc. and their subsidiaries (PG&E GTT). For more
information about the NEG's businesses, see "PG&E National Energy Group, Inc."
below.

     PG&E Corporation has identified five reportable operating segments. The
Utility is one reportable operating segment and the other four are part of the
NEG (PG&E Gen, PG&E Gas Transmission, Northwest Corporation (PG&E GTN), PG&E
GTT, and PG&E ET). During 2000, the NEG has been integrating these lines of
business into two lines of business: (1) an integrated power generation and
energy trading and marketing business, and (2) a natural gas transmission
business. Financial information about each reportable operating segment is
provided in this MD&A and in Note 16 of the Notes to the Consolidated Financial
Statements.

     This is a combined annual report of PG&E Corporation and the Utility. It
includes separate consolidated financial statements for each entity. The
consolidated financial statements of PG&E Corporation reflect the accounts of
PG&E Corporation, the Utility, and PG&E Corporation's wholly owned and
controlled subsidiaries. The consolidated financial statements of the Utility
reflect the accounts of the Utility and its wholly owned and controlled
subsidiaries. This MD&A should be read in conjunction with the consolidated
financial statements included herein.

     This combined annual report, including our Letter to Shareholders and this
MD&A, contains forward-looking statements about the future that are necessarily
subject to various risks and uncertainties. These statements are based on
current expectations and assumptions which management believes are reasonable
and on information currently available to management. These forward-looking
statements are identified by words such as "estimates," "expects,"
"anticipates," "plans," "believes," and other similar expressions. Actual
results could differ materially from those contemplated by the forward-looking
statements.

     Although PG&E Corporation and the Utility are not able to predict all of
the factors that may affect future results, some of the factors that could cause
future results to differ materially from those expressed or implied by the
forward-looking statements or historical results include:

     .    the reorganization plan that is ultimately adopted by the Bankruptcy
          Court;

     .    the regulatory, judicial, or legislative actions (including ballot
          initiatives) that may be taken to meet future power needs in
          California, mitigate the higher wholesale power prices, provide
          refunds for prior power costs, or address the Utility's financial
          condition;

     .    the extent to which the Utility's undercollected wholesale power
          purchase costs may be collected from customers;

     .    any changes in the amount of transition costs the Utility is allowed
          to collect from its customers, and the timing of the completion of the
          Utility's transition cost recovery;

     .    future market prices for electricity and future fuel prices, which in
          part, are influenced by future weather conditions, the availability of
          hydroelectric power, and the development of competitive markets;
<PAGE>

     .    the method and timing of valuation of the Utility's hydroelectric
          generation assets;

     .    future operating performance at the Diablo Canyon Nuclear Power Plant
          (Diablo Canyon) and the future ratemaking applicable to Diablo Canyon;

     .    legislative or regulatory changes, including the pace and extent of
          the ongoing restructuring of the electric and natural gas industries
          across the United States;

     .    future sales levels and economic conditions;

     .    the extent to which our current or planned generation development
          projects are completed and the pace and cost of such completion;

     .    generating capacity expansion and retirements by others;

     .    the outcome of the Utility's various regulatory proceedings;

     .    fluctuations in commodity gas, natural gas liquids, and electric
          prices and the ability to successfully manage such price fluctuations;

     .    the effect of compliance with existing and future environmental laws,
          regulations, and policies, the cost of which could be significant; and

     .    the outcome of pending litigation.

     As the ultimate impact of these and other factors is uncertain, these and
other factors may cause future earnings to differ materially from results or
outcomes we currently seek or expect. Each of these factors is discussed in
greater detail in this MD&A.

     In this MD&A, we first discuss the California energy crisis and its impact
on our liquidity. We then discuss statements of cash flows and financial
resources, and our results of operations for 2000, 1999, and 1998. Finally, we
discuss our competitive and regulatory environment, our risk management
activities, and various uncertainties that could affect future earnings. Our
MD&A applies to both PG&E Corporation and the Utility.

LIQUIDITY AND FINANCIAL RESOURCES



The California Energy Crisis

     The state of California is in the midst of an energy crisis. The cost of
wholesale power has risen to levels almost ten times greater than those in 1999.
Rolling blackouts have occurred as a result of a broken deregulated electricity
market. Because of this crisis, PG&E Corporation and the Utility have
experienced a significant deterioration in their liquidity and consolidated
financial position. The Utility's credit rating has deteriorated to below
investment grade level. As of March 29, 2001, the Utility is in default or has
not paid amounts due under various bank agreements, commercial paper, and
payments to the California Power Exchange (PX), the California Independent
System Operator (ISO), qualifying facilities (QFs), and energy service providers
totaling over $4 billion. In addition, PG&E Corporation and the Utility
recognized a fourth quarter charge to earnings of $6.9 billion ($4.1 billion
after tax) to reflect the fact that the Utility could no longer conclude that
its generation-related regulatory assets and undercollected purchased power
costs were probable of recovery from ratepayers. This charge resulted in
accumulated deficits at December 31, 2000, of $2.0 billion and $2.1 billion for
the Utility and PG&E Corporation, respectively.

     As more fully discussed herein, the Utility has been working with
regulators and state and federal legislators and California leaders in an effort
to seek an overall solution to the California energy crisis. However, the
ongoing uncertainty as to the timing and extent of any solution, in addition to
increasing debt and regulatory changes, caused the Utility to seek protection
from its creditors through a Chapter 11 Bankruptcy Filing. The filing for
bankruptcy protection and the related uncertainty around any reorganization
plan, that is ultimately adopted, will have a significant impact on the
Utility's future liquidity and results of operations. In addition to the $4
billion of defaults and amounts not paid mentioned
<PAGE>

above, the Utility anticipates an aggregate of approximately $1.5 billion of
additional obligations that will become due and payable in April 2001. As of
March 29, 2001, the Utility had $2.6 billion of cash available to fund
operations.

     See Notes 2 and 3 of the Notes to the Consolidated Financial Statements for
a detailed discussion of the California energy crisis and the events leading up
to the charge incurred by PG&E Corporation and the Utility. A discussion of the
current and future liquidity and financial resources, and mitigation efforts
undertaken by the Utility and PG&E Corporation follows.

Pacific Gas and Electric Company

     The California energy crisis described in Note 2 of the Notes to the
Consolidated Financial Statements has had a significant negative impact on the
liquidity and financial resources of the Utility. Beginning in June 2000, the
wholesale price of electric power in California steadily increased to an average
cost of 18.16 cents per kilowatt-hour (kWh) for the seven month period of June
2000 through December 2000, as compared to an average cost of 4.23 cents per kWh
for the same period in 1999. Under California Assemby Bill 1890 (AB 1890), the
Utility's electric rates were frozen at levels that allowed approximately 5.4
cents per kWh to be charged to the Utility's customers as reimbursement for
power costs incurred by the Utility on behalf of its retail customers. The
excess of wholesale electricity costs above the generation-related cost
component available in frozen rates resulted in an undercollection at December
31, 2000, of approximately $6.6 billion, and rose to approximately $8.9 billion
by February 28, 2001.

     The difference between the actual costs incurred to purchase power and the
amount recovered from customers was funded through a series of borrowings. In
October 2000, the Utility fully utilized its existing $1 billion revolving
credit facility to support the Utility's commercial paper program and other
liquidity requirements. On October 18, 2000, the Utility obtained an additional
$1 billion, 364-day revolving credit facility. On November 1, 2000, the Utility
issued $1 billion of short-term floating rate notes and $680 million of five-
year notes. On November 22, 2000, the Utility issued an additional $240 million
of short-term floating rate notes. On December 1, 2000, the bank group reduced
the size of the $1 billion, 364-day revolving credit facility to $850 million.
At December 31, 2000, the Utility had borrowed $614 million against its five-
year revolving credit agreement, had issued $1,225 million of commercial paper,
and had issued $1,240 million of floating rate notes.

     In late 2000, the Utility began to implement cash conservation measures
that included layoffs of 1,000 temporary workers, suspension of dividend
payments, and deferral of merit increases and incentive compensation for
employees. Also, federal and state legislators and regulators recognized that
the wholesale power market was seriously flawed and they began seeking solutions
to the California energy crisis.

     In response to the growing crisis, on January 4, 2001, the California
Public Utilities Commission (CPUC) approved an interim one-cent per kWh rate
increase, which would raise approximately $70 million in cash per month for
three months. Even if all this cash had been available to the Utility
immediately, $210 million represented approximately one week's worth of net
power purchases at the then current prices. Thus, the rate increase did not
raise enough cash for the Utility to pay its ongoing wholesale electric energy
procurement bills or make further borrowing possible.

     On January 10, 2001, the Board of Directors of the Utility suspended the
payment of its fourth quarter 2000 common stock dividend in an aggregate amount
of $110 million payable on January 15, 2001, to PG&E Corporation and PG&E
Holdings, Inc., a wholly-owned subsidiary of the Utility. In addition, the
Utility's Board of Directors decided not to declare the regular preferred stock
dividends for the three-month period ending January 31, 2001, normally payable
on February 15, 2001. Dividends on all Utility preferred stock are cumulative.
Until cumulative dividends on preferred stock are paid, the Utility may not pay
any dividends on its common stock, nor may the Utility repurchase any of its
common stock.

     On January 16 and 17, 2001, the outstanding bonds of the Utility were
downgraded to below investment grade status. Standard and Poor's (S&P) stated
that the downgrade reflected the heightened probability of the Utility's
imminent insolvency and the resulting negative financial implications for PG&E
Corporation and affiliated companies because, among other reasons, (1) some of
the Utility's principal trade creditors were demanding that sizeable cash
payments be made as a pre-condition to the purchase of natural gas and electric
power necessary for on-going business operations; (2) neither legislative nor
negotiated solutions to the California utilities' financial situation appeared
to be forthcoming in a timely manner, which continued to impede access to
financial markets for the working capital needed to avoid insolvency; and (3)
Southern California Edison's (SCE) decision to default on its obligation to pay
principal and interest due on January 16, 2001, diminished the prospects for the
Utility's access to capital markets.
<PAGE>

     This downgrade to below investment grade status was an event of default
under one of the Utility's revolving credit facilities and precluded the Utility
from access to the capital markets. As a result, the banks stopped funding under
the revolving credit facility. On January 17, 2001, the Utility began to default
on maturing commercial paper obligations. In addition, the Utility was no longer
able to meet its obligations to generators, QFs, the ISO, and PX, and began
making partial payments of amounts owed.

     The Utility's credit ratings as of March 29, 2001, are as follows:

          Corporate credit rating: D/D
          Commercial paper: D
          Senior secured debt: CCC
          Senior unsecured debt: CC
          Preferred stock: D
          Shelf senior secured/unsecured subordinated debt: CCC/CC
          Shelf debt preferred stock: D

     After the downgrade, the PX notified the Utility that the ratings downgrade
required the Utility to post collateral for all transactions in the PX day-ahead
market. Since the Utility was unable to post such collateral, the PX suspended
the Utility's trading privileges effective January 19, 2001, in the day-ahead
market. The PX also sought to liquidate the Utility's block-forward contracts
for the purchase of power. On January 25, 2001, a California Superior Court
judge granted the Utility's application for a temporary restraining order, which
thereby restrained and enjoined the PX and its agents from liquidating the
Utility's contracts in the block-forward market, pending hearing on a
preliminary injunction on February 5, 2001. Immediately before the hearing on
the preliminary injunction, California Governor Gray Davis, acting under
California's Emergency Services Act, commandeered the contracts for the benefit
of the state. Under the Act, the state must pay the Utility the reasonable value
of the contracts, although the PX may seek to recover the monies that the
Utility owes to the PX from any proceeds realized from those contracts.
Discussions and negotiations on this issue are currently ongoing between the
state and the Utility.

     On January 19, 2001, the Utility was no longer able to continue purchasing
power for its customers because of a lack of creditworthiness and the state of
California authorized the California Department of Water Resources (DWR) to
purchase electricity for the Utility's customers. Assembly Bill 1X (AB1X) was
passed on February 1, 2001, authorizing the DWR to enter into contracts for the
purchase and sale of electric power and to issue revenue bonds to finance
electricity purchases. The DWR has entered into long-term contracts with several
generators for the supply of electricity. However it continues to purchase
significant amounts of power on the spot market at prevailing market prices. The
DWR is not purchasing electricity for the Utility's entire net open position
(the amount of power that cannot be met by the Utility's own or contracted-for
generation). To the extent that the DWR is not purchasing electricity for the
entire net open position, the remainder is being procured by the ISO. To that
extent, the ISO may attempt to charge the Utility for those purchases.

     As a result of (1) the failure by the state to assume the full procurement
responsibility for the Utility's net open position, as was provided under AB1X,
(2) the negative impact of recent actions by the CPUC that created new payment
obligations for the Utility and undermined its ability to return to financial
viability, (3) a lack of progress in negotiations with the state to provide a
solution for the energy crisis, and (4) the adoption by the CPUC of an illegal
and retroactive accounting change that would appear to eliminate the Utility's
true undercollected purchased power costs, the Utility filed a voluntary
petition for relief under provisions of Chapter 11 of the U.S. Bankruptcy Code
on April 6, 2001.

     As of March 29, 2001, the Utility was in default and had not paid the
following:

<TABLE>
<CAPTION>

                                                                                            Amount
        Description                                                                   (in millions)
        -----------                                                                   ------------
        <S>                                                                         <C>
        Items not paid
        PX/ISO--real time market deliveries                                                 $1,448
        Qualifying facilities                                                                  643
        Direct access credits due to energy service providers                                  503
        Commercial paper                                                                       861
</TABLE>
<PAGE>

<TABLE>
        <S>                                                                                 <C>
        Bank loans                                                                             939*
        Other                                                                                   26

        Total Items Not Paid                                                                $4,420
        Items coming due through April 30, 2001
        PX/ISO--real time market deliveries                                                 $  550
        Qualifying facilities                                                                  340
        Gas suppliers                                                                          470
        Other                                                                                  140

        Total coming due                                                                    $1,500
        Total cash on hand at March 29, 2001                                                $2,600
</TABLE>

          *Loans that lenders have agreed to forbear through April 13, 2001.

     Additionally, the Utility may be required by the CPUC to pay the DWR for
purchases that it has made on behalf of the Utility's customers. As discussed
further in Note 2 of the Notes to the Consolidated Financial Statements, there
is a dispute over how much the Utility must pay the DWR. Also, the DWR has
indicated that it intends to purchase power only at "reasonable prices." The ISO
has continued to purchase power at prices in excess of the DWR's as yet
undisclosed ceiling and has been billing the Utility for the differential. The
Utility does not yet know what the total expected billing is for these
purchases.

     Subject to certain qualifications, the banks under the Utility's $1 billion
revolving credit agreement agreed to forbear from exercising any remedies with
respect to the Utility's default under that agreement until April 13, 2001.

     Subject to the approval by the Bankruptcy Court, the Utility's intent is to
pay its ongoing costs of doing business while seeking resolution of the
wholesale energy crisis. It is the Utility's intention to continue to pay
employees, vendors, suppliers, and other creditors to maintain essential
distribution and transmission services. However, the Utility is not in a
position to pay maturing or accelerated obligations, nor is the Utility in a
position to pay the ISO, PX, and the QFs the amounts due for the Utility's power
purchases above the amount included in rates for power purchase costs. The
Utility's current actions are intended to allow the Utility to continue to
operate while efforts to reach a regulatory or legislative solution continue.
The Utility's plans will be subject to approval of the Bankrupcy Court.

     The Utility has also deferred quarterly interest payments on the Utility's
7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until
further notice in accordance with the indenture. The corresponding quarterly
payments on the 7.90% Cumulative Quarterly Income Preferred Securities, Series
A, (QUIPS) issued by PG&E Capital I, due on April 2, 2001, have been similarly
deferred. Distributions can be deferred up to a period of five years per the
indenture. Investors will accumulate interest on the unpaid distributions at the
rate of 7.90%.

     The weakened financial condition of the Utility also has impacted its
ability to supply natural gas to its natural gas customers. In December 2000 and
January 2001, several gas suppliers demanded prepayment, cash on delivery, or
other forms of payment assurance before they would deliver gas, instead of the
normal payment terms, under which the Utility would pay for the gas after
delivery. As the Utility was unable to meet such demands at that time, several
gas suppliers refused to supply gas, accelerating the depletion of the Utility's
gas storage reserves and potentially exacerbating the electric power crisis if
the Utility were required to divert gas from industrial users, including natural
gas fired power plant operators.

     The U.S. Secretary of Energy issued a temporary order on January 19, 2001,
requiring the gas suppliers to continue to make deliveries to avoid a worsening
natural gas shortage emergency. However, this order expired on February 7, 2001,
and certain companies, representing about 10% of the Utility's natural gas
suppliers, terminated deliveries after the order expired.

     The Utility tried to mitigate the worsening supply situation by withdrawing
more gas from storage and, when able, purchasing additional gas on the spot
market. Additionally, on January 31, 2001, the CPUC authorized the Utility to
pledge its gas account receivables and its gas inventories for up to 90 days
(extended to 180 days in a CPUC draft decision issued on February 15, 2001) to
secure gas for its core customers. At March 29, 2001, the amount of gas accounts
receivables pledged was approximately $900 million. As of March 29, 2001,
approximately 30% of the Utility's suppliers of natural gas had signed security
agreements with the Utility and discussions were continuing with the Utility's
other
<PAGE>

suppliers. Additionally, the Utility is currently implementing a program to
obtain longer-term summer and winter supplies and daily spot supplies.

PG&E Corporation

     The liquidity and financial condition crisis faced by the Utility also
negatively impacted PG&E Corporation. Through December 31, 2000, PG&E
Corporation funded its working capital needs primarily by drawing down on
available lines of credit and other short-term credit facilities. At December
31, 2000, PG&E Corporation had borrowed $185 million against its five-year
revolving credit agreement and had issued $746 million of commercial paper. Due
to the credit ratings downgrades of PG&E Corporation, the banks refused any
additional borrowing requests and terminated their remaining commitments under
existing credit facilities. Commencing January 17, 2001, PG&E Corporation began
to default on its maturing commercial paper obligations.

     Commencing on March 2, 2001, PG&E Corporation refinanced its debt
obligations with $1 billion in aggregate proceeds of two term loans under a
common credit agreement with General Electric Capital Corporation and Lehman
Commercial Paper Inc. In accordance with the credit agreement, the proceeds,
together with other PG&E Corporation cash, were used to pay $501 million in
commercial paper (including $457 million of commercial paper on which PG&E
Corporation had defaulted), $434 million in borrowings under PG&E Corporation's
long-term revolving credit facility, and $116 million to PG&E Corporation
shareholders of record as of December 15, 2000, in satisfaction of a defaulted
fourth quarter 2000 dividend. Further, approximately $85 million was used to
pre-pay the first year's interest under the credit agreement and to pay
transaction expenses associated with the debt restructuring. See Note 3 of the
Notes to the Consolidated Financial Statements for a detailed description of the
loan.

     On March 15, 2001, PG&E Corporation's corporate credit rating was withdrawn
by S&P due to the March 2, 2001, refinancing of its obligations and the fact
that PG&E Corporation had no more public debt to be rated.

     PG&E Corporation itself had cash of $297 million at March 29, 2001, and
believes that the funds will be adequate to maintain its continuing operations
throughout 2001. In addition, PG&E Corporation believes that the holding company
and its non-CPUC regulated subsidiaries are protected from the bankruptcy of the
Utility.

PG&E National Energy Group

     In December 2000, and in January and February 2001, PG&E Corporation and
the NEG undertook a corporate restructuring of NEG, known as a "ringfencing"
transaction. The ringfencing complied with credit rating agency criteria,
enabling the NEG, PG&E GTN, and PG&E ET to receive or retain their own credit
ratings based on their own creditworthiness. The ringfencing involved the
creation or use of special purpose entities (SPEs) as intermediate owners
between PG&E Corporation and its non-CPUC regulated subsidiaries. These SPEs
are: PG&E National Energy Group, LLC, which owns 100% of the stock of the NEG;
PG&E GTN Holdings LLC which owns 100% of the stock of PG&E GTN; and PG&E Energy
Trading Holdings LLC, which owns 100% of the stock of PG&E Corporation's energy
trading subsidiaries, PG&E Energy Trading-Gas Corporation, PG&E Energy Trading
Holdings Corporation, and PG&E Energy Trading-Power, L.P. In addition, the NEG's
organizational documents were modified to include the same structural elements
as the SPEs to meet credit rating agency criteria. Ringfencing is intended to
reduce the likelihood that the assets of the ringfenced companies would be
substantively consolidated in a bankruptcy proceeding involving such companies'
ultimate parent, and to thereby preserve the value of the "protected" entities
as a whole. The SPEs require unanimous approval of their respective boards of
directors, including an independent director, before they can (a) consolidate or
merge with any entity, (b) transfer substantially all of their assets to any
entity, or (c) institute or consent to bankruptcy, insolvency, or similar
proceedings or actions. The SPEs may not declare or pay dividends unless the
respective board of directors has unanimously approved such action and the
company meets specified financial requirements.

STATEMENTS OF CASH FLOWS FOR 2000, 1999, AND 1998

     PG&E Corporation normally funds investing activities from cash provided by
operations after capital requirements and, to the extent necessary, external
financing. Our policy is to finance our investments with a capital structure
that minimizes financing costs, maintains financial flexibility, and, with
regard to the Utility, complies with regulatory guidelines.

PG&E Corporation Consolidated


<PAGE>

Cash Flows from Operating Activities

     Net cash (used) provided by PG&E Corporation's operating activities totaled
$(776) million, $2,155 million, and $3,388 million in 2000, 1999, and 1998,
respectively. The decrease of $2,931 million between 1999 and 2000 is
attributable to the California energy crisis previously discussed.

Cash Flows from Investing Activities

     During 2000, 1999, and 1998, PG&E Corporation used $1.8 billion, $1.6
billion, and $1.6 billion, respectively, for upgrades and expansion of its
facilities in operation or under construction. These capital expenditures were
partially offset by the 1999 and 1998 divestitures of generation facilities at
the Utility and by the completed sales of the PG&E ES and PG&E GTT business
units in 2000. In 2000, PG&E Corporation sold its Energy Services retail
business for $85 million and its value-added-services business and various other
assets for $18 million. The NEG received $306 million, which included a working
capital adjustment for the sale of PG&E GTT. The sale also included the
assumption of liabilities associated with PG&E GTT and debt having a book value
of $564 million. In 1999 and 1998, the Utility received proceeds of $1,014
million and $501 million, respectively, from the sale of generation facilities.
In 1998, PG&E Corporation sold its Australian energy holdings for proceeds of
approximately $126 million, and the NEG sold its Bear Swamp facility for $479
million.

Cash Flows from Financing Activities

     As of March 29, 2001, PG&E Corporation, itself, had $297 million in cash on
hand and had successfully refinanced its obligations that were in default. (See
previous discussion of PG&E Corporation's refinancing.) Net cash provided by
financing activities in 2000 totaled $2.4 billion, principally through
borrowings under credit facilities and issuances of short-term and long-term
debt needed to fund energy purchases. Net cash used by financing activities in
1999 and 1998 totaled $2.0 billion and $1.1 billion, respectively, and was used
principally to retire debt, repurchase outstanding common stock, and pay
dividends.

     During 2000, 1999, and 1998, PG&E Corporation issued $65 million, $54
million, and $63 million of common stock, respectively, primarily through the
Dividend Reinvestment Plan and the stock option plan component of the Long-Term
Incentive Program. During 2000, 1999, and 1998, PG&E Corporation declared
dividends on its common stock of $434 million, $460 million, and $466 million,
respectively.

     During 2000, 1999, and 1998, PG&E Corporation repurchased $2 million, $693
million, and $1,158 million of its common stock, respectively, primarily through
separate, accelerated share repurchase programs. As of December 31, 1997, the
Board of Directors had authorized the repurchase of up to $1.7 billion of PG&E
Corporation's common stock on the open market or in negotiated transactions. As
part of this authorization, in January 1998, PG&E Corporation repurchased in a
specific transaction 37 million shares of common stock. As of December 31, 1998,
approximately $570 million remained available under this repurchase
authorization. In February 1999, PG&E Corporation used this remaining
authorization to purchase 16.6 million shares at a total cost of $531 million. A
subsidiary of PG&E Corporation made this repurchase, along with subsequent stock
repurchases. The stock held by the subsidiary is treated as treasury stock and
reflected as Stock Held by Subsidiary on the Consolidated Balance Sheet of PG&E
Corporation.

     In October 1999, the Board of Directors of PG&E Corporation authorized an
additional $500 million for the purpose of repurchasing shares of PG&E
Corporation's common stock on the open market. This authorization supplemented
the approximately $40 million remaining from the amount previously authorized by
the Board of Directors on December 17, 1997. The authorization for share
repurchase extends through September 30, 2001. As of December 31, 1999, through
its wholly owned subsidiary, PG&E Corporation repurchased an additional 7.2
million shares, at a cost of $159 million under this authorization. At December
31, 2000, the remainder under the share repurchase authorization is
approximately $380 million. PG&E Corporation is precluded by its March 2, 2001,
loan agreement with General Electric Capital Corporation and Lehman Commercial
Paper Inc. from repurchasing its common stock until the loan is repaid.

Utility

     The following section discusses the Utility's significant cash flows from
operating, investing, and financing activities for the three year period ended
December 31, 2000.
<PAGE>

Cash Flows from Operating Activities

     Net cash (used) provided by the Utility's operating activities totaled
$(699) million, $2,196 million, and $3,736 million in 2000, 1999, and 1998,
respectively. The decrease of $2,895 million between 1999 and 2000 is
attributable to the California energy crisis and the significant deterioration
of the Utility's financial condition reflected by the deferred electric
procurement costs of $6,465 million which have not yet been recovered from
ratepayers and which were determined not to be probable of recovery through
regulated rates and recognized as a charge to earnings in the fourth quarter
2000.

Cash Flows from Investing Activities

     The primary uses of cash for investing activities are additions to
property, plant, and equipment. The Utility's capital expenditures were $1,245
million, $1,181 million, and $1,382 million, for the years ended December 31,
2000, 1999, and 1998, respectively.

     During 1999, the Utility sold three fossil-fueled generation facilities and
its geothermal generation facilities. These sales closed in April and May 1999,
respectively, and generated proceeds of $1,014 million. In 1998, the Utility had
proceeds of $501 million from the sale of three fossil-fueled generation plants.

Cash Flows from Financing Activities

     In April 2000, a subsidiary of the Utility repurchased from PG&E
Corporation 11.9 million shares of its common stock at a cost of $275 million.
In December 1999, 7.6 million shares of the Utility's common stock, with an
aggregate purchase price of $200 million, was purchased by a subsidiary of the
Utility. These repurchases are reflected as stock held by subsidiary in the
Consolidated Balance Sheet of the Utility. Earlier in 1999, the Utility
repurchased from PG&E Corporation, and cancelled 20 million shares of its common
stock from PG&E Corporation for an aggregate purchase price of $726 million to
maintain its authorized capital structure. In 2000, 1999, and 1998, the Utility
paid dividends on its common and preferred stock of $475 million, $440 million,
and $444 million, respectively.

     The Utility's long-term debt that either matured, was redeemed, or was
repurchased during 2000 totaled $597 million. Of this amount, (1) $110 million
related to the maturity of its 6.63%, and 6.75% mortgage bonds due June 1, and
December 1, 2000, (2) $81 million related to the Utility's repurchase of various
pollution control loan agreements, (3) $113 million related to the maturity of
the Utility's various medium term notes, (4) $3 million related to the other
scheduled maturities of long-term debt, and (5) $290 million related to maturity
of rate reduction bonds.

     The Utility's long-term debt that either matured, was redeemed, or was
repurchased during 1999 totaled $672 million. Of this amount, (1) $290 million
related to the Utility's rate reduction bonds maturing, (2) $135 million related
to the Utility's repurchase of mortgage and various other bonds, (3) $147
million related to maturity of various utility mortgage bonds, and (4) $100
million related to the maturities and redemption of various of the Utility's
medium-term notes and other debt. During 2000 and 1999, the Utility did not
redeem or repurchase any of its preferred stock.

     On November 1, 2000, the Utility issued $680 million of five-year, fixed-
rate notes and $1,000 million of 364-day floating rate notes. On November 22,
2000, the Utility issued $240 million in floating rate notes.

PG&E National Energy Group

     The California energy crisis has impacted the funding available for new
projects at the NEG. The NEG undertook a ringfencing strategy to facilitate
access to capital markets and insulate the NEG's assets from the risk of
bankruptcy at the Utility. The refinancing of PG&E Corporation's debts on March
2, 2001, further insulates NEG from the risk of bankruptcy at the Utility.

General

     Historically, the NEG has obtained cash from operations, borrowings under
credit facilities, non-recourse project financing and other issuances of debt,
issuances of commercial paper, and borrowings and capital contributions from
PG&E Corporation. These funds have been used to finance operations, service debt
obligations, fund the acquisition, development, and/or construction of
generating facilities, and to start-up other businesses, finance capital
expenditures, and meet other cash and liquidity needs.
<PAGE>

     The projects that the NEG develops typically require substantial capital
investment. Some of the projects in which the NEG has an interest have been
financed primarily with non-recourse debt that is repaid from the project's cash
flows. This debt is often secured by interests in the physical assets, major
project contracts and agreements, cash accounts, and, in some cases, the
ownership interest in that project subsidiary. These financing structures are
designed to ensure that the NEG is not contractually obligated to repay the
project subsidiary's debt; that is, they are "non-recourse" to the NEG and to
its subsidiaries not involved in the project. However, the NEG has agreed to
undertake financial support for some of its project subsidiaries in the form of
limited obligations and contingent liabilities such as guarantees of specified
obligations. To the extent the NEG becomes liable under these guarantees or
other agreements in respect of a particular project, it may have to use
distributions it receives from other projects to satisfy these obligations.

Cash Flows from Operating Activities

     Cash flow (used by) generated from operations totaled $(77) million, $(41)
million, and $(348) million for the years ended December 31, 2000, 1999, and
1998, respectively. The decrease in cash flows for 2000 compared to 1999 of $36
million is attributable to increases in working capital required to support the
expanded energy trading operations and a decrease in depreciation expense as a
result of the impairment of PG&E GTT assets in 1999. The increase in cash flows
generated from operations in 1999 as compared to 1998 of $307 million is due
principally to the increase in earnings, excluding the non-cash charge to
reflect impairment of the investment in PG&E GTT; an increase in working capital
balances of approximately $53 million; realization of gains in energy contracts
accounted for on a mark-to-market basis; and increases in the non-cash charges,
such as depreciation and the deferred tax provision, partially offset by the
increase in the amortization of out-of-market contractual obligations and an
increase in capitalized development costs.

Cash Flows from Investing Activities

     The NEG recognized $65 million, $63 million, and $113 million in earnings
on investments, which are accounted for using the equity method for 2000, 1999
and 1998, respectively. The NEG received cash distributions from these
investments totaling approximately $104 million, $66 million and $69 million
during 2000, 1999 and 1998, respectively.

     Four natural gas-fueled combined-cycle power plants are currently under
construction, which when completed will be owned or leased by the NEG. These
power plants, referred to as "merchant power plants," will sell power as a
commodity in the competitive marketplace. The electricity generated by these
plants will be sold on a wholesale basis to local utilities and power marketers,
including PG&E ET, which, in turn, will sell it to industrial, commercial, and
other electricity customers.

     Millennium Power, a 360-megawatt (MW) power plant located in Massachusetts,
is scheduled to begin commercial service in 2001. Lake Road Generating Plant
(Lake Road), an approximately 780-MW power plant located in Connecticut, is
scheduled to begin commercial service in 2001. La Paloma Generating Plant, an
approximately 1,050-MW power plant, is located in California, and is scheduled
to begin commercial service in 2002. Lake Road and La Paloma are being financed
through a synthetic lease with a third-party owner. PG&E Gen will operate the
plant under operating leases. See Note 14 of the Notes to the Consolidated
Financial Statements. The estimated cost to construct these plants is
approximately $1.4 billion.

     In October 2000, the NEG completed construction on an 11.5 MW wind project
that is the largest wind generating facility in the Eastern United States for a
total cost of $16 million.

     In September 2000, the NEG purchased the Attala Generating Plant for $311
million. The seller is obligated to deliver a fully operating facility by July
1, 2001. Attala is a 500 MW natural gas-fired combined-cycle project, located in
Mississippi.

     The NEG used $1.3 billion in cash for its investing activities in 1998.
During 1998, through its indirect subsidiary USGenNE, the NEG completed the
acquisition of a portfolio of electric generating assets and power supply
contracts from New England Electric System (NEES). The funding requirements for
this acquisition were $1,746 million and included the acquisition of (1)
electric generating assets classified as property, plant, and equipment; (2)
receivable for support payments of approximately $800 million; and (3)
approximately $1,300 million of contractual obligations.

     The NEES assets include hydroelectric, coal, oil, and natural gas -fueled
generation facilities with a combined generating capacity of 4,000 MW. In
addition USGenNE assumed 23 multi-year power-purchase agreements representing an
additional 800 MW of production capacity. USGenNE entered into agreements with
NEES as part of the acquisition,
<PAGE>

which (1) provide that NEES shall make support payments over the next ten years
to USGenNE for the purchase power agreements, and (2) require that USGenNE
provide electricity to NEES under contracts that expire over the next six to
eleven years.

     In 1998, the NEG spent approximately $220 million on development and
construction activities. Also in 1998, the NEG entered into a sale/leaseback
transaction whereby it sold and leased back its Bear Swamp facility, comprised
of the Bear Swamp pumped storage station and the Fife Brook station, to a third
party. This transaction generated cash proceeds of $479 million. Finally in
1998, the NEG completed the sale of its Australian energy holdings for proceeds
of approximately $126 million, and executed some portfolio management
transactions, which generated cash proceeds of approximately $22 million.

Cash Flows from Financing Activities

     The NEG maintains $1,350 million in five revolving credit facilities, which
support commercial paper and Eurodollar borrowing arrangements. At December 31,
2000 and 1999, the NEG had total outstanding balances related to such borrowings
of $1,181 million and $1,173 million, respectively. In addition, certain letters
of credit held by the NEG reduce the available outstanding facility commitments.
At December 31, 2000, approximately $36 million of letters of credit were
outstanding under these facilities. Since the NEG has the ability and intent to
refinance certain borrowings, $661 million and $649 million of such borrowings
are classified as long-term debt as of December 31, 2000 and 1999, respectively.
The remaining outstanding balances are classified as short-term borrowings in
the Consolidated Balance Sheets of PG&E Corporation.

Capital Requirements

     The table below provides information about PG&E Corporation's capital
requirements at December 31, 2000:


<TABLE>
<CAPTION>

Expected maturity date                                         2001       2002      2003      2004      2005      Thereafter
----------------------                                         ----       ----      ----      ----      ----      ----------
                                                                                 (dollars in millions)
<S>                                                          <C>        <C>      <C>        <C>        <C>         <C>
Utility:
Capital spending                                             $1,505
Long-term debt
         Variable rate obligations                           $  120     $  697   $   350    $   40    $   40       $      20
         Fixed rate obligations                              $  274     $  379   $   354    $  392    $1,012       $   2,038
         Average interest rate                                  8.0%       7.8%      6.3%      6.4%      6.9%            7.3%
Rate reductions bonds                                        $  290     $  290   $   290    $  290    $  290       $     580
         Average interest rate                                  6.2%       6.3%      6.4%      6.4%      6.4%            6.4%
National Energy Group:
Capital spending                                             $2,445
Long-term debt
         Variable rate obligations                           $   16     $   94   $   584    $    9    $    9       $      80
         Fixed rate obligations                              $    1     $   34   $     7    $    1    $  251       $     325
         Average interest rate                                  9.4%       6.9%      7.0%      9.4%      7.1%            8.9%
</TABLE>

RESULTS OF OPERATIONS

     In this section, we discuss the operations of the NEG and present the
components of our results of operations for 2000, 1999, and 1998. The table
below shows for 2000, 1999, and 1998, certain items from our Statement of
Consolidated Operations detailed by Utility and the NEG operations of PG&E
Corporation. (In the "Total" column, the table shows the combined results of
operations for these groups.) The information for PG&E Corporation (the "Total"
column) includes the appropriate intercompany elimination. Following this table
we discuss our results of operations.


National Energy Group
<PAGE>

     The NEG has been formed to pursue opportunities created by the gradual
restructuring of the energy industry across the nation. The NEG integrates our
national power generation, gas transmission, and energy trading businesses. The
NEG contemplates increasing PG&E Corporation's national market presence through
a balanced program of development, acquisition, and contractual control of
energy assets and businesses, while at the same time undertaking ongoing
portfolio management of its assets and businesses. The NEG's ability to
anticipate and capture profitable business opportunities created by industry
restructuring will have a significant impact on PG&E Corporation's future
operating results.

Power Generation

     We participate in the development, operation, ownership, and management of
non-utility electric generating facilities that compete in the United States
power generation market. In September 1998, PG&E Corporation, through its
indirect subsidiary USGen New England, Inc. (USGenNE), completed the acquisition
of a portfolio of electric generation assets and power supply contracts from
NEES. The purchased assets include hydroelectric, coal, oil, and natural gas-
fueled generation facilities with a combined generating capacity of about 4,000
MW.

     As part of the New England electric industry restructuring, the local
utility companies were required to offer Standard Offer Service (SOS) to their
retail customers. Retail customers may select alternative suppliers at any time.
The SOS is intended to provide customers with a price benefit (the commodity
electric price offered to the retail customer is expected to be less than the
market price) for the first several years, followed by a price disincentive that
is intended to stimulate the retail market.

     Retail customers may continue to receive SOS through December 31, 2004, in
Massachusetts, and through December 31, 2009, in Rhode Island. However, if
customers choose an alternate supplier, they are precluded from going back to
the SOS.

     In connection with the purchase of the generation assets, USGenNE entered
into wholesale agreements with certain of the retail companies of NEES to supply
at specified prices the electric capacity and energy requirements necessary for
their retail companies to meet their SOS obligations. These companies are
responsible for passing on the revenues generated from the SOS. USGenNE
currently is indirectly serving a large portion of the SOS electric capacity and
energy requirements for these companies. For the years ended December 31, 2000
and 1999, the SOS price paid to generators was $0.043 and $0.035 per kWh for
generation, respectively.

     Like other utilities, New England utilities previously entered into
agreements with unregulated companies (e.g., qualifying facilities under Public
Utilities Regulatory Policies Act (PURPA)) to provide energy and capacity at
prices that are anticipated to be in excess of market prices. The NEG assumed
NEES' contractual rights and duties under several of these power purchase
agreements. At December 31, 2000, these agreements provided for an aggregate 470
MW of capacity. NEES will make support payments to us toward the cost of these
agreements. The remaining support payments by NEES total $0.8 billion in the
aggregate (undiscounted) and are due in monthly installments through January
2008. In certain circumstances, with our consent, NEES may make a full or
partial lump sum accelerated payment.

     Currently, approximately 60% to 70% of the capacity is dedicated to serving
SOS customers. To the extent that customers eligible to receive SOS choose
alternate suppliers, or as these obligations are sold to other parties, this
percentage will continue to decrease. As customers choose alternate suppliers,
or the SOS obligations are sold, a greater proportion of the output of the
acquired operating capacity will be subject to market prices.

Gas Transmission Operations

     The NEG, through PG&E GTN, owns and operates gas transmission pipelines and
associated facilities, subject to regulation by the Federal Energy Regulatory
Commission (FERC). The pipeline and associated facilities extend over 612 miles
from the Canada-U.S. border to the Oregon-California border. PG&E GTN provides
firm and interruptible transportation services to third-party shippers on an
open-access basis. Its customers are principally retail gas distribution
utilities, electric generators that use natural gas to generate electricity,
natural gas marketing companies that purchase and resell natural gas to
utilities and end-use customers, natural gas producers, and industrial
consumers.

     On January 27, 2000, PG&E Corporation signed a definitive agreement with El
Paso Field Services Company (El Paso) providing for the sale to El Paso, a
subsidiary of El Paso Energy Corporation, of the stock of PG&E GTT. Given the
<PAGE>

terms of the sales agreement, in 1999, PG&E Corporation recognized a charge
against pre-tax earnings of $1,275 million, to reflect PG&E GTT's assets at
their fair value.

     On December 22, 2000, after receipt of governmental approvals, PG&E
Corporation completed the stock sale. The sales agreement had a provision, which
included a sales price adjustment for changes in working capital from December
31, 1999 to closing. The total consideration received was $456 million, which
includes the working capital adjustment, less $150 million used to retire the
PG&E GTT short-term debt, and the assumption by El Paso of PG&E GTT long-term
debt having a book value of $565 million. In December 2000, PG&E Corporation
recorded income of approximately $20 million reflecting the sales price true-up.

Energy Trading

     The NEG's trading businesses purchase bulk volumes of power and natural gas
from the NEG's affiliates and the wholesale market. The NEG then transports and
resells these commodities, either directly to third parties or to other PG&E
Corporation affiliates. The NEG also provides risk management services to other
NEG businesses and to wholesale customers. (See "Price Risk Management
Activities" below; and Note 4 of the Notes to the Consolidated Financial
Statements.)

Energy Services

     In December 1999, PG&E Corporation's Board of Directors approved a plan to
dispose of PG&E ES, its wholly owned subsidiary, through a sale. The disposal
has been accounted for as a discontinued operation, and PG&E Corporation's
investment in PG&E ES was written down to its then estimated net realizable
value. In addition, PG&E Corporation provided a reserve for anticipated losses
through the anticipated date of sale. The total provision for discontinued
operations was $58 million, net of income taxes of $36 million. Of this amount,
$33 million (net of taxes) was allocated toward operating losses for the period
leading up to the intended disposal date. In 2000, $31 million (net of taxes) of
actual operating losses were charged against this reserve. During the second
quarter of 2000, the NEG finalized the disposal of the energy commodity portion
of PG&E ES for $20 million, plus net working capital of approximately $65
million, for a total of $85 million. In addition, the sale of the Value-Added
Services business and various other assets was completed on July 21, 2000, for a
total consideration of $18 million. For the year ended December 31, 2000, an
additional estimated loss of $40 million (or $0.11 per share), net of income tax
of $36 million, was recorded. The additional loss was greater than the amount
originally provided for several reasons: (1) the sale was originally
contemplated to be a sale of the entity as a whole; (2) it was ultimately sold
in various pieces; (3) several assets were not sold and were subsequently
abandoned; and (4) wind-down costs associated with abandoned assets were greater
than originally contemplated. In addition, the worsening energy situation in
California also contributed to the additional loss incurred.

<TABLE>
<CAPTION>
                                                    PG&E National Energy Group
                                                   ---------------------------
                                                              PG&E GT
                                                              -------
(in millions)                       Utility    PG&EGen      NW      Texas    PG&E ET    Eliminations &     Total
                                                                                          Other/(1)/
<S>                                 <C>       <C>         <C>      <C>       <C>       <C>                <C>
2000:
Operating revenues                  $ 9,637    $ 1,211    $ 239     $ 873   $ 16,054      $ (1,782)      $ 26,232
Operating expenses                   14,838      1,073      105       869     15,974        (1,820)        31,039
Operating loss                                                                                             (4,807)
Interest income                                                                                               266
Interest expense                                                                                             (788)
Other income (expense), net                                                                                   (23)
Income taxes                                                                                               (2,028)
Loss from continuing operations                                                                            (3,324)
Net loss                                                                                                   (3,364)
Net cash used by operating
 activities                                                                                                  (776)
Net cash used by investing                                                                                   (970)
 activities
Net cash provided by financing                                                                              2,364
 activities
</TABLE>
<PAGE>

<TABLE>
<S>                               <C>           <C>        <C>    <C>       <C>             <C>         <C>
EBITDA/(2)/                         $(1,244)      $  227     $176  $   108   $    91          $   (55)    $  (697)
1999:
Operating revenues                  $ 9,228       $1,122     $224  $ 1,148   $10,521          $(1,423)    $20,820
Operating expenses                    7,235        1,007      104    2,446    10,582           (1,432)     19,942
Operating income                                                                                              878
Interest income                                                                                               118
Interest expense                                                                                             (772)
Other income (expense), net                                                                                    37
Income taxes                                                                                                  248
Income from continuing operations                                                                              13
Net loss                                                                                                      (73)
Net cash provided by operating
 activities                                                                                                 2,155
Net cash used by investing
 activities                                                                                                  (117)
Net cash used by financing
 activities                                                                                                (2,043)
EBITDA/(2)/                         $ 3,523       $  203     $181  $(1,178)  $   (53)         $    19     $ 2,695
1998:
Operating revenues                  $ 8,924       $  649     $237  $ 1,941   $ 8,509          $  (683)    $19,577
Operating expenses                    7,048          489      101    1,996     8,528             (683)     17,479
Operating income                                                                                            2,098
Interest income                                                                                               101
Interest expense                                                                                             (781)
Other income (expense), net                                                                                   (36)
Income taxes                                                                                                  611
Income from continuing operations                                                                             771
Net income                                                                                                    719
Net cash provided by operating                                                                              3,388
 activities
Net cash used by investing
activities                                                                                                 (2,226)
Net cash used by financing
activities                                                                                                 (1,113)
EBITDA/(2)/                         $ 3,294       $  200     $177  $    15   $   (15)         $    (7)    $ 3,664
</TABLE>

(1)  Net income on intercompany positions recognized by segments using mark-to-
     market accounting is eliminated. Intercompany transactions are also
     eliminated.

(2)  EBITDA is defined as income before provision for income taxes, interest
     expense, interest income, deferred electric procurement costs, depreciation
     and amortization, provision for loss on generation-related assets and
     undercollected purchased power costs. EBITDA is not intended to represent
     cash flows from operations and should not be considered as an alternative
     to net income as an indicator of the PG&E Corporation's operating
     performance or to cash flows as a measure of liquidity. Refer to the
     Statement of Cash Flows for the U.S. GAAP basis cash flows. PG&E
     Corporation believes that EBITDA is a standard measure commonly reported
     and widely used by analysts, investors, and other interested parties.
     However, EBITDA as presented herein may not be comparable to similarly
     titled measures reported by other companies.

Overall Results

     PG&E Corporation's financial position and results of operations are
impacted by the ongoing California energy crisis. Please see the Liquidity and
Financial Resources section and Note 2 of the Notes to the Consolidated
Financial Statements for more information on the California energy crisis.
<PAGE>

     Net loss for the year ended December 31, 2000 increased to $3,364 million
from a net loss of $73 million for the same period in 1999. Of the $3,291
million increase, the Utility's net loss allocated to common stock for the year
ended December 31, 2000 accounted for $4,271 million of the increase, partially
offset by an increase in the NEG net income of $980 million.

     The decrease in performance of 2000 compared to 1999 results of operations
is attributable to the following factors:

     .    The Utility's earnings were impacted as a result of the write-off of
          its remaining generation related regulatory assets and undercollected
          purchased power costs ($4.1 billion, after taxes). Because of the
          substantial uncertainty created by the California energy crisis, the
          Utility can no longer conclude that energy costs, which had been
          deferred on its balance sheets, are probable of recovery. Under
          Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting
          for the Effects of Certain Types of Regulations," if a rate mechanism
          provided by legislation or other regulatory authority were
          subsequently established that made recovery from regulated rates
          probable as to all or a portion of the undercollection that was
          previously charged against earnings, a regulatory asset would be
          reinstated with a corresponding increase in earnings.

     .    As a result of the high cost of power, with no offsetting revenues,
          the Utility and PG&E Corporation had a net loss for California tax
          purposes. California law does not permit carrybacks of such losses and
          only permits carryforwards of 55% of such losses. As a result, PG&E
          Corporation was unable to recognize $79 million of state tax benefits
          because of California law. Income tax expense was also higher due to
          depreciation adjustments and a reduction in investment tax credits.

     .    In 2000, the Utility recorded a provision ($83 million, after tax) for
          potential losses associated with litigation discussed in Note 15 of
          the Notes to the Consolidated Financial Statements.

     .    At the end of 1999, PG&E Corporation announced its plans to dispose of
          PG&E GTT, and these assets were written down to estimated fair value
          resulting in a charge of $890 million ($2.24 per share). PG&E GTT has
          operated at a breakeven basis in 2000, while it reported a net loss
          from operations of $7 million ($0.02 per share) in 1999. These
          operations were sold on December 22, 2000.

     .    Also at the end of 1999, PG&E Corporation announced its plans to
          dispose of PG&E ES and these assets were written down to net
          realizable value. PG&E ES operated at a loss during 2000. However,
          those losses were charged against reserves established in 1999 and did
          not impact the current results from operations, while PG&E ES reported
          losses of $98 million ($0.27 per share) for 1999. Additionally, during
          the later half of 2000, PG&E Corporation recorded after-tax charges of
          $40 million ($0.11 per share) to reflect the closing of transactions
          to dispose of the retail energy services business and related
          commodity portfolio.

     .    PG&E ET's net income in 2000, net of restructuring charges of $13
          million after-tax ($0.04 per share) related to the move of natural gas
          trading operations from Houston, Texas, to Bethesda, Maryland,
          increased $57 million compared to 1999 results due to across the board
          improvements in natural gas and power trading, asset management, and
          structured transactions. While trading in electric commodities has
          generally been profitable, the results of the gas trading operations
          have improved significantly as a result of structured transactions.
          Additionally, the gas trading operations benefited from the highest
          gas prices in a number of years. The power trading operations have
          been able to benefit from volatile prices throughout the United
          States.

     .    PG&E Gen and PG&E GTN earnings decreased slightly from 1999 levels,
          primarily attributable to a decline in operating results in the
          generating business and a decrease in operating income at PG&E GTN
          primarily as a result of settlements received in the amount of $19
          million for negotiations regarding transportation contracts and other
          related issues, resulting in the restructuring and/or termination of
          these transportation contracts in 1999 with no similar transactions in
          2000.

     The effective tax rate for PG&E Corporation has decreased to 37.9% in 2000
compared to 95.0% in the prior year as a result of a higher effective tax rate
in 1999, largely due to the disposition of PG&E GTT which resulted in a capital
loss for tax purposes, which could not be fully recognized.
<PAGE>

     The decrease in performance of 1999 over 1998 results of operations is
attributable to the following factors:

     .    PG&E Corporation had a net loss in 1999 of $73 million, or $0.20 per
          share. In 1998 PG&E Corporation had net income of $719 million, or
          $1.88 per share. The decrease was principally due to the write-down to
          fair value of the natural gas business in Texas and the accrual for
          the discontinuance of operations of the Energy Services segment. The
          PG&E GTT write-down was approximately $890 million after taxes or
          $2.42 per share and is comprised of the following pre-tax amounts:
          $819 million write-down of net property, plant, and equipment, $446
          million write-down of goodwill, and an accrual of $10 million for
          selling costs. The PG&E ES discontinued operations generated a charge
          of $58 million after tax.

     .    Partially offsetting these charges were increases in Utility income of
          $153 million or $0.42 per share, primarily as a result of the 1999
          General Rate Case.

     .    Also increasing income was an adjustment of a litigation reserve at
          GTT, associated with a court-approved settlement proposal in the
          amount of $35 million after tax.

     .    The 1998 income from continuing operation also included a loss on the
          sale of the Australian energy holdings of $23 million, or $0.06 per
          share, without a similar charge in 1999.

     .    In addition, PG&E Gen changed its method of accounting for major
          maintenance and overhauls at its generating facilities. Beginning
          January 1, 1999, the cost of major maintenance and overhauls,
          principally at the PG&E Gen business segment, has been accounted for
          as incurred. The change resulted in PG&E Corporation recording income
          of $12 million after-tax ($0.03 per share), reflecting the cumulative
          effect of the change in accounting principle for the year ended
          December 31, 1999.

     PG&E Corporation has recorded income tax expense of $248 million for 1999.
The effective tax rate primarily results from two factors: (1) electric industry
restructuring has resulted in the reversal of temporary differences whose tax
benefits were originally flowed through to customers causing an increase in
income tax expense independent of pre-tax income, and (2) the disposition of
PG&E GTT resulted in a capital loss for tax purposes, which could not be fully
recognized.

Dividends

     PG&E Corporation's historical quarterly common stock dividend was $0.30 per
common share, which corresponded to an annualized dividend of $1.20 per common
share.

     On January 10, 2001, the Board of Directors of PG&E Corporation suspended
the payment of its fourth quarter 2000 common stock dividend of $0.30 per share
declared by the Board of Directors on October 18, 2000 and payable on January
15, 2001 to shareholders of record as of December 15, 2000. The California
energy crisis had created a liquidity crisis for PG&E Corporation, which led to
the suspension of payments of dividends to conserve cash resources. These
defaulted dividends were later paid on March 2, 2001 in conjunction with the
refinancing of PG&E Corporation obligations, discussed above under the Liquidity
and Financial Resources section.

     Additionally, the parent company refinancing agreements mentioned above
prohibit dividends from being declared or paid until the term loans have been
repaid. The agreement is for a term of two years with an option on behalf of
PG&E Corporation to extend the term for an additional year.

     On January 10, 2001, the Utility suspended the payment of its fourth
quarter 2000 common stock dividend of $110 million, declared in October 2000, to
PG&E Corporation and its wholly owned subsidiary PG&E Holdings, Inc. Until its
financial condition is restored, the Utility is precluded from paying dividends
to PG&E Corporation and PG&E Holdings, Inc.

Utility


Overall Results
<PAGE>

     The Utility's net loss allocated to common stock was $3,508 million in 2000
as compared to 1999 net income of $763 million. The decrease was primarily the
result of the write-off of its remaining generation-related regulatory assets
and undercollected purchased power costs, a provision for potential litigation
losses, and higher income tax expense as mentioned previously.

     The Utility's net income available for common stock increased to $763
million in 1999 as compared to 1998 net income of $702 million, primarily
because of the impacts of the 1999 General Rate Case (GRC).

Operating Income

     Operating loss for the Utility was $5,201 million in 2000 as compared to
operating income of $1,993 million in 1999. This decrease in the Utility's
operating income was primarily due to the write-off of its remaining generation
related regulatory assets and undercollected purchased power costs. In addition,
it is attributable to a provision for potential litigation losses and a lower
return on its assets, due to the sale of a portion of the Utility's generating
assets and the ongoing recovery of transition costs.

     Operating income for the Utility was $1,993 million in 1999 as compared to
$1,876 million in 1998. This increase was primarily because of the impacts of
the 1999 GRC. However, the increases from the GRC were partially offset by a
reduction in the Utility's authorized cost of capital and a lower return on its
assets due to the sale of a significant portion of its generating assets and
recovery of transition costs.

Operating Revenues

     The following table shows the components of the Utility's electric revenue
by customer class, natural gas revenues, and total revenues for the years ended
December 31:

<TABLE>
<CAPTION>
                                                                          2000        1999        1998
        <S>                                                             <C>         <C>         <C>
        Residential                                                     $3,351      $3,294      $3,198
        Commercial                                                       2,804       2,940       2,883

        Total residential and commercial                                 6,155       6,234       6,081
        Legislative discount                                              (453)       (435)       (396)

        Revenues from residential and commercial                         5,702       5,799       5,685
        Industrial                                                         509         864         933
        Agriculture                                                        386         392         351
        Miscellaneous                                                      257         177         222

        Total electric operating revenues                               $6,854      $7,232      $7,191

        Total gas operating revenues                                    $2,783      $1,996      $1,733

        Total operating revenues                                        $9,637      $9,228      $8,924
 </TABLE>

     Utility operating revenues increased $409 million or 4.4% to $9,637 million
in 2000 compared to $9,228 million in 1999. The increase in operating revenues
for 2000, as compared to 1999, related primarily to higher gas prices, which are
passed on to customers and collected in gas revenues, partially offset by a
decrease in electric revenues. The average price of gas per thousand cubic feet
was $4.92 in 2000 and $2.47 in 1999. Gas sales volumes for bundled sales and
transportation decreased by 9% from 1999 sales volumes due to warmer winter
weather, while gas sales volumes for transportation-only service increased by
25% due to increased demands by electric generators to meet air-conditioning
loads due to warmer summer weather and new transportation contracts.
<PAGE>

     Electric sales volumes increased for all customer classes, resulting in an
overall increase of 3% over 1999 sales volumes. Electric revenues from
industrial and commercial customers decreased because of higher wholesale power
market prices and resulting credits issued to direct access customers. These
customers, principally large industrial companies, procure electricity from
independent generators under long-term contracts and receive a credit on their
utility bills at prevailing market prices. In accordance with CPUC regulations,
the Utility provides an energy credit to those customers (known as direct access
customers) who have chosen to buy their electric generation energy from an
energy service provider (ESP) other than the Utility. The Utility bills direct
access customers based upon fully bundled rates (generation, distribution,
transmission, public purpose programs, and a competition transition charge).
However, the direct access customer receives an energy credit equal to the PX
price for wholesale electricity (calculated as the average market prices
multiplied by customer energy usage for the period), with the customer being
obligated to their ESP at their direct access contract rate. As wholesale power
prices began to increase in June 2000, the level of PX credits increased
correspondingly to the point where the credits exceeded the Utility's
distribution and transmission charges to direct access customers. During 2000,
the PX credits reduced electric revenue by $472 million, although the Utility
ceased paying most of these credits in December 2000. As of March 29, 2001, the
estimated total of accumulated credits for direct access customers that have not
been paid by the Utility is approximately $503 million. Such amounts are
reflected on the Utility's balance sheet. The actual amount that will be
refunded to ESPs will be dependent upon when the rate freeze ends and whether
there are any adjustments made to wholesale energy prices by FERC.

     Utility operating revenues increased $304 million or 3.4% in 1999 as
compared to 1998. This increase is primarily due to: (1) a $147 million increase
in gas revenues from residential and commercial gas customers due to higher
usage, (2) a $93 million increase in gas revenues as a result of the GRC, (3) a
$43 million increase in revenues from small and medium electric customers due to
increased customers, and (4) a $16 million increase in revenues from an increase
in gas transportation volumes.

Operating Expenses

     Utility operating expenses increased $7,603 million in 2000 compared to
1999.

     The tables below summarize the changes in the Utility's operating expenses:

<TABLE>
<CAPTION>
                                                                        For the Year ended
                                                                           December 31,
                                                                           -----------
                                                                                                Increase          Increase
(in millions)                                                           2000         1999      (Decrease)        (Decrease)
<S>                                                                   <C>          <C>         <C>               <C>
Cost of electric energy, net                                          $ 6,741      $2,411          $ 4,330          179.6%
Deferred electric procurement costs                                    (6,465)         --           (6,465)            --
Cost of gas                                                             1,425         738              687           93.1%
Operating and maintenance, net                                          2,687       2,522              165            6.5%
Depreciation, amortization, and decommissioning                         3,511       1,564            1,947          124.5%
Provision for loss on generation related regulatory assets and
 purchased power costs                                                  6,939          --            6,939             --

Total                                                                 $14,838      $7,235          $ 7,603          105.1%

<CAPTION>
                                                                     For the Year ended
                                                                         December 31,
                                                                         -----------
                                                                                              Increase          Increase
(in millions)                                                         1999       1998        (Decrease)        (Decrease)
<S>                                                                 <C>        <C>        <C>               <C>
Cost of electric energy, net                                          $ 2,411      $2,321         $     90            3.9%
Cost of gas                                                               738         621              117           18.8%
Operating and maintenance, net                                          2,522       2,668             (146)          (5.5%)
Depreciation, amortization, and decommissioning                         1,564       1,438              126            8.8%

Total                                                                 $ 7,235      $7,048         $    187            2.7%
</TABLE>
<PAGE>

     The overall increase in operating expenses is primarily attributable to the
write-off of the Utility's transition cost regulatory assets and undercollected
purchased power costs. In addition, operating expenses increased due to
increases in the cost of gas during the latter half of 2000. The average price
the Utility paid per thousand cubic feet of gas was $4.92 in 2000 and $2.47 in
1999.

     Wholesale electric energy costs increased significantly during the latter
half of 2000. The average monthly costs per kWh of purchased power during the
latter half of 2000 were: June (16.33 cents), July (11.00 cents), August (18.70
cents), September (13.82 cents), October (13.62 cents), November (20.43 cents),
and December (33.24 cents). The amount of purchased power costs in excess of the
revenue for the generation component of frozen rates was reflected as deferred
electric procurement costs prior to the year-end write-off described above.
Revenues for the generation component of frozen rates were approximately 5.4
cents per kWh during 2000.

     Depreciation, amortization, and decommissioning increased $1,947 million in
2000. The increase resulted primarily from an increase in recovery of transition
costs resulting from higher revenues from sales to the PX of Utility-owned
generation, including Diablo Canyon, and generation from QFs and other
providers. As mandated by the CPUC, these revenues, in excess of the related
costs, must be used to recover transition costs. See Note 2 of the Notes to the
Consolidated Financial Statements.

     The Utility's operating expenses increased $187 million in 1999 as compared
to 1998. This increase reflected the increased cost of gas due to higher usage
and the increased amortization of electric transition costs, partially offset by
a decrease in operating and maintenance expense resulting from fewer owned-
generation facilities in 1999 as a result of divestitures.

Dividends


     Dividends paid to PG&E Corporation increased from $440 million in 1999 to
$475 million in 2000, maintaining the CPUC-mandated capital structure. Dividends
paid to PG&E Corporation in 1998 were $444 million.

     Dividends paid to preferred shareholders remained at the same level of $25
million in 2000 and 1999. Dividends paid to preferred shareholders decreased
from $29 million in 1998 to $25 million in 1999, primarily as a result of
redemptions.

     As previously discussed, the Utility has suspended payment of its common
and preferred dividends. Dividends on preferred stock are cumulative. Until
cumulative dividends on preferred stock are paid, the Utility may not pay any
dividends on its common stock.

PG&E National Energy Group


Operating Income

     Operating income at the NEG increased $1,509 million in 2000 as compared to
1999, primarily related to the charge to write PG&E GTT down to its net
realizable value in 1999 with no similar charge occurring in 2000. Additionally,
all business units reflected improved operating results over the prior year,
despite a $22 million charge related to the relocation of the energy trading
operations from Houston, Texas, to Bethesda, Maryland.

     Operating income of the NEG decreased $62 million in 1999 as compared to
1998, excluding the charge to write PG&E GTT down to its net realizable value.
The decline resulted from mild weather in the Northeast, lower interruptible
transport revenue in the Pacific Northwest, less portfolio management activity,
and trading losses in the U.S. gas portfolio. This decline was partially offset
by cost containment efforts across the organization and an increase in the
differential between natural gas liquids prices and the cost of natural gas.

Operating Revenues
<PAGE>

     The NEG operating revenues increased $5,003 million in 2000 compared to
1999. The NEG has focused its trading efforts on asset management and higher-
margin trades, resulting in increased trading volume of electric commodities
principally in the Southeast and Midwest. In addition, increases in the price of
power and gas have resulted in increased revenues.

     The NEG's 1999 operating revenues increased $939 million as compared to
1998, principally due to: (1) the PG&E Gen business segment receiving a full
year of revenue from the New England assets acquired in September 1998, and (2)
increases in trading revenues at PG&E ET reflecting the further maturation of
its business. The 1999 operating revenues also reflected revenue increases at
PG&E GTT resulting from an improved differential between the natural gas liquids
prices and the incoming natural gas. These revenue increases were partially
offset by (1) a decline in interruptible revenues in the Northwest due to the
lower natural gas prices in the Southwest as compared to Canadian prices, and
(2) lower transportation revenue on the Texas transmission system.

Operating Expenses

     Operating expenses at the NEG increased $3,494 million in 2000 compared to
the prior year. The increase results from the increased trading volumes
discussed above, and increases in the cost of power and gas, partially offset by
reduced depreciation and amortization expense at PG&E GTT reflective of the
disposal of the PG&E GTT assets.

     The NEG's operating expenses increased $2,276 million in 1999 as compared
to 1998, due to the charge associated with the disposition of PG&E GTT, a full
year of operating expenses associated with the generation facilities in New
England, and growth of PG&E ET operations.

Dividends

     The NEG currently intends to retain any future earnings to fund the
development and growth of its business. Further, the NEG is precluded from
paying dividends, unless it meets certain financial tests. Therefore, it is not
anticipating paying any cash dividends on its common stock in the foreseeable
future.
<PAGE>

REGULATORY MATTERS

     A significant portion of PG&E Corporation's operations is regulated by
federal and state regulatory commissions. These commissions oversee service
levels and, in certain cases, PG&E Corporation's revenues and pricing for its
regulated services. Following are the percentages of 2000 revenues that fell
under the jurisdiction of these various regulatory agencies:

                                                       Utility      Consolidated

          Cost of service-based                          96.3%           39.2%
          Market                                          3.7%           60.8%

     The Utility is the only subsidiary with significant regulatory proceedings
at this time. The Utility's significant regulatory proceedings are discussed
below. Regulatory proceedings associated with electric industry restructuring
are discussed above in "The California Energy Crisis." See Note 2 of the Notes
to the Consolidated Financial Statements.

The Utility's General Rate Case

     The CPUC authorizes an amount known as "base revenues" to be collected from
ratepayers to recover the Utility's basic business and operational costs for its
gas and electric distribution operations. Base revenues, which include non-fuel-
related operating and maintenance costs, depreciation, taxes, and a return on
invested capital, currently are authorized by the CPUC in GRC proceedings. The
CPUC's final decision in the Utility's 1999 GRC application increased annual
electric distribution revenues by $163 million and annual gas distribution
revenues by $93 million over 1998 authorized base revenues.

     In March 2000, two interveners filed applications for rehearing of the 1999
GRC decision, alleging that the CPUC committed legal errors by approving funding
in certain areas that were not adequately supported by record evidence. In April
2000, the Utility filed its response to these applications for rehearing,
defending the GRC decision against the allegations of error. A CPUC decision on
the applications for rehearing is pending.

     In the 1999 GRC decision the CPUC ordered that the Utility file a 2002 GRC.
As a result of the current energy crisis, the procedural schedule has been
delayed pending the CPUC's resolution of the Utility's request that it be
permitted to file an alternative schedule or an alternative to the 2002 GRC. An
earlier decision initially delaying the schedule affirms that rates would still
become effective on January 1, 2002, although the CPUC decision may not be
rendered until after that date.

Order Instituting Investigation (OII) into Holding Company Activities

     On April 3, 2001, the CPUC issued an order instituting an investigation
into whether the California investor-owned utilities, including the Utility,
have complied with past CPUC decisions, rules, or orders authorizing their
holding company formations and/or governing affiliate transactions, as well as
applicable statutes. The order states that the CPUC will investigate (1) the
utilities' transfer of money to their holding companies since deregulation of
the electric industry commenced, including during times when their utility
subsidiaries were experiencing financial difficulties; (2) the failure of the
holding companies to financially assist the utilities when needed; (3) the
transfer by the holding companies' of assets to unregulated subsidiaries; and
(4) the holding companies' action to "ring fence" their unregulated
subsidiaries. The CPUC will also determine whether additional rules, conditions,
or changes are needed to adequately protect ratepayers and the public from
dangers of abuse stemming from the holding company structure. The CPUC will
investigate whether it should modify, change, or add conditions to the holding
company decisions, make further changes to the holding company structure, alter
the standards under which the CPUC determines whether to authorize the formation
of holding companies, otherwise modify the decisions, or recommend statutory
changes to the California Legislature. As a result of the investigation, the
CPUC may impose remedies (including penalties), prospective rules, or
conditions, as appropriate. PG&E Corporation and the Utility believe that they
have complied with applicable statutes, CPUC decisions, rules, and orders. As
described above, on April 6, 2001, the Utility filed a voluntary petition for
relief under Chapter 11 of the U.S. Bankruptcy Code. PG&E Corporation and the
Utility believe that to the extent the CPUC seeks to investigate past conduct
for compliance purposes, the investigation is automatically stayed by the
bankruptcy
<PAGE>

filing. Neither the Utility nor PG&E Corporation can predict what the outcome of
the investigation will be or whether the outcome will have a material adverse
effect on their results of operation or financial condition.

The Utility's 2001 Attrition Rate Adjustment (ARA)

     In July 2000, the Utility filed an ARA application with the CPUC to
increase its 2001 electric distribution revenues by $189 million, effective
January 1, 2001. The increase reflects inflation and the growth in capital
investments necessary to serve customers. The Utility did not request an
increase in gas distribution revenues. In December 2000, the CPUC issued an
interim order finding that a decision on the application cannot be rendered by
January 1, 2001, and determining that if attrition relief is eventually granted,
that relief will be effective as of January 1, 2001. Hearings are scheduled to
begin in June 2001, and a CPUC decision is expected by January 2002.

The Utility's Cost of Capital Proceedings

     Each year, the Utility files an application with the CPUC to determine the
authorized rate of return that the Utility may earn on its electric and gas
distribution assets and recover from ratepayers. Since February 17, 2000, the
Utility's adopted return on common equity (ROE) has been 11.22% on electric and
gas distribution operations, resulting in an authorized 9.12% overall rate of
return (ROR). The Utility's earlier adopted ROE was 10.6%. The adopted ROR for
2000 resulted in an increase of approximately $49 million over 1999 electric and
gas distribution revenues. In May 2000, the Utility filed an application with
the CPUC to establish its authorized ROR for electric and gas distribution
operations for 2001. The application requests an ROE of 12.4%, and an overall
ROR of 9.75%. If granted, the requested ROR would increase electric distribution
revenues by approximately $72 million and gas distribution revenues by
approximately $23 million. The application also requests authority to implement
an Annual Cost of Capital Adjustment Mechanism for 2002 through 2006 that would
replace the annual cost of capital proceedings. The proposed adjustment
mechanism would modify the Utility's cost of capital based on changes in an
interest rate index. The Utility also proposes to maintain its currently
authorized capital structure of 46.2% long-term debt, 5.8% preferred stock, and
48% common equity. In March 2001, the CPUC issued a proposed decision
recommending no change to the current 11.22% ROE for test year 2001. This
authorized ROE results in a corresponding 9.12% return on rate base and no
change in the Utility's electric or gas revenue requirement for 2001. A final
CPUC decision is expected in the second quarter of 2001.

The Utility's FERC Transmission Rate Cases

     Since April 1998, electric transmission revenues have been authorized by
the FERC, including various rates to recover transmission costs from the
Utility's former bundled retail transmission customers. The FERC has not yet
acted upon a settlement filed by the Utility that, if approved, would allow the
Utility to recover $345 million in electric transmission rates for the 14-month
period of April 1, 1998 through May 31, 1999. During this period, somewhat
higher rates have been collected, subject to refund. A FERC order approving this
settlement is expected by the end of 2001. The Utility has accrued $24 million
for potential refunds related to the period ended May 31, 1999. In April 2000,
the FERC approved a settlement that permits the Utility to recover $264 million
in electric transmission rates retroactively for the 10-month period from May
31, 1999 to March 31, 2000. In September 2000, the FERC approved another
settlement that permits the Utility to recover $340 million annually in electric
transmission rates and made this retroactive to April 1, 2000. Further, in
November 2000, the FERC accepted, subject to refund, the Utility's proposal to
collect $397 million annually in electric transmission rates beginning on May 6,
2001.

The Utility's Catastrophic Event Memorandum Account Proceeding

     In April 2000, the CPUC approved a settlement agreement in a proceeding
addressing the Catastrophic Events Memorandum Account. The settlement provided
for a $59 million increase in electric distribution revenue requirement and an
$11 million increase in gas distribution revenue requirement which was collected
through rates during 2000. The increase compensates the Utility for costs
incurred for several emergencies, including the 1991 Oakland Hills Fire and the
1998 storms.

The Utility's Electric Base Revenue Increase Proceeding

     Section 368(e) of the California Public Utilities Code was adopted as part
of the California electric industry restructuring legislation. It provided for
an increase in the Utility's electric base revenues for 1997 and 1998, for
enhancement of transmission and distribution system safety and reliability. In
accordance with Section 368(e), the CPUC
<PAGE>

authorized a 1997 base revenue increase of $164 million. For 1998, the CPUC
authorized an additional base revenue increase of $77 million. Section 368(e)
expenditures are subject to review by the CPUC.

     In July 1999, the Office of Ratepayer Advocates; a division of the CPUC,
(ORA) recommended a disallowance of $88.4 million in Section 368(e) expenditures
for 1997 and 1998. In August 1999, The Utility Reform Network (TURN) recommended
an additional $14 million disallowance for a total recommended disallowance for
1997 and 1998 expenditures of $102.4 million. The Utility opposed the
recommended disallowances and hearings were held in October 1999. It is
uncertain when a proposed decision will be issued by the CPUC. Any proposed
decision would be subject to comment by the parties and change by the CPUC
before a final decision is issued. The Utility does not expect a material impact
on its financial position or results of operations resulting from these matters.

The Utility's Performance-Based Ratemaking (PBR) Application

     In June 2000, the CPUC granted the Utility's request to withdraw its PBR
application filed in November 1998. The Utility had requested the withdrawal in
accordance with the 1999 GRC decision issued in February 2000, which required a
2002 GRC before a PBR mechanism could be implemented. In closing the PBR
proceeding, the CPUC ordered the Utility to file a new PBR application by
September 2000. This application would propose financial rewards and penalties
associated with utility performance in meeting prescribed standards for measures
such as electric reliability and customer service.

     In September 2000, the Utility filed an application with the CPUC to
establish (1) performance standards and associated financial rewards and
penalties for electric and gas distribution service, (2) a revenue-sharing
mechanism for new categories of non-tariffed products and services (NTP&S)
offered by the Utility, and (3) ratemaking for proceeds from sales or transfers
of certain non-generation related land. The performance standards would cover a
period of five years commencing January 1, 2001. The total maximum annual reward
or penalty is $54 million per year, consisting of $52 million for electric
distribution and $2 million for gas distribution. The revenue-sharing mechanism
proposes to share net positive after-tax revenues from new categories of NTP&S
equally between ratepayers and shareholders. Finally, the Utility requested that
the CPUC establish basic rules about the allocation of gains and losses from the
Utility's non-generation-related land sales. In November 2000, the CPUC
suspended the proceeding until further notice.

MUNICIPALIZATION AND OTHER COMPETITION

     With the uncertainties over future electric utility rates due to the
California energy crisis, municipalization is under consideration by many local
governments in California. Municipalization is the attempt by cities and local
utility districts to take over markets from private, investor-owned utility
companies. Local governments in California are increasingly looking at entering
the utility business as a source of new revenue. Those that already have
municipal utilities are examining expansion to provide new services or to sell
existing services outside of their current boundaries. Municipalization efforts
in San Francisco, Berkeley, and San Diego (among several other California
cities) are being pursued by grass roots organizations and proposals to
municipalize may go before voters. We cannot currently predict what the outcome
will be from these actions.

     As wholesale electric prices increase, alternatives to the current model
become more attractive. These alternative technologies, such as distributed
generation which enables siting of smaller electric generation facilities in
close proximity to the electric demand, have the potential to strand Utility
investment and make recovery more challenging. The CPUC has opened a rulemaking
proceeding to examine various issues concerning distributed generation,
including interconnection issues, who can own and operate distributed
generation, environmental impacts, the role of utility distribution companies,
and the rate design and cost allocation issues associated with the deployment of
distributed generation facilities. This rulemaking is also intended to address
other areas of potential electric competition, such as billing services. There
has been little activity in this rulemaking since its issuance in 1999.

ENVIRONMENTAL MATTERS

     We are subject to laws and regulations established to both maintain and
improve the quality of the environment. Where our properties contain hazardous
substances, these laws and regulations require us to remove those substances or
remedy effects on the environment. See Note 15 of the Notes to the Consolidated
Financial Statements for further discussion of environmental matters.

Utility
<PAGE>

     The Utility records an environmental remediation liability when site
assessments indicate remediation is probable and a range of reasonably likely
clean-up costs can be estimated. The Utility reviews its remediation liability
quarterly for each identified site. The liability is an estimate of costs for
site investigations, remediation, operations and maintenance, monitoring, and
site closure. The remediation costs also reflect (1) current technology, (2)
enacted laws and regulations, (3) experience gained at similar sites, and (4)
the probable level of involvement and financial condition of other potentially
responsible parties. Unless there is a better estimate within this range of
possible costs, the Utility records the lower end of this range.

     At December 31, 2000, the Utility expects to spend $320 million,
undiscounted, for hazardous waste remediation costs at identified sites,
including divested fossil-fueled power plants. The cost of the hazardous
substance remediation ultimately undertaken by the Utility is difficult to
estimate. A change in the estimate may occur in the near term due to uncertainty
concerning the Utility's responsibility, the complexity of environmental laws
and regulations, and the selection of compliance alternatives. If other
potentially responsible parties are not financially able to contribute to these
costs or further investigation indicates that the extent of contamination or
necessary remediation is greater than anticipated, the Utility could spend as
much as $462 million on these costs. The Utility estimates the upper limit of
the range using assumptions least favorable to the Utility, based upon a range
of reasonably possible outcomes. Costs may be higher if the Utility is found to
be responsible for clean-up costs at additional sites or expected outcomes
change.

     The Utility had an environmental remediation liability of $320 million and
$271 million at December 31, 2000 and 1999, respectively. The $320 million
accrued at December 31, 2000 includes (1) $114 million related to the pre-
closing remediation liability, associated with divested generation facilities
(see further discussion in the "Generation Divestiture" section of Note 2 of the
Notes to the Consolidated Financial Statements), and (2) $180 million related to
remediation costs for those generation facilities that the Utility still owns,
manufactured gas plant sites, and gas gathering compressor stations. Of the $320
million environmental remediation liability, the Utility has recovered $168
million through rates, and expects to recover another $87 million in future
rates. The Utility is seeking recovery of the remainder of its costs from
insurance carriers and from other third parties as appropriate.

     In December 1999, the Utility was notified by the purchaser of its former
Moss Landing power plant that it had identified a cleaning procedure used at the
plant that released heated water from the intake, and that this procedure is not
specified in the plant's National Pollutant Discharge Elimination System (NPDES)
permit issued by the Central Coast Regional Water Quality Control Board (Central
Coast Board). The purchaser notified the Central Coast Board of its findings. In
March 2000, the Central Coast Board requested the Utility to provide specific
information regarding the "backflush" procedure used at Moss Landing. The
Utility provided the requested information to the Board in April 2000. The
Utility's investigation indicated that while it owned Moss Landing, significant
amounts of water were discharged from the cooling water intake. While the
Utility's investigation did not clearly indicate that discharged waters had a
temperature higher than ambient receiving water, the Utility believes that the
temperature of the discharged water was higher than that of the ambient
receiving water. In December 2000, the executive officer of the Central Coast
Board made a settlement proposal to the Utility under which the Utility would
pay $10 million, a portion of which would be used for environmental projects and
the balance of which would constitute civil penalties. Settlement negotiations
are continuing.

     The Utility's Diablo Canyon employs a "once through" cooling water system
which is regulated under a NPDES Permit issued by the Central Coast Board. This
permit allows Diablo Canyon to discharge the cooling water at a temperature no
more than 22 degrees above ambient receiving water and requires that the
beneficial uses of the water be protected. The beneficial uses of water in this
region include industrial water supply, marine and wildlife habitat, shell fish
harvesting, and preservation of rare and endangered species. In January 2000,
the Central Coast Board issued a proposed draft Cease and Desist Order (CDO)
alleging that, although the temperature limit has never been exceeded, the
Diablo Canyon's discharge was not protective of beneficial uses. In October
2000, the Central Coast Board and the Utility reached a tentative settlement of
this matter pursuant to which the Central Coast Board has agreed to find that
the Utility's discharge of cooling water from the Diablo Canyon plant protects
beneficial uses and that the intake technology reflects "best technology
available" under Section 316(b) of the Federal Clean Water Act. As part of the
settlement, the Utility will take measures to preserve certain acreage north of
the plant and will fund approximately $5 million in environmental projects
related to coastal resources. The parties are negotiating the documentation of
the settlement. The final agreement will be subject to public comment and will
be incorporated in a consent decree to be entered in California Superior Court.

     The Utility believes the ultimate outcome of these matters will not have a
material impact on the Utility's financial position or results of operations.
<PAGE>

PG&E National Energy Group

     In October and November 1999, the U.S. Environmental Protection Agency
(EPA) and several states filed suits or announced their intention to file suits
against a number of coal-fired power plants in Midwestern and Eastern states.
These suits relate to alleged violations of the Clean Air Act. More
specifically, they allege violations of the deterioration prevention and non-
attainment provisions of the Clean Air Act's new source review requirements
arising out of certain physical changes that may have been made at these
facilities without first obtaining the required permits. In May 2000 the NEG
received a request for information seeking detailed operating and maintenance
histories for the Salem Harbor and Brayton Point power plants. If EPA were to
find that there were physical changes in the past that were undertaken without
first receiving the required permits under the Clean Air Act, then penalties may
be imposed and further emission reductions might be necessary at these plants.

     In addition to the EPA, states may impose more stringent air emissions
requirements. The Commonwealth of Massachusetts is considering the adoption of
more stringent air emission reductions from electric generating facilities. If
adopted, these requirements will impact Salem Harbor and Brayton Point. The NEG
has proposed an emission reduction plan that may include modernization of the
Salem Harbor power plant and use of advanced technologies for emissions removal.
It is also studying various advanced technologies for emissions removal for the
Brayton Point power plant.

     The NEG's subsidiary, USGenNE, has proposed a number of state and regional
initiatives that will require it to achieve significant reductions of emissions
by 2010. The NEG expects that USGenNE will meet these requirements through a
combination of installation of controls, use of emission allowances it currently
owns, and purchase of additional allowances. The NEG currently estimates that
USGenNE's total capital cost for complying with these requirements will be
approximately $300 million.

     PG&E Gen's existing power plants, including USGenNE facilities, are subject
to federal and state water quality standards with respect to discharge
constituents and thermal effluents. Three of the fossil-fueled plants owned and
operated by USGenNE are operating pursuant to NPDES permits that have expired.
For the facilities whose NPDES permits have expired, permit renewal applications
are pending. It is anticipated that all three facilities will be able to
continue to operate under existing terms and conditions until new permits are
issued. It is estimated that USGenNE's cost to comply with the new permit
conditions could be as much as $55 million through 2005. It is possible that the
new permits may contain more stringent limitations than prior permits.

     During September 2000, USGenNE signed a series of agreements that require,
among other things, that USGenNE alter its existing waste water treatment
facilities at two facilities by replacing certain unlined treatment basins,
submit and implement a plan for the closure of such basins, and perform certain
environmental testing at the facilities. USGenNE has incurred $4 million in 2000
and expects to complete the required steps on or before December 2001. The total
expected cost of these improvements is $21 million.

Inflation

     Financial statements, which are prepared in accordance with accounting
principles generally accepted in the United States of America, report operating
results in terms of historical costs and do not evaluate the impact of
inflation. Inflation affects our construction costs, operating expenses, and
interest charges. In addition, the Utility's electric revenues do not reflect
the impact of inflation due to the current electric rate freeze. However,
inflation at current levels is not expected to have a material adverse impact on
PG&E Corporation's or the Utility's financial position or results of operations.

Quantitative and Qualitative Disclosures About Market Risk


Price Risk Management Activities

     We have established a risk management policy that allows derivatives to be
used for both trading and non-trading purposes (a derivative is a contract whose
value is dependent on or derived from the value of some underlying asset). We
use derivatives for hedging purposes primarily to offset PG&E Corporation's or
the Utility's primary market risk exposures, which include commodity price risk,
interest rate risk, and foreign currency risk. We also participate in markets
using derivatives to gather market intelligence, create liquidity, and maintain
a market presence. Such derivatives
<PAGE>

include forward contracts, futures, swaps, options, and other contracts. Net
open positions often exist or are established due to PG&E Corporation's and the
Utility's assessment of their responses to changing market conditions. To the
extent that PG&E Corporation has an open position, it is exposed to the risk
that fluctuating market prices may adversely impact its financial results.

     PG&E Corporation and the Utility may only engage in the trading of
derivatives in accordance with policies established by the PG&E Corporation Risk
Management Committee. Trading is permitted only after the Risk Management
Committee authorizes such activity subject to appropriate financial exposure
limits. Under PG&E Corporation, both the NEG and the Utility have their own Risk
Management Committees that address matters relating to those companies'
respective businesses. These Risk Management Committees are comprised of senior
officers.

Market Risk


Commodity Price Risk

     Commodity price risk is the risk that changes in market prices will
adversely affect earnings and cash flows. PG&E Corporation is primarily exposed
to the commodity price risk associated with energy commodities such as
electricity and natural gas. Therefore, PG&E Corporation's price risk management
activities primarily involve buying and selling fixed-price commodity
commitments into the future.

     In compliance with regulatory requirements, the Utility manages price risk
independently from the activities in PG&E Corporation's unregulated business.
Price risk activities consist of the use of non-trading (hedging) financial
instruments to reduce the impact of commodity price fluctuations for electricity
and natural gas. While the use of these instruments has been authorized by the
CPUC, the CPUC has yet to establish rules around how it will judge the
reasonableness of these instruments. Gains and losses associated with the use of
the majority of these financial instruments primarily affect regulatory
accounts, depending on the business unit and the specific program involved.

     In response to high wholesale electricity costs experienced during the
summer of 2000, the CPUC in August 2000 eliminated the requirement to procure
electricity in the spot market and authorized the Utility to enter into
"bilateral agreements" with third parties. These contracts are used to purchase
electricity from non-PX sources at fixed prices for terms that may extend to the
end of 2005. The purpose of bilateral contracts is to lock in supply and rates
on the future purchase of electricity and to reduce price volatility.

     The CPUC has authorized the Utility to trade natural gas-based financial
instruments to manage price and revenue risks associated with its natural gas
transmission and storage assets, subject to certain conditions. Furthermore, the
Utility was authorized to trade natural gas-based financial instruments to hedge
the gas commodity price swings in serving core gas customers.

     PG&E Corporation's business units measure commodity price risk exposure
using value-at-risk and other methodologies that simulate future price movements
in the energy markets to estimate the size and probability of future potential
losses. We quantify market risk using a variance/co-variance value-at-risk model
that provides a consistent measure of risk across diverse energy markets and
products. The use of this methodology requires a number of important
assumptions, including the selection of a confidence level for losses,
volatility of prices, market liquidity, and a holding period.

     PG&E Corporation uses historical data for calculating the price volatility
of our positions and how likely the prices of those positions will move
together. The model includes all derivatives and commodity investments in our
trading portfolios and only derivative commodity investments for our non-trading
portfolio (but not the related underlying hedged position). PG&E Corporation and
the Utility express value-at-risk as a dollar amount of the potential loss in
the fair value of our portfolios based on a 95% confidence level using a one-day
liquidation period. Therefore, there is a 5% probability that the Company's
portfolios will incur a loss in one day greater than its value-at-risk. The
value-at-risk is aggregated for PG&E Corporation as a whole by correlating the
daily returns of the portfolios for electricity and natural gas for the previous
22 trading days.

     The following tables illustrate the value-at-risk for PG&E Corporation's
daily commodity price risk exposure for the year ended December 31:
<PAGE>

<TABLE>
<CAPTION>
                                                                  2000                         1999
                                                                  ----                         ----
                                                        Trading      Non-Trading     Trading      Non-Trading
                                                                        (Dollars in millions)
<S>                                                     <C>          <C>             <C>         <C>
NEG:
               Value at End of Period                    $11.5           $  8.8        $4.4             $ --
               Average                                     6.8              9.5         4.3              0.6
               Low                                         5.5              7.6         1.3               --
               High                                       12.3             11.1         6.2              1.7

Utility:
               Value at End of Period                       --            187.4          --              3.2
               Average                                      --             24.2          --              4.0
               Low                                          --              0.1          --              2.9
               High                                         --            207.8          --              5.7
</TABLE>

     Value-at-risk has several limitations as a measure of portfolio risk,
including, but not limited to, underestimation of the risk of a portfolio with
significant options exposure, inadequate indication of the exposure of a
portfolio to extreme price movements, and the inability to address the risk
resulting from intra-day trading activities.

Interest Rate Risk

     PG&E Corporation and the Utility are exposed to the following types of
interest rate exposure:

     Floating rate exposure measures the sensitivity of corporate earnings and
cash flows to changes in short-term interest rates. This exposure arises when
short-term debt is rolled over at maturity, when interest rates on floating rate
notes are periodically reset according to a formula or index, and when floating
rate assets are financed with fixed rate liabilities. PG&E Corporation manages
its exposure to short-term interest rates by using an appropriate mix of short-
term debt, long-term floating rate debt, and long-term fixed rate debt.

     Financing exposure measures the effect of an increase in interest rates
that may occur related to any planned or expected fixed rate debt financing.
This includes the exposure associated with replacing debt at maturity. PG&E
Corporation will hedge financing exposure in situations where the potential
impairment of earnings, cash flows, and investment returns or execution
efficiency, or external factors (such as bank imposed credit agreements)
necessitate hedging.

     Refunding exposure measures the effect of an increase in interest rates on
the ability to economically refund a callable debt instrument. Corporate bonds
typically are issued with a call feature that allows the issuer to retire and
replace the bonds at a lower rate if interest rates have fallen. The value of
this call feature to the issuer declines with increases in interest rates. PG&E
Corporation will hedge refunding exposure when it is economic to repurchase all
or part of the underlying debt instrument and replace it with a debt instrument
that has lower cost during its remaining life. The guideline for a refunding to
be economic is that the net present value savings should exceed 5% of the par
value of the debt to be refunded and the refunding efficiency should exceed 85%.

     PG&E Corporation and the Utility use interest rate swaps to manage their
interest rate exposure. Interest rate risk sensitivity analysis is used to
measure PG&E Corporation's interest rate price risk by computing estimated
changes in the fair value in the event of assumed changes in market interest
rates. As of December 31, 2000, if interest rates had averaged 1% higher, it was
estimated that earnings would have decreased by approximately $24 million.

Foreign Currency Risk

     PG&E Corporation is exposed to the following types of foreign currency
risk:

     Economic exposure measures the change in value that results from changes in
future operating or investing cash flows caused by the timing and level of
anticipated foreign currency flows. Economic exposure includes the anticipated
purchase of foreign entities, anticipated cash flows, projected revenues and
expenses denominated in a foreign currency.
<PAGE>

     Transaction exposure measures changes in value of current outstanding
financial obligations already incurred, but not due to be settled until some
future date. This includes the agreement to purchase a foreign entity in a
currency other than the U.S. dollar, an obligation to infuse equity capital into
a foreign entity, foreign currency denominated debt obligations, as well as
actual non-U.S. dollar cash flows such as dividends declared but not yet paid.

     Translation exposure measures potential accounting derived changes in
owners' equity that result from translating a foreign affiliate's financial
statements from its functional currency to U.S. dollars for PG&E Corporation's
consolidated financial statements.

     PG&E Corporation's primary foreign currency exchange rate exposure was with
the Canadian dollar. The following instruments are used to hedge foreign
currency exposures: forwards, swaps, and options. Based on a sensitivity
analysis at December 31, 2000, a 10% devaluation of the Canadian dollar would be
immaterial to PG&E Corporation's consolidated financial statements.

New Accounting Standards

     PG&E Corporation and the Utility will adopt SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities,"
effective January 1, 2001. The Statement will require us to recognize all
derivatives, as defined in the Statement, on the balance sheet at fair value.
Derivatives, or any portions thereof, that are not effective hedges must be
adjusted to fair value through income. If derivatives are effective hedges,
depending on the nature of the hedges, changes in the fair value of derivatives
either will be offset against the change in fair value of the hedged assets,
liabilities, or firm commitments through earnings, or will be recognized in
other comprehensive income until the hedged items are recognized in earnings.
PG&E Corporation estimates that the transition adjustment to implement this new
standard will be an immaterial reduction of net earnings and a negative
adjustment of $377 million to other comprehensive income. The Utility estimates
that the transition adjustment to implement this new standard will be an
immaterial reduction of net earnings and a positive adjustment of $44 million to
other comprehensive income. These adjustments will be recognized as of January
1, 2001 as a cumulative effect of a change in accounting principle. The ongoing
effects will depend on the future market conditions and hedging activities at
PG&E Corporation and the Utility.

     PG&E Corporation and the Utility have certain derivative commodity
contracts for the physical delivery of purchase quantities transacted in the
normal course of business. At this time, these derivatives are exempt from the
requirements of SFAS No. 133 under the normal purchases and sales exception, and
thus will not be reflected on the balance sheet at fair value. The Derivative
Implementation Group of the Financial Accounting Standards Board is currently
evaluating the definition of normal purchases and sales. As such, certain
derivative commodity contracts may no longer be exempt from the requirements of
SFAS No. 133. PG&E Corporation and the Utility will evaluate the impact of the
implementation guidance on a prospective basis when the final decision regarding
this issue is resolved.

Legal Matters

     In the normal course of business, both the Utility and PG&E Corporation are
named as parties in a number of claims and lawsuits. See Note 15 of the Notes to
the Consolidated Financial Statements for further discussion of significant
pending legal matters.
<PAGE>

                               PG&E Corporation
                     STATEMENTS OF CONSOLIDATED OPERATIONS
                    (in millions, except per share amounts)

<TABLE>
<CAPTION>
                                                                                                Year ended December 31,
                                                                                                -----------------------
                                                                                            2000          1999          1998
<S>                                                                                      <C>          <C>           <C>
Operating Revenues
Utility                                                                                  $ 9,637       $ 9,228       $ 8,924
Energy commodities and services                                                           16,595        11,592        10,653

         Total operating revenues                                                         26,232        20,820        19,577

Operating Expenses
Cost of energy for utility                                                                 8,166         3,149         2,942
Deferred electric procurement cost                                                        (6,465)           --            --
Cost of energy commodities and services                                                   15,220        10,587         9,852
Operating and maintenance                                                                  3,520         3,151         3,083
Depreciation, amortization, and decommissioning                                            3,659         1,780         1,602
Loss on assets held for sale                                                                  --         1,275            --
Provision for loss on generation-related regulatory assets and undercollected
purchased power costs                                                                      6,939            --            --

         Total operating expenses                                                         31,039        19,942        17,479

Operating Income (Loss)                                                                   (4,807)          878         2,098
Interest income                                                                              266           118           101
Interest expense                                                                            (788)         (772)         (781)
Other income (expense), net                                                                  (23)           37           (36)

Income (Loss) Before Income Taxes                                                         (5,352)          261         1,382
Income taxes provision (benefit)                                                          (2,028)          248           611

Income (Loss) from continuing operations                                                 $(3,324)      $    13       $   771
Discontinued operations (Note 5)
Loss from operations of PG&E Energy Services (net of applicable income taxes of
$0 million, $35 million, and $41 million, respectively)                                       --           (40)          (52)
Loss on disposal of PG&E Energy Services (net of applicable income taxes of
$36 million, $36 million, and $0 million, respectively)                                      (40)          (58)           --

Net income (loss) before cumulative effect of a change in accounting principle
(Note 1)                                                                                  (3,364)          (85)          719
Cumulative effect of a change in an accounting principle (net of applicable income
taxes of $8 million)                                                                          --            12            --

Net Income (Loss)                                                                        $(3,364)      $   (73)      $   719

Weighted average common shares outstanding                                                   362           368           382
Earnings (Loss) Per Common Share, Basic and Diluted
         Income (Loss) from continuing operations                                        $ (9.18)      $  0.04       $  2.02
         Discontinued operations                                                           (0.11)        (0.27)        (0.14)
         Cumulative effect of a change in an accounting principle                             --          0.03            --

Net Earnings (Loss)                                                                      $ (9.29)      $ (0.20)      $  1.88

Dividends Declared Per Common Share                                                      $  1.20       $  1.20       $  1.20
</TABLE>

The accompanying Notes to the Consolidated Financial Statements are an integral
                            part of this statement.
<PAGE>

                               PG&E Corporation
                          CONSOLIDATED BALANCE SHEETS
                      (in millions, except share amounts)

<TABLE>
<CAPTION>
                                                                                                        Balance at
                                                                                                        December 31,
                                                                                                 -------------------------
                                                                                                    2000            1999
<S>                                                                                              <C>              <C>
ASSETS
Current Assets
   Cash and cash equivalents                                                                     $    899         $    281
   Short-term investments                                                                           1,634              187
   Accounts receivable
        Customers (net of allowance for doubtful accounts of $71 million
         and $65 million, respectively)                                                             2,131            1,486
        Energy marketing                                                                            2,211              532
        Regulatory balancing accounts                                                                 222               --
   Price risk management                                                                            2,039              400
   Inventories                                                                                        392              433
   Income taxes receivable                                                                          1,241               --
   Prepaid expenses and other                                                                         406              255

        Total current assets                                                                       11,175            3,574
Property, Plant, and Equipment
   Utility                                                                                         23,872           23,001
   Non-utility
        Electric generation                                                                         2,008            1,905
        Gas transmission                                                                            1,542            2,541
   Construction work in progress                                                                      900              436
   Other                                                                                              147              184

        Total property, plant, and equipment (at original cost)                                    28,469           28,067
        Accumulated depreciation and decommissioning                                              (11,878)         (11,291)

        Net property, plant, and equipment                                                         16,591           16,776
Other Noncurrent Assets
   Regulatory assets                                                                                1,773            4,957
   Nuclear decommissioning funds                                                                    1,328            1,264
   Price risk management                                                                            2,026              329
   Other                                                                                            2,398            2,570

        Total noncurrent assets                                                                     7,525            9,120

TOTAL ASSETS                                                                                     $ 35,291         $ 29,470
</TABLE>
<PAGE>

                               PG&E Corporation
                          CONSOLIDATED BALANCE SHEETS
                      (in millions, except share amounts)


<TABLE>
<CAPTION>
                                                                                                       Balance at
                                                                                                       December 31,
                                                                                                       ------------
                                                                                                     2000         1999
<S>                                                                                               <C>            <C>
LIABILITIES AND EQUITY
Current Liabilities
   Short-term borrowings                                                                            $ 4,530      $ 1,499
   Long-term debt, classified as current                                                              2,391          558
   Current portion of rate reduction bonds                                                              290          290
   Accounts payable
        Trade creditors                                                                               3,760          708
        Energy marketing                                                                              2,096          480
        Regulatory balancing accounts                                                                   196          384
        Other                                                                                           459          559
   Accrued taxes                                                                                         --          211
   Price risk management                                                                              1,999          323
   Other                                                                                              1,563        1,058

        Total current liabilities                                                                    17,284        6,070
Noncurrent Liabilities
   Long-term debt                                                                                     4,736        6,682
   Rate reduction bonds                                                                               1,740        2,031
   Deferred income taxes                                                                              1,656        3,147
   Deferred tax credits                                                                                 192          231
   Price risk management                                                                              1,867          207
   Other                                                                                              3,864        3,436

        Total noncurrent liabilities                                                                 14,055       15,734
Preferred Stock of Subsidiaries                                                                         480          480
Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely
Utility Subordinated Debentures                                                                         300          300
Common Stockholders' Equity
   Common stock, no par value, authorized 800,000,000 shares, issued 387,193,727 and
384,406,113 shares, respectively                                                                      5,971        5,906
   Common stock held by subsidiary, at cost, 23,815,500 shares                                         (690)        (690)
   Reinvested earnings (Accumulated Deficit)                                                         (2,105)       1,674
   Accumulated other comprehensive income (loss)                                                         (4)          (4)

        Total common stockholders' equity                                                             3,172        6,886

Commitments and Contingencies (Notes 1, 2, 3, 7, 14, and 15)                                             --           --

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                                                          $35,291      $29,470
</TABLE>

The accompanying Notes to the Consolidated Financial Statements are an integral
                            part of this statement.
<PAGE>

                               PG&E Corporation
                     STATEMENTS OF CONSOLIDATED CASH FLOWS
                                 (in millions)

<TABLE>
<CAPTION>
                                                                                              For the year ended December 31,
                                                                                              -------------------------------
                                                                                           2000            1999            1998
<S>                                                                                    <C>           <C>              <C>
Cash Flows From Operating Activities
Net income (loss)                                                                       $(3,364)        $   (73)        $   719
Adjustments to reconcile net (loss) income to net cash provided (used) by
operating activities:
                Depreciation, amortization, and decommissioning                           3,659           1,780           1,602
                Deferred electric procurement costs                                      (6,465)             --              --
                Deferred income taxes and tax credits--net                                 (767)           (754)           (107)
                Other deferred charges and noncurrent liabilities                           256             102              18
                Provision for loss on generation-related regulatory assets and
                 undercollected purchased power costs                                     6,939              --              --
                Loss on assets held for sale                                                 --           1,275              --
                Loss regulatory assets from discontinued operations                          40              98              52
                Cumulative effect of change in accounting principle                          --             (12)             --
                Net effect of changes in operating assets and liabilities:
                        Short-term investments                                           (1,447)           (132)          1,105
                        Accounts receivable--trade                                       (2,324)            370            (342)
                        Inventories                                                          41              23             (33)
                        Income tax receivable                                            (1,241)             --              --
                        Price risk management assets and liabilities, net                    30             (28)            (16)
                        Accounts payable                                                  4,568            (293)            247
                        Regulatory balancing accounts                                      (410)            305             537
                        Accrued taxes                                                      (211)            108            (123)
                        Other working capital                                               324             209             199
                Other--net                                                                 (404)           (823)           (470)

Net cash (used) provided by operating activities                                           (776)          2,155           3,388

Cash Flows From Investing Activities
Capital expenditures                                                                     (1,758)         (1,584)         (1,619)
Acquisitions                                                                                 --              --          (1,779)
Proceeds from sale of assets                                                                415           1,014           1,106
Other--net                                                                                  373             453              66

Net cash used by investing activities                                                      (970)           (117)         (2,226)

Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities                                       2,846            (145)          2,115
Long-term debt issued                                                                     1,023              --              --
Long-term debt matured, redeemed, or repurchased                                         (1,155)           (798)         (1,552)
Preferred stock redeemed or repurchased                                                      --              --            (108)
Common stock issued                                                                          65              54              63
Common stock repurchased                                                                     (2)           (693)         (1,158)
Dividends paid                                                                             (436)           (465)           (470)
Other--net                                                                                   23               4              (3)

Net cash provided (used) by financing activities                                          2,364          (2,043)         (1,113)

Net Change in Cash and Cash Equivalents                                                     618              (5)             49
Cash and Cash Equivalents at January 1                                                      281             286             237

Cash and Cash Equivalents at December 31                                                $   899         $   281         $   286

Supplemental disclosures of cash flow information
                Cash paid for:
                Interest (net of amounts capitalized)                                   $   719         $   727         $   774
                Income taxes (net of refunds)                                                20             723             770
Supplemental disclosures of non-cash investing and financing
                Retirement of long-term debt in the sale of PG&E Gas
                 Transmission--Texas                                                        564              --              --
</TABLE>

The accompanying Notes to the Consolidated Financial Statements are an integral
                            part of this statement.
<PAGE>

                               PG&E Corporation
                STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
                      (in millions, except share amounts)

<TABLE>
<CAPTION>
                                                    Common        Reinvested                                    Total       Compre-
                                                     Stock          Earnings                 Accumulated       Common       hensive
                                    Common         Held by      (Accumulated         Other Comprehensive        Stock        Income
                                     Stock      Subsidiary          Deficit)               Income (Loss)       Equity        (Loss)
<S>                               <C>           <C>             <C>               <C>                        <C>           <C>
Balance December 31, 1997         $  6,366        $     --          $  2,543                   $    (12)     $  8,897      $     --
Net income                              --              --               719                         --           719           719
Foreign currency translation
 adjustment                             --              --                --                          6             6             6

Comprehensive income                    --              --                --                         --            --      $    725

Common stock issued (2,028,303
 shares)                                63              --                --                         --            63
Common stock repurchased
 (37,090,630 shares)                  (565)             --              (593)                        --        (1,158)
Cash dividends declared on
 common stock                           --              --              (466)                        --          (466)
Other                                   (2)             --                 7                         --             5

Balance December 31, 1998            5,862              --             2,210                         (6)        8,066
Net loss                                --              --               (73)                        --           (73)     $    (73)
Foreign currency translation
 adjustment                             --              --                --                          2             2             2

Comprehensive loss                      --              --                --                         --                    $    (71)

Common stock issued (1,879,474
 shares)                                54              --                --                         --            54
Common stock repurchased
 (23,892,425 shares)                    (2)           (690)               (1)                        --          (693)
Cash dividends declared on
 common stock                                                           (460)                        --          (460)
Other                                   (8)             --                (2)                        --           (10)

Balance December 31, 1999            5,906            (690)            1,674                         (4)        6,886
Net loss                                --              --            (3,364)                        --        (3,364)     $ (3,364)

Common stock issued (2,847,269
 shares)                                65              --                --                         --            65
Common stock repurchased
 (59,655 shares)                        (1)             --                (1)                        --            (2)
Cash dividends declared on
 common stock                           --              --              (434)                        --          (434)
Other                                    1              --                20                         --            21

Balance December 31, 2000         $  5,971        $   (690)         $ (2,105)                  $     (4)     $  3,172
</TABLE>

The accompanying Notes to the Consolidated Financial Statements are an integral
                            part of this statement.
<PAGE>

                        Pacific Gas and Electric Company
                     STATEMENTS OF CONSOLIDATED OPERATIONS
                                 (in millions)

<TABLE>
<CAPTION>
                                                                                               Year ended December 31,
                                                                                               -----------------------
                                                                                               2000        1999        1998
<S>                                                                                        <C>           <C>        <C>
Operating Revenues
Electric                                                                                    $ 6,854      $7,232      $7,191
Gas                                                                                           2,783       1,996       1,733

            Total operating revenues                                                          9,637       9,228       8,924

Operating Expenses
Cost of electric energy                                                                       6,741       2,411       2,321
Deferred electric procurement cost                                                           (6,465)         --          --
Cost of gas                                                                                   1,425         738         621
Operating and maintenance                                                                     2,687       2,522       2,668
Depreciation, amortization, and decommissioning                                               3,511       1,564       1,438
Provision for loss on generation-related regulatory assets and undercollected
 purchased power costs                                                                        6,939          --          --

            Total operating expenses                                                         14,838       7,235       7,048

Operating Income (Loss)                                                                      (5,201)      1,993       1,876
Interest income                                                                                 186          45          96
Interest expense                                                                               (619)       (593)       (621)
Other income (expense), net                                                                      (3)         (9)          7

Income (Loss) Before Income Taxes                                                            (5,637)      1,436       1,358
Income taxes provision (benefit)                                                             (2,154)        648         629

Net Income (Loss)                                                                            (3,483)        788         729
Preferred dividend requirement                                                                   25          25          27

Income (Loss) Available for (Allocated to) Common Stock                                     $(3,508)     $  763      $  702

</TABLE>

The accompanying Notes to the Consolidated Financial Statements are an integral
                            part of this statement.
<PAGE>

                        Pacific Gas and Electric Company
                          CONSOLIDATED BALANCE SHEETS
                      (in millions, except share amounts)

<TABLE>
<CAPTION>
                                                                                                    Balance at
                                                                                                    December 31,
                                                                                                    ------------
                                                                                                     2000             1999
<S>                                                                                            <C>             <C>
ASSETS
Current Assets
              Cash and cash equivalents                                                          $    111         $     80
              Short-term investments                                                                1,283               21
              Accounts receivable
                    Customers (net of allowance for doubtful accounts of $52 million
and $46 million, respectively)                                                                      1,711            1,201
                    Related parties                                                                     6                9
                    Regulatory balancing account                                                      222               --
              Inventories
                    Gas stored underground and fuel oil                                               146              139
                    Materials and supplies                                                            134              155
              Income taxes receivable                                                               1,120               --
              Prepaid expenses and other                                                               45               34
              Deferred income taxes                                                                    --              119

              Total current assets                                                                  4,778            1,758
Property, Plant, and Equipment
              Electric                                                                             16,335           15,762
              Gas                                                                                   7,537            7,239
              Construction work in progress                                                           249              214

              Total property, plant, and equipment (at original cost)                              24,121           23,215
              Accumulated depreciation and decommissioning                                        (11,120)         (10,497)

Net property, plant, and equipment                                                                 13,001           12,718
Other Noncurrent Assets
              Regulatory assets                                                                     1,716            4,895
              Nuclear decommissioning funds                                                         1,328            1,264
              Other                                                                                 1,165              835

              Total noncurrent assets                                                               4,209            6,994

TOTAL ASSETS                                                                                     $ 21,988         $ 21,470
</TABLE>
<PAGE>

                       Pacific Gas and Electric Company
                          CONSOLIDATED BALANCE SHEETS
                      (in millions, except share amounts)

<TABLE>
<CAPTION>
                                                                                                     Balance at
                                                                                                    December 31,
                                                                                                    ------------
                                                                                                       2000         1999
<S>                                                                                                 <C>          <C>
LIABILITIES AND EQUITY
Current Liabilities
   Short-term borrowings                                                                            $ 3,079      $   449
   Long-term debt, classified as current                                                              2,374          465
   Current portion of rate reduction bonds                                                              290          290
   Accounts payable
    Trade creditors                                                                                   3,688          577
    Related parties                                                                                     138          216
    Regulatory balancing accounts                                                                       196          384
    Other                                                                                               363          333
   Accrued taxes                                                                                         --          118
   Deferred income taxes                                                                                172           --
   Other                                                                                                670          529

   Total current liabilities                                                                         10,970        3,361
Noncurrent Liabilities
   Long-term debt                                                                                     3,342        4,877
   Rate reduction bonds                                                                               1,740        2,031
   Deferred income taxes                                                                                929        2,510
   Deferred tax credits                                                                                 192          231
   Other                                                                                              2,968        2,252

   Total noncurrent liabilities                                                                       9,171       11,901
Preferred Stock With Mandatory Redemption Provisions
   6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009                                         137          137
Company Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility
 Subordinated Debentures
   7.90%, 12,000,000 shares due 2025                                                                    300          300
Stockholders' Equity
   Preferred stock without mandatory redemption provisions
    Nonredeemable--5% to 6%, outstanding 5,784,825 shares                                               145          145
    Redeemable--4.36% to 7.04%, outstanding 5,973,456 shares                                            149          149
   Common stock, $5 par value, authorized 800,000,000 shares, issued 321,314,760 shares               1,606        1,606
   Common stock held by subsidiary, at cost, 19,481,213 shares and 7,627,765 shares,
    respectively                                                                                       (475)        (200)
   Additional paid-in capital                                                                         1,964        1,964
   Reinvested earnings (Accumulated Deficit)                                                         (1,979)       2,107

   Total stockholders' equity                                                                         1,410        5,771
Commitments and Contingencies (Notes 1, 2, 7, 14, and 15)                                                --           --

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                                                          $21,988      $21,470
</TABLE>

The accompanying Notes to the Consolidated Financial Statements are an integral
                            part of this statement.
<PAGE>

                       Pacific Gas and Electric Company
                     STATEMENTS OF CONSOLIDATED CASH FLOWS
                                 (in millions)

<TABLE>
<CAPTION>
                                                                                             For the year ended
                                                                                                December 31,
                                                                                                ------------
                                                                                           2000            1999            1998
<S>                                                                                     <C>             <C>             <C>
Cash Flows From Operating Activities
Net income (loss)                                                                       $(3,483)        $   788         $   729
Adjustments to reconcile net income to net cash (used) provided by operating
 activities:
    Depreciation, amortization, and decommissioning                                       3,511           1,564           1,438
    Deferred electric procurement costs                                                  (6,465)             --              --
    Deferred income taxes and tax credits--net                                             (930)           (485)           (257)
    Other deferred charges and noncurrent liabilities                                       480             101              31
    Provision for loss on generation-related regulatory assets and
     undercollected purchased power costs                                                 6,939              --              --
    Net effect of changes in operating assets and liabilities:
      Short-term investments                                                             (1,262)             (4)          1,126
      Accounts receivable                                                                  (507)            187             266
      Income taxes receivable                                                            (1,120)             --              --
      Accounts payable                                                                    3,063              15             203
      Regulatory balancing accounts                                                        (410)            305             537
      Accrued taxes                                                                        (118)            116            (227)
      Other working capital                                                                 125             (39)            (71)
    Other--net                                                                             (522)           (352)            (39)

Net cash (used) provided by operating activities                                           (699)          2,196           3,736

Cash Flows From Investing Activities
Capital expenditures                                                                     (1,245)         (1,181)         (1,382)
Proceeds from sale of assets                                                                  6           1,014             501
Other--net                                                                                   32             234              40

Net cash used by investing activities                                                    (1,207)             67            (841)

Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities                                       2,630            (219)            668
Long-term debt issued                                                                       680              --              --
Long-term debt matured, redeemed, or repurchased                                           (597)           (672)         (1,413)
Preferred stock redeemed or repurchased                                                      --              --            (108)
Common stock repurchased                                                                   (275)           (926)         (1,600)
Dividends paid                                                                             (475)           (440)           (444)
Other--net                                                                                  (26)              1              (5)

Net cash provided (used) by financing activities                                          1,937          (2,256)         (2,902)

Net Change in Cash and Cash Equivalents                                                      31               7              (7)
Cash and Cash Equivalents at January 1                                                       80              73              80

Cash and Cash Equivalents at December 31                                                $   111         $    80         $    73

Supplemental disclosures of cash flow information
   Cash paid for:
   Interest (net of amounts capitalized)                                                $   587         $   531         $   600
   Income taxes (net of refunds)                                                             --           1,001           1,115
</TABLE>

The accompanying Notes to the Consolidated Financial Statements are an integral
                            part of this statement.
<PAGE>

                       Pacific Gas and Electric Company
                STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
                      (in millions, except share amounts)

<TABLE>
<CAPTION>
                                                                                                              Preferred
                                                                                     Accumulated                Stock
                                                Addi-      Common       Reinvested      Other       Total      Without      Compre-
                                                tional      Stock        Earnings      Compre-      Common    Mandatory     hensive
                                      Common   Paid-in     Held by     (Accumulated    hensive      Stock    Redemption     Income
                                       Stock   Capital   Subsidiary      Deficit)       (Loss)      Equity   Provisions     (Loss)
<S>                                   <C>      <C>       <C>           <C>           <C>          <C>        <C>            <C>
Balance December 31, 1997             $2,018    $2,564     $  --         $ 2,671         $--        7,253       $402
Net income                                --        --        --             729          --          729         --        $   729
Foreign currency translation
 adjustments                              --        --        --              --          (1)          (1)        --             (1)

Comprehensive income                      --        --        --              --          --           --         --        $   728

Common stock repurchased
 (62,150,837 shares)                    (311)     (481)       --            (808)         --       (1,600)        --
Preferred stock redeemed
 (4,323,948 shares)                       --        (7)       --              (3)         --          (10)       (98)
Cash dividends declared
   Preferred stock                        --        --        --             (28)         --          (28)        --
   Common stock                           --        --        --            (300)         --         (300)        --
Other                                     --        11        --              --          --           11        (10)

Balance December 31, 1998             $1,707    $2,087        --         $ 2,261          (1)     $ 6,054       $294
Net income                                --        --        --             788          --          788         --        $   788
Foreign currency translation
 adjustments                              --        --        --              --           1            1         --              1

Comprehensive income                      --        --        --              --          --           --         --        $   789


Common stock repurchased
 (27,666,460 shares)                    (101)     (123)     (200)           (502)         --         (926)        --
Cash dividends declared
   Preferred stock                        --        --        --             (25)         --          (25)        --
   Common stock                           --        --        --            (415)         --         (415)        --

Balance December 31, 1999             $1,606    $1,964     $(200)        $ 2,107          --      $ 5,477       $294
Net loss                                  --        --        --          (3,483)         --       (3,483)        --        $(3,483)

Common stock repurchased
 (11,853,448 shares)                      --        --      (275)             --          --         (275)        --
Cash dividends declared
   Preferred stock                        --        --        --             (25)         --          (25)        --
   Common stock                           --        --        --            (578)         --         (578)        --

Balance December 31, 2000             $1,606    $1,964     $(475)        $(1,979)        $--      $ 1,116       $294
</TABLE>

The accompanying Notes to the Consolidated Financial Statements are an integral
                            part of this statement.
<PAGE>

                NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1: General



Basis of Presentation

     PG&E Corporation was incorporated in California in 1995 and became the
holding company of Pacific Gas and Electric Company (the Utility) on January 1,
1997. The Utility, incorporated in California in 1905, is the predecessor of
PG&E Corporation. Effective with PG&E Corporation's formation, the Utility's
interests in its unregulated subsidiaries were transferred to PG&E Corporation.
As discussed further in Notes 2 and 3, on April 6, 2001, the Utility filed a
voluntary petition for relief under provisions of Chapter 11 of the U.S.
Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility
retains control of its assets and is authorized to operate its business as a
debtor in possesion while being subject to the jurisdiction of the Bankruptcy
Court.

     This is a combined annual report of PG&E Corporation and the Utility.
Therefore, the Notes to the Consolidated Financial Statements apply to both PG&E
Corporation and the Utility. PG&E Corporation's consolidated financial
statements include the accounts of PG&E Corporation, the Utility, and PG&E
Corporation's wholly owned and controlled subsidiaries. The Utility's
consolidated financial statements include its accounts as well as those of its
wholly owned and controlled subsidiaries. All significant inter-company
transactions have been eliminated from the consolidated financial statements.

     The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions. These estimates and assumptions
affect the reported amounts of revenues, expenses, assets, and liabilities and
the disclosure of contingencies. Actual results could differ from these
estimates.

     Accounting principles used include those necessary for rate-regulated
enterprises, which reflect the ratemaking policies of the California Public
Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).

Operations

     PG&E Corporation is an energy-based holding company headquartered in San
Francisco, California. PG&E Corporation's Northern and Central California energy
utility subsidiary, the Utility, delivers electric service to approximately 4.6
million customers and natural gas service to approximately 3.8 million
customers. PG&E Corporation's PG&E National Energy Group, Inc. (NEG) markets
energy services and products throughout North America.

     The NEG is an integrated energy company with a strategic focus on power
generation, new power plant development, natural gas transmission, and wholesale
energy marketing and trading in North America. NEG businesses include its power
plant development and generation unit, PG&E Generating Company, LLC and its
affiliates (collectively, PG&E Gen); its natural gas transmission unit, PG&E Gas
Transmission Corporation (PG&E GT); and its wholesale energy and marketing
trading unit, PG&E Energy Trading Holdings Corporation, which owns PG&E Energy
Trading-Gas Corporation and PG&E Energy Trading-Power, L.P. (collectively, PG&E
Energy Trading or PG&E ET). During 2000, NEG sold its energy services unit, PG&E
Energy Services Corporation (PG&E ES). Also, during the fourth quarter of 2000,
NEG sold its Texas natural gas and natural gas liquids business carried on
through PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco,
Inc. and their subsidiaries (PG&E GTT).

Cash Equivalents and Short-Term Investments

     Cash equivalents (stated at cost, which approximates market) include
working funds and consist primarily of Eurodollar time deposits, bankers'
acceptances, and commercial paper with original maturities of three months or
less when purchased.
<PAGE>

Restricted Cash

     Restricted cash includes cash and cash equivalents, as defined above, which
are restricted under the terms of certain agreements for payment to third
parties, primarily for debt service. Restricted cash included under Cash and
Cash Equivalents in PG&E Corporation's and the Utility's Consolidated Balance
Sheets as of December 31, 2000 and 1999 is as follows:

          (in millions)                                  2000      1999

          Utility                                       $  50     $  42
          National Energy Group                            53        81


Inventories

     Inventories include materials and supplies, gas stored underground, coal,
and fuel oil. Materials and supplies, coal, and gas stored underground are
valued at average cost, except for the gas storage inventory of PG&E ET, which
is recorded at fair value. Fuel oil is valued by the last-in first-out method.

Income Taxes

     PG&E Corporation and the Utility use the liability method of accounting for
income taxes. Income tax expense (benefit) includes current and deferred income
taxes resulting from operations during the year. Tax credits are amortized over
the life of the related property.

     PG&E Corporation files a consolidated federal income tax return that
includes domestic subsidiaries in which its ownership is 80% or more. The
Utility and various other subsidiaries are parties to a tax-sharing arrangement
with PG&E Corporation. PG&E Corporation files consolidated state income tax
returns when applicable. The Utility reports taxes on a stand-alone basis.

Earnings (Loss) Per Share

     Basic earnings (loss) per share is computed by dividing net income (loss)
by the weighted average number of common shares outstanding during the period.
Diluted earnings per share is computed by dividing net income (loss) by the
weighted average number of common shares outstanding plus the assumed issuance
of common shares for all potentially dilutive securities.

     The following is a reconciliation of PG&E Corporation's net income (loss)
and weighted average common shares outstanding for calculating basic and diluted
net income (loss) per share.

<TABLE>
<CAPTION>
                                                                                Years ended December 31,
                                                                                -----------------------
       <S>                                                                  <C>            <C>          <C>
       (in millions)                                                           2000         1999          1998

       Income (loss) from continuing operations                             $(3,324)      $   13        $  771
       Discontinued operations                                                  (40)         (98)          (52)

       Net income (Loss) before cumulative effect of accounting
        change                                                               (3,364)         (85)          719
       Cumulative effect of accounting change                                    --           12            --

       Net Income (Loss)                                                    $(3,364)      $  (73)       $  719


       Earnings (Loss) per common share, Basic and Diluted:
       Weighted average common shares outstanding                               362          368           382
</TABLE>
<PAGE>

<TABLE>
       <S>                                                                  <C>           <C>           <C>
       Income (Loss) from continuing operations                             $ (9.18)      $ 0.04        $ 2.02
       Discontinued operations                                                (0.11)       (0.27)        (0.14)
       Cumulative effect of accounting change                                    --         0.03            --

       Net Income (Loss)                                                    $ (9.29)      $(0.20)       $ 1.88
</TABLE>

     The diluted share base for 2000 excludes incremental shares of 2 million
related to employee stock options. These shares are excluded due to the anti-
dilutive effect as a result of the loss from continuing operations. For 1999 and
1998, the assumed conversion of stock options issued under the long-term
incentive plan increased the weighted average shares outstanding for dilutive
purposes to 369 million and 383 million, respectively. PG&E Corporation reflects
the preferred dividends of subsidiaries as other expense for computation of both
basic and diluted earnings per share.

Property, Plant, and Equipment

     Plant additions and replacements are capitalized. The capitalized costs
include labor, materials, construction overhead, and capitalized interest or an
allowance for funds used during construction (AFUDC). AFUDC is the estimated
cost of debt and equity funds used to finance regulated plant additions.
Capitalized interest and AFUDC for PG&E Corporation amounted to $19 million, $18
million, and $28 million for the years ended December 31, 2000, 1999, and 1998,
respectively. Capitalized interest and AFUDC for the Utility amounted to $18
million, $16 million, and $26 million for the years ended December 31, 2000,
1999, and 1998, respectively. Nuclear fuel inventories are included in property,
plant, and equipment. Stored nuclear fuel inventory is stated at lower of
average cost or market. Nuclear fuel in the reactor is amortized based on the
amount of energy output.

     The original cost of retired plant and removal costs less salvage value is
charged to accumulated depreciation upon retirement of plant in service for the
Utility and the NEG businesses that apply Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," as amended. For the remainder of the NEG business operations, the
cost and accumulated depreciation of property, plant, and equipment retired or
otherwise disposed of is removed from related accounts and included in the
determination of the gain or loss on disposition.

     Property, plant, and equipment are depreciated using a straight-line
remaining-life method. PG&E Corporation's composite depreciation rates were
4.44%, 3.60%, and 3.89% for the years ended December 31, 2000, 1999, and 1998,
respectively. The Utility's composite depreciation rates were 4.54 %, 3.41%, and
3.88% for the years ended December 31, 2000, 1999, and 1998, respectively.
Estimated useful lives of property, plant, and equipment are as follows:

<TABLE>
<CAPTION>
                                                                          Utility            Non-Utility
       <S>                                                             <C>                  <C>
       Electric generating facilities                                  20 to 50 years       20 to 50 years
       Electric distribution facilities                                10 to 63 years                  N/A
       Electric transmission                                           27 to 65 years                  N/A
       Gas distribution facilities                                     28 to 49 years                  N/A
       Gas transmission                                                25 to 45 years       22 to 40 years
       Gas storage                                                     25 to 48 years                  N/A
       Other                                                            5 to 38 years         2 to 7 years
</TABLE>

     The useful life of the Utility's property, plant, and equipment complies
with CPUC-authorized ranges.

Capitalized Software Costs

     Costs incurred during the application development stage of internal use
software projects are capitalized. At December 31, 2000 and 1999, capitalized
software costs totaled $235 million and $216 million, net of $80 million and $59
million accumulated amortization, respectively. Such capitalized amounts are
amortized in accordance with
<PAGE>

regulatory requirements ratably over the expected lives of the projects when
they become operational, over periods ranging from 2 to 15 years.

Gains and Losses on Reacquired Debt

     Gains and losses on reacquired debt associated with regulated operations
that are subject to the provisions of SFAS No. 71 are deferred and amortized
over the remaining original amortization period of the debt reacquired,
consistent with ratemaking principles. Gains and losses on reacquired debt
associated with unregulated operations are recognized in earnings as
extraordinary gains or losses at the time such debt is reacquired.

Intangible Assets and Asset Impairment

     PG&E Corporation amortizes the excess of purchase price over fair value of
net assets of businesses acquired (goodwill) using the straight-line method over
periods ranging from 5 to 40 years. PG&E Corporation periodically assesses
goodwill and intangible assets for potential impairment.

     PG&E Corporation and the Utility periodically evaluate long-lived assets,
including property, plant, and equipment, goodwill, and specifically
identifiable intangible assets, when events or changes in circumstances indicate
that the carrying value of these assets may be impaired. The determination of
whether impairment has occurred is based on an estimate of undiscounted cash
flows attributable to the assets, as compared to the carrying value of the
assets.

     In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed of," requires PG&E Corporation
and the Utility to write off regulatory assets when they are no longer probable
of recovery. On an ongoing basis, PG&E Corporation and the Utility review their
regulatory assets and liabilities for the continued applicability of SFAS No. 71
and the effect of SFAS No. 121.

Regulation and Statement of Financial Accounting Standards (SFAS) No. 71

     The Utility is regulated by the CPUC, the FERC, and the Nuclear Regulatory
Commission (NRC), among others. The gas transmission business in the Pacific
Northwest is regulated by the FERC.

     PG&E Corporation and the Utility account for the financial effects of
regulation in accordance with SFAS No. 71. This statement allows for the
recording of a regulatory asset or liability for costs that will be collected or
refunded through the ratemaking process in the future.

     Regulatory assets comprise the following:

<TABLE>
<CAPTION>
                                                                                            Balance at
                                                                                           December 31,
                                                                                           ------------
       (in millions)                                                                       2000       1999
       <S>                                                                               <C>        <C>
       Rate Reduction Bonds/(1)/                                                         $1,178     $  727
       Unamortized loss, net of gain, on reacquired debt                                    342        376
       Regulatory assets for deferred income tax                                            160        705
       Transition Revenue Account/(1)/                                                       --         69
       Transition Cost Balancing Account/(1)/                                                --        220
       Diablo Canyon/(1)/                                                                    --      1,891
       Other, net                                                                            36        907

       Total Utility regulatory assets                                                   $1,716     $4,895
       PG&E GTN                                                                              57         62

       Total PG&E Corporation regulatory assets                                          $1,773     $4,957
</TABLE>

(1)  See Note 2 of the Notes to the Consolidated Financial Statements for
     further discussion.
<PAGE>

     Regulatory assets are amortized over the period that the costs are
reflected in regulated revenues. The Utility has amortized its eligible
generation-related transition costs, including the Transition Cost Balancing
Account (TCBA) and the regulatory assets related to Diablo Canyon, over the
transition period in conjunction with the available competition transition
charge (CTC) revenues.

     During 2000, the energy crisis materially and adversely affected PG&E
Corporation's and the Utility's cash flow and liquidity and created substantial
uncertainty about their prospects for the future. As a result, the Utility can
no longer conclude that energy costs, which have been deferred on its balance
sheet in accordance with SFAS No. 71, are probable of recovery through future
rates. Accordingly, the Utility wrote off the generation-related transition
costs and undercollected purchased power costs at December 31, 2000 (see Note 2
of the Notes to the Consolidated Financial Statements).

     In general, the Utility does not earn a return on regulatory assets where
the related costs do no accrue interest. At December 31, 2000, the Utility did
not earn a return on the regulatory asset related to recording deferred taxes as
required by SFAS No. 109 "Accounting for Income Taxes" of $160 million. During
2000, all other assets that did not earn a return were recovered or written off
as referred to above.

     At December 31, 1999, the Utility did not earn a return on (1) the $410
million regulatory asset related to recording deferred taxes as required by SFAS
No. 109, (2) the regulatory asset related to the Western Area Power
Administration contract of $86 million, and (3) a regulatory asset related to
the generation portion of certain employee benefits of $15 million.

Revenues and Regulatory Balancing Accounts

     For gas utility revenues, sales balancing accounts accumulate differences
between authorized and actual base revenues. Further, gas cost balancing
accounts accumulate differences between the actual cost of gas and the revenues
designated for recovery of such costs. The regulatory balancing accounts
accumulate balances until they are refunded to or received from Utility
customers through authorized rate adjustments. Utility revenues included amounts
for services rendered but unbilled at the end of each year.

Revenue Recognition

     Revenues derived from power generation are recognized upon output, product
delivery, or satisfaction of specific targets, all as specified by contractual
terms. Regulated gas transmission revenues are recorded as services are
provided, based on rate schedules approved by the FERC. Substantially all of
PG&E ET's operations are accounted for under a mark-to-market accounting
methodology.

     Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition," was issued
by the Securities and Exchange Commission (SEC), on December 3, 1999. SAB No.
101, as amended, summarizes certain of the SEC staff's views in applying
accounting principles generally accepted in the United States of America to
revenue recognition in financial statements. PG&E Corporation's consolidated
financial statements reflect the accounting principles provided in SAB No. 101.

Accounting for Price Risk Management Activities

     PG&E Corporation, primarily through its subsidiaries, engages in price risk
management activities for both trading and non-trading purposes. PG&E
Corporation conducts trading activities principally through its unregulated
lines of business. Trading activities are conducted to generate profit, create
liquidity, and maintain a market presence. Net open positions often exist or are
established due to the NEG's assessment of and response to changing market
conditions. Non-trading activities are conducted to optimize and secure the
return on risk capital deployed within the NEG's existing asset and contractual
portfolio. In addition, non-trading activity exists within the Utility to hedge
against price fluctuations of electricity and natural gas.

     Derivative and other financial instruments associated with electricity,
natural gas, natural gas liquids, and related trading activities are accounted
for using the mark-to-market method of accounting. Under mark-to-market
accounting, PG&E Corporation's trading contracts, including both physical
contracts and financial instruments, are recorded at market value, which
approximates fair value. The market prices used to value these transactions
reflect management's best estimates considering various factors, including
market quotes, time value, and volatility factors of the underlying

                                       43
<PAGE>

commitments. The values are adjusted to reflect the potential impact of
liquidating a position in an orderly manner over a reasonable period of time
under present market conditions.

     Changes in the market value of these contract portfolios, resulting
primarily from newly originated transactions and the impact of commodity price
or interest rate movements, are recognized in operating income in the period of
change. Unrealized gains and losses on these contract portfolios are recorded as
assets and liabilities, respectively, from price risk management.

     In addition to the trading activities, as discussed previously, PG&E
Corporation may engage in non-trading activities using futures, forward
contracts, options, and swaps to hedge the impact of market fluctuations on
energy commodity prices, interest rates, and foreign currencies when there is a
high degree of correlation between price movements in the derivative and the
item designated as being hedged. PG&E Corporation accounts for non-trading
transactions under the deferral method. Initially, PG&E Corporation defers
unrealized gains and losses on these transactions and classifies them as assets
or liabilities. When the underlying item settles, PG&E Corporation recognizes
the gain or loss in operating expense. In instances where the anticipated
correlation of price movements does not occur, hedge accounting is terminated
and future changes in the value of the derivative are recognized as gains or
losses. If the hedged item is sold, the value of the associated derivative is
recognized in income.

     PG&E Corporation and the Utility will adopt SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities"
effective January 1, 2001. The Statement will require PG&E Corporation and the
Utility to recognize all derivatives, as defined in the Statement, on the
balance sheet at fair value. Derivatives, or any portion thereof, that are not
effective hedges must be adjusted to fair value through income. If derivatives
are effective hedges, depending on the nature of the hedges, changes in the fair
value of derivatives either will be offset against the change in fair value of
the hedged assets, liabilities, or firm commitments through earnings, or will be
recognized in other comprehensive income until the hedged items are recognized
in earnings. PG&E Corporation estimates that the transition adjustment to
implement this new standard will be a non-material reduction of net earnings and
a negative adjustment of $377 million to other comprehensive income. The Utility
estimates that the transition adjustment to implement this new standard will be
a non-material reduction of net earnings and a negative adjustment of $44
million to other comprehensive income. These adjustments will be recognized as
of January 1, 2001 as a cumulative effect of a change in accounting principle.
The ongoing effects will depend on the future market conditions and hedging
activities at PG&E Corporation and the Utility.

     PG&E Corporation and the Utility have certain derivative commodity
contracts for the physical delivery of purchase quantities transacted in the
normal course of business. At this time, these derivatives are exempt from the
requirements of SFAS No. 133 under the normal purchases and sales exception, and
thus will not be reflected on the balance sheet at fair value. The Derivative
Implementation Group of the Financial Accounting Standards Board is currently
evaluating the definition of normal purchases and sales. As such, certain
derivative commodity contracts may no longer be exempt from the requirements of
SFAS No. 133. PG&E Corporation and the Utility will evaluate the impact of the
implementation guidance on a prospective basis when the final decision regarding
this issue is resolved.

Comprehensive Income

     PG&E Corporation's and the Utility's comprehensive income consists of net
income and other items recorded directly to the equity accounts. The objective
is to report a measure of all changes in equity of an enterprise that result
from transactions and other economic events of the period other than
transactions with shareholders. PG&E Corporation's and the Utility's other
comprehensive income consists principally of foreign currency translation
adjustments and will include changes in the market value of certain financial
hedges upon the implementation of SFAS No. 133 on January 1, 2001. See
Accounting for Price Risk Management Activities above for discussion of
implementation of SFAS No. 133.

Cumulative Effect of Change in Accounting Method

     Effective January 1, 1999, PG&E Corporation changed its method of
accounting for major maintenance and overhauls of generating assets at the NEG.
Beginning January 1, 1999, the cost of major maintenance and overhauls of
generating assets, principally at the PG&E Gen business segment, were accounted
for as incurred. Previously, the estimated cost of major maintenance and
overhauls was accrued in advance in a systematic and rational manner over the
period between major maintenance and overhauls. The change resulted in PG&E
Corporation recording income of $12 million net of income tax ($0.03 per share)
as of December 31, 1999, reflecting the cumulative effect of the change in
accounting principle. The Utility has consistently accounted for major
maintenance and overhauls as incurred.

                                       44
<PAGE>

Related Party Agreements

     In accordance with various agreements, the Utility and other subsidiaries
provide and receive various services from their parent, PG&E Corporation. The
Utility and PG&E Corporation exchange administrative and professional support
services in support of operations. These services are priced at either the fully
loaded cost or at the higher of fully loaded cost or fair market value depending
on the nature of the services provided. PG&E Corporation also allocates certain
other corporate administrative and general costs to the Utility and other
subsidiaries using a variety of factors, including their share of employees,
operating expenses, assets, and other cost causal methods. Additionally, the
Utility purchases gas commodity and transmission services and sells reservation
and other ancillary services to the NEG. These services are priced at either
tariff rates or fair market value depending on the nature of the services
provided. Intercompany transactions are eliminated in consolidation and no
profit results from these transactions. For the years ended December 31, 2000,
1999, and 1998, the Utility's significant related party transactions were as
follows:

<TABLE>
<CAPTION>
       (in millions)                                                                   2000      1999      1998
       <S>                                                                            <C>       <C>       <C>
       Utility revenues from:
       Administrative services provided to PG&E Corporation                           $  12     $  23     $  17
       Transportation and distribution services provided to PG&E ES                      --       134        --
       Gas reservation services provided to PG&E ET                                      12         7         1
       Other                                                                              2         3         4
       Utility expenses from:
       Administrative services received from PG&E Corporation                         $  83     $  66     $  58
       Gas commodity and transmission services received from PG&E ET                    136        30         1
       Transmission services received from PG&E GT                                       46        47        49
</TABLE>

Stock-based Compensation

     PG&E Corporation accounts for stock-based compensation using the intrinsic
value method in accordance with the provisions of Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," as allowed by SFAS
No. 123, "Accounting for Stock-Based Compensation." Under the intrinsic value
method, PG&E Corporation does not recognize any compensation expense as the
exercise price of all stock options is equal to the fair market value at the
time the options are granted.

Reclassifications
     Certain amounts in 1999 and 1998 financial statements have been
reclassified to conform to the 2000 presentation.

Note 2: The California Energy Crisis

     In 1998, California became one of the first states in the country to
implement electric industry restructuring and establish a competitive market
framework for electric generation. Electric industry restructuring was mandated
by the California Legislature in Assembly Bill 1890 (AB 1890). The electric
industry restructuring established a transition period, mandated a rate freeze,
included a plan for recovery of uneconomic generation-related costs (transition
costs), and encouraged the disposition of a portion of utility-owned generation
facilities. The competitive market framework called for the creation of the
Power Exchange (PX) and the Independent System Operator (ISO). The PX would
establish market-clearing prices for electricity, and the ISO would schedule
delivery of electricity for all market participants and operate certain markets
for electricity. The Utility was required to purchase electricity for its
customers through the PX and ISO. Customers were given the choice of continuing
to buy electricity from the Utility or buying electricity from independent power
generators or retail electricity suppliers. Most of the Utility's customers
continued to buy electricity through the Utility.

     Beginning in June 2000, wholesale prices for electricity sold through the
PX and ISO experienced unanticipated and massive increases. The average price of
electricity purchased by the Utility for the benefit of its customers was 18.2
cents per kWh for the period of June 1 through December 31, 2000, compared to
4.2 cents per kWh during the same period in 1999. The Utility was only permitted
to collect approximately 5.4 cents per kWh in rates from its customers

                                       45
<PAGE>

during that period. The increased cost of the purchased electricity has strained
the financial resources of the Utility. Because of the rate freeze, the Utility
was unable to pass on the increases in power costs to its customers through
current rates. In order to finance the higher costs of energy, during the third
and fourth quarter of 2000, the Utility increased its lines of credit to $1,850
million (net increase of $850 million), issued $1,240 million of debt under a
364-day facility, and issued $680 million of five-year notes.

     The Utility continued to finance the higher costs of wholesale electric
power while interested parties evaluated various solutions to the energy crisis.
In November 2000, the Utility filed its Rate Stabilization Plan (RSP), which
sought to end the rate freeze and pass along the increased wholesale electric
costs to customers through increased rates. The CPUC evaluated the Utility's
proposal and deferred its decision until after hearings could be held, although
the CPUC did increase rates one cent per kWh for 90 days effective January 4,
2001. This increase resulted in approximately $70 million of additional revenue
per month, which was not nearly enough to cover the higher wholesale costs of
electricity, nor did it help with the costs already incurred.

     By December 31, 2000, the Utility had borrowed more than $3.0 billion under
its various credit facilities to pay its energy costs. As a result of the
California energy crisis and its impact on the Utility's financial resources,
PG&E Corporation's and the Utility's credit rating deteriorated to below
investment grade in January 2001. This credit downgrade precluded PG&E
Corporation and the Utility from access to capital markets. Commencing in
January 2001, PG&E Corporation and the Utility began to default on maturing
commercial paper. In addition, the Utility became unable to pay the full amount
of invoices received for wholesale power purchases and made only partial
payments. The Utility had no credit under which it could purchase wholesale
electricity on behalf of its customers on a continuing basis and generators were
only selling to the Utility under emergency actions taken by the U.S. Secretary
of Energy.

     In January 2001 the California Legislature and the Governor authorized the
California Department of Water Resources (DWR) to purchase wholesale electric
energy on behalf of the Utility's retail customers. In February 2001, the
California Legislature passed California Assembly Bill 1X (AB 1X), which
authorized the DWR to purchase wholesale electricity on behalf of the Utility's
customers.

     On March 27, 2001, the CPUC authorized an average increase in retail rates
of 3.0 cents per kWh, which was in addition to the emergency 1.0 cent per kWh
surcharge adopted on January 4, 2001 by the CPUC. The revenue generated by this
rate increase is to be used only for electric power procurement costs that are
incurred after March 27, 2001. Although the rate increase is authorized
immediately, the 3.0 cent surcharge will not be collected in rates until the
CPUC establishes the rate design which is not expected to be adopted until May
2001.

     As more fully described below, the energy crisis has materially and
adversely affected the Utility's cash flow and liquidity and has created
substantial uncertainty about their prospects for the future. As a result, the
Utility can no longer conclude that energy costs, which had been deferred on its
balance sheet in accordance with SFAS No. 71, are probable of recovery through
future rates. Accordingly, the Utility has taken a charge against earnings of
$6.9 billion ($4.1 billion after tax) to write off its remaining generation-
related regulatory assets and undercollected purchased power costs. This charge
has resulted in an accumulated deficit at the Utility of $2.0 billion as of
December 31, 2000. PG&E Corporation's accumulated deficit at December 31, 2000
is $2.1 billion. Further, the Utility does not have authority to recover any
purchased power costs it incurs during 2001 in excess of revenues from retail
rates. Such amounts also will be charged against earnings, as incurred, absent a
regulatory or legislative solution that provides for recovery of such costs.

     Under SFAS No. 71, if a rate mechanism provided by legislation or other
regulatory authority is subsequently established that makes recovery from
regulated rates probable as to all or a portion of the undercollection that was
previously charged against earnings, a regulatory asset will be reinstated with
a corresponding increase in earnings.

     As discussed more fully herein, the Utility is seeking resolution on many
fronts. The ongoing uncertainty and lack of successful resolution continues to
have a negative impact on the Utility's ability to obtain funding and pay its
debt and power procurement liabilities. As discussed further in Note 3, on April
6, 2001, the Utility sought protection from its creditors through a Chapter 11
bankruptcy filing. The filing for bankruptcy and the related uncertainty around
any reorganization plan that  is ultimately adopted will have a significant
impact on the Utility's future liquidity and results of operations. PG&E
Corporation, itself, had cash of $297 million at March 29, 2001 and believes
that the funds will be adequate to maintain its operations through and beyond
2001. In addition, PG&E Corporation believes that PG&E Corporation, itself, and
its other subsidiaries not subject to CPUC regulation are substantially
protected from the continuing liquidity and financial difficulties of the
Utility. A discussion of the events leading up to the charge, PG&E Corporation's
and the Utility's mitigation efforts and the ongoing uncertainty follows.

                                       46
<PAGE>

Transition Period and Rate Freeze

     California's deregulation legislation passed by the California Legislature
in 1996 established a transition period, which was to begin in 1998. During this
period, electric rates for all customers were frozen at 1996 levels, with rates
for residential and small commercial customers being reduced in 1998 by 10% and
frozen at that level. During the transition period, investor-owned utilities
were given the opportunity to recover their transition costs. Transition costs
were generation-related costs that proved to be uneconomic under the new
industry structure.

     To pay for the 10% rate reduction, the Utility refinanced $2.9 billion (the
expected revenue reduction from the rate decrease) of its transition costs with
the proceeds from the sale of rate reduction bonds. The bonds allow for the rate
reduction by lowering the carrying cost on a portion of the transition costs and
by deferring recovery of a portion of the transition costs until after the
transition period. During the rate freeze, the rate reduction bond debt service
did not increase the Utility customers' electric rates (See Note 9). If the
transition period ends before March 31, 2002, the Utility may be obligated to
return a portion of the economic benefits of the transaction to customers. The
timing of any such return and the exact amount of such portion, if any, have not
yet been determined.

     The rate freeze was scheduled to end on the earlier of March 31, 2002 or
the date the Utility has recovered all of its transition costs. The Utility
believes it recovered its eligible transition costs during August 2000 or
potentially earlier as a result of recording a credit to the Utility's account
for tracking the recovery of transition costs in recognition of the fair market
value of the Utility's hydroelectric generation facilities. On August 31, 2000,
the Utility recorded a $2.1 billion credit to the Utility's account for tracking
the recovery of the TCBA, which was an amount by which a negotiated $2.8 billion
hydroelectric generation asset valuation exceeded the aggregate book value of
such assets. At August 31, 2000, there was a balance of approximately $2.2
billion of undercollected wholesale electricity costs recorded in the regulatory
balancing account called the Transition Revenue Account (TRA). If the final
valuation for the hydroelectric assets is greater than $2.8 billion, as the
Utility expects, the Utility will have recovered its transition costs earlier.
The undercollected TRA balance as of the end of the earlier determined
transition period will be less than the August 31 balance of $2.2 billion, and
could be zero depending on the ultimate valuation of the hydroelectric
generating facilities and when the transition period actually ends. However, the
CPUC has not yet accepted the Utility's estimated market valuation of its
hydroelectric assets nor has the CPUC determined that the rate freeze has ended.

Wholesale Prices of Electricity

     As previously stated, beginning in June 2000, the Utility experienced
unanticipated and massive increases in the wholesale costs of the electricity
purchased from the PX and ISO on behalf of its retail customers. For the year
ended December 31, 2000 and 1999, the average monthly prices in cents per kWh
that the PX and ISO charged the Utility for electricity were as follows:


                                                   2000     1999

                 January                           4.38     3.15
                 February                          3.78     2.87
                 March                             3.24     2.87
                 April                             3.28     2.90
                 May                               6.08     2.82
                 June                             16.33     2.95
                 July                             11.00     3.85
                 August                           18.70     4.10
                 September                        13.82     4.09
                 October                          13.62     6.18
                 November                         20.43     4.46
                 December                         33.24     3.97


     It is expected that the wholesale costs will continue to be extremely high
through 2001 unless significant changes occur in the wholesale electricity
market. The generation-related cost component, which provides for recovery of

                                       47
<PAGE>

wholesale electricity purchased by the Utility and, if available, for recovery
of transition cost, was approximately 5.4 cents per kWh, during 2000.

     The excess of wholesale electricity costs above the generation-related cost
component available in frozen rates was deferred to the TRA. The TRA balance as
of December 31, 2000, prior to being written off against earnings, was an
undercollection of approximately $6.6 billion. Under current CPUC decisions, if
the TRA undercollection is not recovered through frozen rates by the end of the
transition period, it cannot be recovered or offset against overcollections of
transition cost recovery. Once the transition period has ended and the rate
freeze is over, the Utility's customers will be responsible for reasonable
wholesale electricity costs. However, actual changes in customer rates will not
occur until new retail rates are authorized by the CPUC or, to the extent
allowed, by the bankruptcy court.

     The Utility has reviewed on an ongoing basis the facts and circumstances
relating to the TRA and remaining transition cost regulatory assets. Due to the
lack of regulatory, legislative, or judicial relief, the Utility has determined
that it can no longer conclude that its uncollected wholesale electricity costs
and remaining transition costs are probable of recovery in future rates.
Accordingly, the Utility wrote off, as a charge against earnings, the TRA and
TCBA of approximately $6.9 billion. In addition, absent a regulatory, judicial,
or legislative solution that provides for full recovery of such costs, the
Utility will be unable to defer the costs of wholesale power purchases in excess
of amounts recovered through rates in 2001 and such expenses are expected to
reduce the Utility's future earnings accordingly.

Transition Cost Recovery

     Beginning January 1, 1998, the Utility started amortizing eligible
transition costs, including most generation-related regulatory assets. These
transition costs were offset by or recovered through the frozen rates, market
valuation of generation assets in excess of book value, net energy sales from
the Utility's electric generation facilities, and the amount by which long-term
contract prices to purchase electricity were lower than the PX price. Transition
costs and associated recoveries are recorded in the Utility's TCBA. During the
transition period, a reduced rate of return on common equity of 6.77% applies to
all generation assets, including those generation assets reclassified to
regulatory assets.

     During the transition period, the CPUC reviews the Utility's compliance
with accounting methods established in the CPUC's decisions governing transition
cost recovery and the amount of transition costs requested for recovery. In
January 2001, the CPUC approved all non-nuclear transition costs that were
amortized from July 1, 1998, to June 30, 1999. The CPUC currently is reviewing
non-nuclear transition costs amortized from July 1, 1999, to June 30, 2000.

Mitigation Efforts

     The Utility is actively exploring ways to reduce its exposure to the higher
wholesale electricity costs and to recover its written-off TRA and TCBA
balances. As previously indicated, the Utility believes the transition period
has ended and filed an application with the CPUC asking it to so rule. The
Utility has also filed a lawsuit against the CPUC in Federal District Court,
filed an application with the CPUC seeking approval of a five-year rate
stabilization plan, filed an application with the FERC to address the current
market crisis, worked with interested parties to address power market
dysfunction before appropriate regulatory bodies, and hedged a portion of its
open procurement position against higher purchased power costs through forward
purchases. The Utility's actions and related activities are discussed below.

Application with the FERC

     On October 16, 2000, the Utility joined with Southern California Edison and
The Utility Reform Network (TURN), in filing a petition with the FERC requesting
that the FERC (1) immediately find the California wholesale electricity market
to be not workably competitive and the resulting prices to be unjust and
unreasonable; (2) immediately impose a cap on the price for energy and ancillary
services; and (3) institute further expedited proceedings regarding the market
failure, mitigation of market power, structural solutions, and responsibility
for refunds. However, the reduced price cap requested, even if approved, would
still be above the approximate 5.4 cents per kWh available through frozen rates
for the payment of the Utility's wholesale electricity costs.

     On December 15, 2000, the FERC issued an order in response to the above
filing. The remedies proposed by the FERC include, among other things: (1)
eliminating the requirement that the California investor-owned utilities must
sell all of their power into, and buy all of their power needs from, the PX; (2)
modifying the single price auction so that bids above $150 per megawatt hour
(MWh) (15 cents per kWh) cannot set the market clearing prices paid to all
bidders, effective January 1, 2001 through April 30, 2001; (3) establishing an
independent governing board for the ISO; and

                                       48
<PAGE>

(4) establishing penalties for under-scheduling power loads. The FERC did not
order any refunds based on its findings, but announced its intent to retain the
discretion to order refunds for wholesale electricity costs incurred from
October 2000 through December 31, 2002. In March 2001, the FERC ordered refunds
of $69 million for January 2001 and indicated it would continue to review
December 2000 wholesale prices. The generators have appealed the decision. Any
refunds will be offset against amounts owed the generators.

Federal Lawsuit

     On November 8, 2000, the Utility filed a lawsuit in federal district court
in San Francisco against the CPUC. The Utility asked the court to declare that
the federally-approved wholesale electricity costs the Utility has incurred to
serve its customers are recoverable in retail rates both before and after the
end of the transition period. The lawsuit states that the wholesale power costs
the Utility has incurred are paid pursuant to filed rates, which the FERC has
authorized and approved and that under the United States Constitution and
numerous federal court decisions, state regulators cannot disallow such costs.
The Utility's lawsuit also alleges that to the extent that the Utility is denied
recovery of these mandated wholesale electricity costs by order of the CPUC,
such action constitutes an unlawful taking and confiscation of the Utility's
property. On January 29, 2001, the Utility's lawsuit was transferred to the
federal district court in Los Angeles where Southern California Edison has its
identical case pending.

Legislative Action

     On February 1, 2001, the governor of California signed into law AB 1X. AB
1X extended a preliminary authority of the DWR to purchase power. Public
Utilities Code Section 360.5, adopted in AB 1X, authorizes the CPUC to determine
the portion of each electric utility's existing electric retail rate that
represents the difference between the generation related component of the
utility's retail rate in effect on January 5, 2001, and the sum of the costs of
the utility's own generation, qualifying facilities (QF) contracts, existing
bilateral contracts, and ancillary services (the California Procurement
Adjustment or CPA). The CPA is payable to the DWR by each utility upon receipt
from its retail end use customers.

                                       49
<PAGE>

     The DWR has indicated that it intends to buy power only at "reasonable
prices" to meet the power needs of the retail electric customer that cannot be
met by the utility-owned generation or power under contract to the utilities;
i.e. the utilities' net open position. As the DWR has set a yet undisclosed
ceiling on what it will pay for power, the ISO has been left to pay the
remainder. The ISO has purchased energy at costs above the DWR's ceiling and, in
turn, is expected to bill the Utility for those costs. AB 1X does not address
whether or how the Utility will be able to pay for or recover purchase power
costs it has incurred because ISO purchases were not under the DWR's ceiling for
"reasonable prices." PG&E Corporation and the Utility cannot predict what
regulatory, legislative, or judicial actions may be taken with respect to this
issue.

     In response to the ISO's concern over the weakened financial condition of
the Utility and its ability to pay for power purchases, on February 14, 2001,
the FERC issued an order stating that the ISO could not allow the Utility to
schedule power from a third party supplier, unless the Utility was creditworthy
or was backed by creditworthy parties. The FERC order also stated that the ISO
could continue to schedule power for the Utility as long as it comes from its
own generation units and is routed over its own transmission lines. The ISO has
stated that it will charge the Utility for the power it buys on an emergency
basis, despite the FERC ruling. On April 6, 2001, the FERC issued a further
order directing the ISO to implement its prior order which the FERC clarified
applies to all third -party transactions whether scheduled or not.

Rate Stabilization Plan (RSP)

     On November 22, 2000, the Utility filed an application with the CPUC
seeking approval of a five-year RSP beginning on January 1, 2001. The Utility
requested an initial average rate increase of 22.4%. The Utility also proposed
that it receive actual costs, including a regulated return, for electricity
generation provided by it with the idea that profits that would have been
generated at market rates be recovered from customers later in the five-year
rate stabilization period. With respect to Diablo Canyon Nuclear Power Plant
(Diablo Canyon) the Utility has proposed to defer all profits (discussed below
in "Diablo Canyon Benefits Sharing"), until 2003, when the allocation of
revenues between ratepayers and shareholders will be readjusted. The
readjustment is intended to allow, by the end of 2005, the total net revenues
earned by Diablo Canyon, over the five-year plan, to be allocated equally
between shareholders and ratepayers according to existing CPUC decisions.

     On January 4, 2001, the CPUC issued an emergency interim decision denying
the Utility's request for a rate increase. Instead, the decision permitted the
Utility to establish an interim surcharge applied to electric rates on an equal-
cents-per-kWh basis of 1.0 cent per kWh, subject to refund and adjustment. The
surcharge was to remain in effect for 90 days from the effective date of the
decision. The Utility was required to establish a balancing account to track the
revenue provided by the surcharge and to apply these revenues to ongoing
wholesale electricity costs. The surcharge was made permanent in the CPUC's
March 27, 2001 decision, referred to below.

     On January 26, 2001, an assigned CPUC commissioner's ruling was issued in
the Utility's rate stabilization plan proceeding. The ruling stated that in
phase one of the case, the scope of the proceeding will include (1) reviewing
the independent audits of the utilities accounts to determine whether there is a
financial necessity for additional relief for the utilities, (2) reviewing
TURN's accounting proposal to transfer the undercollected balances in the
utilities' TRAs to their respective TCBAs and reviewing the generation
memorandum accounts, and (3) considering whether the rate freeze has ended only
on a prospective basis.

     On January 30, 2001, the independent consultants engaged by the CPUC issued
their review report on the Utility's financial position as of December 31, 2000,
as well as that of PG&E Corporation and the Utility's affiliates. The review
found that the Utility made an accurate representation of its financial
situation noting accurate representations of its borrowing capabilities, credit
condition, and events of default. The review also found that the Utility
accurately represented recorded entries to its TRA and TCBA. The review alleged
certain deficiencies with respect to bidding strategies, cash conservation
matters, and cash flow forecast assumptions. The Utility filed rebuttal
testimony on February 14, 2001. Hearings to consider the issues and reports of
the independent consultants began on February 20, 2001.

     On March 27, 2001, the CPUC ruled on parts of the Utility's RSP and granted
an increase in rates by adopting an average 3.0 cents per kWh surcharge.
Although the increase is authorized immediately, the 3.0 cents per kWh surcharge
will not be collected in rates until the CPUC establishes an appropriate rate
design for the surcharge, which is not expected to be adopted until May 2001, at
the earliest. The revenue generated by the rate increase is to be used only for
electric power procurement costs that are incurred after March 27, 2001. The
CPUC declared that the revenues generated

                                       50
<PAGE>

by this surcharge are subject to refund (1) if not used to pay for such power
purchases, (2) to the extent that generators and sellers of power make refunds
for overcollections, or (3) to the extent any administrative body or court
denies the refunds of overcollections in a proceeding where recovery has been
hampered by a lack of cooperation from the Utility. The 3.0 cents per kWh
surcharge is in addition to the emergency interim surcharge approved in January
4, 2001, which the CPUC made permanent in this decision. The CPUC also modified
accounting rules in response to a proposal made by TURN as described below.

     Also, on March 27, 2001, the CPUC issued a decision ordering the Utility
and the other California investor-owned utilities to pay the DWR a per-kWh price
equal to the applicable generation-related retail rate per kWh established for
each utility as in effect on January 5, 2001, for each kWh the DWR sells to the
customers of each utility. The CPUC determined that the generation-related
component of retail rates should be equal to the total bundled electric rate
(including the 1 cent per kWh interim surcharge adopted by the CPUC on January
5, 2001) less the following non-generation-related rates or charges:
transmission, distribution, public purpose programs, nuclear decommissioning,
and the fixed transition amount. The CPUC determined that the Utility's company-
wide average generation-related rate component is 6.471 cents per kWh and that
this is the amount that should be paid to the DWR for each kWh delivered by the
DWR to the Utility's retail customers after February 1, 2001, until specific
rates are calculated. The CPUC ordered the utilities to pay the DWR within 45
days after the DWR supplies power to their retail customers, subject to
penalties for each day that payment is late. The amount of power supplied to
retail end-use customers after March 27, 2001, for which the DWR is entitled to
be paid would be based on the product of the number of kWh that the DWR provided
45 days earlier and the Utility's company-wide average generation-related rate
of 6.471 cents per kWh, and the additional 3 cent per kWh surcharge described
above.

     The CPUC also ordered that the utilities immediately pay the sums owed to
the DWR for power sold by the DWR from January 18, 2001 through January 31,
2001, under California Senate Bill 7X. Based on an estimated number of kWh sold
by the DWR, the Utility paid approximately $30 million to the DWR at the rate of
5.471 cents per kWh as adopted by the CPUC.

     In addition, on April 3, 2001, the CPUC adopted a method to calculate the
CPA, as described in Public Utilities Code Section 360.5 (added by AB 1X
effective February 1, 2001). Section 360.5 requires the CPUC to determine (1)
the portion of each electric utility's electric retail rate effective on January
5, 2001, the CPA, that is equal to the difference between the generation-related
component of the utility's retail rate in effect on January 5, 2001, and the sum
of the costs of the utility's own generation, QFs contracts, existing bilateral
contracts (i.e., entered into before February 1, 2001), and ancillary services,
and (2) the amount of the CPA that is allocable to the power sold by the DWR.
The CPUC decided that the CPA should be a set rate calculated by determining
each utility's generation-related revenues (for the Utility the CPUC has
proposed that this be equal to 6.471 cents per kWh multiplied by total kWh sales
by the Utility to the Utility's retail customers), then subtracting each
utility's statutorily authorized generation-related costs, and dividing the
result by each utility's total kWh sales. Each utility's CPA rate will be used
to determine the amount of bonds the DWR may issue.

     Using the CPUC's methodology, but substituting the CPUC's cost assumptions
with actual expected costs and including costs the CPUC has refused to
recognize, the Utility's calculations show that the CPA for the 11-month period
February through December 2001 would be negative by $2.2 billion, (i.e., there
would be no CPA available to the DWR) assuming the DWR purchases 84% of the
Utility's net open position. (The net open position is the amount of power that
cannot be met by the utilities' own or contracted-for generation.) If AB 1X were
amended to also include in the CPA all the incremental revenue from the 3 cent
per kWh increase discussed above (approximately $2.3 billion for 11 months),
then the amount available to the DWR for the CPA for the comparable 11-month
period, assuming the Utility were allowed to recover its costs first, would be
approximately $100 million. The Utility believes the method adopted by the CPUC
is unlawful and inconsistent with Section 360.5 because, among other reasons, it
establishes a set rate that does not reflect actual residual revenues,
overstates the CPA by excluding and/or understating authorized costs, and to the
extent it is dedicated to the DWR does not allow the Utility to recover its own
revenue requirements and costs of service. The Utility intends to file an
application for rehearing of this decision.

     The CPUC noted that although the DWR has assumed responsibility to purchase
some of the utilities' power requirements, it has not committed to purchase all
of the utilities' net open position. To the extent the DWR does not buy enough
power to cover the Utility's net open position, the ISO purchases emergency
power on the high-priced spot market to meet system reliability requirements and
the net open position. The ISO may attempt to charge the Utility a proportionate
share of the ISO's purchases. The Utility believes that under the current
circumstances and applicable tariffs it is not responsible for such ISO charges.
As the DWR has not advised the CPUC of its revenue requirement for the DWR's
power purchases, it is unclear how much of the 3 cent surcharge will be needed
by the DWR and how much, if

                                       51
<PAGE>

any, may be used by the Utility to recover its procurement costs incurred after
March 27, 2001 (including any ISO charges).

     Since the end of January 2001, the Utility has been paying only 15% of
amounts due QFs. On March 27, 2001, the CPUC issued a decision requiring the
Utility and the other California investor-owned utilities to pay QFs fully for
energy deliveries made on and after the date of the decision, within 15 days of
the end of the QFs' billing period. The decision permits QFs to establish a 15-
day billing period as compared to the current monthly billing period. The CPUC
noted that its change to the payment provision was required to maintain energy
reliability in California and thus provided that failure to make a required
payment would result in a fine in the amount owed to the QF. The decision also
adopts a revised pricing formula relating to the California border price of gas
applicable to energy payments to all QFs, including those that do not use
natural gas as a fuel. Based on the Utility's preliminary review of the
decision, the revised pricing formula would reduce the Utility's 2001 average QF
energy and capacity payments from approximately 12.7 cents per kWh to 12.3 cents
per kWh.

     The CPUC also adopted TURN's proposal to transfer on a monthly basis the
balance in each Utility's TRA to the Utility's TCBA. The TRA is a regulatory
balancing account that is credited with total revenue collected from ratepayers
through frozen rates and which tracks undercollected power purchase costs. The
TCBA is a regulatory balancing account that tracks the recovery of generation-
related transition costs. The accounting changes are retroactive to January 1,
1998. The Utility believes the CPUC is retroactively transforming the power
purchase costs in the TRA into transition costs in the TCBA. However, the CPUC
characterized the accounting changes as merely reducing the prior revenues
recorded in the TCBA, thereby affecting only the amount of transition cost
recovery achieved to date. The CPUC also ordered that the utilities restate and
record their generation memorandum account balances to the TRA on a monthly
basis before any transfer of generation revenues to the TCBA. The CPUC found
that based on the accounting changes, the conditions for meeting the end of the
rate freeze have not been met.

     The Utility believes the adoption of TURN's proposed accounting changes
results in illegal retroactive ratemaking, constitutes an unconstitutional
taking of the Utility's property, and violates the federal filed rate doctrine.
The Utility also believes the other CPUC decisions are similarly illegal to the
extent they would compel the Utility to make payments to the DWR and QFs without
providing adequate revenues for such payments. The Utility plans to challenge
the decisions in appropriate legal forums.

Bilateral Contracts

     Under the terms of AB 1890, the Utility was required to purchase all of its
power from the PX and ISO to meet the needs of its customers. On August 3, 2000,
after the California energy crisis had begun, the CPUC approved the Utility's
use of bilateral contracts, subject to the CPUC approving a set of standards or
criteria by which the reasonableness of such contracts would be reviewed on an
after-the-fact basis. The CPUC has yet to approve such standards or criteria.

     In October 2000, the Utility entered into multiple bilateral contracts with
suppliers for long-term electricity deliveries. As of December 31, 2000, these
contracts ranged from approximately 1,228,000 MWhs to 6,344,800 MWhs of supply
annually. The contracts extended from 2001 to 2005. Each of the contracts was
for delivery beginning January 1, 2001 or later. As a result of the energy
crisis, certain of these contracts were terminated, subsequent to December 31,
2000.

PX Energy Credits

     In accordance with CPUC regulations, the Utility provides a PX energy
credit to those customers (known as direct access customers) who have chosen to
buy their electric energy from an energy service provider (ESP) other than the
Utility. As wholesale power prices began to increase beginning in June 2000, the
level of PX credits increased correspondingly to the point where the credits
exceeded the Utility's distribution and transmission charges to direct access
customers. During 2000, the PX credits reduced electric revenue by $472 million,
although the Utility ceased paying most of these credits in December 2000. These
amounts are reflected on the accompanying consolidated balance sheet at December
31, 2000. As of March 29, 2001, the estimated total of accumulated credits for
direct access customers that have not been paid by the Utility is approximately
$503 million. The actual amount that will be refunded to ESPs will be dependent
upon when the rate freeze ends and whether there are any adjustments made to
wholesale energy prices by the FERC.
<PAGE>

Generation Divestiture

     In April 1999, the Utility sold three fossil-fueled generation plants for
$801 million. At the time of sale, these three fossil-fueled plants had a
combined book value of $256 million and a combined capacity of 3,065 MW.

     In May 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and a combined capacity of 1,224 MW. The
Lake facility was sold at a gain of $8 million while the Sonoma facility was
sold at a loss of $39 million.

     The gains from the sale of the fossil-fueled generation plants and the Lake
facility were used to offset other transition costs. Likewise, the loss from the
sale of the Sonoma geothermal generation facilities is being recovered as a
transition cost.

     The Utility has retained a liability for required environmental remediation
related to any pre-closing soil or groundwater contamination at the plants it
has sold.

     Under the California electric industry restructuring legislation, the
valuation of the Utility's remaining generation assets (primarily its
hydroelectric facilities) must be completed by December 31, 2001. Any excess of
market value over the assets' book value would be used to offset the Utility's
transition costs.

     In August 2000, the Utility and a number of interested parties filed an
application with the CPUC requesting that the CPUC approve a settlement
agreement reached by these parties. The agreement was filed in the Utility's
proceeding to determine the market value of its hydroelectric generation assets.
In this settlement agreement, the Utility indicated that it would transfer its
hydroelectric generation assets, at a negotiated value of $2.8 billion, to an
affiliate. Due to the high wholesale prices and the corresponding increase in
the value of its hydroelectric generation assets, in November 2000 as part of an
application with the CPUC seeking approval of a five-year RSP, the Utility
withdrew its support from the settlement agreement, eliminating it from
consideration in the proceeding.

     In January 2001, California Assembly Bill 6 was passed which prohibits
disposal of any of the Utility's generation facilities, including the
hydroelectric facilities, prior to January 1, 2006. In December 2000, the
Utility submitted updated testimony in the hydroelectric valuation proceeding
indicating the market value of the hydroelectric assets ranges from $3.9 billion
to $4.2 billion assuming a competitive auction or other arms-length sale. At
December 31, 2000, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $692 million.

Diablo Canyon Benefits Sharing

     As required by a prior CPUC decision on June 30, 2000, the Utility filed an
application with the CPUC requesting approval of its proposal for sharing with
ratepayers 50% of the post-rate freeze net benefits of operating Diablo Canyon.
The net benefit sharing methodology proposed in the Utility's application would
be effective at the end of the current electric rate freeze for the Utility's
customers and would continue for as long as the Utility owned Diablo Canyon.
Under the proposal, the Utility would share the net benefits of operating Diablo
Canyon based on the audited profits from operations, determined consistent with
the prior CPUC decisions. If Diablo Canyon experiences losses, such losses would
be deferred and netted against profits in the calculation of the net benefits in
subsequent periods (or against profits in prior periods if subsequent profits
are insufficient to offset such losses). Any changes to the net sharing
methodology must be approved by the CPUC. The CPUC has suspended the proceedings
to consider the net benefit sharing proposal. In the Utility's RSP, parties have
proposed that the requirement to establish a sharing methodology be rescinded
and the Diablo Canyon be placed on cost-of-service ratemaking. It is uncertain
what future ratemaking will be applicable to Diablo Canyon.

Cost of Electric Energy

     For the years ended December 31, 2000 and 1999, and the period March 31,
1998 (the PX establishment date) to December 31, 1998, the cost of electric
energy for the Utility, reflected on the Utility's Statement of Consolidated
Operations, comprises the cost of fuel for electric generation and QF purchases,
the cost of PX purchases, and ancillary services charged by the ISO, net of
sales to the PX, as follows:


                                                      Year Ended December 31,
                                                     ------------------------

     (in millions)                                2000        1999         1998
<PAGE>

Cost of fuel resources at market prices         $ 9,512      $3,233     $ 3,370
Proceeds from sales to the PX                    (2,771)       (822)     (1,049)

Total Utility cost of electric energy           $ 6,741      $2,411     $ 2,321


Note 3: Subsequent Events


Credit Rating Downgrades

     As a result of the Utility's deteriorating financial condition from the
California energy crisis, the major credit agencies have downgraded the long-
term and short-term credit ratings of both PG&E Corporation and the Utility. The
following is a summary of current credit ratings by Standard & Poor's (S&P) and
Moody's Investors Service (Moody's) as of March 29, 2001, for the Utility:

<TABLE>
<CAPTION>
          Standard & Poors                                                     Current Ratings
          <S>                                                                  <C>
          Corporate credit rating                                                    D/D
          Commercial paper                                                            D
          Senior secured debt                                                        CCC
          Senior unsecured debt                                                      CC
          Preferred stock                                                             D
          Shelf senior secured/unsecured subordinated debt                         CCC/CC
          Shelf preferred stock                                                       D
          Moody's Investors Service
          Commercial paper                                                        Not prime
          Mortgage                                                                   B3
          Secured pollution control bonds                                            B3
          Issuer rating                                                             Caa2
          Senior unsecured notes                                                    Caa2
          Unsecured debentures                                                      Caa2
          Unsecured pollution control bonds                                         Caa2
          Bank credit facility                                                      Caa2
          Preferred Stock                                                            caa
          Shelf senior secured debt                                                 (P)B3
          Shelf senior unsecured debt                                              (P)Caa2
          Shelf preferred stock                                                    (P)caa
          Variable rate demand bonds                                          Speculative Grade
</TABLE>

PG&E Corporation

     On January 16 and 17, 2001, in response to the continued energy crisis, S&P
and Moody's, respectively, downgraded PG&E Corporation's credit ratings to below
investment grade. The downgrade, in addition to PG&E Corporation's and the
Utility's non-payment of commercial paper constituted an event of default under
both the $436 million and the $500 million credit facilities. In response, the
banks immediately terminated their outstanding commitments under these defaulted
credit facilities. Through February 28, 2001, PG&E Corporation had $501 million
in outstanding commercial paper, of which $457 million came due and was not
paid.

     On March 2, 2001, PG&E Corporation refinanced its debt obligations with $1
billion in aggregate proceeds of two term loans under a common credit agreement
with General Electric Capital Corporation and Lehman Commercial Paper, Inc. In
accordance with the credit agreement, the proceeds, together with other PG&E
Corporation cash, were used to pay the $501 million in outstanding commercial
paper, $434 million in borrowings under PG&E Corporation's long-
<PAGE>

term revolving credit facility, and $116 million to PG&E Corporation's
shareholders of record on December 15, 2000 in satisfaction of the defaulted
fourth quarter 2000 common stock dividend. Further, approximately $85 million
was used to pre-pay the first year's interest under the credit agreement and to
pay transaction expenses associated with the debt restructuring.

     The loans will mature on March 2, 2003 (which date may be extended at the
option of PG&E Corporation for up to one year upon payment of a fee of up to 5%
of the then outstanding indebtedness), or earlier, if a spin-off of the shares
of the NEG were to occur. As required by the credit agreement, PG&E Corporation
has given the lenders a security interest in the NEG. The loans prohibit PG&E
Corporation from declaring dividends, making other distributions to
shareholders, or incurring additional indebtedness until the loans have been
repaid, although PG&E Corporation could incur unsecured indebtedness provided it
meets certain requirements. The loan also prohibits NEG from making
distributions to PG&E Corporation and restricts certain other intercompany
transactions.

     Further, as required by the credit agreement, NEG LLC has granted to
affiliates of the lenders options that entitle these affiliates to purchase up
to 3% of the shares of the NEG at an exercise price of $1.00 based on the
following schedule:


                                                    Percentages of Shares
                                                    subject to NEG Options
                                                    ----------------------

               Loans outstanding for:
               Less than six months                                   2.0%
               Six to eighteen months                                 2.5%
               Greater than eighteen months                           3.0%

     The option becomes exercisable on the date of full repayment or, earlier,
if an initial public offering of the shares of the NEG (IPO) were to occur. The
NEG has the right to call the option in cash at a purchase price equal to the
fair market value of the underlying shares, which right is exercisable at any
time following the repayment of the loans. If an IPO has not occurred, the
holders of the option have the right to require the NEG or PG&E Corporation to
repurchase the option at a purchase price equal to the fair market value of the
underlying shares, which right is exercisable at any time after the earlier of
full repayment of the loans or 45 days before expiration of the option. The
option will expire 45 days after the maturity of the loans. PG&E Corporation
will account for the options by recording the fair value of the option at
issuance as a debt issuance cost to be amortized over the expected life of the
loans. The options will be marked to market through an increase or decrease to
current earnings.

     Under the credit agreement, the NEG is permitted to make investments, incur
indebtedness, sell assets, and operate its businesses pursuant to its business
plan. Mandatory repayment of the loans will be required from the net after-tax
proceeds received by the NEG or any subsidiary of the NEG from (1) the issuance
of indebtedness, (2) the issuance or sale of any equity (except for cash
proceeds from an IPO), (3) asset sales, and (4) casualty insurance, condemnation
awards, or other recoveries. However, if such proceeds are retained as cash,
used to pay indebtedness, or reinvested in the NEG's businesses, mandatory
repayment will not be required.

     Any net proceeds from an IPO must be used to reduce the outstanding balance
of the loans to $500 million or less. In addition, all distributions made by the
NEG to PG&E Corporation other than (1) to reimburse PG&E Corporation for
corporate overhead expenses, (2) pursuant to any tax sharing arrangements which
the NEG and PG&E Corporation are parties, and (3) pursuant to any note that may
be payable to PG&E Corporation in connection with an IPO and similar
arrangements must be used to pay the loans.

     The credit agreement also prohibits PG&E Corporation from taking certain
actions, including a restriction against declaring or paying any dividends for
as long as the loans are outstanding. A breach of covenants, including
requirements that (1) the NEG's unsecured long-term debt have a credit rating of
at least BBB- by S&P or Baa3 by Moody's, (2) the ratio of fair market value of
the NEG to the aggregate amount of principal then outstanding under the loans is
not less than 2 to 1, and (3) PG&E Corporation maintain a cash or cash
equivalent reserve of at least 15% of the total principal amount of the loans
outstanding, entitles the lenders to declare the loans to be due and payable.

Utility
<PAGE>

     The Utility had been drawing on its $1 billion facility to pay maturing
commercial paper. As of January 16, 2001, the Utility had drawn down $938
million under this facility. On January 16 and 17, 2001, S&P and Moody's,
respectively, downgraded the Utility's credit ratings to below investment grade.
This downgrade resulted in an event of default under the $850 million credit
facility, while the Utility's non-payment of commercial paper exceeding $100
million constituted events of default under both the $1 billion and $850 million
credit facilities. Although they have the ability under the terms of the various
agreements, no bank has called for accelerated payment of any of the Utility's
outstanding debt, nor has any bank permanently waived any requirements violated
which resulted in the events of default described above. Lenders have agreed to
forbear from accelerating payments until April 13, 2001.

     On January 10, 2001, the Board of Directors of the Utility suspended the
payment of its fourth quarter 2000 common stock dividend in an aggregate amount
of $110 million payable on January 15, 2001, to PG&E Corporation and PG&E
Holdings, Inc., a subsidiary of the Utility. In addition, the Utility's Board of
Directors decided not to declare the regular preferred stock dividends for the
three-month period ending January 31, 2001, normally payable on February 15,
2001. Dividends on all Utility preferred stock are cumulative. Until cumulative
dividends on preferred stock are paid, the Utility may not pay any dividends on
its common stock, nor may the Utility repurchase any of its common stock.

     After the downgrade, the PX notified the Utility that the ratings downgrade
required the Utility to post collateral for all transactions in the PX day-ahead
market. Since the Utility was unable to post such collateral, the PX suspended
the Utility's trading privileges effective January 19, 2001 in the day-ahead
market. The PX also sought to liquidate the Utility's block forward contracts
for the purchase of power. On January 25, 2001, a California Superior Court
judge granted the Utility's application for a temporary restraining order, which
thereby restrained and enjoined the PX and its agents from liquidating the
Utility's contracts in the block forward market, pending hearing on a
preliminary injunction on February 5, 2001. Immediately before the hearing on
the preliminary injunction, California Governor Gray Davis, acting under
California's Emergency Services Act, commandeered the contracts for the benefit
of the state. Under the Act, the state must pay the Utility the reasonable value
of the contracts, although the PX may seek to recover the monies that the
Utility owes to the PX from any proceeds realized from those contracts.
Discussions and negotiations on this issue are currently ongoing between the
state and the Utility.

     As of March 29, 2001, the Utility was in default and/or had not paid the
following:

<TABLE>
<CAPTION>

          Description                                                                  Amount
                                                                                   in millions)
                                                                                    (unaudited)
          <S>                                                                      <C>
          Items not paid
          PX/ISO--real time market deliveries                                               $1,448
          Qualifying facilities                                                                643
          Direct access credits due to energy service providers                                503
          Commercial paper                                                                     861
          Bank loans                                                                           939*
          Other                                                                                 26

          Total Items Not Paid                                                              $4,420
          Items coming due through April 30, 2001
          PX/ISO--real time market deliveries                                               $  550
          Qualifying facilities                                                                340
          Gas suppliers                                                                        470
          Other                                                                                140

          Total coming due                                                                   1,500
          Total cash on hand at March 29, 2001                                              $2,600
          </TABLE>

*    Loans that lenders have agreed to forbear through April 13, 2001.
<PAGE>

     Additionally, the Utility may owe the DWR for purchases that the DWR has
made on behalf of the Utility's customers. As discussed further in Note 2 of the
Notes to the Consolidated Financial Statements, there is a dispute over how much
the Utility owes the DWR. Also, the DWR has indicated that it intends to
purchase power at only "reasonable prices." The ISO has continued to purchase
power at prices in excess of the DWR's as yet undisclosed ceiling and is
expected to bill the Utility for the differential. The Utility does not yet know
what the total expected billing is for these purchases.

     As a result of (1) the failure by the state to assume the full procurement
responsibility for the Utility's net open position as was provided under AB1X,
(2) the negative impact of recent actions by the CPUC that created new payment
obligations for the Utility and undermined its ability to return to financial
viability, (3) a lack of progress in negotiations with the state to provide a
solution for the energy crisis, and (4) the adoption by the CPUC of an illegal
and retroactive accounting change that would appear to eliminate the Utility's
true uncollected purchased power costs, the Utility filed a voluntary petition
for relief under provisions of Chapter 11 of the U.S. Bankruptcy Code on April
6, 2001. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains
control of its assets and is authorized to operate its business as a debtor in
possession while being subject to the jurisdiction of the bankruptcy court.
Subject to the approval of the bankruptcy court, the Utility's intent is to pay
its ongoing costs of doing business while seeking resolution of the wholesale
power crisis. It is the Utility's intention to continue to pay employees,
vendors, suppliers, and other creditors to maintain essential distribution and
transmission services. However, the Utility is not in a position to pay maturing
or accelerated obligations, nor is the Utility in a position to pay the ISO, PX,
and the QFs, the massive amounts due for the Utility's power purchases above the
amount included in rates for power purchase costs. The Utility's current actions
are intended to allow the Utility to continue to operate while efforts to reach
a regulatory or legislative solution continue.

     The Utility has also deferred quarterly interest payments on the Utility's
7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until
further notice in accordance with the indenture. The corresponding quarterly
payments on the 7.90% Cumulative Quarterly Income Preferred Securities, Series
A, (QUIPS) issued by PG&E Capital I, due on April 2, 2001, have been similarly
deferred. Distributions can be deferred up to a period of five years per the
indenture. Investors will accumulate interest on the unpaid distributions at the
rate of 7.90%.

National Energy Group

     In December 2000 and in January and February 2001, PG&E Corporation and the
NEG undertook a corporate restructuring of the NEG, known as a "ringfencing"
transaction. The ringfencing complied with credit rating agency criteria,
enabling NEG, PG&E Gas Transmission, Northwest Corporation (PG&E GTN), and PG&E
ET to receive or retain their own credit rating, based upon their
creditworthiness. The ringfencing involved the creation of new special purpose
entities (SPEs) as intermediate owners between PG&E Corporation and its non
CPUC-regulated subsidiaries. These new SPEs are: PG&E National Energy Group,
LLC, which owns 100% of the stock of the NEG; GTN Holdings LLC, which owns 100%
of the stock of PG&E GTN; and PG&E Energy Trading Holdings LLC which owns 100%
of the stock of PG&E Corporation's energy trading subsidiaries, PG&E Energy
Trading--Gas Corporation, PG&E Energy Trading Holdings Corporation, and PG&E
Energy Trading-Power, L.P. In addition, the NEG's organizational documents were
modified to include the same structural elements as the SPEs to meet credit
rating agency criteria. Ringfencing is intended to reduce the likelihood that
the assets of the ringfenced entities would be substantially consolidated in a
bankruptcy proceeding involving such companies' ultimate parent, and to thereby
preserve the value of the "protected" entities as a whole. The SPEs require
unanimous approval of their respective boards of directors, which includes an
independent director, before they can (a) consolidate or merge with any entity,
(b) transfer substantially all of their assets to any entity, or (c) institute
or consent to bankruptcy, insolvency, or similar proceedings or actions. The
SPEs may not declare or pay dividends unless the respective boards of directors
has unanimously approved such action and the company meets specified financial
requirements.

Note 4: Price Risk Management and Financial Instruments


Trading and Non-Trading Activities

  The following table is a summary of the contract or notional amounts and
maturities of commodity derivatives related to commodity price risk management
as of December 31, 2000 and 1999:
<PAGE>

<TABLE>
<CAPTION>
                                                                                               Maximum
Electricity, Natural Gas,                                        Purchase         Sale         Term in
and Natural Gas Liquids Contracts                                 (Long)         (Short)        Years

(billions of MMBtu equivalents/(1)/)
<S>                                                            <C>            <C>            <C>
NEG:
Trading Activities--December 31, 2000
Swaps                                                                  2.04           1.95            6
Options                                                                0.46           0.37            8
Futures                                                                0.14           0.15            3
Forward Contracts                                                      1.42           1.38           16
Trading Activities--December 31, 1999
Swaps                                                                  2.38           2.33            7
Options                                                                 .94            .86            8
Futures                                                                 .19            .18            2
Forward Contracts                                                      1.49           1.46           12
Non-Trading Activities--December 31, 2000
Forward Contracts                                                      1.70           0.74           22
Non-Trading Activities--December 31, 1999
Forward Contracts                                                      0.02           0.01            3
Utility:
Non-Trading Activities--December 31, 2000
Swaps                                                                  0.06           0.07            1
Forward Contracts                                                      0.02             --            5
Non-Trading Activities--December 31, 1999
Swaps                                                                    --           0.01            1
</TABLE>

(1)  One MMBtu is equal to one million British thermal units. Electricity
     contracts, measured in megawatts, were converted to MMBtu equivalents using
     a conversion factor of 10 MMBtus per 1 MWh. Natural gas liquids contracts
     were converted to MMBtu equivalents using an appropriate conversion factor
     for each type of natural gas liquids product.

     The following table is a summary of the contract or notional amounts and
maturities of PG&E Corporation's financial instruments used for non-trading
activities as of December 31:

<TABLE>
<CAPTION>
                                                         2000                          1999
                                                        -----                         -----
(in millions)                                    Notional        Contract      Notional        Contract
                                                   Amount      Expiration        Amount      Expiration
<S>                                              <C>           <C>             <C>           <C>
Non-Trading Activities:
Interest Rate                                      $1,756            2012         $ 724            2003
Foreign Currency                                       94            2003           104            2002
</TABLE>

     Notional amounts shown represent volumes that are used to calculate amounts
due under the agreements and do not necessarily represent volumes exchanged.
Because the changes in market value of these derivatives used as hedges are
generally offset by changes in the value of the underlying physical
transactions, the amounts at risk are significantly lower than these notional
amounts might suggest.

     PG&E Corporation's net gain (loss) on trading contracts held during the
years ended December 31, are as follows:

<TABLE>
<CAPTION>
(in millions)                                                                  2000        1999       1998
<S>                                                                          <C>         <C>        <C>
Swaps                                                                         $ 173       $  15      $  69
Options                                                                          66         (41)       (49)
Futures                                                                        (106)        (36)       (63)
</TABLE>
<PAGE>

<TABLE>

<S>                                                                          <C>         <C>        <C>
Forward Contracts                                                                72          98        101

Net gain                                                                      $ 205       $  36      $  58
</TABLE>

  The following table discloses PG&E Corporation's estimated average fair value
and ending fair value of price risk management assets and liabilities at
December 31, 2000 and 1999.

<TABLE>
<CAPTION>
                                                Average                        Ending
                                               Fair Value                     Fair Value
                                               ----------                     ----------
(in millions)                             Assets        Liabilities      Assets        Liabilities
<S>                                       <C>           <C>              <C>           <C>
Trading Activities--December 31, 2000
Swaps                                     $  163             $   75      $  286            $  121
Options                                      153                106         250               171
Futures                                       34                 78          33                98
Forward Contracts                          2,053              1,921       3,496             3,476

               Total                      $2,403             $2,180      $4,065            $3,866

Noncurrent portion                                                       $2,026            $1,867
Current portion                                                          $2,039            $1,999
Trading Activities--December 31, 1999
Swaps                                     $  218             $  197      $   50            $   33
Options                                       75                 87          56                41
Futures                                       89                119          35                58
Forward Contracts                            475                356         588               398

               Total                      $  857             $  759      $  729            $  530

Noncurrent portion                                                       $  329            $  207
Current portion                                                          $  400            $  323
</TABLE>

        Credit Risk

  The use of financial instruments to manage the risks associated with changes
in energy commodity prices creates exposure resulting from the possibility of
nonperformance by counterparties pursuant to the terms of their contractual
obligations. The counterparties in PG&E Corporation's and the Utility's
portfolio consist primarily of investor-owned and municipal utilities, energy
trading companies, financial institutions, and oil and gas production companies.
PG&E Corporation and the Utility minimize credit risk by dealing primarily with
creditworthy counterparties in accordance with established credit approval
practices and limits. PG&E Corporation assesses the financial strength of its
counterparties at least quarterly and requires that counterparties post security
in the forms of cash, letters of credit, corporate guarantees of acceptable
credit quality, or eligible securities if current net receivables and
replacement cost exposure exceed contractually specified limits. Neither PG&E
Corporation nor the Utility has experienced material losses due to the
nonperformance of counterparties in 2000. Counterparties considered to be
investment grade or higher comprise 76% of the total credit exposure. At
December 31, 2000, PG&E Corporation's and the Utility's gross credit risk
amounted to $3.3 billion and $978 million, respectively.

Fair Value of Financial Instruments

  PG&E Corporation's financial instruments consist of cash and cash equivalents,
restricted cash, accounts receivable, accounts payable and certain accrued
liabilities, notes payable, commercial paper, capital leases, and long-term
debt.
<PAGE>

     The fair value of these financial instruments, with the exception of long-
term receivables, fixed rate debt, and interest rate swaps, approximates their
carrying value as of December 31, 2000 and 1999, due to their short-term nature
or due to the fact that the interest rate paid on the instrument is variable.

     The carrying amounts of the long-term receivables approximate fair value at
December 31, 2000 and 1999, as the assumptions used to value these instruments
at the acquisition date had not changed.

     The fair values of long-term receivables and long-term debt were estimated
using discounted cash flows analysis, based on PG&E Corporation's current
incremental borrowing rate. The approximate carrying values were based on
currently quoted market prices for similar types of borrowing arrangements.

     The fair value of interest rate swap agreements, which are not carried on
the consolidated balance sheets, is estimated by calculating the present value
of the difference between the total fixed payments of the interest rate swap
agreements and the total floating payments using the appropriate current market
rates.

     The carrying amount and fair value of PG&E Corporation's long-term
receivables, long-term debt, and interest rate swaps as of December 31, 2000 and
1999, is summarized as follows:

<TABLE>
<CAPTION>
                                                         2000                           1999
                                                         ----                           ----
        PG&E Corporation                         Carrying      Fair Value       Carrying      Fair Value
        (in millions)                              Amount                         Amount
        <S>                                      <C>           <C>              <C>           <C>
        Long-term receivables                      $  611          $  526         $  680          $  680
        Long-term debt                              9,157           9,010          9,561           9,393
        Interest rate swaps                            --             (73)            --              (9)
</TABLE>

     Fair value of the Utility's rate reduction bonds, and Utility obligated
mandatorily redeemable preferred securities of trust holding solely Utility
subordinated debentures, are all determined based on quoted market prices. Fair
value of the Utility's preferred stock with mandatory provisions is based on
indicative market prices. Where quoted or indicative market prices are not
available, the estimated fair value is determined using other valuation
techniques (for example, the present value of future cash flows). Most of the
Utility's debt is determined using quoted market prices, but the fair value of a
small portion of Utility debt is determined using the present value of future
cash flows. See Note 3 of the Notes to the Consolidated Financial Statements for
subsequent events regarding PG&E Corporation's and the Utility's credit
facilities.

     At December 31, 2000 and 1999, the Utility's carrying amount and ending
fair value of its financial instruments was:

<TABLE>
<CAPTION>
                                                                  2000                          1999
                                                                  ----                          ----
        Utility:                                          Carrying      Fair Value      Carrying      Fair Value
        (in millions)                                       Amount                        Amount
        <S>                                               <C>           <C>             <C>           <C>
        Nuclear decommissioning funds noncurrent
        asset (see Note 11)                                 $1,328          $1,328        $1,264          $1,264
        Total long-term debt(1) (see Note 8)                 5,716           5,320         5,342           5,217
        Rate reduction bonds(2) (see Note 9)                 2,030           2,044         2,321           2,265
        Preferred stock with mandatory redemption
        provisions (see Note 7)                                137              98           137             140
        Utility obligated mandatorily redeemable
        preferred securities of trust holding
        solely Utility subordinated debentures
        (See note 7)                                           300             180           300             267
</TABLE>

          (1)  Total long-term debt includes the current portion of long-term
               debt.

          (2)  Rate reduction bonds include the current portion of rate
               reduction bonds.

Note 5: Acquisitions and Disposals
<PAGE>

     On September 28, 2000, the NEG purchased for $311 million the Attala
Generating Company LLC, which owns a gas-fired power plant under construction.
Under the purchase agreement, the NEG prepaid the estimated remaining
construction costs, which are being managed by the seller. The project, which
was approximately 75% complete as of December 31, 2000, is expected to begin
commercial service in July 2001. In connection with the acquisition, the NEG
also assumed industrial revenue bonds in the amount of $158 million. The seller
has agreed to pay off the bonds prior to December 15, 2001; accordingly, the NEG
recorded a receivable equal to the amount of the outstanding bonds and accrued
interest at December 31, 2000.

     On January 27, 2000, PG&E Corporation signed a definitive agreement with El
Paso Field Services Company (El Paso) providing for the sale to El Paso, a
subsidiary of El Paso Energy Corporation, of the stock of PG&E Gas Transmission,
Texas Corporation, PG&E Gas Transmission Teco, Inc., and their subsidiaries
(PG&E GTT). PG&E GTT assets consist of 8,500 miles of natural gas and natural
gas liquids pipeline, nine natural gas processing plants, and natural gas
storage facilities, all located in Texas. Given the terms of the sales
agreement, in 1999 PG&E Corporation recognized a charge against pre-tax earnings
of $1,275 million, to reflect PG&E GTT's assets at their fair value. The
composition of the pre-tax charge is as follows: (1) an $819 million write-down
of net property, plant, and equipment, (2) the elimination of the unamortized
portion of goodwill in the amount of $446 million, and (3) an accrual of $10
million representing selling costs.

     On December 22, 2000, after receipt of governmental approvals, PG&E
Corporation completed the stock sale. The total consideration received was $456
million, less $150 million used to retire the PG&E GTT short-term debt, and the
assumption by El Paso of PG&E GTT long-term debt having a book value of $564
million. The final sale price is subject to adjustment during a 120-day working
capital true-up period. The NEG recorded a gain of approximately $20 million
based on its best estimate of the final sales price.

     PG&E GTT's total assets and liabilities, including the charge noted above,
included in PG&E Corporation's Consolidated Balance Sheet at December 31, 1999,
were as follows:

                                                     (in millions)

        Assets
        Current assets                                         $  229
        Noncurrent assets                                         988

                       Total assets                             1,217

        Liabilities
        Current liabilities                                       448
        Noncurrent liabilities                                    624

                       Total liabilities                        1,072

                       Net assets                              $  145


     The following table reflects PG&E GTT's results of operations included in
PG&E Corporation's Statement of Consolidated Operations for the years ended
December 31:


        (in millions)                              2000        1999      1998

        Revenue                                   $ 873     $ 1,753    $2,064
        Operating expenses                          869       3,058     2,115

        Operating income (loss)                       4      (1,305)      (51)

<PAGE>

        Interest expense and other, net             (36)          7       (50)
        Sales price true-up                          20          --        --

        Income (Loss) before income taxes           (12)     (1,298)     (101)
        Income tax provision (benefit)              (32)       (390)      (31)

        Net income (loss)                         $  20     $  (908)   $  (70)

     In December 1999, PG&E Corporation's Board of Directors approved a plan to
dispose of PG&E Energy Services (PG&E ES), a wholly owned subsidiary, through a
sale. The disposal has been accounted for as a discontinued operation, and PG&E
Corporation's investment in PG&E ES was written down to its then estimated net
realizable value. In addition, PG&E Corporation provided a reserve for
anticipated losses through the anticipated date of sale. The total provision for
discontinued operations was $58 million, net of income taxes of $36 million at
December 31, 1999. Of this amount, $33 million (net of taxes) was allocated
toward operating losses for the period leading up to the intended disposal date.
In 2000, $31 million (net of taxes) of actual operating losses was charged
against this reserve. During the second quarter of 2000, the NEG finalized the
transactions related to the disposal of the energy commodity portion of PG&E ES
for $20 million, plus net working capital of approximately $65 million, for a
total of $85 million. In addition, the sale of the Value-Added Services business
and various other assets was completed on July 21, 2000, for a total
consideration of $18 million. For the year ended December 31, 2000, an
additional estimated loss of $40 million (or $0.11 per share), net of income tax
of $36 million, was recorded as actual losses in connection with the disposition
exceeded that originally estimated. The principal reason for the additional loss
was due to the mix of assets, and the structure and timing of the actual sales
agreements, as opposed to the one reflected in the initial provision established
in 1999. In addition, the worsening energy situation in California also
contributed to the additional loss incurred. The PG&E ES business segment
generated net losses from operations of $40 million (or $0.11 per share) for the
year ended December 31, 1999.

     In September 1998, PG&E Gen through its indirect subsidiary USGen New
England, Inc. (USGenNE), acquired a portfolio of electric generating assets and
power supply agreements from a wholly-owned subsidiary of the New England
Electric System (NEES). The purchase price, including fuel and other inventories
and transaction costs, was approximately $1.8 billion funded through $1.3
billion of debt and a $425 million equity contribution from PG&E Corporation.
The net purchase price was allocated as follows: electric generating assets of
$2.3 billion classified as property, plant, and equipment, long-term receivables
of $0.8 billion, and out-of-market contractual obligations of $1.3 billion and
asset contracts related to acquired power sales agreement of $45 million. The
acquisition of the NEES assets was considered an asset purchase. Accordingly,
the purchase has been allocated to the assets purchased and the liabilities
assumed based upon an assessment of fair value at the date of acquisition. The
assets acquired included hydroelectric, coal, oil, and natural gas generation
facilities with a combined generating capacity of 4,000 MW. In addition, the
NEG, USGenNE, assumed 23 multi-year power purchase agreements representing an
additional 800 MW of production capacity. The NEG, through a wholly-owned
subsidiary, entered into the agreements as part of the acquisition, which (1)
provided that a wholly-owned subsidiary of NEES would make payments through
January 2008 for the purchase power agreements, and (2) required that the NEG,
through its wholly-owned subsidiary, provide electricity to certain NEES
affiliates under contracts that expire at various times through 2008.

     In July 1998, PG&E Corporation sold its Australian energy holdings for $126
million. PG&E Corporation recognized a loss of approximately $23 million related
to the sale, which is included in other income (expense) on the Statement of
Consolidated Operations.

Note 6: Common Stock


PG&E Corporation

     PG&E Corporation has authorized 800 million shares of no-par common stock,
of which 387 million and 384 million shares were issued as of December 31, 2000
and 1999, respectively.

     During the years ended December 31, 2000 and 1999, PG&E Corporation
repurchased $2 million and $693 million of its common stock, respectively. The
2000 repurchases were for the Dividend Reinvestment Program. The
<PAGE>

1999 repurchases were executed through open market purchases and an accelerated
share repurchase program. Under the 1999 accelerated share repurchase program
agreement, PG&E Corporation repurchased in a specific transaction 16.6 million
shares of its common stock at a cost of $502 million. In connection with this
transaction, PG&E Corporation entered into a forward contract with an investment
institution. PG&E Corporation settled the forward contract and its additional
obligation of $29 million in September 1999. A wholly owned subsidiary of PG&E
Corporation made this repurchase, along with subsequent stock repurchases. The
stock held by the subsidiary is treated as treasury stock and reflected as stock
held by subsidiary on the Consolidated Balance Sheet of PG&E Corporation.

     In October 1999, the Board of Directors of PG&E Corporation authorized an
additional $500 million for the purpose of repurchasing shares of PG&E
Corporation's common stock. The authorization for share repurchases extends
through September 30, 2001. As of December 31, 2000, a subsidiary of PG&E
Corporation had repurchased 23.8 million shares at a cost of $690 million.

     On January 10, 2001, the Board of Directors of PG&E Corporation suspended
the payment of its fourth quarter 2000 stock dividend of $.30 per common share
declared by the Board of Directors on October 18, 2000 and payable on January
15, 2001 to shareholders of record as of December 15, 2000.

     On March 2, 2001, PG&E Corporation refinanced its debt obligations with the
$1 billion aggregate proceeds of two term loans under a common credit agreement
with General Electric Capital Corporation and Lehman Commercial Paper, Inc. (see
Note 3). In accordance with the credit agreement, a part of the proceeds,
together with other PG&E Corporation cash, was used to pay $116 million to PG&E
Corporation shareholders of record as of December 15, 2000, in satisfaction of
the defaulted fourth quarter 2000 common stock dividend. PG&E Corporation is
precluded by these loan agreements from declaring further dividends or
repurchasing its common stock.

Utility

     PG&E Corporation and a subsidiary of the Utility hold all of the Utility's
outstanding common stock. The Utility has authorized 800 million shares of $5
par value common stock of which 321 million shares were issued as of December
31, 2000 and 1999.

     In April 2000, a subsidiary of the Utility repurchased from PG&E
Corporation 11.9 million shares of the Utility's common stock at a cost of $275
million. In December 1999, 7.6 million shares of the Utility's common stock,
with an aggregate purchase price of $200 million, was purchased by the same
subsidiary of the Utility. Total shares purchased were 19.5 million with an
aggregate purchase price of $475 million. These repurchases are reflected as
stock held by subsidiary in the Utility's Consolidated Balance Sheet. Earlier in
1999, the Utility repurchased and cancelled 20 million shares of its common
stock from PG&E Corporation for an aggregate purchase price of $726 million to
maintain its authorized capital structure.

     The CPUC requires the Utility to maintain its CPUC-authorized capital
structure, potentially limiting the amount of dividends the Utility may pay PG&E
Corporation. On January 10, 2001, the Utility suspended the payment of its
fourth quarter 2000 common stock dividend of $110 million, declared in October
2000, to PG&E Corporation. The Utility has suspended payment of its common and
preferred dividends. Dividends on preferred stock are cumulative. Until
cumulative dividends on preferred stock are paid, the Utility may not pay any
dividends on common stock.

Note 7: Preferred Stock and Utility Obligated Mandatorily Redeemable Preferred
        Securities of Trust Holding Solely Utility Subordinated Debentures


Shareholder Rights Plan of PG&E Corporation

     On December 20, 2000, the Board of Directors of PG&E Corporation declared a
distribution of preferred stock purchase rights (the Rights) at a rate of one
Right for each outstanding share of PG&E Corporation's common stock, no par
value. The Rights apply to outstanding shares of PG&E Corporation common stock
held as of the close of business on January 2, 2001, and for each share of
common stock issued by PG&E Corporation thereafter and before the "distribution
date", as described below. Each Right entitles the registered holder, in certain
circumstances, to purchase from PG&E Corporation one one-hundredth of a share (a
Unit) of PG&E Corporation's Series A Preferred Stock, par value $100 per
<PAGE>

share, at an initially fixed purchase price of $95 per Unit, subject to
adjustment. Effective December 22, 2000, the PG&E Corporation Dividend
Reinvestment Plan was modified to note these changes.

     The Rights are not exercisable until the distribution date and will expire
December 22, 2010, unless redeemed earlier by the PG&E Corporation Board of
Directors. The distribution date will occur upon the earlier of (1) 10 days
following a public announcement that a person or group (other than the PG&E
Corporation, any of its subsidiaries, or its employee benefit plans) has
acquired or obtained the right to acquire beneficial ownership of 15% or more of
the then-outstanding shares of PG&E Corporation common stock and (2) 10 business
days (or later, as determined by the Board of Directors) following the
commencement of a tender offer or exchange offer that would result in a person
or group owning 15% or more of the then-outstanding shares of PG&E Corporation
common stock. After the distribution date, certain triggering events will enable
the holder of each Right (other than a potential acquiror) to purchase Units of
Series A Preferred Stock having twice the market value of the initially fixed
exercise price, i.e., at a 50% discount. Until a Right is exercised, the holder
shall have no rights as a shareholder of PG&E Corporation, including, without
limitation, the right to vote or to receive dividends.

     A total of 5,000,000 shares of preferred stock will be reserved for
issuance upon exercise of the Rights. The Units of preferred stock that may be
acquired upon exercise of the Rights will be non-redeemable and subordinate to
any other shares of preferred stock that may be issued by PG&E Corporation. Each
Unit of preferred stock will have a minimum preferential quarterly dividend rate
of $.01 per Unit but will, in any event, be entitled to a dividend equal to the
per share dividend declared on the common stock. In the event of liquidation,
the holder of a Unit will receive a preferred liquidation payment.

     The Rights also have certain anti-takeover effects and will cause
substantial dilution to a person or group that attempts to acquire the Utility
on terms not approved by PG&E Corporation's Board of Directors unless the offer
is conditioned on a substantial number of Rights being acquired. The Rights
should not interfere with any approved merger or other business combination, as
the Board of Directors, at its option, may redeem the Rights. Thus, the Rights
are intended to encourage persons who may seek to acquire control of the PG&E
Corporation to initiate such an acquisition through negotiations with the PG&E
Corporation Board of Directors. However, the effect of the Rights may be to
discourage a third party from making a partial tender offer or otherwise
attempting to obtain a substantial equity position in the equity securities of,
or seeking to obtain control of the PG&E Corporation. To the extent any
potential acquirors are deterred by the Rights, the Rights may have the effect
of preserving incumbent management in office.

Preferred Stock of Utility

     The Utility has authorized 75 million shares of $25 par value preferred
stock, which may be issued as redeemable or non-redeemable preferred stock. At
December 31, 2000 and 1999, the Utility had issued and outstanding 5,784,825
shares of non-redeemable preferred stock.

     At December 31, 2000 and 1999, the Utility had issued and outstanding
5,973,456 shares of redeemable preferred stock. The Utility's redeemable
preferred stock is subject to redemption at the Utility's option, in whole or in
part, if the Utility pays the specified redemption price plus accumulated and
unpaid dividends through the redemption date. Annual dividends and redemption
prices per share at December 31, 2000, range from $1.09 to $1.76 and from $25.75
to $27.25, respectively.

     The Utility's redeemable preferred stock with mandatory redemption
provisions consists of 3 million shares of the 6.57% series and 2.5 million
shares of the 6.30% series at December 31, 2000. The 6.57% series and 6.30%
series may be redeemed at the Utility's option beginning in 2002 and 2004,
respectively, at par value plus accumulated and unpaid dividends through the
redemption date. These series of preferred stock are subject to mandatory
redemption provisions entitling them to sinking funds providing for the
retirement of stock outstanding.

     At December 31, 2000, the redemption requirements for the Utility's
redeemable preferred stock with mandatory redemption provisions are $4 million
per year beginning 2002, and $3 million per year beginning 2004 for the series
6.57% and 6.30%, respectively.

     Holders of the Utility's non-redeemable preferred stock 5%, 5.5%, and 6%
series have rights to annual dividends per share ranging from $1.25 to $1.50.
<PAGE>

  Due to the California energy crisis, the Utility's Board of Directors decided
not to declare the regular preferred stock dividends for the three-month periods
ending January 31, 2001 (normally payable on February 15, 2001) and April 30,
2001 (normally payable May 15, 2001).

  Dividends on all Utility preferred stock are cumulative. All shares of
preferred stock have voting rights and equal preference in dividend and
liquidation rights. The dividend for the three-month period ending January 31,
2001 became a dividend in arrears and, as such, will accumulate from period to
period. Upon liquidation or dissolution of the Utility, holders of preferred
stock would be entitled to the par value of such shares plus all accumulated and
unpaid dividends, as specified for the class and series. Until cumulative
dividends on its preferred stock are paid, the Utility may not pay any dividends
on its common stock, nor may the Utility repurchase any of its common stock.
Accumulated and unpaid preferred stock dividends for the three-month period
ending January 31, 2001 amounted to $6 million.

Preferred Stock of the NEG

  Preferred stock of the NEG consists of $57 million of preferred stock issued
by a subsidiary of PG&E Gen. The preferred stock, with $100 par value, has a
stated non-cumulative quarterly dividend of $3.35 per share, and is redeemable
when there is an excess of available cash. There were 549,594 shares of
preferred stock outstanding at December 31, 2000 and 1999.

Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding
Solely Utility Subordinated Debentures

  The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust), has
outstanding 12 million shares of 7.9% QUIPS, with an aggregate liquidation value
of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to
the Utility 371,135 shares of common securities with an aggregate liquidation
value of $9 million. The Trust in turn used the net proceeds from the QUIPS
offering and issuance of the common stock securities to purchase subordinated
debentures issued by the Utility with a face value of $309 million, due 2025.
These subordinated debentures are the only assets of the Trust. Proceeds from
the sale of the subordinated debentures were used to redeem and repurchase
higher-cost preferred stock.

  The Utility's guarantee of the QUIPS, considered together with the other
obligations of the Utility with respect to the QUIPS, constitutes a full and
unconditional guarantee by the Utility of the Trust's contractual obligations
under the QUIPS issued by the Trust. The subordinated debentures may be redeemed
at the Utility's option beginning in 2000 at par value plus accrued interest
through the redemption date. The proceeds of any redemption will be used by the
Trust to redeem QUIPS in accordance with their terms.

  Upon liquidation or dissolution of the Utility, holders of these QUIPS would
be entitled to the liquidation preference of $25 per share plus all accrued and
unpaid dividends thereon to the date of payment.

  On March 16, 2001, the Utility deferred quarterly interest payments on the
Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025,
until further notice in accordance with the indenture. The corresponding
quarterly payments on the 7.90% Cumulative Quarterly Income Preferred
Securities, Series A, issued by PG&E Capital I due on April 2, 2001, have been
similarly deferred. Distributions can be deferred up to a period of five years
under the terms of the indenture. Investors will accumulate interest on the
unpaid distributions at the rate of 7.90%.

Note 8: Long-Term Debt

  For further information and discussion on credit ratings, downgrades, and
events of default, see Note 3, Subsequent Events of the Notes to the
Consolidated Financial Statements.
<PAGE>

 Long-term debt at December 31, 2000 and 1999 consisted of the following:

<TABLE>
<CAPTION>
                                                                                                 Balance at
                                                                                                December 31,
                                                                                                ------------
(in millions)                                                                                 2000       1999
<S>                                                                                         <C>        <C>
Utility long-term debt
                First and refunding mortgage bonds
             Maturity   Interest rates
             2001-2003  6.25% to 8.75%                                                       $  706     $  816
             2004-2008  5.875% to 6.25%                                                         600        600
             2009-2021  6.35% to 8.08%                                                          160        160
             2022-2026  5.85% to 8.80%                                                        2,004      2,004

             Principal amounts outstanding                                                    3,470      3,580
             Unamortized discount net of premium                                                (28)       (29)

                Total mortgage bonds                                                          3,442      3,551
                Senior notes, 7.375%, due 2005                                                  680         --
                Pollution control loan agreements, variable rates, due 2016-2026              1,267      1,348
                Unsecured medium-term notes, 5.81% to 8.45%, due 2001-2014                      305        418
                Other Utility long-term debt                                                     22         25

Total Utility long-term debt                                                                  5,716      5,342
Long-term debt, classified as current                                                         2,374        465

Total Utility long-term debt, net of current portion                                         $3,342     $4,877

National Energy Group long-term debt
                First mortgage notes, 10.02% to 11.50%, due 2001-2009                        $   --     $  333
                Senior notes, 7.10%, due 2005                                                   250        248
                Medium term notes
             Maturity      Interest Rates
             2001-2003     6.61% to 6.96%                                                        39         70
             2001-2009     7.35% to 9.25%                                                        --        229
                Senior debentures
             Maturity      Interest Rates
             2010          10.00%                                                               159
             2025           7.80%                                                               150        150
                Stock margin loan, LIBOR + 0.40% due 2003                                        --          8
                Premium on long-term debt, due 2000-2009                                         --         63
                Amounts outstanding under credit facilities (See Note 10)                       661        649
                Capital lease obligations, 8.80%, due 2015                                       15         16
                Term loans, various, 2009-2011                                                  107        116
                Mortgage loan payable, 30 day commercial paper rate plus 6.07%, due 2010          8          9
                Other long-term debt                                                             22          7

Total National Energy Group long-term debt                                                    1,411      1,898
Current portion of long-term debt                                                                17         93

Total National Energy Group long-term debt, net of current portion                           $1,394     $1,805

Total long-term debt                                                                         $4,736     $6,682

</TABLE>

PG&E Corporation

Utility
<PAGE>

  The Utility's revolving credit agreement balance of $614 million, as of
December 31, 2000, went into default subsequent to year-end and remains as such.
It has been reclassified to short-term borrowings and is discussed in Note 10 of
the Notes to the Consolidated Financial Statements.

  For further discussion of default status, see Note 3 of the Notes to the
Consolidated Financial Statements. For debt obligations, the priority and
subordination is as follows: senior secured debt (first and refunding mortgage
bonds), and then all other unsecured debt, including notes and bank loans.

First and Refunding Mortgage Bonds

  First and refunding mortgage bonds are issued in series and bear annual
interest rates ranging from 5.85% to 8.80%. All real properties and
substantially all personal properties of the Utility are subject to the lien of
the mortgage, and the Utility is required to make semi-annual sinking fund
payments for the retirement of the bonds. Additional bonds may be issued subject
to CPUC approval, up to a maximum total amount outstanding of $10 billion,
assuming compliance with indenture covenants for earnings coverage and available
property balances as security.

  The Utility redeemed or repurchased $110 million and $281 million of the bonds
in 2000 and 1999, respectively, with interest rates ranging from 6.25% to 8.80%.

  Included in the total of outstanding bonds at December 31, 2000 and 1999 are
$345 million of bonds held in trust for the California Pollution Control
Financing Authority (CPCFA) with interest rates ranging from 5.85% to 6.625% and
maturity dates ranging from 2009 to 2023. In addition to these bonds, the
Utility holds long-term pollution control loan agreements with the CPCFA as
described below.

Senior Notes

  In November 2000, the Utility issued $680 million of five-year senior notes
with an interest rate of 7.375%. The Utility used the net proceeds to repay
short-term indebtedness incurred to finance scheduled payments due to the PX for
August power purchases from the PX and for other general corporate purposes.

  The interest rate on the senior notes is subject to adjustment until May 1,
2002. As such, in the event of a downgrade in the rating below A3 by Moody's or
A- by S&P prior to May 1, 2002, the interest rate on the notes will be
readjusted accordingly.

  As a result of the credit rating downgrades by S&P and Moody's, as described
in Note 3 of the Notes to the Consolidated Financial Statements, there will be
an interest rate adjustment of 1.75% on the $680 million senior notes. The
revised rate will be increased to 9.125% from 7.375% on May 1, 2001, the next
interest payment date. An event of default under the senior notes occured
subsequent to December 31, 2000. Under the default provisions, the trustee or
holders of not less than 25% of the outstanding notes may declare the amounts
outstanding due and payable by notice to the Utility. Accordingly, the amount
outstanding, as of December 31, 2000, has been classified as current in the
accompanying financial statements.

Pollution Control Loan Agreements

  Pollution control loan agreements from the CPCFA totaled $1,267 million and
$1,348 million at December 31, 2000 and 1999, respectively. Interest rates on
the loans vary with average annual interest rates. For 2000 the interest rates
ranged from 2.10% to 4.81%. These loans are subject to redemption by the holder
under certain circumstances. These loans are secured primarily by irrevocable
letters of credit (LOC), which mature in 2001 through 2003. In December 2000,
two of these loans totaling $81 million, were reacquired by the Utility. On
March 1, 2001, a $200 million loan was converted to a fixed interest rate of
5.35%. The Company is in default under the credit provider's reimbursement
agreements due to nonpayment of $100 million of commercial paper. Due to this
default, the credit providers can declare the $1,267 million of principal and
interest immediately due and payable. Through March 29, 2001, no banks had
accelerated the debt. Declaration of bankruptcy is also an event of default
under certain of the pollution control loan agreements. Under certain of the
default provisions, the trustee or holders of the pollution control bonds may
declare the amount outstanding due and payable. Accordingly, amounts outstanding
at December 31, 2000 under the pollution control agreements have been classified
as current in the accompanying financial statements.

Medium-Term Notes
<PAGE>

  The Utility has outstanding $305 million of medium-term notes due 2001 to 2014
with interest rates ranging from 5.81% to 8.45%. An event of default under the
medium-term notes occured subsequent to December 31, 2000. Under the default
provisions, the trustee or holders of not less than 25% of the outstanding notes
may declare amounts outstanding due and payable by notice to the Utility.
Accordingly, the amount outstanding at December 31, 2000 has been classified as
current in the accompanying financial statements.

National Energy Group

  Long-term debt of the NEG consists of first mortgage notes and other secured
and unsecured obligations.

  The first mortgage notes were comprised of three series due annually through
2009, and were secured by mortgages and security interests in the natural gas
transmission and natural gas processing facilities and other real and personal
property of PG&E GTT. The mortgage indenture required semi-annual payments with
one-half of each interest payment and one-fourth of each annual principal
payment escrowed quarterly in advance. The mortgage indenture also contained
covenants that restricted the ability of PG&E GTT to incur additional
indebtedness and precluded cash distributions if certain cash flow coverage were
not met. In January 2000, PG&E GTT obtained an amendment that provided PG&E GTT
the ability to redeem in whole or in part, its mortgage notes, including the
premium set forth in the mortgage note indenture, anytime after January 1, 2000.
These notes were assumed by the buyer of PG&E GTT as of December 31, 2000 (see
Note 5).

  In May 1995, PG&E GTN issued $250 million of 10-year senior unsecured notes
and $150 million of senior unsecured debentures. Other long-term debt consists
of non-recourse project financing associated with unregulated PG&E Generating
facilities, premiums, and other loans.

  Other long-term debt consists of project financing associated with unregulated
generation facilities, premiums, and other loans.

Repayment Schedule

  At December 31, 2000, PG&E Corporation's combined aggregate amounts of capital
spending, maturing long-term debt, and sinking fund requirements are reflected
in the table below:

<TABLE>
<CAPTION>
Expected maturity date                  2001       2002       2003       2004        2005     Thereafter      Total
(dollars in millions)
<S>                                    <C>        <C>         <C>       <C>          <C>      <C>            <C>
Utility:
Long-term debt
   Variable rate obligations            $ 120      $ 697      $ 350      $  40       $   40       $   20      $1,267
   Fixed rate obligations               $ 274      $ 379      $ 354      $ 392       $1,012       $2,038      $4,449
   Average interest rate                  8.0%       7.8%       6.3%       6.4%         6.9%         7.3%        7.2%
Rate reductions bonds                   $ 290      $ 290      $ 290      $ 290       $  290       $  580      $2,030
   Average interest rate                  6.2%       6.3%       6.4%       6.4%         6.4%         6.4%        6.4%

National Energy Group
Long-term debt
   Variable rate obligations            $  16      $  94      $ 584      $   9       $    9       $   80      $  792
   Fixed rate obligations               $   1      $  34      $   7      $   1       $  251       $  325      $  619
   Average interest rate                  9.4%       6.9%       7.0%       9.4%         7.1%         8.9%        8.1%
</TABLE>

Note 9: Rate Reduction Bonds

  In December 1997, PG&E Funding LLC (SPE), a special-purpose entity wholly
owned by the Utility, issued $2.9 billion of rate reduction bonds to the
California Infrastructure and Economic Development Bank Special Purpose Trust
PG&E-1 (Trust), a special-purpose entity. The terms of the bonds generally
mirror the terms of the pass-through certificates issued by the Trust. The
proceeds of the rate reduction bonds were used by the SPE to purchase from the
<PAGE>

Utility the right, known as "transition property," to be paid a specified amount
from a non-bypassable tariff levied on residential and small commercial
customers which was authorized by the CPUC pursuant to state legislation.

  On January 4, 2001, S&P lowered the short-term credit rating of the SPE to A-
3, and on January 5, 2001, Moody's lowered the short-term credit rating of the
SPE to P-3. As a result, on January 8, 2001, remittances for charges paid by
ratepayers for the pass-through certificates issued by the Trust were required
to be made on a daily basis, as opposed to once a month, as had previously been
required.

  The rate reduction bonds have maturities ranging from 6 months to 7 years, and
bear interest at rates ranging from 6.16% to 6.48%. The bonds are secured solely
by the transition property and there is no recourse to the Utility or PG&E
Corporation.

  At December 31, 2000, $2,030 million of rate reduction bonds were outstanding.
The combined expected principal payments on the rate reduction bonds for the
years 2001 through 2005 are $290 million for each year.

  While the SPE is consolidated with the Utility for purposes of these financial
statements, the SPE is legally separate from the Utility. The assets of the SPE
are not available to creditors of the Utility or PG&E Corporation, and the
transition property is not legally an asset of the Utility or PG&E Corporation.

Note 10: Credit Facilities and Short-term Borrowings

See Note 3 for discussion of default status regarding credit facilities and
short-term borrowings.

  At December 31, 2000 and 1999, PG&E Corporation had borrowed $5,191 million
and $2,148 million, respectively, through short-term borrowings and various
credit facilities. At December 31, 2000 and 1999, $661 million and $649 million,
respectively, of these borrowings were outstanding balances related to NEG
credit facilities, which are classified as long-term debt because the NEG has
the ability and intent to finance the amounts outstanding on a long-term basis.
The weighted average interest rate on the short-term borrowings as of December
31, 2000 and 1999, was 7.4% and 5.4%, respectively.

  The following table summarizes PG&E Corporation's lines of credit (see Note 8
of the Notes to the Consolidated Financial Statements) as of December 31, 2000
and 1999:

<TABLE>
<CAPTION>
                                                        Amount of Credit               Amount of Credit
                                                        December 31, 2000              December 31, 1999
                                                        -----------------              -----------------
Lines of Credit                                   Revolving                       Revolving
(in millions)                                       Credit       Outstanding       Credit         Outstanding
                                                    Limits         Balance         Limits           Balance
<S>                                                <C>           <C>              <C>             <C>
PG&E Corporation:
          5-year Revolving Credit                  $  500           $  185          $  500           $   --
          364-day Revolving Credit                    436               --             500               --

Utility:
          5-year Revolving Credit                   1,000              614           1,000               --
          364-day Revolving Credit                    850               --              --               --

National Energy Group:
          Revolving Credit                          1,350              661           1,600              649

Total Lines of Credit                              $4,136           $1,460          $3,600           $  649

Short-Term Borrowings
PG&E Corporation:
          Commercial Paper                                             746                              450
          Extendible Commercial Notes                                   --                               76

Utility:
          Commercial Paper                                           1,225                              449
</TABLE>
<PAGE>

      Floating Rate Notes                              1,240            --

National Energy Group:
      Commercial Paper                                   520           524

Total Commercial Paper and Short-Term Notes           $3,731        $1,499

Sub-total                                             $5,191        $2,148
Less: Classified as long-term debt
      NEG Revolving credit                              (661)         (649)

Total Short Term Borrowings                           $4,530        $1,499


PG&E Corporation

  PG&E Corporation had $436 million and $500 million revolving credit
facilities, which were scheduled to expire in November 2001 and August 2002,
respectively. These credit facilities were used to support PG&E Corporation's
commercial paper program and other liquidity requirements. As a result of the
credit downgrades on January 16 and 17, 2001 (see Note 3), PG&E Corporation
began to default under these credit facilities and the banks refused any
additional borrowing requests and terminated their commitments under the
facilities. As of December 31, 2000, $185 million had been drawn from the $500
million facility. In March 2001, PG&E Corporation secured $1 billion in
aggregate proceeds from two term loans under a common credit agreement with
General Electric Capital Corporation and Lehman Commercial Paper Inc. to
refinance defaulted commercial paper and revolving credit agreements. In
connection with PG&E Corporation's refinancing, the revolving credit facilities
were cancelled. The total amount of commercial paper outstanding at December 31,
2000, backed by the two facilities, was $746 million. The total amount of
commercial paper outstanding at December 31, 1999, backed by the $500 million
facility was $450 million.

Utility

  The Utility had a $1 billion revolving credit facility which was scheduled to
expire in December 2002. In October 2000, the Utility obtained an additional
$1.0 billion credit facility (which was subsequently reduced to $850 million in
December 2000) which expires in December 2001. These facilities were used to
support the Utility's commercial paper program and other liquidity requirements.
As of December 31, 2000, $614 million had been drawn from the $1 billion
facility. Due to a subsequent credit rating downgrade, the banks refused any
additional borrowing requests and terminated their outstanding commitments under
the Utility's two credit facilities (see Note 3). The total amount of commercial
paper outstanding at December 31, 2000 backed by the two facilities was $1,225
million. The weighted average interest rate on the Utility's short-term
borrowings as of December 31, 2000 and 1999 was 7.5% and 5.3%, respectively. The
total amount outstanding at December 31, 1999 backed by the $1 billion facility
was $449 million in commercial paper.

  In addition, the Utility issued a total of $1,240 million in 364-day floating
rate notes in November 2000. These notes mature on November 30, 2001, with
interest payable quarterly. The nonpayment of the Utility's outstanding
commercial paper is an event of default under the floating rate notes, entitling
the floating rate note trustees to accelerate the repayment of these notes. (See
Note 3)

National Energy Group

  The NEG maintains $1,350 million in five revolving credit facilities, which
support commercial paper and Eurodollar borrowing arrangements. At December 31,
2000 and 1999, the NEG had total outstanding balances related to such borrowings
of $1,181 million and $1,173 million, respectively. In addition, certain letters
of credit held by the NEG reduce the available outstanding facility commitments.
At December 31, 2000, approximately $36 million in letters of credit were
outstanding. Since the NEG has the ability and intent to refinance certain
borrowings, $661 million and $649 million of such borrowings were classified as
long-term debt as of December 31, 2000 and 1999, respectively (see Note 8).
<PAGE>

  Certain credit arrangements contain, among other restrictions, customary
affirmative covenants, representations, and warranties and are cross-defaulted
to the NEG's other obligations. The credit agreements also contain certain
negative covenants including restrictions on the following: consolidations,
mergers, sales of assets and investments; certain liens on the NEG's property or
assets; incurrence of indebtedness; entering into agreements limiting the right
of any subsidiary of the NEG to make payments to its shareholders; and certain
transactions with affiliates. Certain credit agreements also require that the
NEG maintain a minimum ratio of cash flow available for fixed charges and a
maximum ratio of funded indebtedness to total capitalization. The NEG was in
compliance with all convenants at December 31, 2000.

Note 11: Nuclear Decommissioning

  Decommissioning of the Utility's nuclear power facilities is scheduled to
begin for ratemaking purposes in 2015 with scheduled completion in 2034. Nuclear
decommissioning means to safely remove nuclear facilities from service and
reduce residual radioactivity to a level that permits termination of the Nuclear
Regulatory Commission license and release of the property for unrestricted use.

  The estimated total obligation for nuclear decommissioning costs, based on a
1997 site study, is $1.7 billion in 2000 dollars (or $5.1 billion in future
dollars). This estimate assumes after-tax earnings on the tax-qualified and non-
tax qualified decommissioning funds of 6.34% and 5.39%, respectively, as well as
a future annual escalation rate of 5.5% for decommissioning costs. The
decommissioning cost estimates are based on the plant location and cost
characteristics for the Utility's nuclear plants. Actual decommissioning costs
are expected to vary from this estimate because of changes in assumed dates of
decommissioning, regulatory requirements, technology, and costs of labor,
materials, and equipment. The estimated total obligation is being recognized
proportionately over the license term of each facility.

  For the year ended December 31, 2000, 1999, and 1998 nuclear decommissioning
costs recovered in rates were $25 million, $26 million, and $33 million,
respectively. The CPUC has established a Nuclear Decommissioning Cost Triennial
Proceeding to review, every three years, updated decommissioning cost estimates
and to establish the annual trust contribution, absent General Rate Cases.

  At December 31, 2000, the total nuclear decommissioning obligation accrued was
$1.3 billion and is included in the balance sheet classification of accumulated
depreciation and decommissioning. Decommissioning costs recovered in rates are
placed in external trust funds. These funds along with accumulated earnings will
be used exclusively for decommissioning and cannot be released from the trust
funds until authorized by CPUC.

  The following table provides a summary of fair value, based on quoted market
prices, of these nuclear decommissioning funds:

<TABLE>
<CAPTION>
                                                                  For the year ended
                                                                     December 31,
                                                                     ------------
                (in millions)                                     Maturity Date   2000        1999
             <S>                                                   <C>           <C>         <C>
             U.S. government and agency issues                     2001-2030     $  409      $  380
             Equity securities                                                      239         223
             Municipal bonds and other                             2001-2034        252         201
             Gross unrealized holding gains                                         447         474
             Gross unrealized holding losses                                        (19)        (14)

             Fair value                                                          $1,328      $1,264
</TABLE>

  The proceeds received from sales of securities were $1.4 billion, $1.7
billion, and $1.4 billion in 2000, 1999, and 1998, respectively. The gross
realized gains on sales of securities held as available-for-sale were $74
million, $59 million, and $52 million in 2000, 1999, and 1998, respectively. The
gross realized losses on sales of securities held as available-for-sale were $64
million, $60 million, and $39 million in 2000, 1999, and 1998, respectively. The
cost of debt and equity securities sold is determined by specific
identification.

  Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy
(DOE) is responsible for the permanent storage and disposal of spent nuclear
fuel. The Utility has signed a contract with the DOE to provide for the
<PAGE>

disposal of spent nuclear fuel and high-level radioactive waste from the
Utility's nuclear power facilities. The DOE's current estimate for an available
site to begin accepting physical possession of the spent nuclear fuel is 2010.
At the projected level of operation for Diablo Canyon, the Utility's facilities
are sufficient to store on-site all spent fuel produced through approximately
2006. It is likely that an interim or permanent DOE storage facility will not be
available for Diablo Canyon's spent fuel by 2006. The Utility is examining
options for providing additional temporary spent fuel storage at Diablo Canyon
or other facilities, pending disposal or storage at a DOE facility.

Note 12: Employee Benefit Plans

     Several of PG&E Corporation's subsidiaries provide noncontributory defined
benefit pension plans for their employees and retirees. In addition, these
subsidiaries provide contributory defined benefit medical plans for certain
retired employees and their eligible dependents and noncontributory defined
benefit life insurance plans for certain retired employees (referred to
collectively as other benefits). For both pension and other benefit plans, the
Utility's plan represents substantially all of the plan assets and the benefit
obligation. Therefore, all descriptions and assumptions are based on the
Utility's plan. The schedules below aggregate all of PG&E Corporation's plans.

  The following schedule reconciles the plans' funded status (the difference
between fair value of plan assets and the benefit obligation) to the prepaid or
accrued benefit cost recorded on the consolidated balance sheet:

<TABLE>
<CAPTION>
                                                         Pension Benefits              Other Benefits
                                                         ----------------              --------------
<S>                                                      <C>            <C>            <C>          <C>
(in millions)                                               2000           1999           2000        1999

Change in benefit obligation
Benefit obligation at January 1                          $(4,807)       $(4,977)       $  (970)     $ (949)
Service cost for benefits earned                            (119)          (121)           (16)        (19)
Interest cost                                               (386)          (347)           (72)        (69)
Plan amendments                                             (347)            --             --          (4)
Actuarial gain (loss)                                        (33)           372            (11)        (19)
Divestiture (acquisition)                                      7             --             17          --
Participants paid benefits                                    --             --            (14)        (14)
Benefits and expenses paid                                   280            266             57         104

Benefit obligation at December 31                        $(5,405)       $(4,807)       $(1,009)     $ (970)

Change in plan assets
Fair value of plan assets at January 1                   $ 8,153        $ 7,104        $ 1,091      $  951
Actual return on plan assets                                 (66)         1,331            (33)        240
Company contributions                                          3              4              2          15
Plan participant contribution                                 --             --             14          14
Divestiture                                                   (2)            --             --          --
Benefits and expenses paid                                  (280)          (286)           (62)       (103)

Fair value of plan assets at December 31                 $ 7,808        $ 8,153        $ 1,012      $1,117

Funded Status
Plan assets in excess of benefit obligation              $ 2,403        $ 3,346        $     3      $  121
Unrecognized prior service cost                              399             93             15          17
Unrecognized net (loss) gain                              (2,001)        (2,963)          (348)       (520)
Unrecognized net transition obligation                        50             65            314         339

Prepaid (accrued) benefit cost                           $   851        $   541        $   (16)     $  (43)

</TABLE>

  The Utility's share of the plan's assets in excess of the benefit obligation
for pensions in 2000 and 1999 was $2,407 million and $3,344 million,
respectively. The Utility's share of the prepaid (accrued) benefit cost for the
pensions in 2000 and 1999 was $864 million and $556 million, respectively.
<PAGE>

     The plan assets of the Utility exceeded its share of the benefit obligation
for other benefits by $3 million and $167 million in 2000 and 1999,
respectively. The Utility's share of the accrued benefit liability for other
benefits in 2000 and 1999 was $15 million and $22 million, respectively.

     Unrecognized prior service costs and the net gains are amortized on a
straight-line basis over the average remaining service period of active plan
participants. The transition obligations for pension benefits and other benefits
are being amortized over 17.5 years from 1987.

     Net benefit income (cost) was as follows:

<TABLE>
<CAPTION>
                                                         Pension Benefits                     Other Benefits
                                                            December 31,                        December 31,
                                                    -----------------------------      -----------------------------
     <S>                                            <C>         <C>         <C>        <C>         <C>         <C>
     (in millions)                                   2000        1999        1998       2000        1999        1998

     Service cost for benefits earned               $(119)      $(121)      $(108)     $ (17)      $ (19)      $ (19)
     Interest cost                                   (386)       (347)       (333)       (72)        (69)        (64)
     Expected return on assets                        679         634         567         91          83          73
     Amortized prior service and transition
      cost                                            (55)        (25)        (26)       (28)        (27)        (28)
     Actuarial gain recognized                        183         111         114         32          20          22
     Settlement gain                                    6          --          --         18          --          --

     Benefit income (cost)                          $ 308       $ 252       $ 214      $  24       $ (12)      $ (16)

</TABLE>

     The Utility's share of the net benefit income for pensions in 2000, 1999,
and 1998 was $302 million, $253 million, and $215 million, respectively.

     The Utility's share of the net benefit cost for other benefits in 2000,
1999, and 1998 was $7 million, $9 million, and $12 million, respectively.

     Net benefit income (cost) is calculated using expected return on plan
assets of 8.5%. The difference between actual and expected return on plan assets
is included in net amortization and deferral and is considered in the
determination of future net benefit income (cost). In 1999 and 1998, actual
return on plan assets exceeded expected return, while actual return on plan
assets was below expected in 2000.

  In conformity with SFAS No. 71, regulatory adjustments have been recorded in
the income statement and balance sheet of the Utility, which reflect the
difference between Utility pension income determined for accounting purposes and
Utility pension income determined for ratemaking, which is based on a funding
approach.

  The CPUC has authorized the Utility to recover the costs associated with its
other benefit plans for 1993 and beyond. Recovery is based on the lesser of the
annual accounting costs or the annual contributions on a tax-deductible basis to
the appropriate trusts. The amount of post-employment benefit costs included in
the regulatory assets as of December 31, 2000 is $34 million, and is expected to
be recovered through rates.

  The following actuarial assumptions were used in determining the plans' funded
status and net benefit income (cost). Year-end assumptions are used to compute
funded status, while prior year-end assumptions are used to compute net benefit
income (cost).

<TABLE>
<CAPTION>
                                                              Pension Benefits                 Other Benefits
                                                                 December 31,                    December 31,
                                                           ------------------------       ------------------------
                                                           2000      1999      1998       2000      1999      1998
<S>                                                       <C>        <C>       <C>       <C>        <C>       <C>

Discount rate                                              7.5%      7.5%      7.0%       7.5%      7.5%      7.0%
Average rate of future compensation increases              5.0%      5.0%      5.0%       5.0%      5.0%      5.0%
Expected long-term rate of return on plan assets           8.5%      8.5%      9.0%       8.5%      9.0%      9.0%
</TABLE>
<PAGE>

  The assumed health care cost trend rate for 2001 is approximately 8.0%,
grading down to an ultimate rate in 2005 and beyond of approximately 6.0%. The
assumed health care cost trend rate can have a significant effect on the amounts
reported for health care plans. A one-percentage point change would have the
following effects:

<TABLE>
<CAPTION>
               (in millions)                            1-Percentage          1-Percentage
                                                       Point Increase        Point Decrease

               <S>                                     <C>                   <C>
               Effect on total service and
                interest cost components                     $ 5                 $ (4)
               Effect on postretirement benefit
                obligation                                   $45                 $(42)
</TABLE>

  PG&E Corporation and its subsidiaries also sponsor defined contribution
pension plans. These plans are intended to qualify under Sections 401(a),
409(a), and 501(a) of the Internal Revenue Code. Employer contribution expense
reflected in the accompanying PG&E Corporation Consolidated Statement of Income
totaled $60 million, $53 million, and $49 million, for the years ended December
31, 2000, 1999, and 1998, respectively.

Long-Term Incentive Program

  PG&E Corporation maintains a Long-Term Incentive Program (Program) that
provides for grants of stock options to eligible participants with or without
associated stock appreciation rights and dividend equivalents. As of December
31, 2000, 30,992,530 shares of PG&E Corporation common stock had been authorized
for award under the Program, with 6,649,736 shares still available under the
Program. Options granted in 2000, 1999, and 1998 had weighted average fair value
at date of grant of approximately $3.26, $4.19, and $3.81 per share,
respectively, using the Black-Scholes valuation method. In addition, PG&E
Corporation granted stock options covering 26,852 shares on January 2, 2001 at
an exercise price of $19.56, and 5,498,500 shares on January 5, 2001 at an
exercise price of $12.63, the then-current market price. Significant assumptions
used in the Black-Scholes valuation method for shares granted in 2000, 1999, and
1998 were: expected stock price volatility of 20.19%, 16.79%, and 17.60%,
respectively; expected dividend yield of 5.18%, 3.77%, and 4.47%, respectively;
risk-free interest rate of 6.10%, 4.69%, and 6.03%, respectively; and an
expected 10-year life for all periods.

  Outstanding stock options become exercisable on a cumulative basis at one-
third each year commencing two years from the date of grant and expire ten years
and one day after the date of grant. Shares outstanding at December 31, 2000 had
option prices ranging from $16.75 to $34.25 and a weighted-average remaining
contractual life of 9.2 years. As permitted under SFAS No. 123, "Accounting for
Stock-Based Compensation," PG&E Corporation applies Accounting Principles Board
Opinion No. 25 "Accounting for Stock Issued to Employees" in accounting for the
Program. As the exercise prices of all stock options is equal to the respective
fair market value at the date of grant, PG&E Corporation does not recognize any
compensation expense related to the Program using the intrinsic value-based
method. Had compensation expense been recognized using the fair value-based
method under SFAS No. 123, PG&E Corporation's pro forma consolidated earnings
(loss) per share would have been as follows:

<TABLE>
<CAPTION>

               <S>                                           <C>            <C>           <C>
                                                                     2000          1999        1998

               Net earnings (loss):
               As reported                                        $(3,364)       $  (73)      $ 719
               Pro-forma                                           (3,374)          (79)        717
               Basic and diluted earnings (loss) per share:
               As reported                                          (9.29)        (0.20)       1.88
               Pro-forma                                            (9.32)        (0.21)       1.88
</TABLE>

  The following table summarizes the Program's activity as of and for the years
ended December 31:

                      2000                      1999                      1998
                      ----                      ----                      ----
<PAGE>

<TABLE>
<CAPTION>
                                                           Weighted                  Weighted                  Weighted
                                                            Average                   Average                   Average
                                                             Option                    Option                    Option
          (shares in million)                 Shares          Price     Shares          Price     Shares          Price
          <S>                                 <C>          <C>          <C>          <C>          <C>          <C>
          Outstanding--beginning of year        16.4         $29.42       11.1         $28.35        6.2         $26.21
          Granted during year                   10.2         $20.03        7.0         $30.94        6.4         $30.53
          Exercised during year                 (1.2)        $23.52       (0.5)        $25.86       (0.7)        $29.63
          Cancellations during year             (1.1)        $26.57       (1.2)        $29.82       (0.8)        $28.16
          Outstanding--end of year              24.3         $25.90       16.4         $29.43       11.1         $28.35
          Exercisable--end of year               6.3         $27.73        3.0         $29.08        2.4         $29.06
</TABLE>

  The following summarizes information for options outstanding and exercisable
at December 31, 2000. Of the outstanding options at December 31, 2000,
11,271,169 shares had exercise prices ranging from $16.75 to $24.38 with a
weighted average remaining contractual life of 9.7 years, of which 2,143,943
shares were exercisable at a weighted average exercise price of $21.90, while
13,071,625 shares had option prices ranging from $24.50 to $34.25, with a
weighted average remaining contractual life of 8.8 years, of which 4,155,548
shares were exercisable at a weighted average exercise price of $30.73.

Performance Unit Plan

  PG&E Corporation grants performance units to certain officers of PG&E
Corporation and its affiliates. The performance units vest one-third in each of
the three years following the year of grant. Each time a cash dividend is
declared on PG&E Corporation common stock, an amount equal to the cash dividend
per share multiplied by the number of outstanding but unearned units held by the
recipient of a performance unit will be accrued on behalf of the recipient. As
soon as practicable following the end of each year, recipients will receive a
cash payment of the dividends accrued for the year, modified by performance for
that year as measured against the applicable performance target. The number of
performance units granted and the amounts of compensation expense recognized in
connection with the issuance of performance units during the years ended
December 31, 2000, 1999, and 1998 was not material.

Note 13: Income Taxes

  The significant components of income tax (benefit) expense for continuing
operations were:

<TABLE>
<CAPTION>
                                                        PG&E Corporation                         Utility
                                                     Year Ended December 31,               Year Ended December 31,
                                               --------------------------------           --------------------------
          <S>                                  <C>            <C>         <C>        <C>            <C>         <C>
          (in millions)                                2000        1999       1998           2000        1999         1998

          Current                                   $(1,261)     $1,002      $ 718        $(1,224)     $1,133        $ 886
          Deferred                                     (728)       (702)       (51)          (891)       (433)        (201)
          Tax credits, net                              (39)        (52)       (56)           (39)        (52)         (56)

          Income tax (benefit) expense              $(2,028)     $  248      $ 611        $(2,154)     $  648        $ 629
</TABLE>

  In 2000, the income tax expense of PG&E Corporation was allocated to
continuing operations ($2,028 million benefit) and discontinued operations ($36
million tax benefit).

 The significant components of net deferred income tax liabilities were:


<TABLE>
<CAPTION>
                                                         PG&E Corporation             Utility
                                                            Year ended               Year ended
                                                            ----------               ----------
                                                           December 31,              December 31,
                                                           ------------              -------------
<S>                                                        <C>           <C>         <C>        <C>
                                                            2000        1999        2000       1999
                                                                         (in millions)
</TABLE>
<PAGE>

<TABLE>
     <S>                                                             <C>         <C>         <C>        <C>
     Deferred income tax assets:
        Customer advances for construction                           $  176      $  109      $  176     $  109
        Unamortized investment tax credits                              114         118         114        118
        Provision for injuries and damages                              203         185         203        185
        Tax benefit of loss carryforward                                 70          --         100         --
        Deferred contract costs                                         124         182          --         --
        Other                                                           322         544         233        442

     Total deferred income tax assets                                $1,009      $1,138      $  826     $  854

     Deferred income tax liabilities:
        Regulatory balancing accounts                                    17         (47)         17        (47)
        Plant in service                                              2,185       2,827       1,719      2,428
        Income tax regulatory asset                                      68         297          65        287
        Other                                                           564       1,075         126        577

     Total deferred income tax liabilities                            2,834       4,152       1,927      3,245

     Total net deferred income taxes                                 $1,825      $3,014      $1,101     $2,391

     Classification of net deferred income taxes:
        Included in current liabilities (assets)                     $  169      $ (133)     $  172     $ (119)
        Included in noncurrent liabilities                            1,656       3,147         929      2,510

     Total net deferred income taxes                                 $1,825      $3,014      $1,101     $2,391

</TABLE>

  The differences between income taxes and amounts determined by applying the
federal statutory rate to income before income tax expense for continuing
operations were:

<TABLE>
<CAPTION>
                                                                     PG&E  Corporation                  Utility
                                                                   Year ended December 31,         Year ended December 31,
                                                                   ------------------------        ----------------------
                                                                    2000      1999     1998        2000     1999     1998
<S>                                                                 <C>       <C>      <C>         <C>      <C>      <C>
Federal statutory income tax rate                                   35.0%     35.0%    35.0%       35.0%    35.0%    35.0%
Increase (decrease) in income tax rate resulting from:
   State income tax (net of federal benefit)                         4.4      10.1      3.2         4.3      6.2      6.6
   Effect of regulatory treatment of depreciation
differences                                                         (2.1)     51.7      9.7        (2.0)     9.4      9.8
   Tax credits--net                                                  0.7     (19.9)    (4.0)        0.7     (3.6)    (4.1)
   Effect of foreign earnings at different tax rates                 0.1      (1.3)     0.6          --       --       --
   Stock sale differences                                           (1.4)     (6.8)      --          --       --       --
   Stock sale valuation allowance                                    1.5      30.2       --          --       --       --
   Other--net                                                       (0.3)     (4.0)    (0.3)        0.2     (1.9)    (1.0)

Effective tax rate                                                  37.9%     95.0%    44.2%       38.2%    45.1%    46.3%

</TABLE>

  As a result of the Utility's purchased power costs which were not recovered in
rates charged to the customers, PG&E Corporation and the Utility incurred a Net
Operating Loss (NOL) for 2000. The NOL was carried back to prior years in
accordance with federal income tax law resulting in a refund of approximately
$1.2 billion. For California income tax purposes 55% of the California NOL may
only be carried forward. The amount of this NOL carryforward is
<PAGE>

$1.2 billion for PG&E Corporation of which $1.7 billion is attributable to the
Utility. The Company has recognized the benefits of its NOLs in the consolidated
financial statements.

  During 1999, PG&E Corporation generated a capital loss carryforward from the
sale of stock of approximately $225 million. The capital loss carryforward
expires in 2005. A valuation allowance of approximately $75 million was recorded
in 1999 reflecting the estimated net realizable value of this capital loss
carryforward. PG&E Corporation, based upon its forecasted net capital gains,
believed that it was more likely than not that it would not be able to fully
utilize the full capital loss carryforward.

Note 14: Commitments



Surety Bonds



Utility

  PG&E Corporation has arranged on behalf of the Utility $456 million in surety
bonds to secure future workers' compensation liabilities. Effective in March,
2001, three of the five insurers of surety bonds have cancelled their coverage.
The aggregate amount of this cancellation is approximately $285 million. This
cancellation relieves the insurers only for claims arising from incidents
occurring after the date of cancellation. They will still be responsible
indefinitely for all future claims arising from incidents occurring prior to the
date of cancellation. This cancellation has not impacted the Utility's self-
insurance program under California law or its ability to meet its current plan
obligations.

Restructuring Trust Guarantees



Utility

  A tax-exempt restructuring trust was established to oversee the development of
the operating framework for the competitive generation market in California. The
CPUC has authorized California utilities to guarantee bank loans of up to $85
million to be used by the trust for this purpose. Under the CPUC authorization,
the Utility's remaining guarantee is for up to a maximum of $38 million of the
loan. Although the remaining bank loan was repaid, the guarantee remains in
place until the earlier of voluntary termination by the trust of the
commitments, or the trust obtaining proceeds from permanent financing or
recovery in rates, or the expiration date of bank loan commitments in December
2001.

Tolling Agreements



National Energy Group

  In 2000 and 1999, the NEG, through PG&E ET, entered into tolling agreements
with several counterparties giving the NEG the right to sell electricity
generated by facilities owned and operated by other parties which are under
construction until June 2003. Under the tolling agreements, the NEG, at its
discretion, supplies the fuel to the power plants, then sells the plant's output
in the competitive market. Committed payments are reduced if the plant
facilities do not achieve agreed-upon levels of performance criteria. At
December 31, 2000, the annual estimated committed payments under such contracts
ranged from approximately $21 million to $304 million, resulting in total
committed payments over the next 28 years of approximately $6.2 billion
commencing at the completion of construction. Estimated amounts payable in
future years are as follows:


          (in millions)

          2001                                                            $   21
<PAGE>

               2002                                                      98
               2003                                                     220
               2004                                                     280
               2005                                                     285
               Thereafter                                             5,300

               Total                                                 $6,204



     During 2000, the NEG paid total committed payments of approximately $12
million under tolling agreements.

Power Purchase Contracts



Utility

     The Utility is required to purchase electric energy and capacity provided
by independent power producers that are QFs under the Public Utilities
Regulatory Policies Act of 1978 (PURPA.) The CPUC required the Utility to enter
into a series of QF long-term power purchase contracts and approved the
applicable terms, conditions, price options, and eligibility requirements.

     Under these contracts, the Utility is required to make payments only when
energy is supplied or when capacity commitments are met. Costs associated with
these contracts are eligible for recovery by the Utility as transition costs
through the collection of the non-bypassable CTC. The Utility's contracts with
these power producers expire on various dates through 2028. Deliveries from
these power producers account for approximately 23% of the Utility's 2000
electric energy requirements, and no single contract accounted for more than
five percent of the Utility's energy needs.

     Prior to 2000, the Utility has negotiated with several QFs for early
termination of their power purchase contracts. At December 31, 2000, the total
discounted future payments due under the renegotiated contracts was
approximately $145 million.

     Approximately half of the Utility's suppliers under long-term QF contracts
have currently elected to receive PX-based prices for energy in addition to
contractual capacity payments. However, pursuant to a CPUC order issued on
February 22, 2001, PX-based-priced QFs reverted back to transition formula
prices on January 19, 2001. Since the end of January 2001, the Utility has been
partially paying amounts due QFs. On March 27, 2001, the CPUC issued a decision
requiring the Utility and the other California investor-owned utilities to pay
QFs fully for energy deliveries made on and after the date of the decision,
within 15 days of the end of the QFs' billing period. The decision permits QFs
to establish a 15-day billing period as compared to the current monthly billing
period. The decision also adopts a revised pricing formula relating to the
California border price of gas applicable to energy payments to all QFs,
including those that do not use natural gas as a fuel. Based on the Utility's
preliminary review of the decision, the revised pricing formula would reduce the
Utility's 2001 average QF energy and capacity payments from approximately 12.7
cents per kWh to 12.3 cents per kWh.

     The amount of energy received and the total payments made under all of
these power purchase contracts were:

                                                    Year Ended December 31,
                                                    -----------------------
(in millions)                                        2000      1999        1998

Kilowatt-hours received                            25,446    25,910      25,994
Energy payments                                  $  1,549  $    837    $    943
Capacity payments                                $    519  $    539    $    529
Irrigation district and water agency pay         $     56  $     60    $     53


National Energy Group
<PAGE>

     The NEG, through its indirect subsidiary, USGenNE, assumed rights and
duties under several power purchase contracts with third-party independent power
producers as part of the acquisition of the NEES assets. At December 31, 2000,
these agreements provided for an aggregate of 800 MW of capacity. Under the
transfer agreement, the NEG is required to pay to NEES amounts due to the third-
party power producers under the power purchase contracts. The approximate dollar
amounts under these agreements are as follows:


               (in millions)


               2001                                                  $  228
               2002                                                     215
               2003                                                     217
               2004                                                     220
               2005                                                     220
               Thereafter                                             1,585

               Total                                                 $2,685



Natural Gas Supply and Transportation Commitments



Utility

     The Utility has long-term gas transportation service contracts with various
Canadian and interstate pipeline companies. These agreements include provisions
for payment of fixed demand charges for reserving firm capacity on the
pipelines. The total demand charges that the Utility will pay each year may
change due to changes in tariff rates. The total demand and volumetric
transportation charges the Utility paid under these agreements were $94 million,
$97 million, and $113 million in 2000, 1999, and 1998, respectively. These
amounts include payments made by the Utility to PG&E GTN of $46 million, $47
million, and $49 million in 2000, 1999, and 1998, respectively, which are
eliminated in the consolidated financial statements of PG&E Corporation.

     The Utility's obligations related to capacity held pursuant to long-term
contracts on various pipelines are as follows:


               (in millions)

               2001                                                 $100
               2002                                                  101
               2003                                                   77
               2004                                                   77
               2005                                                   68
               Thereafter                                             29

               Total                                                $452


     As a result of regulatory changes, the Utility no longer procures gas for
most of its industrial and larger commercial (non-core) customers, resulting in
a decrease in the Utility's need for capacity on these pipelines. Despite these
changes, the Utility continues to procure gas for substantially all of its
residential and smaller commercial (core) customers and its non-core customers
who choose bundled service. To the extent that the Utility's current capacity
<PAGE>

holdings exceed demand for gas transportation by its customers, the Utility will
continue its efforts to broker such excess capacity.

     The Utility's deteriorating credit situation has caused many of its gas
suppliers to decline to sell the Utility any more gas, even under existing gas
contracts, in the absence of accelerated payments. Specifically, some gas
suppliers (1) have made demands that the Utility provide prepayment, cash on
delivery, or other forms of payment assurance for gas supplies instead of the
normal payment terms under which the Utility would pay for gas delivery, which
the Utility is unable to meet given its current cash constraints, and (2) have
refused to sell gas to the Utility for future periods. Failure to procure gas
supplies to meet residential and smaller commercial gas (core) customer demands
could result in diverting gas supplies from industrial and larger commercial gas
(non-core) customers, which would only exacerbate the crisis.

     The U.S. Secretary of Energy issued a temporary order on January 19, 2001
requiring the gas suppliers to continue to make deliveries to avoid a worsening
natural gas shortage emergency. However, this order expired on February 7, 2000,
and certain companies, representing about 10% of the Utility's natural gas
suppliers, terminated deliveries after the order expired. The Utility has tried
to mitigate the worsening supply situation by withdrawing more gas from storage
and, when able, purchasing additional gas on the spot market. Additionally, on
January 31, 2001, the CPUC authorized the Utility to pledge its gas account
receivables and its gas inventories for up to 90 days (extended to 180 days in a
CPUC draft decision issued on February 15, 2001) to secure gas for its core
customers. At March 29, 2001, the amount of gas accounts receivable pledged was
approximately $900 million. To date, approximately 30% of the Utility's
suppliers of natural gas have signed security agreements with the Utility and
discussions are continuing with the Utility's other suppliers. Additionally, the
Utility is currently implementing a program to obtain longer term summer and
winter supplies and daily spot supplies of natural gas.

National Energy Group

     The NEG, through its subsidiaries PG&E Gen and PG&E ET, has entered into
various gas supply and firm transportation agreements with various pipelines and
transporters. Under these agreements, the NEG must make specific minimum
payments each month. The approximate dollar obligations under these gas supply
and transportation agreements are as follows:



               (in millions)

               2001                                                $   87
               2002                                                    87
               2003                                                    87
               2004                                                    85
               2005                                                    85
               Thereafter                                             708

               Total                                               $1,139



Acquisition of Turbine Rights


National Energy Group

     On September 8, 2000, the NEG, through one of its subsidiaries, entered
into operative documents with a special purpose entity (the Lessor) in order to
facilitate the development, construction, financing, and leasing of several
power generation projects. The Lessor has an aggregate financing commitment from
debt and equity participants (the Investors) of $7.8 billion. The NEG, in its
role as construction agent for the Lessor, is responsible for completing
construction by the sixth anniversary of the closing date, but has limited its
risk related to construction completion to less than 90% of project costs
incurred to date. Upon completion of an individual project, the NEG is required
to make lease payments to the Lessor in an amount sufficient to provide a return
to the Investors. At the end of an individual project's operating lease term
(three years from construction completion), the NEG has the option to extend the
lease at fair value, purchase the
<PAGE>

project at a fixed amount (equal to the original construction cost), or act as
remarketing agent for the Lessor and sell the project to an independent third
party. If the NEG elects the remarketing option, the NEG may be required to make
a payment to the Lessors, up to 85% of the project cost, if the proceeds from
remarketing are deficient to repay the Investors. PG&E Corporation committed to
fund up to $314 million of equity to support the NEG's obligation to the Lessor
during the construction and post-construction periods. The NEG is attempting to
replace PG&E Corporation equity support commitments with substitute commitments
of the NEG.

Standard Offer Agreements



National Energy Group

     USGenNE entered into three standard offer agreements with NEES' retail
subsidiaries under which USGenNE will provide "standard offer" service to such
subsidiaries. The standard offer agreements initially covered all of the retail
customers served by NEES' distribution subsidiaries in Rhode Island, New
Hampshire, and Massachusetts at the date of USGenNE's acquisition of the NEES
assets. The Standard Offer Agreements continue through June 30, 2002 in New
Hampshire; December 31, 2004 in Massachusetts; and December 31, 2009 in Rhode
Island. The pricing per MWh is standard for all contracts and was below market
prices at the date of the agreement. On January 7, 2000, USGenNE paid
approximately $15 million by entering into an agreement with a third party which
assumed the obligation to deliver power to NEES to serve 10% of the
Massachusetts customers and 40% of the Rhode Island customers under the terms of
the standard offer agreements. The payment was recorded as a deferred standard
offer fee and is amortized over the remaining life of the standard offer
agreements.

Operating Leases



National Energy Group

     The NEG and its subsidiaries have entered into several operating lease
agreements for generating facilities and office space. Lease terms vary between
three and 48 years. In November 1998, a subsidiary of the NEG entered into a
$479 million sale-leaseback transaction whereby the subsidiary sold and leased
back a pumped storage station under an operating lease.

     During 2000 and 1999, two indirect wholly owned subsidiaries of the NEG
entered into two operating lease commitments relating to projects that are under
construction, for which they act as the construction agent for the lessors. Upon
completion of the construction projects, expected to be in 2001 and 2002, the
lease terms of five years and three years, respectively, will commence. At the
conclusion of each of the operating lease terms, the NEG has the option to
extend the leases at fair market value, purchase the projects, or act as
remarketing agent for the lessors for sales to third parties. If the Company
elects to remarket the projects, then the NEG would be obligated to the lessors
for up to 85% of the project costs if the proceeds are deficient to pay the
lessor's investors. PG&E Corporation has committed to fund up to $604 million in
the aggregate of equity to support the NEG's obligation to the lessors during
the construction and post-construction periods. The NEG is attempting to replace
PG&E Corporation's equity support commitments with substitute commitments of
NEG.

     The approximate obligations under these operating lease agreements as of
December 31, 2000 were as follows:


               (in millions)

               2001                                                $   97
               2002                                                   159
               2003                                                   166
               2004                                                   162
               2005                                                    88
               Thereafter                                             965

<PAGE>

               Total                                               $1,637



     Operating lease expense amounted to $58 million, $67 million, and $35
million in 2000, 1999, and 1998, respectively.

     In addition to those obligations described above, the NEG entered into
operative agreements with a special purpose entity that will own and finance
construction of a facility totaling $775 million. PG&E Corporation has committed
to fund up to $122 million of equity support commitments to meet the obligations
to the entity. The NEG is attempting to replace the PG&E Corporation's equity
support commitments with substitute commitments of NEG.

Construction



National Energy Group

     An indirect wholly owned subsidiary of PG&E Gen entered into a turnkey
construction contract with a third-party contractor to construct a 360-MW
natural gas-fired combined-cycle power plant in Charlton, Massachusetts. The
total contract value is $72 million. The contractor's responsibilities include
designing and engineering the project and providing procurement and construction
services, start-up, training, and performance testing. The contractor had
guaranteed that substantial completion will occur on or prior to August 20,
2000. Through the date of these financial statements, substantial completion has
not occurred and the contractor is paying delay damages in accordance with the
terms of the turnkey construction contract. At December 31, 2000 and 1999,
approximately $69 million and $54 million, respectively, had been paid to the
contractor under the turnkey construction contract.

     The same subsidiary also entered into a power island equipment and supply
contract with Westinghouse Power Corporation (WPC) to provide the power island,
the steam turbine, and the heat recovery steam generator. The total contract
value is $69 million. At December 31, 2000 and 1999, approximately $67 million
had been paid to WPC under the power island contract.

     In another construction transaction, an indirect wholly-owned subsidiary of
PG&E Gen contracted with Siemens Westinghouse Power (SWP) in 2000 to provide the
combustion turbine generator, steam turbine generator and heat recovery steam
generator for its 1,080-MW natural gas-fired combined cycle power plant under
development in Greene County, New York. The total contract value is
approximately $223 million. At December 31, 2000, approximately $69 million had
been paid to SWP. Construction is expected to commence June 2001.

Long-Term Service Agreements



National Energy Group

     The NEG has entered into long-term service agreements for the maintenance
and repair of certain of its combustion turbine or combined-cycle generating
plants under construction. These agreements, which are for periods up to 20
years, may be terminated in the event a planned construction project is
cancelled. Annual amounts for long-term service agreements committed for the
next five years under the current construction plan are as follows as of
December 31, 2000:


               (in millions)


               2001                                                  $ 12
               2002                                                    35
               2003                                                    35
               2004                                                    34
               2005                                                    35
<PAGE>

               Thereafter                                             269

               Total                                                 $420



Note 15: Contingencies



Nuclear Insurance

     The Utility has insurance coverage for property damage and business
interruption losses as a member of Nuclear Electric Insurance Limited (NEIL).
Under this insurance, if a nuclear generating facility suffers a loss due to a
prolonged accidental outage, the Utility may be subject to maximum retrospective
assessments of $12 million (property damage) and $4 million (business
interruption), in each case per policy period, in the event losses exceed the
resources of NEIL.

     The Utility has purchased primary insurance of $200 million for public
liability claims resulting from a nuclear incident. The Utility has secondary
financial protection, which provides an additional $9.3 billion in coverage,
which is mandated by federal legislation. It provides for loss sharing among
utilities owning nuclear generating facilities if a costly incident occurs. If a
nuclear incident results in claims in excess of $200 million, then the Utility
may be assessed up to $176 million per incident, with payments in each year
limited to a maximum of $20 million per incident.

Environmental Remediation



Utility

     The Utility may be required to pay for environmental remediation at sites
where it has been or may be a potentially responsible party under the
Comprehensive Environmental Response, Compensation, and Liability Act, and
similar state environmental laws. These sites include former manufactured gas
plant sites, power plant sites, and sites used by it for the storage or disposal
of potentially hazardous materials. Under federal and California laws, the
Utility may be responsible for remediation of hazardous substances, even if it
did not deposit those substances on the site.

     The Utility records an environmental remediation liability when site
assessments indicate remediation is probable and a range of reasonably likely
clean-up costs can be estimated. The Utility reviews its remediation liability
quarterly for each identified site. The liability is an estimate of costs for
site investigations, remediation, operations and maintenance, monitoring, and
site closure. The remediation costs also reflect (1) current technology, (2)
enacted laws and regulations, (3) experience gained at similar sites, and (4)
the probable level of involvement and financial condition of other potentially
responsible parties. Unless there is a better estimate within this range of
possible costs, the Utility records the lower end of this range.

     At December 31, 2000, the Utility expects to spend $320 million for
hazardous waste remediation costs at identified sites, including divested
fossil-fueled power plants. The cost of the hazardous substance remediation
ultimately undertaken by the Utility is difficult to estimate. A change in
estimate may occur in the near term due to uncertainty concerning the Utility's
responsibility, the complexity of environmental laws and regulations, and the
selection of compliance alternatives. If other potentially responsible parties
are not financially able to contribute to these costs or further investigation
indicates that the extent of contamination or necessary remediation is greater
than anticipated, the Utility could spend as much as $462 million on these
costs. The Utility estimates the upper limit of the range using assumptions
least favorable to the Utility, based upon a range of reasonably possible
outcomes. Costs may be higher if the Utility is found to be responsible for
clean-up costs at additional sites or expected outcomes change.

     The Utility had an environmental remediation liability of $320 million and
$271 million at December 31, 2000 and 1999, respectively. The $320 million
accrued at December 31, 2000 includes (1) $140 million related to the pre-
closing remediation liability, associated with the divested generation
facilities discussed further in the "Generation Divestiture" section of Note 2
of the Notes to the Consolidated Financial Statements, and (2) $180 million
related to remediation costs for those generation facilities that the Utility
still owns, manufactured gas plant sites, and gas gathering
<PAGE>

compressor stations. Of the $320 million environmental remediation liability,
the Utility has recovered $168 million through rates, and expects to recover
another $87 million in future rates. The Utility is seeking recovery of the
remainder of its costs from insurance carriers and from other third parties as
appropriate.

     In December 1999, the Utility was notified by the purchaser of its former
Moss Landing power plant that it had identified a cleaning procedure used at the
plant that released heated water from the intake, and that this procedure is not
specified in the plant's National Pollutant Discharge Elimination System (NPDES)
permit issued by the Central Coast Regional Water Quality Control Board (Central
Coast Board). The purchaser notified the Central Coast Board of its findings. In
March 2000, the Central Coast Board requested the Utility to provide specific
information regarding the "backflush" procedure used at Moss Landing. The
Utility provided the requested information to the Board in April 2000. The
Utility's investigation indicated that while it owned Moss Landing, significant
amounts of water discharged from the cooling water intake. While the Utility's
investigation did not clearly indicate that discharged waters had a temperature
higher than ambient receiving water, the Utility believes that the temperature
of the discharged water was higher than that of the ambient receiving water. In
December 2000, the executive officer of the Central Coast Board made a
settlement proposal to the Utility under which it would pay $10 million, a
portion of which would be used for environmental projects and the balance of
which would constitute civil penalties. Settlement negotiations are continuing.

     The Utility's Diablo Canyon employs a "once through" cooling water system
which is regulated under a NPDES Permit issued by the Central Coast Board. This
permit allows Diablo Canyon to discharge the cooling water at a temperature no
more than 22 degrees above ambient receiving water, and requires that the
beneficial uses of the water be protected. The beneficial uses of water in this
region include industrial water supply, marine and wildlife habitat, shell fish
harvesting, and preservation of rare and endangered species. In January 2000,
the Central Coast Board issued a proposed draft Cease and Desist Order (CDO)
alleging that, although the temperature limit has never been exceeded, the
Diablo Canyon's discharge was not protective of beneficial uses. In October
2000, the Central Coast Board and the Utility reached a tentative settlement of
this matter pursuant to which the Central Coast Board has agreed to find that
the Utility's discharge of cooling water from the Diablo Canyon plant protects
beneficial uses and that the intake technology reflects the "best technology
available" under Section 316(b) of the Federal Clean Water Act. As part of the
settlement, the Utility will take measures to preserve certain acreage north of
the plant and will fund approximately $4.5 million in environmental projects
related to coastal resources. The parties are negotiating the documentation of
the settlement. The final agreement will be subject to public comment and will
be incorporated in a consent decree to be entered in California's Superior
Court.

     PG&E Corporation believes the ultimate outcome of these matters will not
have a material impact on its or the Utility's financial position or results of
operations.

National Energy Group

     In October and November 1999, the U.S. Environmental Protection Agency
(EPA) and several states filed suits or announced their intention to file suits
against a number of coal-fired power plants in Midwestern and Eastern states.
These suits relate to alleged violations of the Clean Air Act. More
specifically, they allege violations of the deterioration prevention and non-
attainment provisions of the Clean Air Act's new source review requirements
arising out of certain physical changes that may have been made at these
facilities without first obtaining the required permits. In May 2000, the NEG
received a request for information seeking detailed operating and maintenance
histories for the Salem Harbor and Brayton Point power plants. If EPA were to
find that there were physical changes in the past that were undertaken without
first receiving the required permits under the Clean Air Act, then penalties may
be imposed and further emission reductions might be necessary at these plants.

     In addition to the EPA, states may impose more stringent air emissions
requirements. The Commonwealth of Massachusetts is considering the adoption of
more stringent air emission reductions from electric generating facilities. If
adopted, these requirements will impact Salem Harbor and Brayton Point. The NEG
has proposed an emission reduction plan that may include modernization of the
Salem Harbor power plant and use of advanced technologies for emissions removal.
It is also studying various advanced technologies for emissions removal for the
Brayton Point power plant.

     The NEG's subsidiary, USGenNE, has proposed a number of state and regional
initiatives that will require it to achieve significant reductions of emissions
by 2010. The NEG expects that USGenNE will meet these requirements through a
combination of installation of controls, use of emission allowances it currently
owns, and purchase of additional allowances. The NEG currently estimates that
USGenNE's total capital cost for complying with these requirements will be
approximately $270 million.
<PAGE>

     PG&E Gen's existing power plants, including USGenNE facilities, are subject
to federal and state water quality standards with respect to discharge
constituents and thermal effluents. Three of the fossil-fueled plants owned and
operated by USGenNE are operating pursuant to NPDES permits that have expired.
For the facilities whose NPDES permit have expired, permit renewal applications
are pending, and it is anticipated that all three facilities will be able to
continue to operate under existing terms and conditions until new permits are
issued. It is estimated that USGenNE's cost to comply with the new permit
conditions could be as much as $55 million through 2005. It is possible that the
new permits may contain more stringent limitations than prior permits.

     During September 2000, USGenNE signed a series of agreements that require,
among other things, that USGenNE alter its existing waste water treatment
facilities at two facilities by replacing certain unlined treatment basins,
submit and implement a plan for the closure of such basins, and perform certain
environmental testing at the facilities. USGenNE has incurred $4 million in 2000
and expects to complete the required steps on or before December 2001. The total
expected cost of these improvements is $21 million.

Legal Matters



Utility

     The Utility's Chapter 11 bankruptcy filing on April 6, 2001, discussed in
Notes 2 and 3, automatically stayed the litigation described below against the
Utility.

Chromium Litigation:

     Several civil suits are pending against the Utility in California state
court. The suits seek an unspecified amount of compensatory and punitive damages
for alleged personal injuries resulting from alleged exposure to chromium in the
vicinity of the Utility's gas compressor stations at Hinckley, Kettleman, and
Topock, California. Currently, there are claims pending on behalf of
approximately 1,050 individuals. The trial of 18 test cases is currently
scheduled for July 2001.

     The Utility is responding to the suits and asserting affirmative defenses.
The Utility will pursue appropriate legal defenses, including statute of
limitations or exclusivity of workers' compensation laws, and factual defenses,
including lack of exposure to chromium and the inability of chromium to cause
certain of the illnesses alleged. PG&E Corporation has recorded a legal reserve
in its financial statements in the amount of $160 million for these matters.
PG&E Corporation and the Utility believe that, after taking into account the
reserves recorded as of December 31, 2000, the ultimate outcome of this matter
will not have a material adverse impact on PG&E Corporation's or the Utility's
financial condition or future results of operations.

Wilson vs PG&E Corporation and Pacific Gas and Electric Company:

     On February 13, 2001, two complaints were filed against PG&E Corporation
and the Utility in the Superior Court of the State of California, San Francisco
County: Richard D. Wilson v. Pacific Gas and Electric Company et al. (Wilson I),
and Richard D. Wilson v. Pacific Gas and Electric Company, et al. (Wilson II).

     In Wilson I, the plaintiff alleges that in 1998 and 1999, PG&E Corporation
violated its fiduciary duties and California Business and Professions Code
Section 17200 by causing the Utility to repurchase shares of Pacific Gas and
Electric Company common stock from PG&E Corporation at an aggregate price of
$2,326 million. The complaint alleges an unlawful business act or practice under
Section 17200 because these repurchases allegedly violated PG&E Corporation's
fiduciary duties, a first priority capital requirement allegedly imposed by the
CPUC's decision approving the formation of a holding company, and also an
implicit public trust imposed by Assembly Bill 1890, which granted authority for
the issuance of rate reduction bonds. The complaint seeks to enjoin the
repurchase by the Utility of any more of its common stock from PG&E Corporation
or other entities or persons unless good cause is shown, and seeks restitution
from PG&E Corporation of $2,326 million, with interest, on behalf of the
Utility. The complaint also seeks an accounting, costs of suit, and attorney's
fees.

     In Wilson II, the plaintiff alleges that PG&E Corporation, the Utility, and
other subsidiaries have been parties to a tax-sharing arrangement under which
PG&E Corporation annually files consolidated federal and state income tax
returns for, and pays, the income taxes of PG&E Corporation and participating
subsidiaries. According to the plaintiff, between
<PAGE>

1997 and 1999, PG&E Corporation collected $2,957 million from the Utility under
this tax-sharing arrangement, but paid only $2,294 million (net of refunds) to
all governments under the tax-sharing agreement. Plaintiff alleges that these
monies were held under an express and implied trust to be used by PG&E
Corporation to pay the Utility's share of income taxes under the tax-sharing
arrangement. Plaintiff alleges that PG&E Corporation overcharged the Utility
$663 million under the tax-sharing arrangement and has declined voluntarily to
return these monies to the Utility, in violation of the alleged trust, the
alleged first priority capital condition, and California Business and
Professions Code Section 17200. The complaint seeks to enjoin PG&E Corporation
from engaging in the activities alleged in the complaint (including the tax-
sharing arrangement), and seeks restitution from PG&E Corporation of $663
million, with interest, on behalf of the Utility. The complaint also seeks an
accounting, costs of suit, and attorney's fees.

     PG&E Corporation's and the Utility's analysis of these complaints is at a
preliminary stage, but PG&E Corporation and the Utility believe them to be
without merit and intend to present a vigorous defense. PG&E Corporation and the
Utility are unable to predict whether the outcome of this litigation will have a
material adverse affect on their financial condition or results of operation.

National Energy Group

     The NEG is involved in various litigation matters in the ordinary course of
its business. Except as described below, the NEG is not currently involved in
any litigation that is expected, either individually or in the aggregate, to
have a material adverse effect on financial condition or results of operations.

Texas Franchise Fee Litigation Against PG&E GTT

     PG&E GTT and various of its affiliates are defendants in at least two class
action suits and five separate suits filed by various Texas cities. Generally,
these cities allege, among other things, that (1) owners or operators of
pipelines occupied city property and conducted pipeline operations without the
cities' consent and without compensating the cities, and (2) the gas marketers
failed to pay the cities for accessing and utilizing the pipelines located in
the cities to flow gas under city streets. Plaintiffs also allege various other
claims against the defendants for failure to secure the cities' consent. Damages
are not quantified.

     PG&E Corporation believes that the ultimate outcome of these matters will
not have a material adverse impact on its financial position or its results of
operations. The NEG completed the sale of PG&E GTT in December 2000.

Recorded Liability for Legal Matters:

     In accordance with SFAS No. 5 "Accounting for Contingencies," PG&E
Corporation makes a provision for a liability when both it is probable that a
liability has been incurred and the amount of the loss can be reasonably
estimated. These provisions are reviewed quarterly and adjusted to reflect the
impacts of negotiations, settlements, rulings, advice of legal counsel, and
other information and events pertaining to a particular case. The following
table reflects the current year's activity to the recorded liability for legal
matters:



                                                       PG&E
               (in millions)                        Corporation      Utility


               Beginning balance, January 1, 2000           $106         $ 50
               Provisions for liabilities                    144          144
               Payments                                      (45)         (43)
               Adjustments                                   (20)          34

               Ending balance, December 31, 2000            $185         $185


Note 16: Segment Information

     PG&E Corporation has identified four reportable operating segments, which
were determined based on similarities in economic characteristics, products and
services, types of customers, methods of distributions, the regulatory
environment, and how information is reported to PG&E Corporation's key decision
makers. The Utility is one reportable
<PAGE>

operating segment and the other three are part of PG&E Corporation's NEG. These
four reportable operating segments provide different products and services and
are subject to different forms of regulation or jurisdictions. PG&E
Corporation's reportable segments are described below.

Utility

     PG&E Corporation's Northern and Central California energy utility
subsidiary, Pacific Gas and Electric Company, provides natural gas and electric
service to its customers.

National Energy Group

     PG&E Corporation's subsidiary, the NEG, is an integrated energy company
with a strategic focus on power generation, new power plant development, natural
gas transmission, and wholesale energy marketing and trading in North America.
The NEG businesses include its power plant development and generation unit, PG&E
Generating Company, LLC and its affiliates; its natural gas transmission unit,
PG&E Gas Transmission Corporation; and its wholesale energy marketing and
trading unit, PG&E Energy Trading Holdings Corporation which owns PG&E Energy
Trading--Power, L.P., PG&E Energy Trading-Gas Corporation, and their affiliates.
During 2000, the NEG sold its energy services unit, PG&E Energy Services
Corporation. Also during the fourth quarter of 2000, the NEG sold its Texas
natural gas and natural gas liquids business operated through PG&E Gas
Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their
subsidiaries.

     Segment information for the years 2000, 1999, and 1998 was as follows:

<TABLE>
<CAPTION>
                                                              National Energy Group/(4)/
                                                   --------------------------------------------------
                                                                            PG&E GT
                                                                     ----------------------
                                                                                                         Eliminations &
(in millions)                          Utility     PG&E Gen/(4)/     Northwest   Texas/(4)/   PG&E ET      Other/(5)/      Total
<S>                                    <C>         <C>               <C>         <C>          <C>        <C>              <C>
2000
Operating revenues                     $ 9,623           $1,201       $  188       $  817      $14,414        $   (11)    $26,232
Intersegment revenues/(1)/                  14               10           51           56        1,640         (1,771)         --

Total operating revenues                 9,637            1,211          239          873       16,054         (1,782)     26,232
Depreciation, amortization
and decommissioning                      3,511               91           41           70           11            (65)      3,659
Interest income                            186               66            1           (4)           7             10         266
Interest expense/(3)/                     (619)             (61)         (41)         (49)          (5)           (13)       (788)
Income taxes (benefits)/(2)/            (2,154)              57           37          (35)          55             12      (2,028)
Income (loss) from
continuing operations                   (3,508)              84           58           20           27             (5)     (3,324)
Capital expenditures/(6)/                1,245              495           15           --            3             --       1,758
Total assets at year-end/(5)/(6)/      $21,988           $4,568       $1,204       $   --      $ 7,098        $   433     $35,291

1999
Operating revenues                     $ 9,084           $1,116       $  172       $1,034      $ 9,404        $    10     $20,820
Intersegment revenues/(1)/                 144                6           52          114        1,117         (1,433)         --

Total operating revenues                 9,228            1,122          224        1,148       10,521         (1,423)     20,820
Depreciation, amortization
and decommissioning                      1,564               89           41           75            9              2       1,780
Interest income                             45               62           --            9            4             (2)        118
Interest expense/(3)/                     (593)             (63)         (41)         (59)         (12)            (4)       (772)
Income taxes (benefits)/(2)/               648               16           32         (407)         (36)            (5)        248
Income (loss) from
continuing operations                      763               97           68         (897)         (34)            16          13
Capital expenditures/(6)/                1,181              323           30           19           14             17       1,584
Total assets at year-end/(5)/(6)/      $21,470           $3,852       $1,160       $1,217      $ 1,876        $  (105)    $29,470

1998
Operating revenues                     $ 8,919           $  645       $  185       $1,640      $ 8,183        $     5     $19,577
Intersegment revenues/(1)/                   5                4           52          301          326           (688)         --

Total operating revenues                 8,924              649          237        1,941        8,509           (683)     19,577
Depreciation, amortization
and decommissioning                      1,438               52           39           65            5              3       1,602
Interest income                             96               29            1            9            6            (40)        101
Interest expense/(3)/                     (621)             (43)         (43)         (77)          (7)            10        (781)
Income taxes (benefits)/(2)/               629               28           31          (47)         (17)           (13)        611
Income (loss) from
continuing operations                      702              106           65          (71)          (6)           (25)        771
Capital expenditures/(6)/                1,382               98           49           39           12             39       1,619
Total assets at year-end/(5)/(6)/      $22,950           $3,844       $1,169       $2,655      $ 2,555        $    61     $33,234
</TABLE>
<PAGE>

(1)      Inter-segment electric and gas revenues are recorded at market prices,
         which for the Utility and GTN are tariffed rates prescribed by the CPUC
         and the FERC, respectively.

(2)      Income tax expense for the Utility is computed on a stand-alone basis.
         The balance of the consolidated income tax provision is allocated among
         the National Energy Group.

(3)      Interest expense incurred by PG&E Corporation is allocated to the
         segments using specific identification.

(4)      Income from equity-method investees for 2000, 1999, and 1998 was $65
         million, $63 million, and $113 million, respectively, for PG&E Gen, and
         $1 million, zero, and $3 million, respectively, for PG&E GTT.

(5)      Assets of PG&E Corporation are included in "Eliminations & Other"
         column exclusive of investment in its subsidiaries.

(6)      Capital expenditures and assets of the discontinued operations of
         Energy Services are included in "Eliminations & Other" column. Total
         assets for PG&E ES at December 31, 2000, 1999, and 1998 were $1
         million, $197 million, and $202 million, respectively. Capital
         expenditures for 2000, 1999, and 1998 were zero, $17 million, and $38
         million, respectively.

<PAGE>

               QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)



<TABLE>
<CAPTION>

Quarter ended                                                    December 31       September 30     June 30      March 31
(in millions, except per share amounts)

<S>                                                            <C>                <C>               <C>          <C>
2000
PG&E Corporation
Operating revenues                                                     $ 8,082             $7,504      $5,638        $5,008
Operating income (loss)/(1)(4)/                                         (6,734)               629         622           676
Income (loss) from continuing operations                                (4,096)               244         248           280
Net income (loss)/(1)(4)/                                               (4,117)               225         248           280
Earnings (loss) per common share from continuing operations,
 basic                                                                  (11.28)               .67         .69           .78
Earnings (loss) per common share from continuing operations,
 diluted                                                                (11.28)               .67         .68           .77
Dividends declared per common share                                        .30                .30         .30           .30
Common stock price per share
    High                                                                 28.78              30.90       26.67         22.01
    Low                                                                  18.25              22.50       20.39         18.80
Utility
Operating revenues                                                     $ 2,600             $2,523      $2,296        $2,218
Operating income  (loss)                                                (6,856)               533         552           570
Net income (loss)                                                       (4,156)               217         222           234
Income (loss) available for (allocated to) common stock                 (4,163)               211         216           228
1999
PG&E Corporation
Operating revenues                                                     $ 4,795             $6,217      $4,682        $5,126
Operating income (loss)/(1)(2)(3)/                                        (579)               516         480           461
Income (loss) from continuing operations                                  (547)               197         196           167
Net income (loss)/(1)(2)(3)/                                              (611)               185         182           171
Earnings (loss) per common share from continuing operations,
 basic                                                                   (1.49)              0.54        0.53          0.45
Earnings (loss) per common share from continuing operations,
 diluted                                                                 (1.49)              0.54        0.50          0.39
Dividends declared per common share                                       0.30               0.30        0.30          0.30
Common stock price per share
    High                                                                 26.69              33.25       34.00         33.69
    Low                                                                  20.25              25.00       30.56         29.50
Utility
Operating revenues                                                     $ 2,323             $2,587      $2,233        $2,085
Operating income/(3)/                                                      633                486         452           422
Net income/(3)/                                                            272                185         178           153
Income available for common stock                                          265                179         172           147
</TABLE>

(1)  In the fourth quarter 1999, the NEG adopted a plan to dispose of the PG&E
     ES segment. This planned transaction has been accounted for as a
     discontinued operation. Results of operations of PG&E ES have been excluded
     from continuing operations for all periods presented. The operating loss
     and net loss of PG&E ES for the quarters ending March 31, June 30, and
     September 30, 1999, were $15 million and $8 million, $23 million and $14
     million, and $20 million and $12 million, respectively. An estimated loss
     of $19 million ($0.05 per share), net of income taxes of $13 million, was
     recorded for the quarter and nine months ended September 30, 2000.
     Additionally, an estimated loss of $21 million ($0.06 per share), net of
     income taxes of $23 million, was recorded for the quarter and three-month
     period ended December 31, 2000.

(2)  Amounts have been restated to reflect the change in accounting for major
     maintenance and overhauls at the NEG (see Note 1), and reclassification of
     PG&E ES operating results to discontinued operations (see above). The
     accounting change resulted in a cumulative effect being recorded as of
     January 1, 1999 of $12 million ($0.03 per share), net of income taxes of $8
     million. Operating income previously reported for 1999 was $442 million,
     $454 million, and $492 million for each of the first three quarters,
     respectively. Net income previously reported for 1999 was $156 million
     ($0.42 per share), $180 million ($0.49 per share), and $183 million ($0.50
     per share) for the same periods.

(3)  In the fourth quarter of 1999, the Utility recorded the effects of the
     outcome of the GRC. This resulted in an increase of $256 million in
     operating income and an increase of $153 million in net income.
     Additionally, the NEG recorded an after-tax charge of $890 million
     reflecting PG&E GTT's assets at their fair market value. (See MD&A and Note
     5.)

(4)  In the fourth quarter of 2000, the Utility recorded a charge to earnings
     for the write-off of regulatory assets representing transition costs and
     undercollected purchased power costs. The write-off was $6.9 billion ($4.1
     after-tax) and reflected the fact that based upon the current status of the
     California energy crisis, the Utility could no longer conclude that the
     regulatory assets were probable of recovery through regulated rates.

     Also in the fourth quarter of 2000, the Utility recognized a $140 million
     ($83 million, after tax) provision for an increase in legal reserves.
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

To the Boards of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company

  We have audited the accompanying consolidated balance sheets of PG&E
Corporation and subsidiaries and Pacific Gas and Electric Company and
subsidiaries as of December 31, 2000 and 1999, and the related statements of
consolidated operations, cash flows and common stock equity of PG&E Corporation
and the related statements of consolidated operations, cash flows and
stockholders' equity of Pacific Gas and Electric Company for the years then
ended. These financial statements are the responsibility of the management of
PG&E Corporation and of Pacific Gas and Electric Company. Our responsibility is
to express an opinion on these financial statements based on our audits. The
consolidated financial statements for the year ended December 31, 1998 were
audited by other auditors whose report, dated February 8, 1999, expressed an
unqualified opinion on those statements.

  We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audits 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, such 2000 and 1999 financial statements present fairly, in all
material respects, the financial position of PG&E Corporation and Pacific Gas
and Electric Company as of December 31, 2000 and 1999, and the results of their
consolidated operations and cash flows for the years then ended in conformity
with accounting principles generally accepted in the United States of America.

  As discussed in Note 1 of the Notes to Consolidated Financial Statements, in
1999 PG&E Corporation changed its method of accounting for major maintenance and
overhauls.

  The accompanying consolidated financial statements have been prepared on a
going concern basis of accounting. As discussed in Notes 2 and 3 of the Notes to
the Consolidated Financial Statements, Pacific Gas and Electric Company, a
subsidiary of PG&E Corporation, has incurred power purchase costs substantially
in excess of amounts charged to customers in rates. On April 6, 2001, Pacific
Gas and Electric Company sought protection from its creditors by filing a
voluntary petition under provisions of Chapter 11 of the U.S. Bankruptcy Code.
These matters raise substantial doubt about Pacific Gas and Electric Company's
ability to continue as a going concern. Managements' plans in regard to these
matters are also described in Notes 2 and 3 of the Notes to the Consolidated
Financial Statements. The consolidated financial statements do not include any
adjustments that might result from the outcome of this uncertainty.

DELOITTE & TOUCHE LLP
San Francisco, California
April 6, 2001
<PAGE>

            RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS

  In both PG&E Corporation and Pacific Gas and Electric Company (the Utility)
management is responsible for the integrity of the accompanying consolidated
financial statements. These statements have been prepared in accordance with
accounting principles generally accepted in the United States of America.
Management considers materiality and uses its best judgment to ensure that such
statements reflect fairly the financial position, results of operations, and
cash flows of PG&E Corporation and the Utility.

  PG&E Corporation and the Utility maintain systems of internal controls
supported by formal policies and procedures which are communicated throughout
PG&E Corporation and the Utility. These controls are adequate to provide
reasonable assurance that assets are safeguarded from material loss or
unauthorized use and that necessary records are produced for the preparation of
consolidated financial statements. There are limits inherent in all systems of
internal controls, based on recognition that the costs of such systems should
not exceed the benefits to be derived. PG&E Corporation and the Utility believe
that their systems of internal control provide this appropriate balance. PG&E
Corporation management also maintains a staff of internal auditors who evaluate
the adequacy of, and assess the adherence to, these controls, policies, and
procedures for all of PG&E Corporation, including the Utility.

  Both PG&E Corporation's and the Utility's 2000 and 1999 consolidated financial
statements have been audited by Deloitte & Touche LLP, PG&E Corporation's
independent auditors. The audit includes consideration of internal accounting
controls and performance of tests necessary to support an opinion. The auditors'
report contains an independent informed judgment as to the fairness, in all
material respects, of reported results of operations and financial position.

  The Audit Committee of the Board of Directors for PG&E Corporation meets
regularly with management, internal auditors, and Deloitte & Touche, jointly and
separately, to review internal accounting controls and auditing and financial
reporting matters. The internal auditors and Deloitte & Touche LLP have free
access to the Audit Committee, which consists of five outside directors. The
Audit Committee has reviewed the financial data contained in this report.

  PG&E Corporation and the Utility are committed to full compliance with all
laws and regulations and to conducting business in accordance with high
standards of ethical conduct. Management has taken the steps necessary to ensure
that all employees and other agents understand and support this commitment.
Guidance for corporate compliance and ethics is provided by an officers' Ethics
Committee and by a Legal Compliance and Business Ethics organization. PG&E
Corporation and the Utility believe that these efforts provide reasonable
assurance that each of their operations is conducted in conformity with
applicable laws and with their commitment to ethical conduct.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-21
<SEQUENCE>33
<FILENAME>dex21.txt
<DESCRIPTION>SUBSIDIARES OF THE REGISTRANT
<TEXT>

<PAGE>

                                                                      EXHIBIT 21


      Subsidiaries of PG&E Corporation and Pacific Gas and Electric Company
      ---------------------------------------------------------------------

1.  Name, State of organization, location and nature of business of registrants
    and every subsidiary thereof,

        1.1.       PG&E Corporation ("Claimant")
                   California corporation

                   PG&E Corporation
                   One Market, Spear Tower, Suite 2400
                   San Francisco, CA 94105

                   PG&E Corporation, incorporated under the laws of the State of
                   California, is a holding company formed by Pacific Gas and
                   Electric Company, a public utility. On January 1, 1997 PG&E
                   Corporation became the parent of Pacific Gas and Electric
                   Company pursuant to a corporate reorganization plan. PG&E
                   Corporation is also the parent of nonutility subsidiaries
                   formerly owned by Pacific Gas and Electric Company.

        1.2.       Subsidiaries

        1.2.1.     Elm Power Corporation
                   Delaware corporation

                   One Market, Spear Tower, Suite 2400
                   San Francisco, CA 94105

                   Elm Power Corporation, incorporated under the laws of the
                   State of Delaware, is a wholly subsidiary of PG&E
                   Corporation.

        1.2.2.     Pacific Gas and Electric Company California corporation

                   77 Beale Street
                   P.O. Box 770000
                   San Francisco, CA 94177

                   Pacific Gas and Electric Company is a wholly owned subsidiary
                   of PG&E Corporation. Pacific Gas and Electric Company is an
                   operating public utility engaged principally in the business
                   of supplying electric and natural gas service throughout most
                   of Northern and Central California.

        1.2.2.1.   Alberta and Southern Gas Co., Ltd.
                   Alberta corporation

                   1500 Bankers Hall
                   855 Second Street, SW
                   Calgary, Alberta T2P 4J7

                   Alberta and Southern Gas Co. Ltd. is a wholly owned Canadian
                   subsidiary of Pacific Gas and Electric Company. Alberta and
                   Southern Gas Co. Ltd. formerly purchased natural gas in
                   Canada for the California market.

        1.2.2.1.1. Alberta and Southern Gas Marketing, Inc.
                   Alberta corporation

                   1500 Bankers Hall
                   855 Second Street, SW
                   Calgary, Alberta T2P 4J7

                   Alberta and Southern Gas Marketing, Inc. is a wholly owned
                   subsidiary of Alberta and Southern Gas Co. Ltd. Alberta and
                   Southern Gas Marketing, Inc., formerly marketed natural gas
                   in non-California markets.

                                       1
<PAGE>

1.2.2.2.     Natural Gas Corporation of California
             California corporation

             P.O. Box 770000
             77 Beale Street, 32nd Floor
             San Francisco, CA 94177

             Natural Gas Corporation of California is a wholly owned subsidiary
             of Pacific Gas and Electric Company. Natural Gas Corporation of
             California acts as the vehicle for the amortization of certain
             regulatory assets.

1.2.2.2.1.   NGC Production Company
             California corporation

             P.O. Box 770000
             77 Beale Street, 32nd Floor
             San Francisco, CA 94177

             NGC Production Company is a wholly owned subsidiary of Natural Gas
             Corporation of California. NGC Production Company facilitates
             project financing for Natural Gas Corporation of California's
             capital requirements.

1.2.2.2.2.   Alaska Gas Exploration Associates
             California corporation

             P.O. Box 770000
             77 Beale Street, 32nd Floor
             San Francisco, CA 94177

             Alaska Gas Exploration Associates is 50% owned by Natural Gas
             Corporation of California.

1.2.2.3.     Pacific Conservation Services Company
             California corporation

             P.O. Box 770000
             77 Beale Street, 32nd Floor
             San Francisco, CA 94177

             Pacific Conservation Services Company is a wholly owned subsidiary
             of Pacific Gas and Electric Company. Pacific Conservation Services
             Company engages in borrowing and lending operations required to
             fund Pacific Gas and Electric Company conservation loan programs.

1.2.2.4.     Calaska Energy Company
             California corporation

             P.O. Box 770000
             77 Beale Street, 32nd Floor
             San Francisco, CA 94177

             Calaska Energy Company is a wholly owned subsidiary of Pacific Gas
             and Electric Company. Calaska Energy Company was Pacific Gas and
             Electric Company's representative in the Alaska Highway Pipeline
             Project, which was formed to bring Prudhoe Bay natural gas to the
             lower 48 states.

1.2.2.5.     Eureka Energy Company
             California corporation

             P.O. Box 770000
             77 Beale Street, 32nd Floor
             San Francisco, CA 94177

             Eureka Energy Company is a wholly owned subsidiary of Pacific Gas
             and Electric Company. Eureka Energy Company owns land in San Luis
             Obispo County.

                                       2
<PAGE>

1.2.2.6.    Standard Pacific Gas Line, Incorporated
            California corporation

            P.O. Box 770000
            77 Beale Street, 32nd Floor
            San Francisco, CA 94177

            Standard Pacific Gas Line, Incorporated is a subsidiary of Pacific
            Gas and Electric Company. Standard Pacific Gas Line, Inc. transports
            natural gas in California. Pacific Gas and Electric Company owns a
            85.71% interest, and Chevron Pipe Line Company owns the remaining
            14.29% interest.

1.2.2.7.    Pacific California Gas System, Inc.
            California corporation

            P.O. Box 770000
            77 Beale Street, 32nd Floor
            San Francisco, CA 94177

            Pacific California Gas System, Inc. is a wholly owned subsidiary of
            Pacific Gas and Electric Company. Pacific California Gas System,
            Inc. was created to hold intrastate gas pipeline operations.

1.2.2.8.    Pacific Energy Fuels Company
            California corporation

            P.O. Box 770000
            77 Beale Street, 32nd Floor
            San Francisco, CA 94177

            Pacific Energy Fuels Company is a wholly owned subsidiary of Pacific
            Gas and Electric Company. Pacific Energy Fuels Company owns and
            finances nuclear fuel inventory.

1.2.2.9.    Pacific Gas Properties Company
            California corporation

            P.O. Box 770000
            77 Beale Street, 32nd Floor
            San Francisco, CA 94177

            Pacific Gas Properties Company is a wholly owned subsidiary of
            Pacific Gas and Electric Company. Pacific Gas Properties Company
            owns California property.

1.2.2.9.1.  Pacific Properties
            California corporation

            P.O. Box 770000
            77 Beale Street, 32nd Floor
            San Francisco, CA 94177

            Pacific Properties is 50% owned by Pacific Gas Properties Company.
            Pacific Properties owns California property.

1.2.2.10.   Chico Commons, L.P.
            California partnership

            One Market, Spear Tower, Suite 2400 San Francisco, CA 94105

            Chico Commons, L.P. is 41% owned by Pacific Gas and Electric Company
            as a limited partner. Chico Commons, L.P. was created to construct
            and own low income housing.

1.2.2.11.   PG&E Capital I

            P.O. Box 770000 77 Beale Street, 32nd Floor
            San Francisco, CA 94177

                                       3
<PAGE>

           PG&E Capital I, a business trust, is 3% owned by Pacific Gas and
           Electric Company. PG&E Capital I was formed as a special purpose
           financing vehicle for the purpose of issuing deferrable income
           securities.

1.2.2.12.  PG&E Funding, LLC
           Delaware corporation

           245 Market Street, Suite 424
           San Francisco, CA 94105

           PG&E Funding, LLC is a wholly owned subsidiary of Pacific Gas and
           Electric Company. PG&E Funding, LLC is a special purpose financing
           vehicle formed for the ownership of transition property and issuance
           of securities.

1.2.2.13.  201 Turk Street, L.P.
           California partnership

           One Market, Spear Tower, Suite 2400
           San Francisco, CA 94105

           201 Turk Street, L.P. is 32.4% owned by Pacific Gas and Electric
           Company as a limited partner. 201 Turk Street, L.P. was created to
           construct and own a low income housing project.

1.2.2.14.  1989 Oakland Housing Partnership Associates, L.P.
           California partnership

           One Market, Spear Tower, Suite 2400
           San Francisco, CA 94105

           1989 Oakland Housing Partnership Associates, L.P. is owned 40% by
           Pacific Gas and Electric Company as a limited partner. 1989 Oakland
           Housing Partnership Associates, L.P. was created to construct and own
           low income housing.

1.2.2.15.  1992 Oakland Regional Housing Partnership Associates, L.P.
           California partnership

           One Market, Spear Tower, Suite 2400
           San Francisco, CA 94105

           1992 Oakland Regional Housing Partnership Associates, L.P. is owned
           17% by Pacific Gas and Electric Company as a limited partner. 1992
           Oakland Housing Partnership Associates, L.P. was created to construct
           and own low income housing.

1.2.2.16.  1994 Oakland Regional Housing Partnership Associates, L.P.
           California partnership

           One Market, Spear Tower, Suite 2400 San Francisco, CA 94105

           1994 Oakland Regional Housing Partnership Associates, L.P. is owned
           12% by Pacific Gas and Electric Company as a limited partner. 1994
           Oakland Regional Housing Partnership Associates, L.P. was created to
           construct and own low income housing.

1.2.2.17.  Pacific Gas and Electric Housing Fund Partnership, L.P.
           California partnership

           One Market, Spear Tower, Suite 2400
           San Francisco, CA 94105

           Pacific Gas and Electric Housing Fund Partnership, L.P. is owned
           99.9% by Pacific Gas and Electric Company as a limited partner.
           Pacific Gas and Electric Housing Fund Partnership, L.P., invests in
           projects that construct and own low income housing.

1.2.2.18.  Merritt Community Capital Fund V, L.P.
           California partnership

                                       4
<PAGE>

           One Market, Spear Tower, Suite 2400
           San Francisco, CA 94105

           Merritt Community Capital Fund V, L.P. is owned 2.2% by Pacific Gas
           and Electric Company as a limited partner. Merritt Community Capital
           Fund V, L.P., was created to construct and own low income housing.

1.2.2.19.  Schoolhouse Lane Apartments, L.P.
           California partnership

           One Market, Spear Tower, Suite 2400
           San Francisco, CA 94105

           Schoolhouse Lane Apartments, L.P. is owned 99% by Pacific Gas and
           Electric Company as a limited partner. Schoolhouse Lane Apartments,
           L.P., was created to construct and own low income housing.

1.2.2.20.  PG&E Holdings, LLC
           Delaware corporation

           One Market, Spear Tower, Suite 2400
           San Francisco, CA 94105

           PG&E Holdings, LLC is a wholly owned subsidiary of Pacific Gas and
           Electric Company. PG&E Holdings, LLC was formed as a holding company
           for repurchased shares.

1.2.2.21.  PG&E CalHydro, LLC
           California corporation

           One Market, Spear Tower, Suite 2400
           San Francisco, CA 94105

           PG&E CalHydro, LLC is a wholly owned subsidiary of Pacific Gas and
           Electric Company. PG&E CalHydro, LLC was formed for the purpose of
           owning and operating a system of hydroelectric facilities and related
           watershed.

1.2.3.     PG&E National Energy Group, Inc.
           Delaware corporation

           7500 Old Georgetown Road, 13/th/ Floor
           Bethesda, MD 20814-6161

           PG&E National Energy Group, Inc. is a wholly owned subsidiary of PG&E
           Corporation. PG&E National Energy Group, Inc. was formed for the
           purpose of holding ownership of PG&E Corporation's unregulated
           subsidiaries, both direct and indirect.

1.2.3.1.   PG&E Enterprises
           California corporation

           One Market, Spear Tower, Suite 2400
           San Francisco, CA 94105

           PG&E Enterprises is a wholly owned subsidiary of PG&E National Energy
           Group, Inc. PG&E Enterprises was formed as a holding company for oil
           and gas, real estate, electric generation, and technology
           investments.

1.2.3.1.1. PG&E Shareholdings, Inc.
           California corporation

           One Market, Spear Tower, Suite 2400
           San Francisco, CA 94105

           PG&E Shareholdings, Inc is a wholly owned non-regulated subsidiary of
           PG&E Enterprises. Through its subsidiaries, PG&E Shareholdings, Inc.
           develops real estate in Pacific Gas and Electric Company's service
           territory. In addition, some subsidiaries of PG&E Shareholdings, Inc.
           have made fuel-related investments and a limited number of non-energy

                                       5
<PAGE>

                related investments.

1.2.3.1.1.1.    Gilia Enterprises
                California corporation

                4615 Cowell Blvd.
                Davis, CA 95616

                100% owned by PG&E Shareholdings, Inc. A wholly owned, non-
                regulated indirect subsidiary of PG&E Enterprises through its
                ownership of PG&E Sharingholdings, Inc. Formed to hold interest
                in real estate investment

1.2.3.1.1.1.1.  Marengo Ranch Joint Venture
                California partnership

                4615 Cowell Blvd.
                Davis, CA 95616

                63% owned by PG&E Shareholdings, Inc. as limited partner 1.3%
                owned by Gilia Enterprises as general partner Land development
                in Sacramento County

1.2.3.1.1.1.2.  Oat Creek Associates Joint Venture
                California partnership

                4615 Cowell Blvd.
                Davis, CA 95616

                50% owned by PG&E Shareholdings, Inc. as limited partner 50%
                owned by Gilia Enterprises as general partner Land development
                in Yolo County

1.2.3.1.1.2.    Rancho Murieta Joint Venture
                California partnership

                4615 Cowell Blvd.
                Davis, CA 95616

                45% owned by PG&E Shareholdings, Inc. as limited partner.
                Real estate development.

1.2.3.1.1.3.    1701 Oak Partnership
                California partnership

                4615 Cowell Blvd.
                Davis, CA 95616

                50% owned by PG&E Shareholdings, Inc. as limited partner.
                Real estate development.

1.2.3.1.1.4.    1801 Oak Partnership
                California partnership

                4615 Cowell Blvd.
                Davis, CA 95616

                50% owned by PG&E Shareholdings, Inc. as limited partner.
                Real estate development.

1.2.3.1.1.5.    BPS I, Inc.
                California corporation

                One Market, Spear Tower, Suite 2400
                San Francisco, CA 94105

                100% owned by PG&E Shareholdings, Inc. A wholly-owned, non-
                regulated real estate development subsidiary of PG&E Enterprises
                through its ownership of PG&E Shareholdings, Inc.

1.2.3.1.1.5.1.  Alhambra Pacific (Joint Venture)
                California partnership

                4615 Cowell Blvd.

                                       6
<PAGE>

                   Davis, CA 95616

                   80% owned by PG&E Shareholdings, Inc. as general partner; 20%
                   owned by BPS I, Inc. as limited partner Ownership of property
                   in Yolo County.

1.2.3.1.1.6.       The Conaway Ranch Company
                   California corporation

                   One Market, Spear Tower, Suite 2400
                   San Francisco, CA 94105

                   100% owned by PG&E Shareholdings, Inc. A wholly-owned, non-
                   regulated indirect subsidiary of PG&E Enterprises through its
                   ownership of PG&E Shareholdings, Inc., in partnership with
                   the Conaway Conservancy Group, an existing California general
                   partnership owning the Conaway Ranch.

1.2.3.1.1.6.1.     Conaway Conservancy Group Joint Venture
                   California partnership

                   4615 Cowell Blvd.
                   Davis, CA 95616

                   70% by PG&E Shareholdings, Inc.; and 30% by Conaway Ranch
                   Company Ownership of property in Yolo County.

1.2.3.1.1.7.       DPR, Inc.
                   California corporation

                   One Market, Spear Tower, Suite 2400
                   San Francisco, CA 94105

                   100% owned by PG&E Shareholdings, Inc. A wholly-owned, non-
                   regulated indirect subsidiary of PG&E Enterprises through its
                   ownership of PG&E Shareholdings, Inc.; general partner in a
                   real estate partnership.

1.2.3.1.1.8.       McSweeney Ranch Joint Venture
                   California partnership

                   4615 Cowell Blvd.
                   Davis, CA 95616

                   50% owned by PG&E Shareholdings, Inc.

1.2.3.1.1.9.       PG&E Energy Trading Holdings, LLC
                   Delaware limited liability company

                   7500 Old Georgetown Road, 13th Floor
                   Bethesda, MD 20814-6161

                   100% owned by PG&E Shareholdings, Inc. Formed for the limited
                   purpose of holding stock in PG&E Energy Trading - Power
                   Holdings Corporation.

1.2.3.1.1.9.1.     PG&E Energy Trading - Power Holdings Corporation
                   California corporation

                   7500 Old Georgetown Road, 13th Floor
                   Bethesda, MD 20814-6161

                   100% owned by PG&E Energy Trading Holdings, LLC. Holding
                   company for energy trading and overseas entities.

1.2.3.1.1.9.1.1.   PG&E ET Investments Corporation
                   Delaware corporation

                   7500 Old Georgetown Road, 13th Floor
                   Bethesda, MD 20814-6161

                   100% owned by PG&E Energy Trading - Power Holdings
                   Corporation. Owns the 98% limited partner interest in

                                       7
<PAGE>

                         PG&E Energy Trading - Power, L.P., and the 98%
                         membership interest in PG&E ET Synfuel 166, LLC.

1.2.3.1.1.9.1.1.1.       PG&E Energy Trading-Power, L.P. Delaware limited
                         partnership

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         98% owned by PG&E ET Investments Corporation; 2% owned
                         by PG&E Energy Trading - Power Holdings Corporation
                         Engages in electric power marketing and trading.

1.2.3.1.1.9.1.1.2.       PG&E ET Synfuel 166, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         98% owned by PG&E ET Investments Corporation; and 2%
                         owned by PG&E Energy Trading - Power Holdings
                         Corporation. Formed to acquire a synthetic fuel
                         production facility located in South Carolina.

1.2.3.1.1.9.1.2.         PG&E International Inc.
                         California corporation

                         One Market, Spear Tower, Suite 2400
                         San Francisco, CA 94105

                         PG&E International Inc. is a wholly owned subsidiary of
                         PG&E Energy Trading Power Holdings Corporation, and is
                         a holding company for overseas project companies.

1.2.3.1.1.9.1.2.1.       PG&E International Development Holdings, LLC
                         Delaware limited liability company

                         One Market, Spear Tower, Suite 2400
                         San Francisco, CA 94105

                         A wholly-owned subsidiary of PG&E International, Inc.,
                         formed to own and sell an Australian pipeline
                         development company.

1.2.3.1.1.9.1.2.2.       Gannet Power Corporation
                         California corporation

                         One Market, Spear Tower, Suite 2400
                         San Francisco, CA 94105

                         100% owned by PG&E International Inc.

1.2.3.1.1.9.1.2.3.       PG&E Overseas Holdings I, Ltd.
                         Cayman Islands Company

                         P.O. Box 309, George Town
                         Grand Cayman, Cayman Islands, BWI

                         A wholly-owned subsidiary of PG&E International, Inc.,
                         and is a holding Company for PG&E Overseas Holdings II,
                         Ltd.

1.2.3.1.1.9.1.2.3.1.     PG&E Overseas Holdings II, Ltd. Labuan Company

                         Unit Level 9(A2), Main Office Tower
                         Financial Park Labuan, Jalan Merdeka
                         87000 W.P. Labuan
                         Malaysia

                         100% owned by PG&E Overseas Holdings I, LTD., and is an
                         investment company

1.2.3.1.1.9.1.2.3.1.1.   PG&E Corporation Australian Holdings Pty, Ltd.
                         Australian corporation

                                       8
<PAGE>

                              Level 33, Waterfront Place
                              One Eagle Street
                              Brisbane, Queensland  4000
                              Australia

                              100% owned by PG&E Overseas Holding II, Ltd.
                              Holding company for Australian companies

1.2.3.1.1.9.1.2.3.1.1.1.      PG&E Gas Transmission Australia Pty Ltd.
                              Australian corporation

                              Level 33, Waterfront Place
                              One Eagle Street
                              Brisbane, Queensland 4000
                              Australia

                              100% owned by PG&E Corporation Australian
                              Holdings Pty, Ltd.
                              Investment company.

1.2.3.1.1.9.1.2.3.1.1.2.      PG&E Gas Transmission Queensland Pty Ltd
                              Australian corporation

                              Level 33, Waterfront Place
                              One Eagle Street
                              Brisbane, Queensland 4000
                              Australia

                              100% owned by PG&E Corporation Australian
                              Holdings Pty, Ltd.
                              Pipeline operator.

1.2.3.1.1.9.1.2.3.1.1.3.      PG&E Gas Transmission Unit Holdings Pty Ltd
                              Australian corporation

                              Level 33, Waterfront Place
                              One Eagle Street
                              Brisbane, Queensland 4000
                              Australia

                              100% owned by PG&E Corporation Australian
                              Holdings Pty, Ltd.
                              Investment company.

1.2.3.1.1.9.1.2.3.1.1.4.      PG&E Energy Trading Australia Pty Ltd
                              Australian corporation

                              Level 33, Waterfront Place
                              One Eagle Street
                              Brisbane, Queensland 4000
                              Australia

                              100% owned by PG&E Corporation Australian
                              Holdings Pty, Ltd.
                              Energy marketing company.

1.2.3.1.1.9.1.2.3.1.1.5.      PG&E Corporation Australia Pty Ltd.
                              Australian corporation

                              Level 33, Waterfront Place
                              One Eagle Street
                              Brisbane, Queensland 4000
                              Australia

                              100% owned by PG&E Corporation Australian
                              Holdings Pty, Ltd.
                              Provides corporate services.

1.2.3.1.1.9.1.2.4.            PG&E Gas Transmission Bundaberg Pty Ltd.
                              Australian corporation

                              Level 33, Waterfront Place
                              One Eagle Street
                              Brisbane, Queensland 4000
                              Australia

                                       9
<PAGE>

                         100% owned by PG&E International, Inc.
                         Project development company.

1.2.3.1.1.9.1.2.5.       Rocksavage Services I, Inc.
                         Delaware corporation

                         One Market, Spear Tower, Suite 2400
                         San Francisco, CA 94105

                         100% owned by PG&E International Inc.

1.2.3.1.1.9.1.3.         PG&E Energy Trading - Gas Corporation
                         California corporation

                         7500 Georgetown Road, 13/th/ Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Energy Trading - Power Holdings
                         Corporation. Engages in natural gas marketing and
                         trading activities in the United States.

1.2.3.1.1.9.1.3.1.       PG&E Energy Trading, Canada Corporation
                         Alberta corporation

                         335 Eighth Avenue, S.W. Suite 1740
                         Calgary, Alberta T2P 1CP
                         Canada

                         100% owned by PG&E Energy Trading - Gas Corporation.
                         Engages in natural gas marketing and trading activities
                         in Canada.

1.2.3.1.1.9.1.3.1.1.     CEG Energy Options Inc.
                         Saskatchewan corporation

                         2366 Avenue C North, Suite 101
                         Saskatoon, Saskatchewan S7L 5X5
                         Canada

                         100% owned by PG&E Energy Trading, Canada Corporation.
                         Engages in natural gas marketing in Saskatchewan.

1.2.3.1.1.9.1.3.2.       True Quote LLC
                         Kentucky limited liability company

                         9931 Corporate Campus Drive, Suite 2400
                         Louisville, KY 40223

                         46.24% owned by PG&E Energy Trading - Gas. Engages in
                         the business of designing, developing, implementing,
                         operating and commercializing a business-to-business e-
                         commerce venture for the transmission of energy and
                         energy-related products

1.2.3.1.1.10.            PG&E Generating Company, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13/th/ Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Shareholdings, Inc. Holding company
                         for PG&E Generating Company activities.

1.2.3.1.1.10.1.          PG&E Generating Energy Group, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13/th/ Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Company, LLC Holding
                         company for PG&E National Energy Group merchant
                         projects and USGen New England, Inc.

1.2.3.1.1.10.1.1.        PG&E Generating Energy Holdings, Inc.
                         Delaware corporation

                                       10
<PAGE>

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC. Formed
                         to be the holding company for the 1% membership
                         interests of the limited liability companies under PG&E
                         Generating Energy Group, LLC

1.2.3.1.1.10.1.1.1.      Badger Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC Formed
                         to own a membership interest in Badger Generating
                         Company, LLC.

1.2.3.1.1.10.1.1.1.1.    Badger Generating Company, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         99% owned by Badger Power Corporation, and 1% owned by
                         PG&E Generating Energy Holdings, Inc. Formed to
                         develop, own, manage and operate a merchant electric
                         generating facility to be located in Wisconsin.

1.2.3.1.1.10.1.2.        Black Hawk Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Energy Group, LLC
                         General and limited partner in Athens Generating
                         Company, L.P.

1.2.3.1.1.10.1.3.        Black Hawk III Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Energy Group, LLC General
                         and limited partner in Lake Road Generating Company,
                         L.P.; holds membership interest in Lake Road Power I,
                         LLC.

1.2.3.1.1.10.1.3.1.      Lake Road Power I, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by Black Hawk III Power Corporation. Formed
                         to own a future partnership Interest in Lake Road
                         Generating Company, L.P.

1.2.3.1.1.10.1.4.        Harlan Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Energy Group, LLC General
                         and limited partner in Umatilla Generating Company,
                         L.P.

1.2.3.1.1.10.1.4.1.      Umatilla Generating Company, L.P.
                         Delaware limited partnership

                         7500 Old Georgetown Road, 13th Floor

                                       11
<PAGE>

                         Bethesda, MD 20814-6161

                         51% owned by Harlan Power Corporation, and 49% owned by
                         Juniper Power Corporation Electric generating facility
                         to be located near Umatilla, Oregon.

1.2.3.1.1.10.1.5.        Peach I Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Holds general partnership interest in
                         Athens Generating Company, L.P.

1.2.3.1.1.10.1.6.        Peach IV Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC Holds
                         general partnership interest in Lake Road Generating
                         Company, L.P.

1.2.3.1.1.10.1.6.1.      Lake Road Power II, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by Peach IV Power Corporation
                         Formed to hold a future partnership interest in Lake
                         Road Generating Company, L.P.

  1.2.3.1.1.10.1.7.      Juniper Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         General partner in Umatilla Generating Company, L.P.

  1.2.3.1.1.10.1.8.      Plover Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Energy Group, LLC
                         General and limited partner in Mantua Creek Generating
                         Company, L.P. and Mantua Creek Urban Renewal, L.P.

1.2.3.1.1.10.1.9.        Beech Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         General partner in Mantua Creek Generating Company,
                         L.P. and Mantua Creek Urban Renewal, L.P.

1.2.3.1.1.10.1.9.1.      Mantua Creek Urban Renewal, L.P.
                         Delaware limited partnership

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         51% owned by Plover Power Corporation, and
                         49% owned by Beech Power Corporation
                         Special purpose tax partnership formed for Mantua Creek
                         Project; formed to operate under the Long Term

                                       12
<PAGE>

                         Tax exemption Law, and to initiate and conduct projects
                         for redevelopment of a redevelopment area pursuant to a
                         redevelopment plan, and, when authorized by financial
                         agreement with the municipality, to acquire, plan,
                         develop, construct, alter, maintain, or operate
                         industrial, commercial or administrative projects.

1.2.3.1.1.10.1.10.       Black Hawk II Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Energy Group, LLC
                         Inactive; formerly a general partner in the "old"
                         Millennium Power Partners, L.P.

1.2.3.1.1.10.1.11.       Peach III Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formerly held interest in Millennium Power Partners,
                         L.P. Inactive and in process of dissolution.

1.2.3.1.1.10.1.12.       First Arizona Land Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formed to enter into real estate options in the State
                         of Arizona for the Harquahala Project.

1.2.3.1.1.10.1.13.       First California Land Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC.
                         Formed to enter into real estate options and/or leases
                         in the State of California

1.2.3.1.1.10.1.14.       PG&E Generating New England, Inc.
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formed to own membership interst in PG&E Generating New
                         England, LLC.

1.2.3.1.1.10.1.14.1.     PG&E Generating New England, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating New England, Inc.
                         Formed to be the successor company to USGen New
                         England, Inc. in the Patriot Project.

1.2.3.1.1.10.1.15.       Attala Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group LLC.
                         Investment company for the Duke/Attala acquisition;

                                       13
<PAGE>

                         owner of Attala Generating Company, LLC.


1.2.3.1.1.10.1.15.1.     Attala Generating Company, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by Attala Power Corporation.
                         Merchant electric generating facility being constructed
                         in Kosciusko, Mississippi.

1.2.3.1.1.10.1.16.       Osprey Power Corporation
                         California corporation

                         100 Pine Street, 20th Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Energy Group, LLC
                         General and limited partner in Millennium Power
                         Partners, L.P. (f/k/a East Syracuse Generating Company,
                         L.P.); owns Magnolia Power Corporation.

1.2.3.1.1.10.1.16.1.     Magnolia Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by Osprey Power Corporation
                         General partner in Millenium Power Parners, L.P.

1.2.3.1.1.10.1.17.       San Gorgonio Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC.
                         Investment company for the acquisition of the Sea
                         West Wind Project.

1.2.3.1.1.10.1.18.       Kennerdell Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formed to own a membership in Kennerdell Generating
                         Company, LLC

1.2.3.1.1.10.1.18.1.     Kennerdell Generating Company, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         99% owned by Kennerdell Power Corporation, and 1% owned
                         by PG&E Generating Energy Holdings, Inc. Formed to
                         develop, own, manage, and operate a merchant electric
                         generating facility to be located in Western
                         Pennsylvania.

1.2.3.1.1.10.1.19.       La Paloma Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC Formed
                         to own a membership interest in La Paloma Generating
                         Company, LLC.

1.2.3.1.1.10.1.20.       Liberty Generating Corporation
                         Delaware corporation

                                       14
<PAGE>

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formed to own a membership interest in Liberty
                         Generating Company, LLC.

1.2.3.1.1.10.1.20.1      Liberty Urban Renewal LLC
                         Delaware limited liability corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         99% owned by Liberty Generating Corporation,
                         1% owned by PG&E Generating Energy Holdings, Inc.
                         Formed to own and lease a merchant electric
                         generating facility to be located in Linden,
                         New Jersey

1.2.3.1.1.10.1.21.       Otay Mesa Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formed to own a membership interest in Otay Mesa
                         Generating Company, LLC.

1.2.3.1.1.10.1.21.1.     Otay Mesa Generating Company, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         99% owned by Otay Mesa Power Corporation, and
                         1% owned by PG&E Generating Energy Holdings, Inc.
                         Formed to develop, manage, and operate a merchant
                         electric generating facility to be located in San
                         Diego County, California.

1.2.3.1.1.10.1.22.       Bluebonnet Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formed to own a membership interest in Bluebonnet
                         Generating Company, LLC.

1.2.3.1.1.10.1.22.1.     Bluebonnet Generating Company, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         99% owned by Bluebonnet Power Corporation, and
                         1% owned by PG&E Generating Energy Holdings, Inc.
                         Formed to develop, own manage, and operate a merchant
                         electric generating facility to be located in Texas.

1.2.3.1.1.10.1.23.       Harquahala Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Owns a membership interest in Harquahala Generating
                         Company, LLC.

1.2.3.1.1.10.1.23.1.     Harquahala Generating Company, LLC
                         Delaware limited liability company


                                       15
<PAGE>

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         99% owned by Harquahala Power Corporation, and
                         1% owned by PG&E Generating Energy Holdings, Inc.
                         Formed to develop, own, manage, and operate a merchant
                         electric generating facility to be located in Arizona.

1.2.3.1.1.10.1.24.       Madison Wind Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formed to own a membership interest in Madison Wind
                         Power, LLC.

1.2.3.1.1.10.1.25.       Okeechobee Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formed to own a membership interest in Okeechobee
                         Generating Company, LLC.

1.2.3.1.1.10.1.26.       PG&E Dispersed Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formed to own membership interest in PG&E Dispersed
                         Generating Company, LLC.

1.2.3.1.1.10.1.27.       Covert Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC
                         Formed to own a membership interest in Covert
                         Generating Company, LLC.

1.2.3.1.1.10.1.28.       Goose Lake Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Energy Group, LLC.
                         Formed to own a membership interest in Goose Lake
                         Generating Company, LLC

1.2.3.1.1.10.1.28.1.     Goose Lake Generating Company, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         99% owned by Goose Lake Power Corporation, and
                         1% owned by PG&E Generating Energy Holdings, Inc.
                         Merchant electric generating facility to be
                         constructed in Goose Lake, Illinois

1.2.3.1.1.10.1.29.       Meadow Valley Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                                       16
<PAGE>

                         100% owned by PG&E Generating Energy Group, LLC,
                         Formed to own a membership interest in
                         Meadow Valley Generating Company, LLC

1.2.3.1.1.10.1.29.1.     Meadow Valley Generating Company, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         99% owned by Meadow Valley Power Corporation, and
                         1% owned by PG&E Generating Energy Holdings, Inc.
                         Formed to develop, own, manage, and operate a
                         merchant electric generating facility to be located
                         near Las Vegas, Nevada.

1.2.3.1.1.10.2.          PG&E Generating Power Group, LLC
                         Delaware limited liability company

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Company, LLC
                         Holding company for PG&E Generating Company
                         operating projects

1.2.3.1.1.10.2.1.        Aplomado Power Corporation
                         California corporation

                         100 Pine Street, 20th Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Power Group, LLC
                         Investment company for the Panther Creek Project.

1.2.3.1.1.10.2.2.        Beale Generating Company
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         89% owned by PG&E Generating Power Group, LLC
                         Holding company

1.2.3.1.1.10.2.2.1.      Indian Orchard Generating Company, Inc.
                         Delaware corporation

                         7500 Old Georgetown Road
                         Bethesda, MD 20814-6161

                         100% owned by Beale Generating Company
                         49% membership interest in MASSPOWER, L.L.C.

1.2.3.1.1.10.2.2.1.1.    MASSPOWER, L.L.C.
                         (formerly MASSPOWER, Inc.)
                         Delaware limited liability company

                         One Bowdoin Square
                         Boston, MA 02114

                         49% owned by Indian Orchard Generating
                         Company, Inc.
                         39% general partnership interest in MASSPOWER,
                         L.L.C.

1.2.3.1.1.10.2.2.2.      JMC Altresco, Inc.
                         Colorado corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by Beale Generating Company
                         Holding company for subsidiaries/projects acquired
                         through acquisition of Altresco Financial, Inc.

1.2.3.1.1.10.2.2.2.1.    Altresco, Inc.

                                       17
<PAGE>

                         Colorado corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by JMC Altresco, Inc.
                         General Partners - Pittsfield Generating Company,
                         L.P.


1.2.3.1.1.10.2.2.2.2.    Berkshire Pittsfield, Inc.
                         Colorado corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by JMC Altresco, Inc.
                         General Partner - Berkshire Feedline Acquisition
                         Limited Partnership

1.2.3.1.1.10.2.2.2.2.1.  Berkshire Feedline Acquisition Limited
                         Partnership
                         Massachusetts partnership

                         One Bowdoin Square
                         Boston, MA 02114

                         1% owned by Berkshire Pittsfield, Inc.
                         Owner of pipeline connecting Pittsfield Generating
                         Company, L.P. facility and Tennessee Gas Pipeline
                         Company facilities

1.2.3.1.1.10.2.2.2.3.    Pittsfield Partners, Inc.
                         Colorado corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by JMC Altresco, Inc.
                         Limited Partner - Pittsfield Generating Company,
                         L.P.

1.2.3.1.1.10.2.2.3.      JMC Iroquois, Inc.
                         Delaware corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by Beale Generating Company
                         4.57% General Partner and .36% Limited Partner
                         in Iroquois Gas Transmission System, L.P.

1.2.3.1.1.10.2.2.3.1.    Iroquois Gas Transmission System, L.P.
                         Delaware partnership

                         One Bowdoin Square
                         Boston, MA 02114

                         4.93% owned by JMC Iroquois, Inc.
                         Owner of a 375 mile natural gas pipeline extending
                         through New York State and Connecticut providing
                         services to markets in New York, New Jersey and
                         New England

1.2.3.1.1.10.2.2.4.      JMC Selkirk Holdings, Inc.
                         Delaware corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by Beale Generating Company

                         100% ownership of JMC Selkirk, Inc. and JMCS I
                         Holdings, Inc.

                                       18
<PAGE>

1.2.3.1.1.10.2.2.4.1.    JMC Selkirk, Inc.
                         Delaware corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by JMC Selkirk Holdings, Inc.
                         Managing General Partner and Limited Partner
                         of Selkirk Cogen Partners, L.P.
                         Limited Partner interest (46.57%) in
                         PentaGen Investors, L.P.

1.2.3.1.1.10.2.2.4.1.1.  PentaGen Investors, L.P.
                         Delaware partnership

                         One Bowdoin Square
                         Boston, MA 02114

                         46.57% owned by JMC Selkirk, Inc., and
                         3.43% owned by JMCS I Holdings, Inc.
                         Limited partner (5.2502% preferred percentage
                         Interest) in Selkirk Cogen Partners, L.P.

1.2.3.1.1.10.2.2.4.2.    JMCS I Holdings, Inc.
                         Delaware corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by JMC Selkirk Holdings, Inc.
                         General Partner (.50%) and Limited Partner
                         (2.93%) interests in PentaGen Investors, L.P.

1.2.3.1.1.10.2.2.5.      Orchard Gas Corporation
                         Delaware corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by Beale Generating Company
                         Administration and monitoring of gas supply for
                         MASSPOWER project.

1.2.3.1.1.10.2.3.        Mason Generating Company
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         89% owned by PG&E Generating Power Group, LLC
                         Holding Company

1.2.3.1.1.10.2.3.1.      Bowdoin Storage Services, Inc.
                         Delaware corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by Mason Generating Company
                         Serves as Administrator for PentaGen
                         Investors, L.P.

1.2.3.1.1.10.2.3.2.      J. Makowski Associates, Inc.
                         Massachusetts corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by Mason Generating Company

                         Serve as Administrator for PentaGen Investors, L.P.

1.2.3.1.1.10.2.3.3.      JMC Avoca, Inc.
                         Delaware corporation


                                       19
<PAGE>

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by Mason Generating Company
                         General Partner - Avoca Natural Gas Storage
                         Project.  Voluntary petition for relief under
                         Chapter 11 filed on July 29, 1997 with the
                         United States Bankruptcy Court, District of
                         Delaware.

1.2.3.1.1.10.2.3.3.1.    Avoca Natural Gas Storage
                         New York general partnership

                         One Bowdoin Square
                         Boston, MA 02114

                         46.88% owned by JMC Avoca, Inc.

1.2.3.1.1.10.2.3.4.      JMC Cayuta, Inc.
                         Delaware corporation

                         One Bowdoin Square
                         Boston, MA 02114

                         100% owned by Mason Generating Company

1.2.3.1.1.10.2.4.        Eagle Power Corporation
                         California corporation

                         100 Pine Street, 20th Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Power Group, LLC
                         General partner in Logan Generating Company, L.P.,
                         Granite Generating Company, L.P., and Keystone
                         Cogeneration Company, L.P.

1.2.3.1.1.10.2.4.1.      Granite Generating Company, L.P.
                         Delaware limited partnership

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         50% owned by Eagle Power Corporation
                         Limited Partner in Keystone Urban Renewal Limited
                         Partnership.

1.2.3.1.1.10.2.4.1.1.    Granite Water Supply Company, Inc.
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by Granite Generating Company, L.P.
                         Supplies water for the Logan Project.

1.2.3.1.1.10.2.4.2.      Keystone Cogeneration Company, L.P.
                         Delaware limited partnership

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         50% owned by Eagle Power Corporation
                         General Partner in Keystone Urban Renewal Limited
                         Partnership.

1.2.3.1.1.10.2.5.        Larkspur Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Power Group, LLC
                         General Partner and limited partner in Hermiston
                         Generating Company, L.P.

                                       20
<PAGE>

1.2.3.1.1.10.2.6.        Buckeye Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Power Group, LLC
                         General Partner in Hermiston Generating Company, L.P.

1.2.3.1.1.10.2.7.        Raptor Holdings Company
                         California corporation

                         100 Pine Street, 20th Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Power Group, LLC
                         Holding company for Cedar Bay Project entities; owns
                         PG&E Management Services.

1.2.3.1.1.10.2.7.1.      Gray Hawk Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by Raptor Holdings Company
                         Investment Company for Cedar Bay Project.

1.2.3.1.1.10.2.7.1.1.    Cedar Bay Cogeneration, Inc.
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by Gray Hawk Power Corporation
                         General partner in Cedar Bay Generating Company,
                         Limited Partnership.

1.2.3.1.1.10.2.7.2.      PG&E Management Services Company
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by Raptor Holdings Company
                         Inactive.

1.2.3.1.1.10.2.8.        Toyan Enterprises
                         California corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Power Group, LLC
                         Limited partner in Indiantown Cogeneration, L.P.;
                         general partner in Indiantown Project.

1.2.3.1.1.10.2.8.1.      Indiantown Project Investment Partnership, L.P.
                         Delaware limited partnership

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         24.817% owned by Toyan Enterprises
                         General partner in Indiantown Cogeneration, L.P.

1.2.3.1.1.10.2.9.        Spruce Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Power Group, LLC
                         Holds general partnership interest in Spruce Limited
                         Partnership.


                                       21
<PAGE>

     1.2.3.1.1.10.2.9.1.  Spruce Limited Partnership
                          Delaware limited partnership

                          7500 Old Georgetown Road, 13th Floor
                          Bethesda, MD 20814-6161

                          35.5% owned by Spruce Power Corporation
                          Hold limited partnership interest in Colstrip
                          Energy Limited Partnership.

     1.2.3.1.1.10.2.9.1.1.  Colstrip Energy Limited Partnership
                            Montana limited partnership

                            314 N. Last Chance Gulch
                            Helena, MT 59624

                            37.5% owned by Spruce Limited Partnership
                            Owns and operates an electric generating facility
                            in Colstrip, Montana.

     1.2.3.1.1.10.2.10.  Merlin Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Power Group, LLC
                         General partner in Fellows Generating Company,
                         L.P.

     1.2.3.1.1.10.2.10.1.  Fellows Generating Company, L.P.
                           Delaware limited partnership

                           7500 Old Georgetown Road, 13th Floor
                           Bethesda, MD 20814-6161

                           51% owned by Merlin Power Corporation
                           Formed to own, develop, finance, construct,
                           operate and maintain an electric generation
                           facility near Fellows, CA.

     1.2.3.1.1.10.2.11.  Pelican Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Power Group, LLC
                         General partner in Okeelanta Power Limited
                         Partnership.

     1.2.3.1.1.10.2.11.1.  Okeelanta Power Limited Partnership
                           Florida limited partnership

                           316 Royal Poinciana Plaza
                           Palm Beach, FL 33480

                           37.54% owned by Pelican Power Corporation
                           Formed to develop, own and operate an electric
                           generating facility in Okeelanta, Florida.
                           Voluntarily filed a petition for relief under
                           Chapter 11 on May 14, 1997.

     1.2.3.1.1.10.2.12.  Peregrine Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Power Group, LLC
                         General partner in Chambers Cogeneration Limited
                         Partnership.

     1.2.3.1.1.10.2.13.  Heron Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111


                                       22
<PAGE>

                         100% owned by PG&E Generating Power Group, LLC
                         General and limited partner in Gator Generating
                         Company, L.P. (Osceola Project).

     1.2.3.1.1.10.2.13.1.  Gator Generating Company, L.P.
                           Delaware limited partnership

                           7500 Old Georgetown Road, 13th Floor
                           Bethesda, MD 20814-6161

                           79.2% owned by Heron Power Corporation
                           Formed to develop, own, operate and lease (as
                           lessor) a cogeneration facility (Osceola) in Palm
                           Beach County, Florida. Filed a voluntary petition
                           for bankruptcy protection under Chapter 11 on May
                           14, 1997.

     1.2.3.1.1.10.2.14.  Jaeger Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Power Group, LLC
                         Partner in Northampton Generating Company, L.P.

     1.2.3.1.1.10.2.15.  Falcon Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Power Group, LLC
                         General and Limited partner in Scrubgrass
                         Generating Company, L.P.; owner of Scrubgrass
                         Power Corp.

     1.2.3.1.1.10.2.15.1.  Scrubgrass Power Corp.
                           Pennsylvania corporation

                           7500 Old Georgetown Road, 13th Floor
                           Bethesda, MD 20814-6161

                           100% owned by Falcon Power Corporation
                           General partner in Scrubgrass Generating Company,
                           L.P.

     1.2.3.1.1.10.2.16.  Eucalyptus Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Power Group, LLC
                         General Partner in Citrus Generating, Company,
                         L.P.

     1.2.3.1.1.10.2.16.1.  Citrus Generating Company, L.P.
                           Delaware limited partnership

                           7500 Old Georgetown Road, 13th Floor
                           Bethesda, MD 20814-6161

                           49% owned by Cooper's Hawk Power Corporation,
                           49% owned by Eucalyptus Power Corporation, and
                           2% owned by PG&E Shareholdings, Inc.
                           Inactive Company. Originally formed to own and
                           operate an electric generating facility.

     1.2.3.1.1.10.2.17.  Cooper's Hawk Power Corporation
                         California corporation

                         100 Pine Street, 20/th/ Floor
                         San Francisco, CA 94111

                         100% owned by PG&E Generating Power Group, LLC
                         General partner in Citrus Generating Company, L.P.


                                       23
<PAGE>

     1.2.3.1.1.10.2.18.  Loon Power Corporation
                         Delaware corporation

                         7500 Old Georgetown Road, 13th Floor
                         Bethesda, MD 20814-6161

                         100% owned by PG&E Generating Power Group, LLC
                         Investment company.

     1.2.3.1.1.10.3.  PG&E Generating Services, LLC
                      Delaware limited liability company

                      7500 Old Georgetown Road, 13th Floor
                      Bethesda, MD 20814-6161

                      100% owned by PG&E Generating Company, LLC
                      Holding company for PG&E Generating Company
                      service entities.

     1.2.3.1.1.10.3.1.  J. Makowski Pittsfield, Inc.
                        Delaware corporation

                        One Bowdoin Square
                        Boston, MA 02114

                        100% owned by PG&E Generating Services, LLC

     1.2.3.1.1.10.3.2.  J. Makowski Services, Inc.
                        Delaware corporation

                        One Bowdoin Square
                        Boston, MA 02114

                        100% owned by PG&E Generating Services, LLC

     1.2.3.1.1.10.3.3.  JMCS I Management, Inc.
                        Delaware corporation

                        One Bowdoin Square
                        Boston, MA 02114

                        100% owned by PG&E Generating Services, LLC

     1.2.3.1.1.10.3.4.  USGen Fuel Services, Inc.
                        Delaware corporation

                        One Bowdoin Square
                        Boston, MA 02114

                        100% owned by PG&E Generating Services, LLC

     1.2.3.1.1.10.3.5.  PG&E Construction Agency Services I, LLC
                        Delaware limited liability company

                        7500 Old Georgetown Road, 13th Floor
                        Bethesda, MD 20814-6161

                        100% owned by PG&E Generating Services, LLC.
                        Formed to act as construction agent under the
                        Master Turbine Trust with GE.

     1.2.3.1.1.10.3.6.  PG&E Construction Agency Services II, LLC
                        Delaware limited liability company

                        7500 Old Georgetown Road, 13th Floor
                        Bethesda, MD 20814-6161

                        100% owned by PG&E Generating Services, LLC.
                        Formed to act as construction agent under the Master
                        Turbine Trust with Mitsubishi.

     1.2.3.1.1.10.3.7.  PG&E Construction Agency Services III, LLC
                        Delaware limited liability company

                        7500 Old Georgetown Road, 13th Floor


                                       24
<PAGE>

                        Bethesda, MD 20814-6161

                        100% owned by PG&E Generating Services, LLC.
                        Formed to act as construction agent under the
                        Master Turbine Trust.

     1.2.3.1.1.10.3.8.  PG&E Turbine Acquisition Company, LLC
                        Delaware limited liability company

                        7500 Old Georgetown Road, 13th Floor
                        Bethesda, MD 20814-6161

                        100% owned by PG&E Generating Services, LLC.
                        Formed to act as construction agent under the
                        Master Turbine Trust with GE.

     1.2.3.1.1.10.3.9.  PG&E Operating Services Holdings, Inc.
                        California corporation

                        100 Pine Street, 20/th/ Floor
                        San Francisco, CA 94111

                        100% owned by PG&E Generating Services, LLC
                        General partner in PG&E Generating Company and
                        PG&E Operating Services Company; sole member of
                        PG&E National Energy Group Acquisition Company.

     1.2.3.1.1.10.3.9.1.  USOSC Holdings, Inc.
                          Delaware corporation

                          7500 Old Georgetown Road, 13th Floor
                          Bethesda, MD 20814-6161

                          100% owned by PG&E Operating Services Holdings, Inc.
                          Holds a partnership interest in PG&E Operating
                          Services Company.

     1.2.3.1.1.10.3.9.1.1.  PG&E Operating Services Company
                            California general partnership

                            7500 Old Georgetown Road, 13th Floor
                            Bethesda, MD 20814-6161

                            98% owned by PG&E Operating Services Holdings,
                            Inc.; and 2% owned by USOSC Holdings, Inc.
                            Formed to enter into operations and maintenance
                            activities.

     1.2.3.1.1.10.3.9.2.  USGen Holdings, Inc.
                          Delaware corporation

                          7500 Old Georgetown Road, 13th Floor
                          Bethesda, MD 20814-6161

                          100% Owned by PG&E Generating Services, LLC
                          Holds a partnership interest in PG&E National
                          Energy Group Company.

     1.2.3.1.1.10.3.9.2.1.  PG&E National Energy Group Company
                            (formerly PG&E Generating Company)
                            California general partnership

                            7500 Old Georgetown Road, 13th Floor
                            Bethesda, MD 20814-6161

                            98% owned by PG&E Operating Services Holdings,
                            Inc., and 2% owned by USGen Holdings, Inc.
                            Develops and manages electrical generation
                            facilities.

     1.2.3.1.1.10.3.9.2.1.1.  First Oregon Land Corporation

                                       25
<PAGE>

                              Delaware corporation

                              7500 Old Georgetown Road, 13th Floor
                              Bethesda, MD 20814-6161

                              100% owned by PG&E National Energy Group Company
                              Formed to enter into real estate options in the
                              State of Oregon.

     1.2.3.1.1.10.3.9.2.1.2.  Topaz Power Corporation
                              Delaware corporation

                              7500 Old Georgetown Road, 13th Floor
                              Bethesda, MD 20814-6161

                              100% owned by PG&E National Energy Group Company
                              Holds partnership interest in Carneys Point
                              Generating Company.

     1.2.3.1.1.10.3.9.2.1.2.1.  Carneys Point Generating Company
                                Delaware general partnership

                                7500 Old Georgetown Road, 13th Floor
                                Bethesda, MD 20814-6161

                                50% owned by Topaz Power Corporation, and
                                50% owned by Garnet Power Corporation.
                                Formed to lease, manage, operate and maintain a
                                cogeneration facility in Carneys Point, New
                                Jersey.

     1.2.3.1.1.10.3.9.2.1.3.  Garnet Power Corporation
                              Delaware corporation

                              7500 Old Georgetown Road, 13th Floor
                              Bethesda, MD 20814-6161

                              100% owned by PG&E National Energy Group Company
                              Holds partnership interest in Carneys Point
                              Generating Company.

     1.2.3.1.1.10.3.9.3.  PG&E National Energy Group Acquisition Company,
                          LLC
                          Delaware limited liability company

                          7500 Old Georgetown Road, 13th Floor
                          Bethesda, MD 20814-6161

                          100% owned by PG&E Operating Services Holdings,
                          Inc.
                          Formed for acquisitions purposes.

     1.2.3.1.1.11.  Valley Real Estate, Inc
                    California corporation

                    One Market, Spear Tower, Suite 2400
                    San Francisco, CA 94105

                    100% owned by PG&E Shareholdings, Inc.; was formed
                    for real estate development.

     1.2.3.1.2.  PG&E Overseas, Inc.
                 California corporation

                 One Market, Spear Tower, Suite 2400
                 San Francisco, CA 94105

                 100% by PG&E Enterprises. U.S. shareholder of PG&E
                 Overseas, Ltd., and PG&E Overseas II, Ltd.

     1.2.3.1.2.1.  PG&E Australia
                   California corporation

                   One Market, Spear Tower, Suite 2400
                   San Francisco, CA 94105

                   A wholly-owned, non-regulated indirect subsidiary
                   of PG&E Enterprises through its ownership of PG&E


                                       26
<PAGE>

                   Overseas, Inc. for business development in
                   Australia.

     1.2.3.1.2.2.  PG&E Overseas, Ltd.
                   Cayman Islands company

                   Maples & Calder
                   P.O. Box 309
                   George Town, Grand Cayman
                   Cayman Islands, B.W.I.

                   A wholly-owned, indirect subsidiary of PG&E
                   Enterprises through its ownership of PG&E
                   Overseas, Inc.; holding company for PG&E Pacific
                   I, Ltd. and PG&E Pacific II, Ltd.

     1.2.3.1.2.2.1.  PG&E Pacific I, Ltd.
                     Cayman Islands company

                     Maples & Calder
                     P.O. Box 309
                     George Town, Grand Cayman
                     Cayman Islands, B.W.I.

                     A non-regulated indirect subsidiary of PG&E
                     Enterprises through its ownership of PG&E Overseas
                     Inc.; an overseas distribution company of PG&E
                     Overseas, Ltd.

     1.2.3.1.2.2.2.  PG&E Pacific II, Ltd.
                     Cayman Islands company

                     Maples & Calder
                     P.O. Box 309
                     George Town, Grand Cayman
                     Cayman Islands, B.W.I.

                     A non-regulated indirect subsidiary of PG&E
                     Enterprises through its ownership of PG&E Overseas
                     Inc.; an overseas distribution company of PG&E
                     Overseas, Ltd.

     1.2.3.1.3.  Quantum Ventures
                 California corporation

                 One Market, Spear Tower, Suite 2400
                 San Francisco, CA 94105

                 A wholly-owned, non-regulated subsidiary of PG&E
                 Enterprises.

     1.2.3.1.3.1.  PG&E Energy Services Ventures, Inc.
                   (Formerly PG&E Energy Services Ventures, LLC)
                   Delaware corporation

                   345 California St., 23rd Floor
                   San Francisco, CA 94105

                   PG&E Energy Services Ventures, Inc. is a wholly
                   owned, non-regulated indirect subsidiary of PG&E
                   Enterprises through its ownership in Quantum
                   Ventures. PG&E Energy Services Ventures, Inc.
                   provides energy-related goods and services.

     1.2.3.1.3.2.  Barakat & Chamberlin, Inc.
                   California corporation

                   345 California Street, Suite 3200
                   San Francisco, CA 94104

                   100% owned by Quantum Ventures

     1.2.3.1.3.3.  Creston Financial
                   California corporation

                   345 California Street, Suite 3200
                   San Francisco, CA 94104


                                       27
<PAGE>

                   100% owned by Quantum Ventures

     1.2.3.1.3.4.  Real Estate Energy Solutions, LLC
                   Delaware limited liability company

                   888 S.W. Fifth Avenue, Suite 3200
                   Portland, OR 97204

                   50% owned by Quantum Ventures, and
                   50% owned by Jones Lang LaSalle Management
                   Services, Inc.

     1.2.3.2.  PG&E Gas Transmission Corporation
               California corporation

               1400 SW Fifth Avenue, Suite 900
               Portland, OR 97201

               100% owned by PG&E National Energy Group, Inc.
               Gas holding company

     1.2.3.2.1.  PG&E Gas Transmission, Holdings Corporation
                 (formerly PG&E Gas Transmission, Northeast
                 Corporation) California corporation

                 1400 SW Fifth Avenue, Suite 900
                 Portland, Oregon  97201

                 100% owned by PG&E Gas Transmission Corporation.
                 Formed to pursue gas transmission business
                 opportunities.

     1.2.3.2.1.1.  North Baja Pipeline, LLC
                   Delaware limited liability company

                   1400 SW Fifth Avenue, Suite 900
                   Portland, OR 97201

                   100% owned by PG&E Gas Transmission Holdings
                   Corporation. Formed for the construction and
                   operation of a natural gas pipeline capable of
                   transporting natural gas from Arizona to the
                   Mexico border.

     1.2.3.2.2.  GTN Holdings, LLC
                 Delaware limited liability company

                 7500 Old Georgetown Road, 13th Floor
                 Bethesda, MD 20814-6161

                 100% owned by PG&E Gas Transmission Corporation.
                 Formed for the limited purpose of holding stock in
                 PG&E Gas Transmission, Northwest Corporation

     1.2.3.2.2.1.  PG&E Gas Transmission, Northwest Corporation
                   California corporation

                   1400 SW Fifth Avenue, Suite 900
                   Portland, Oregon 97201

                   100% owned by GTN Holdings LLC. Owns and operates
                   gas transmission pipelines and associated
                   facilities capable of transporting natural gas from the
                   Canadian-U.S. border to the Oregon-California border.

     1.2.3.2.2.1.1.  Pacific Gas Transmission International, Inc.
                     California corporation

                     1400 SW Fifth Avenue, Suite 900
                     Portland, Oregon  97201

                     100% owned by PG&E Gas Transmission, Northwest
                     Corporation. Previously owned 99% of the
                     beneficial interest of PG&E Queensland Unit Trust
                     (which interest was sold to PG&E Gas Transmission
                     Unit Holdings Pty Ltd. in September 1997).

                                       28
<PAGE>

  1.2.3.2.2.1.2.  Pacific Gas Transmission Company
                  California corporation

                  1400 SW Fifth Avenue, Suite 900
                  Portland, Oregon 97201

                  100% owned by PG&E Gas Transmission, Northwest
                  Corporation.  Formed to pursue business opportunities
                  in the natural gas business in the United States.

  1.2.3.2.2.1.3.  Stanfield Hub Services, LLC
                  Washington limited liability company

                  1400 SW Fifth Avenue, Suite 900
                  Portland, Oregon 97201

                  50% owned by PG&E Gas Transmission, Northwest Corporation.
                  Formed to pursue opportunities for construction and
                  operation of natural gas storage facilities.

  1.2.4.  PG&E Strategic Capital, Inc.
          Delaware corporation

          One Market, Spear Tower, Suite 2400
          San Francisco, CA 94105

          PG&E Strategic Capital, Inc. is a wholly-owned subsidiary of PG&E
          Corporation.  PG&E Strategic Capital, Inc. was formed for general
          business purposes.

  1.2.5.  PG&E Corporation Support Services, Inc.
          Delaware corporation

          One Market, Spear Tower, Suite 2400
          San Francisco, CA 94105

          PG&E Corporation Support Services, Inc. is a wholly-
          owned subsidiary of PG&E Corporation that provides general
          corporate support services to the PG&E Corporation family outside
          the State of California.

  1.2.6.  PG&E National Energy Group, LLC
          Delaware limited liability company

          7500 Old Georgetown Road, 13th Floor
          Bethesda, MD 20814-6161

          100% owned by PG&E Corporation and was formed for the
          limited purpose of holding stock in PG&E National Energy
          Group, Inc.

  1.2.7.  The PG&E Corporation Foundation
          California corporation

          One Market, Spear Tower, Suite 2400
          San Francisco, CA 94105

          The PG&E Corporation Foundation is a wholly-owned non-profit entity
          of PG&E Corporation that was formed and operates exclusively for
          charitable, scientific, educational and literary purposes.

  1.2.8.  PG&E Ventures ePro, LLC
          Delaware corporation

          One Market, Spear Tower, Suite 2400
          San Francisco, CA 94105

          PG&E Ventures ePro, LLC is a wholly-owned subsidiary of PG&E
          Corporation that was formed to make and hold an investment in an
          e-procurement exchange.

  1.2.9.  PG&E Ventures, LLC
          Delaware corporation

          One Market, Spear Tower, Suite 2400

                                       29
<PAGE>

          San Francisco, CA  94105

          PG&E Ventures, LLC incorporated under the laws of the State of
          Delaware, is a wholly-owned subsidiary of PG&E Corporation that was
          formed for the purpose of holding interests in other businesses,
          financing and other transactions.

  1.2.9.1.  Pacific Venture Capital, LLC
            Delaware corporation

            One Market, Spear Tower, Suite 2400
            San Francisco, CA  94105

            Pacific Venture Capital, LLC is a wholly-owned subsidiary of PG&E
            Ventures, LLC that was formed to build and manage a portfolio of
            capital investments in growing energy and telecommunications
            companies.

  1.2.9.2.  PG&E Telecom, LLC
            Delaware corporation

            One Market, Spear Tower, Suite 2400
            San Francisco, CA  94105

            PG&E Telecom, LLC is a wholly-owned subsidiary of PG&E Ventures, LLC
            that was formed for the purpose of engaging in telecommunications
            and related business activities.

  1.2.9.2.1.  PG&E Capital, LLC
              Delaware corporation

              One Market, Spear Tower, Suite 2400
              San Francisco, CA  94105

              PG&E Capital, LLC is a wholly-owned subsidiary of PG&E Telecom,
              LLC, formed for financing and other transactions related to the
              energy industry.


                                       30
<PAGE>

     4.1.  PITTSFIELD GENERATING COMPANY, L.P.

           Pittsfield Generating Company, L.P.
           235 Merrill Road
           Pittsfield, MA 01202

           Pittsfield Generating Company, L.P. is a 165 megawatt (MW) combined
           cycle, natural gas-fired cogeneration facility (the "Facility")
           selling power to Commonwealth Electric Company, Cambridge Electric
           Company, and USGen New England, Inc. and selling steam to General
           Electric Company.


     4.2.  SELKIRK COGEN PARTNERS, L.P.

           Selkirk Cogen Partners, L.P.
           24 Power Park Drive
           Selkirk, NY  12158

           Selkirk Cogen Partners, L.P. Unit I is an 80 MW natural gas fired
           dispatchable cogeneration facility selling power to Niagara Mohawk
           Power Corporation. Selkirk Cogen Partners, L.P. Unit II is a 265 MW
           natural gas fired dispatchable cogeneration facility (Unit I and Unit
           II together, the "Facility") selling power to Consolidated Edison
           Company of New York, Inc.


     4.3.  KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP

           Keystone Urban Renewal Limited Partnership
           Box 169-C, Route 130 South, Swedesboro, NJ 08085

           Keystone Urban Renewal Limited Partnership is a 225 MW pulverized
           coal-fired dispatchable generation facility (the "Facility") selling
           power to Connectiv (formerly Atlantic Energy Company).


     4.4.  LOGAN GENERATING COMPANY, L.P.

           Logan Generating Company, L.P.
           Box 169-C, Route 130 South, Swedesboro, NJ 08085

           Logan Generating Company, L.P. is a 225 MW pulverized coal fired
           dispatchable generation facility (the "Facility") selling power to
           Connectiv (formerly Atlantic Electric Company).


     4.5.  HERMISTON GENERATING COMPANY, L.P.

           Hermiston Generating Company, L.P.
           Box 930, Hermiston, OR 97838

           Hermiston Generating Company, L.P. is a 474 MW natural gas fired
           dispatchable cogeneration facility (the "Facility") selling power to
           PacifiCorp. PacifiCorp owns a 50% undivided interest in the Facility.


                                       31
<PAGE>

     4.6.  MASSPOWER

           MASSPOWER
           750 Worcester Street
           Indian Orchard, MA 01151

           MASSPOWER is a 240 MW natural gas-fired combined cycle cogeneration
           facility located in Springfield, MA, selling power to Western
           Massachusetts Electric Company, Boston Edison Company, Commonwealth
           Electric Company and Massachusetts Municipal Wholesale Electric
           Company, and selling steam to Monsanto Company.


     4.7.  MILLENNIUM POWER PARTNERS, L.P.

           Millennium Power Partners, L.P.
           P.O. Box 588
           10 Sherwood Lane
           Charlton, Massachusetts 01508-0588

           Millennium Power Partners, L.P. is currently under construction, with
           commercial operation expected in the spring of 2001. Millennium Power
           Partners, L.P. will be a nominal 360 MW natural gas-fired combined
           cycle merchant power facility which anticipates selling power into
           the New England Power Pool on a spot basis as well as under short-to
           medium-term bilateral contracts.


     4.8.  CEDAR BAY GENERATING COMPANY, LIMITED PARTNERSHIP

           Cedar Bay Generating Company, Limited Partnership
           9640 Eastport Road
           Jacksonville, FL 32218

           Cedar Bay Generating Company, Limited Partnership owns and operates a
           250 MW coal-fired electric generating facility in Jacksonville,
           Florida, selling power to Florida Power & Light Company, and selling
           steam to Smurfit Stone Container Corporation (formerly Stone
           Container Corporation).


     4.9.  NORTHAMPTON GENERATING COMPANY, L.P.

           Northampton Generating Company, L.P.
           One Horwith Drive
           Northampton, PA 18067

           Northampton Generating Company, L.P. owns and operates an
           approximately 98 MW anthracite waste coal-fired electric generating
           facility in Northampton, Pennsylvania, selling power to Metropolitan
           Edison Company, and selling steam to unrelated industrial operations.


     4.10. SCRUBGRASS GENERATING COMPANY, L.P.

           Scrubgrass Generating Company, L.P.
           RR1 Lisbon Road
           Kennerdell, PA 16374

           Scrubgrass Generating Company, L.P. leases an 87 MW waste coal-fired
           electric generating facility in Venango County, Pennsylvania, to
           Buzzard Power Corporation.


                                       32
<PAGE>

     4.11. INDIANTOWN COGENERATION, L.P.

           Indiantown Cogeneration, L.P.
           19140 SW Warfield Boulevard
           Indiantown, FL 34956

           Indiantown Cogeneration, L.P. owns and operates a 330 MW coal-fired
           electric generating facility in Indiantown, Florida, selling power to
           Florida Power & Light Company, and selling steam to Caulkins
           Indiantown Citrus Co.


     4.12. CHAMBERS COGENERATION LIMITED PARTNERSHIP

           Chambers Cogeneration Limited Partnership
           500 Shell Road
           Carneys Point, NJ 08069-2926

           Chambers Cogeneration Limited Partnership owns and operates a 252 MW
           coal-fired electric generating facility in Carneys Point, New Jersey,
           selling power to Connectiv (formerly Atlantic Energy Company), and
           selling power and steam to DuPont.


     4.13. ATHENS GENERATING COMPANY, L.P.

           Athens Generating Company, L.P.
           7500 Old Georgetown Road, 13th Floor
           Bethesda, MD 20814-6161

           Athens Generating Company, L.P. is currently developing a 1,080 MW
           natural gas-fired electric generating merchant power facility in
           Athens, New York, with commercial operation expected in the summer of
           2003.


     4.14. LA PALOMA GENERATING COMPANY, LLC

           La Paloma Generating Company, LLC
           1760 W. Skyline Road
           McKittrick, CA 93251

           La Paloma Generating Company, LLC is currently constructing a 1,020
           MW gas-fired electric generating merchant power facility in Kern
           County, California. It anticipates selling power into the California
           market on a spot basis as well as under short-to-medium term
           bilateral contracts.


                                       33
<PAGE>

     4.15. LAKE ROAD GENERATING COMPANY, L.P.

           Lake Road Generating Company, L.P.
           56 Alexander Parkway
           Dayville, CT 06241

           Lake Road Generating Company, L.P. is currently under construction,
           with commercial operation expected in the summer of 2001. Lake Road
           Generating Company, L.P. will be a nominal 792 MW natural gas-fired
           combined cycle merchant power facility which anticipates selling
           power into the New England Power Pool on a spot basis as well as
           under short-to medium-term bilateral contracts.


     4.16. MANTUA CREEK GENERATING COMPANY, L.P.

           Mantua Creek Generating Company, L.P.
           7500 Old Georgetown Road, 13/th/ Floor
           Bethesda, MD 20814-6161


     4.17. OKEECHOBEE GENERATING COMPANY, LLC

           Okeechobee Generating Company, LLC
           7500 Old Georgetown Road, 13/th/ Floor
           Bethesda, MD 20814-6161

           Okeechobee Generating Company, LLC is currently developing a 550 MW
           natural gas-fired electric generating merchant power facility in
           Okeechobee, Florida


     4.18. USGEN NEW ENGLAND, INC.

           USGen New England, Inc.
           7500 Old Georgetown Road, 13/th/ Floor
           Bethesda, MD 20814-6161

           USGen New England, Inc. owns and operates 17 generating facilities
           comprising of approximately 3,962 megawatts of generation, selling
           power in the New England area markets.


                                       34
<PAGE>

     4.19. PG&E DISPERSED GENERATING COMPANY, LLC

           PG&E Dispersed Generating Company, LLC
           7500 Old Georgetown Road, 13/th/ Floor
           Bethesda, MD 20814-6161

           PG&E Dispersed Generating Company, LLC is currently developing and/or
           operating small peaker facilities in Ohio and is acting as an
           engineering procurement construction contractor on two small peaker
           facilities in California.


     4.20. LIBERTY GENERATING COMPANY, LLC

           Liberty Generating Company, LLC
           7500 Old Georgetown Road, 13th Floor
           Bethesda, MD 20814-6161

           Liberty Generating Company, LLC is currently developing a 1,100 MW
           natural gas-fired electric generating merchant power facility in
           Linden, New Jersey.


     4.21. BADGER GENERATING COMPANY, LLC

           Badger Generating Company, LLC
           7500 Old Georgetown Road, 13th Floor
           Bethesda, MD 20814-6161

           Badger Generating Company, LLC is currently developing a 1,100 MW
           natural gas-fired electric generating merchant power facility in
           Pleasant Prairie, Wisconsin.


     4.22. MADISON WINDPOWER LLC

           Madison Windpower LLC
           7500 Old Georgetown Road, 13th Floor
           Bethesda, MD 20814-6161

           Madison Windpower, LLC is currently operating a 12MW wind-powered
           merchant power facility in Madison, New York.


     4.23. COVERT GENERATING COMPANY, LLC

           Covert Generating Company, LLC
           7500 Old Georgetown Road, 13th Floor
           Bethesda, MD 20814-6161

           Covert Generating Company, LLC is currently developing a 1,080
           natural gas-fired electric generating merchant power facility in
           Covert Township, Michigan.


                                       35
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23.1
<SEQUENCE>34
<FILENAME>dex231.txt
<DESCRIPTION>CONSENT OF DELOITTE & TOUCHE LLP
<TEXT>

<PAGE>

                                                                   EXHIBIT 23.1

                         INDEPENDENT AUDITORS' CONSENT

We consent to the incorporation by reference in Registration Statements No.
333-16255 and 333-25685 on Form S-3 and 333-16253, 333-27015, 333-68155, 333-
46772, 333-77145 and 333-77149 on Form S-8 of PG&E Corporation and
Registration Statements No. 33-64136, 33-50707, 33-62488 and 33-61959 on Form
S-3 of Pacific Gas and Electric Company of our reports dated April 6, 2001
(which express an unqualified opinion and include an explanatory paragraph
relating to items discussed in Notes 2 and 3 of the notes to the consolidated
financial statements), appearing in and incorporated by reference in this
Annual Report on Form 10-K of PG&E Corporation and Pacific Gas and Electric
Company for the year ended December 31, 2000.

DELOITTE & TOUCHE LLP

San Francisco, California
April 11, 2001
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23.2
<SEQUENCE>35
<FILENAME>dex232.txt
<DESCRIPTION>CONSENT OF ARTHUR ANDERSEN LLP
<TEXT>

<PAGE>
                                                                    EXHIBIT 23.2


                   CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS


As independent public accountants, we hereby consent to the incorporation of our
report dated February 8,1999, incorporated by reference in this Form 10-K, into
the Company's previously filed registration statements as follows: (1) PG&E
Corporation's Form S-3 Registration Statement File No. 333-16255 (relating to
PG&E Corporation's Dividend Reinvestment Plan); (2) Pacific Gas and Electric
Company's Form S-3 Registration Statement File No. 33-64136 (relating to
$2,000,000,000 aggregate principal amount of Pacific Gas and Electric Company's
First and Refunding Mortgage Bonds and Medium-Term Notes); (3) Pacific Gas and
Electric Company's Form S-3 Registration Statement File No. 33-50707 (relating
to $1,500,000,000 aggregate principal amount of Pacific Gas and Electric
Company's First and Refunding Mortgage Bonds); (4) Pacific Gas and Electric
Company's Form S-3 Registration Statement File No. 33-62488 (relating to
10,000,000 shares of Pacific Gas and Electric Company's Redeemable First
Preferred Stock); (5) Pacific Gas and Electric Company's Form S-3 Registration
Statement File No. 33-61959 (relating to $335,000,000 aggregate liquidation
value of Cumulative Quarterly Income Preferred Securities); (6) PG&E
Corporation's Form S-8 Registration Statement File No. 333-16253 (relating to
PG&E Corporation's Long-Term Incentive Program); (7) PG&E Corporation's Form S-3
Registration Statement File No. 333- 25685 (relating to the resale of PG&E
Corporation shares held by certain shareholders); (8) PG&E Corporation's Post-
Effective Amendment on Form S-8 to Form S-4 Registration Statement File No. 333-
27015 (relating to Valero Energy Corporation Stock Option Plan No. 4, Valero
Energy Corporation Stock Option Plan No. 5, and Valero Energy Corporation
Executive Stock Incentive Plan); (9) PG&E Corporation's Form S-8 Registration
Statement File No. 333-68155 (relating to PG&E Gas Transmission, Northwest
Corporation Savings Fund Plan for Non- Management Employees); (10) PG&E
Corporation's Form S-8 Registration Statement File No. 333-77145 (relating to
the PG&E Corporation Retirement Savings Plan); (11) PG&E Corporation's Form S-8
Registration Statement File No. 333-77149 (relating to PG&E Corporation's Long-
Term Incentive Program) and (12) PG&E Corporation's Form S-8 Registration
Statement File No. 333-46772 (relating to Pacific Gas and Electric Company
Savings Fund Plan for Union-Represented Employees).



ARTHUR ANDERSEN LLP


San Francisco, California
April 11, 2001
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-24.1
<SEQUENCE>36
<FILENAME>dex241.txt
<DESCRIPTION>RESOLUTIONS OF THE BOARD OF DIRECTORS - PG&E CORP.
<TEXT>

<PAGE>

                                                                    EXHIBIT 24.1


                               RESOLUTION OF THE
                               -----------------
                             BOARD OF DIRECTORS OF
                             ---------------------
                               PG&E CORPORATION
                               ----------------

                                 April 5, 2001
                                 -------------

          WHEREAS, the Audit Committee of this Board of Directors has reviewed
the audited consolidated financial statements for this corporation for the year
ended December 31, 2000, and has recommended to the Board that such financial
statements be included in the corporation's Annual Report on Form 10-K for the
year ended December 31, 2000, to be filed with the Securities and Exchange
Commission;

          BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY
S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES is hereby
authorized to sign on behalf of this corporation and as attorneys in fact for
the Chairman of the Board, President, and Chief Executive Officer, the Senior
Vice President, Chief Financial Officer, and Treasurer, and the Vice President
and Controller of this corporation the Form 10-K Annual Report for the year
ended December 31, 2000, required by Section 13 or 15(d) of the Securities
Exchange Act of 1934 and all amendments and other filings or documents related
thereto to be filed with the Securities and Exchange Commission, and to do any
and all acts necessary to satisfy the requirements of the Securities Exchange
Act of 1934 and the regulations of the Securities and Exchange Commission
adopted thereunder with regard to said Form 10-K Annual Report.
<PAGE>

          I, LINDA Y.H. CHENG, do hereby certify that I am an Assistant
Corporate Secretary of PG&E CORPORATION, a corporation organized and existing
under the laws of the State of California; that the above and foregoing is a
full, true, and correct copy of a resolution which was duly adopted by the Board
of Directors of said corporation at a meeting of said Board which was duly and
regularly called and held at the office of said corporation on April 5, 2001;
and that this resolution has never been amended, revoked, or repealed, but is
still in full force and effect.

          WITNESS my hand and the seal of said corporation hereunto affixed this
11th day of April, 2001.


                                        LINDA Y.H. CHENG
                                        -------------------------------
                                        Linda Y.H. Cheng
                                        Assistant Corporate Secretary
                                        PG&E CORPORATION



C  O  R  P  O  R  A  T  E

       S  E  A  L
<PAGE>

                               RESOLUTION OF THE
                               -----------------
                             BOARD OF DIRECTORS OF
                             ---------------------
                       PACIFIC GAS AND ELECTRIC COMPANY
                       --------------------------------

                                 April 5, 2001
                                 -------------

          WHEREAS, the Audit Committee of this Board of Directors has reviewed
the audited consolidated financial statements for this company for the year
ended December 31, 2000, and has recommended to the Board that such financial
statements be included in the company's Annual Report on Form 10-K for the year
ended December 31, 2000, to be filed with the Securities and Exchange
Commission;

          BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY
S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES is hereby
authorized to sign on behalf of this company and as attorneys in fact for the
President and Chief Executive Officer and the Senior Vice President - Chief
Financial Officer, and Treasurer, and the Vice President - Controller of this
company the orm 10-K Annual Report for the year ended December 31, 2000,
required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and all
amendments and other filings or documents related thereto to be filed with the
Securities and Exchange Commission, and to do any and all acts necessary to
satisfy the requirements of the Securities Exchange Act of 1934 and the
regulations of the Securities and Exchange Commission adopted thereunder with
regard to said Form 10-K Annual Report.
<PAGE>

          I, LINDA Y.H. CHENG, do hereby certify that I am Senior Assistant
Corporate Secretary of PACIFIC GAS AND ELECTRIC COMPANY, a corporation organized
and existing under the laws of the State of California; that the above and
foregoing is a full, true, and correct copy of a resolution which was duly
adopted by the Board of Directors of said corporation at a meeting of said Board
which was duly and regularly called and held on April 5, 2001; and that this
resolution has never been amended, revoked, or repealed, but is still in full
force and effect.

          WITNESS my hand and the seal of said corporation hereunto affixed this
11th day of April, 2001.


                                   LINDA Y.H. CHENG
                                   ----------------------------------
                                   Linda Y.H. Cheng
                                   Senior Assistant Corporate Secretary
                                   PACIFIC GAS AND ELECTRIC COMPANY



C  O  R  P  O  R  A  T  E

       S  E  A  L
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-24.2
<SEQUENCE>37
<FILENAME>dex242.txt
<DESCRIPTION>POWERS OF ATTORNEY
<TEXT>

<PAGE>

                                                                    EXHIBIT 24.2

                               POWER OF ATTORNEY


     Each of the undersigned Directors of PG&E Corporation hereby constitutes
and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC
MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his or
her attorneys in fact with full power of substitution to sign and file with the
Securities and Exchange Commission in his or her capacity as such Director of
said corporation the Form 10-K Annual Report for the year ended December 31,
2000, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and
any and all amendments and other filings or documents related thereto, and
hereby ratifies all that said attorneys in fact or any of them may do or cause
to be done by virtue hereof.

     IN WITNESS WHEREOF, we have signed these presents this 5th day of April,
2001.

DAVID R. ANDREWS                        DAVID M. LAWRENCE
--------------------------              --------------------------------
David R. Andrews                        David M. Lawrence, MD


DAVID A. COULTER                        MARY S. METZ
--------------------------              --------------------------------
David A. Coulter                        Mary S. Metz


C. LEE COX                              CARL E. REICHARDT
--------------------------              --------------------------------
C. Lee Cox                              Carl E. Reichardt


WILLIAM S. DAVILA                       BARRY LAWSON WILLIAMS
--------------------------              --------------------------------
William S. Davila                       Barry Lawson Williams


ROBERT D. GLYNN, JR.
--------------------------
Robert D. Glynn, Jr.
<PAGE>

                               POWER OF ATTORNEY


          ROBERT D. GLYNN, JR., the undersigned, Chairman of the Board, Chief
Executive Officer, and President of PG&E Corporation, hereby constitutes and
appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT,
GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact
with full power of substitution to sign and file with the Securities and
Exchange Commission in his capacity as Chairman of the Board, Chief Executive
Officer, and President (principal executive officer) of said corporation the
Form 10-K Annual Report for the year ended December 31, 2000, required by
Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all
amendments and other filings or documents related thereto, and hereby ratifies
all that said attorneys in fact or any of them may do or cause to be done by
virtue hereof.

          IN WITNESS WHEREOF, I have signed these presents this 5th day of
April, 2001.


                                        ROBERT D. GLYNN, JR.
                                        --------------------------------
                                        Robert D. Glynn, Jr.
<PAGE>

                               POWER OF ATTORNEY

          PETER A. DARBEE, the undersigned, Senior Vice President, Chief
Financial Officer, and Treasurer of PG&E Corporation, hereby constitutes and
appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT,
GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact
with full power of substitution to sign and file with the Securities and
Exchange Commission in his capacity as Senior Vice President, Chief Financial
Officer, and Treasurer (principal financial officer) of said corporation the
Form 10-K Annual Report for the year ended December 31, 2000, required by
Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all
amendments and other filings or documents related thereto, and hereby ratifies
all that said attorneys in fact or any of them may do or cause to be done by
virtue hereof.

          IN WITNESS WHEREOF, I have signed these presents this 5th day of
April, 2001.


                                      PETER A. DARBEE
                                      ------------------------------
                                      Peter A. Darbee
<PAGE>

                               POWER OF ATTORNEY


          CHRISTOPHER P. JOHNS, the undersigned, Vice President and Controller
of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA
Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN
HAYES, and each of them, as his attorneys in fact with full power of
substitution to sign and file with the Securities and Exchange Commission in his
capacity as Vice President and Controller (principal accounting officer) of said
corporation the Form 10-K Annual Report for the year ended December 31, 2000,
required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any
and all amendments and other filings or documents related thereto, and hereby
ratifies all that said attorneys in fact or any of them may do or cause to be
done by virtue hereof.

          IN WITNESS WHEREOF, I have signed these presents this 5th day of
April, 2001.


                                      CHRISTOPHER P. JOHNS
                                      ---------------------------
                                      Christopher P. Johns
<PAGE>

                               POWER OF ATTORNEY


          Each of the undersigned Directors of Pacific Gas and Electric Company
hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S.
LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them,
as his or her attorneys in fact with full power of substitution to sign and file
with the Securities and Exchange Commission in his or her capacity as such
Director of said corporation the Form 10-K Annual Report for the year ended
December 31, 2000, required by Section 13 or 15(d) of the Securities Exchange
Act of 1934 and any and all amendments and other filings or documents related
thereto, and hereby ratifies all that said attorneys in fact or any of them may
do or cause to be done by virtue hereof.

          IN WITNESS WHEREOF, we have signed these presents this 5th day of
April, 2001.


DAVID R. ANDREWS                   DAVID M. LAWRENCE, MD
------------------------           --------------------------
David R. Andrews                   David M. Lawrence, MD


DAVID A. COULTER                   MARY S. METZ
------------------------           --------------------------
David A. Coulter                   Mary S. Metz


C. LEE COX                         CARL E. REICHARDT
------------------------           --------------------------
C. Lee Cox                         Carl E. Reichardt


WILLIAM S. DAVILA                  GORDON R. SMITH
------------------------           --------------------------
William S. Davila                  Gordon R. Smith


ROBERT D. GLYNN, JR.               BARRY LAWSON WILLIAMS
------------------------           --------------------------
Robert D. Glynn, Jr.               Barry Lawson Williams
<PAGE>

                               POWER OF ATTORNEY


          GORDON R. SMITH, the undersigned, President and Chief Executive
Officer of Pacific Gas and Electric Company, hereby constitutes and appoints
LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P.
ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with
full power of substitution to sign and file with the Securities and Exchange
Commission in his capacity as President and Chief Executive Officer (principal
executive officer) of said corporation the Form 10-K Annual Report for the year
ended December 31, 2000, required by Section 13 or 15(d) of the Securities
Exchange Act of 1934 and any and all amendments and other filings or documents
related thereto, and hereby ratifies all that said attorneys in fact or any of
them may do or cause to be done by virtue hereof.

          IN WITNESS WHEREOF, I have signed these presents this 5th day of
April, 2001.



                                   GORDON R. SMITH
                                   ------------------------------
                                   Gordon R. Smith
<PAGE>

                               POWER OF ATTORNEY


          KENT M. HARVEY, the undersigned, Senior Vice President - Chief
Financial Officer and Treasurer of Pacific Gas and Electric Company, hereby
constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC
MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his
attorneys in fact with full power of substitution to sign and file with the
Securities and Exchange Commission in his capacity as Senior Vice President -
Chief Financial Officer and Treasurer (principal financial officer) of said
corporation the Form 10-K Annual Report for the year ended December 31, 2000,
required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any
and all amendments and other filings or documents related thereto, and hereby
ratifies all that said attorneys in fact or any of them may do or cause to be
done by virtue hereof.

          IN WITNESS WHEREOF, I have signed these presents this 5th day of
April, 2001.



                                   KENT M. HARVEY
                                   ------------------------------
                                   Kent M. Harvey
<PAGE>

                               POWER OF ATTORNEY


          DINYAR B. MISTRY, the undersigned, Vice President - Controller of
Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H.
EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and
KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of
substitution to sign and file with the Securities and Exchange Commission in his
capacity as Vice President - Controller (principal accounting officer) of said
corporation the Form 10-K Annual Report for the year ended December 31, 2000,
required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any
and all amendments and other filings or documents related thereto, and hereby
ratifies all that said attorneys in fact or any of them may do or cause to be
done by virtue hereof.

          IN WITNESS WHEREOF, I have signed these presents this 5th day of
April, 2001.



                                        DINYAR B. MISTRY
                                        ---------------------
                                        Dinyar B. Mistry
</TEXT>
</DOCUMENT>
</SUBMISSION>
