<SUBMISSION>
<ACCESSION-NUMBER>0001021408-02-003038
<TYPE>10-K/A
<PUBLIC-DOCUMENT-COUNT>4
<PERIOD>20001231
<FILING-DATE>20020305
<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/A
<ACT>34
<FILE-NUMBER>001-12609
<FILM-NUMBER>02566549
</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/A
<SEQUENCE>1
<FILENAME>d10ka.txt
<DESCRIPTION>FORM 10-K/A FOR PERIOD ENDING 12/31/2000
<TEXT>
<PAGE>

                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                                   FORM 10-K/A
                               Amendment No. 1 to

(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
     -----------                           ----------------------------                    -------------           ------
<S>                       <C>                                                              <C>                <C>
     1-12609              PG&E CORPORATION                                                   California          94-3234914
     1-2348               PACIFIC GAS AND ELECTRIC COMPANY                                   California          94-0742640


                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 offices)                         (Address of principal executive offices)
                              94177                                                           94105
                           (Zip Code)                                                       (Zip Code)
                         (415) 973-7000                                                   (415) 267-7000
      (Registrant's telephone number, including area code)               (Registrant's telephone number, including area code)
</TABLE>

           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 Securities,                        American Stock Exchange and
          Series A (liquidation preference $25), issued by PG&E                       Pacific Exchange
          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 shares held by sub)
Pacific Gas and Electric Company:               Wholly owned by PG&E Corporation

                       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>

INTRODUCTORY NOTE

     PG&E Corporation has previously disclosed that its subsidiary, PG&E
National Energy Group, Inc (PG&E NEG), has used "synthetic leases" in connection
with some of its power plant projects and turbine acquisition commitments.
Subsequent to the issuance of PG&E Corporation's 1999 and 2000 consolidated
financial statements, management determined that the assets and liabilities
associated with these leases should have been consolidated. This Amendment No. 1
to PG&E Corporation's and Pacific Gas and Electric Company's joint Annual Report
on Form 10-K for the year ended December 31, 2000, contains revised consolidated
financial statements for PG&E Corporation for the years ended December 31, 1999
and 2000. To reflect the revisions, this Amendment No. 1 hereby amends:

Part I, Item 1. Business (by correcting the statement of the amount of PG&E
Corporation's assets for the year ended December 31, 2000 that appears on page 2
of the original filing)

Part I, Items 2 through 4 - unchanged

Part II, Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters (references are to amended 2000 Annual Report to Shareholders)

Part II, Item 6. Selected Financial Data (references are to amended 2000 Annual
Report to Shareholders)

Part II, Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations, (references are to amended 2000 Annual Report to
Shareholders)

Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk
(references are to amended 2000 Annual Report to Shareholders)

Part II, Item 8. Financial Statements and Supplementary Data (references are to
amended 2000 Annual Report to Shareholders)

Part III, Items 10 through 13 - unchanged

Part IV, Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K (amended to file herewith amended Exhibit 13 - portions of the amended 2000
Annual Report to Shareholders, Exhibit 23.1 - Independent Auditors' Consent
(Deloitte & Touche LLP), and Exhibit 23.2 - Consent of Arthur Andersen LLP. All
other exhibits that were filed with the original filing have not been re-filed
with this amendment but instead have been incorporated by reference to the
original filing.)

Although the full text of the amended Form 10-K is contained herein, this
Amendment No. 1 does not update any other disclosures to reflect developments
since the original date of filing.

                                       i

<PAGE>

                                TABLE OF CONTENTS
<TABLE>
<CAPTION>
                                                                                                                        Page
                                                                                                                        ----
<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 ...............................................................................   4
         Regulation of Pacific Gas and Electric Company ...............................................................   5
            Federal Regulation ........................................................................................   5
            State Regulation ..........................................................................................   5
            Licenses and Permits ......................................................................................   6
         Regulation of PG&E National Energy Group, Inc. Businesses ....................................................   6
            Federal Regulation ........................................................................................   6
            State and Other Regulations ...............................................................................   7

         UTILITY OPERATIONS ...........................................................................................   8
         Ratemaking Mechanisms ........................................................................................   8
              General Rate Case .......................................................................................   8
              Cost of Capital .........................................................................................   8
              Electric and Gas Distribution Performance-Based Ratemaking (PBR) ........................................   8
            Electric Ratemaking .......................................................................................   9
              Rate Stabilization Plan Proceeding ......................................................................   9
              General Rate Case .......................................................................................  10
              2001 Attrition Rate Adjustment Request ..................................................................  11
              Revenue Adjustment Proceeding ...........................................................................  11
              Annual Transition Cost Proceeding .......................................................................  11
              Electric Industry Restructuring Implementation Costs ....................................................  11
              Electric Restructuring Costs Account (ERCA) .............................................................  11
              Revenues from Must-Run Contracts ........................................................................  12
              FERC Transmission Owner Rate Case .......................................................................  12
              AB 1890 Electric Base Revenue Increase ..................................................................  12
              Electric Transmission Rates .............................................................................  13
              Post-Transition Period Ratemaking Proceeding ............................................................  13
            Gas Ratemaking ............................................................................................  13
              Gas Accord ..............................................................................................  13
              General Rate Case .......................................................................................  13
              Gas Procurement Costs ...................................................................................  13
              The Biennial Cost Allocation Proceeding (BCAP) ..........................................................  13
         Public Purpose Programs ......................................................................................  14
         Electric Utility Operations ..................................................................................  15
            Electric Industry Restructuring ...........................................................................  15
              California Power Crisis .................................................................................  15
              FERC Order ..............................................................................................  15
              The California Independent System Operator and the California Power Exchange ............................  16
              New California Legislation ..............................................................................  17
</TABLE>

                                       ii

<PAGE>

<TABLE>
<CAPTION>
                                                                                                         Page
                                                                                                         ----
<S>                                                                                                      <C>
              Recovery of Transition Costs, Wholesale Power Purchase Costs, and End of Rate Freeze ....   18
              Retail Direct Access ....................................................................   19
         Electric Operating Statistics ................................................................   20
         Electric Resources ...........................................................................   21
         Generating Capacity ..........................................................................   21
            Hydroelectric Generation Assets ...........................................................   22
            Diablo Canyon Nuclear Power Plant .........................................................   22
              Diablo Canyon Ratemaking ................................................................   23
              Nuclear Fuel Supply and Disposal ........................................................   23
              Insurance ...............................................................................   24
              Decommissioning .........................................................................   24
         Other Electric Resources .....................................................................   25
              QF Generation and Other Power Purchase Contracts ........................................   25
              Bilateral Agreements ....................................................................   26
         Electric Transmission and Distribution .......................................................   27
         Gas Utility Operations .......................................................................   28
              Gas Operating Statistics ................................................................   29
              Natural Gas Supplies ....................................................................   30
              Gas Regulatory Framework ................................................................   31
              Transportation Commitments ..............................................................   32

         PG&E NATIONAL ENERGY GROUP, INC. .............................................................   32
         Integrated Power Generation, and Energy Trading and Marketing Business .......................   33
            Ownership and Operation of Generating Facilities ..........................................   33
            New Power Plant Development and Construction ..............................................   33
            Contractual Control of Generating Capacity ................................................   34
            Energy Marketing and Trading ..............................................................   34
            Description of Generating Facilities ......................................................   37
            Competition ...............................................................................   37
         Natural Gas Transmission Business ............................................................   38
              PG&E GT-Northwest (PG&E GTN) ............................................................   38
              North Baja Pipeline .....................................................................   39
              Competition .............................................................................   39

         ENVIRONMENTAL MATTERS ........................................................................   40
         Environmental Matters ........................................................................   40
            Environmental Protection Measures .........................................................   40
            Air Quality ...............................................................................   40
            Water Quality .............................................................................   42
            Hazardous Waste Compliance and Remediation ................................................   43
            Potential Recovery of Hazardous Waste Compliance and Remediation Costs ....................   44
            Compressor Station Litigation .............................................................   45
            Electric and Magnetic Fields ..............................................................   45
            Low Emission Vehicle Programs .............................................................   45
Item 2.  Properties ...................................................................................   45
Item 3.  Legal Proceedings ............................................................................   46
         Pacific Gas and Electric Company Bankruptcy ..................................................   46
         Pacific Gas and Electric Company vs. California Public Utilities Commissioners ...............   46
         Wilson vs. PG&E Corporation and Pacific Gas and Electric Company .............................   46
         Moss Landing Power Plant .....................................................................   47
</TABLE>

                                      iii

<PAGE>

<TABLE>
<CAPTION>
                                                                                                          Page
                                                                                                          ----
<S>                                                                                                       <C>
           Compressor Station Chromium Litigation ......................................................   48
           Texas Franchise Fee Litigation ..............................................................   49
Item 4.    Submission of Matters to a Vote of Security Holders .........................................   49

           EXECUTIVE OFFICERS OF THE REGISTRANTS .......................................................   50

                                            PART II

Item 5.    Market for the Registrant's Common Equity and Related Stockholder Matters ...................   53
Item 6.    Selected Financial Data .....................................................................   53
Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations .......   53
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk ..................................   53
Item 8.    Financial Statements and Supplementary Data .................................................   53
Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ........   54

                                            PART III

Item 10.   Directors and Executive Officers of the Registrant ..........................................   54
Item 11.   Executive Compensation ......................................................................   54
Item 12.   Security Ownership of Certain Beneficial Owners and Management ..............................   54
Item 13.   Certain Relationships and Related Transactions ..............................................   54

                                            PART IV

Item 14.   Exhibits, Financial Statement Schedules, and Reports on Form 8-K ............................   55
           Signatures ..................................................................................   63
           Independent Auditors' Report (Deloitte & Touche LLP) ........................................   64
           Report of Independent Public Accountants (Arthur Andersen LLP) ..............................   65
           Report of Independent Public Accountants (Arthur Andersen LLP) ..............................   66
</TABLE>

                                       iv


<PAGE>

                                GLOSSARY OF TERMS
<TABLE>
<S>                            <C>
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
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
ICIP ......................... Incremental Cost Incentive Price
</TABLE>

                                       v

<PAGE>

                         GLOSSARY OF TERMS--(Continued)
<TABLE>
<S>                                      <C>
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
RAP .................................... Revenue Adjustment Proceeding
</TABLE>

                                       vi


<PAGE>

                         GLOSSARY OF TERMS--(Continued)
<TABLE>
<S>                  <C>
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>

                                      vii






<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 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

                                        1

<PAGE>

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 $36.2 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;

     .  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

                                        2

<PAGE>

     . 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.

     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.

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<PAGE>

     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 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.

                                        4

<PAGE>

     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 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

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<PAGE>

     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
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

                                       6

<PAGE>

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
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.

                                       7

<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.

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<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 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

                                       9

<PAGE>

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, 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.

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     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.

     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

                                       11

<PAGE>

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 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.

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<PAGE>

     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.

     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

                                       13

<PAGE>

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.

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.

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<PAGE>

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 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.

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<PAGE>

     . 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.

     . 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.


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     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 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-

                                       17

<PAGE>

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 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.

                                       18

<PAGE>

     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 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.

                                       19

<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
                                              ==========   ===========    ==========   ==========    ==========
</TABLE>

     The following table shows certain customer information:

<TABLE>
<CAPTION>
Selected Statistics:                                          2000      1999     1998      1997    1996
                                                              ----      ----     ----      ----    ----
<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.

                                       20

<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>
                                                                                                           Net
                                                                                              Number    Operating
                     Generation Type                                     County Location     of Units  Capacity kW
                     ---------------                                     ---------------     --------  -----------
Hydroelectric:
<S>                                                            <C>                              <C>     <C>
   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.

                                       21

<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.

                                       22

<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
                                                                       -----    -----      -----        -----         ----
Unit 1
<S>                                                                    <C>      <C>      <C>          <C>           <C>
     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 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.

                                       23

<PAGE>

     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.

     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.

                                       24

<PAGE>

     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.

     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.

                                       25

<PAGE>

     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 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

                                       26

<PAGE>

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 PUC 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 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.

                                       27

<PAGE>

     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.

     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.

                                       28

<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.

                                       29

<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 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.

                                       30

<PAGE>

<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)."

     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.

                                       31

<PAGE>

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.

                                       32

<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 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.

                                       33

<PAGE>

     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.

     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.

                                       34

<PAGE>

     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.

     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.

                                       35

<PAGE>

     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.

                                       36

<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                                                                    Commercial
    Generating Facility        State    MW      MW(1)  Structure       Fuel     Primary Output Sales 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.

     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

                                       37

<PAGE>

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.

     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

                                       38

<PAGE>

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.

     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.

                                       39

<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.

                                       40

<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.

     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.

                                       41

<PAGE>

     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 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.

                                       42

<PAGE>

     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.

     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.

                                       43

<PAGE>

     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 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.

                                       44

<PAGE>

     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.

     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.

                                       45

<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 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

                                       46

<PAGE>

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.

     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.

                                       47

<PAGE>

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 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.

                                       48

<PAGE>

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.

                                       49

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

                                       50

<PAGE>

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

                                       51

<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,                                    Position
            ----             -------------------                                    --------
                                     2000
                                     ----
<S>                                   <C>            <C>
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, Jr. .........          50             Senior Vice President, Public 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
            -----                                  ---------                                   ------------------
<S>                             <C>                                                 <C>
G. R. Smith ................    President and Chief Executive Officer               June 1, 1997 to present
                                Chief Financial Officer, PG&E Corporation           December 18, 1996 to May 31, 1997
                                Senior Vice President and Chief Financial           June 1, 1995 to May 31, 1997
                                  Officer
                                Vice President and Chief Financial Officer          November 1, 1991 to May 31, 1995
K. M. Harvey ...............    Senior Vice President, Chief Financial Officer,     November 1, 2000 to present
                                  and Treasurer
                                Senior Vice President, Chief Financial Officer,     January 1, 2000 to October 31, 2000
                                  Controller, and Treasurer
                                Senior Vice President, Chief Financial Officer,     July 1, 1997 to December 31, 1999
                                  and Treasurer
                                Vice President and Treasurer                        June 1, 1995 to June 30, 1997
R. J. Peters ...............    Senior Vice President and General Counsel           January 1, 1999 to present
                                Vice President and General Counsel                  July 1, 1997 to December 31, 1998
                                Chief Counsel, Regulatory                           January 1, 1993 to June 30, 1997
J. K. Randolph .............    Senior Vice President and Chief of Utility          April 6, 2000 to present
                                Operations
                                Senior Vice President and General Manager,          July 1, 1997 to April 5, 2000
                                  Transmission, Distribution and
                                  Customer Service Business Unit
                                Vice President and General Manager, Power           January 1, 1997 to June 30, 1997
                                  Generation, Business Unit
                                Vice President, Power Generation                    November 1, 1991 to December 31, 1996
D. D. Richard, Jr. .........    Senior Vice President, Public Affairs               May 1, 1998 to present
                                Senior Vice President, Governmental and             July 1, 1997 to April 30, 1998
                                  Regulatory Relations
                                Senior Vice President, Public Affairs,              October 18, 2000 to present
                                  PG&E Corporation
                                Vice President, Governmental Relations,             July 1, 1997 October 17, 2000
                                  PG&E Corporation
                                Vice President, Governmental Relations              January 1, 1997 to June 30, 1997
                                Executive Vice President and Principal,             January 1993 to December 1996
                                  Morse, Richard, Weisenmiller & Assoc., Inc.
                                  (energy, project finance, and
                                  environmental consulting)
G. M. Rueger ...............    Senior Vice President, Generation and chief         April 6, 2000 to present
                                  Nuclear Officer
                                Senior Vice President and General Manager,          November 1, 1991 to April 5, 2000
                                  Nuclear Power Generation Business Unit
</TABLE>

                                       52

<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 amended 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 under the heading "Selected Financial Data" in the amended 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 under
the heading "Management's Discussion and Analysis" in the amended 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 under the heading "Management's Discussion and
Analysis--Quantitative and Qualitative Disclosures about Market Risk," and under
Notes 1, 4, 8 and 9 of the "Notes to the Consolidated Financial Statements" of
the amended 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 in the amended 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 "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

                                       53

<PAGE>

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.

                                       54

<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 amended report on
Form 10-K:

         1.   The following consolidated financial statements, supplemental
              information, and report of independent public accountants
              contained in the amended 2000 Annual 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 64 of this amended report on Form 10-K.

         3.   Report of Independent Public Accountants (Arthur Andersen LLP)
              included at page 65 of this amended report on Form 10-K.

         4.   Report of Independent Public Accountants (Arthur Andersen LLP)
              included at page 66 of this amended report on Form 10-K.

         5.   Financial statement schedules (these schedules are the same as the
              schedules filed with the original filing):

                    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:

              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 (incorporated by
                    reference to PG&E Corporation's Form 10-K for the year ended
                    December 31, 2000 (File No.1-12609), Exhibit 3.2)

              3.3   By-Laws of PG&E Corporation amended as of February 21, 2001
                    (incorporated by reference to PG&E Corporation's Form 10-K
                    for the year ended December 31, 2000 (File No. 1-12609),
                    Exhibit 3.3)

                                       55

<PAGE>
          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 (incorporated by reference to Pacific Gas and
                 Electric Company's Form 10-K for the year ended December 31,
                 2000 (File No. 1-2348), Exhibit 3.5)

                 First and Refunding Mortgage of Pacific Gas and Electric
          4.1    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

                 Form of Rights Agreement dated as of December 22, 2000 between
          4.2    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 (incorporated by reference to PG&E
                 Corporation's Form 10-K for the year ended December 31, 2000
                 (File No. 1-12609), Exhibit 4.2)

                 The Gas Accord Settlement Agreement, together with accompanying
          10.    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
                 (incorporated by reference to Form 10-K filed by PG&E
                 Corporation and Pacific Gas and Electric Company for the year
                 ended December 31, 2000 (File No. 1-12609 and File No. 1-2348),
                 Exhibit 10)

                 Stock Purchase Agreement By and Between PG&E National Energy
          10.1   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)

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

         *10.3   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, 1999
                 (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)

                                       56

<PAGE>

          *10.6      Letter regarding Compensation Arrangement between PG&E
                     Corporation and Thomas B. King dated November 4, 1998
                     (incorporated by reference to PG&E Corporation's Form 10-K
                     for the year ended December 31, 2000 (File No. 1-12609),
                     Exhibit 10.6)

          *10.7      Letter regarding Compensation Arrangement between PG&E
                     Corporation and Lyn E. Maddox dated April 25, 1997
                     (incorporated by reference to PG&E Corporation's Form 10-K
                     for the year ended December 31, 2000 (File No. 1-12609),
                     Exhibit 10.7)

          *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 (incorporated by reference to
                     PG&E Corporation's Form 10-K for the year ended December
                     31, 2000 (File No. 1-12609), Exhibit 10.9)

          *10.10     PG&E Corporation Senior Executive Officer Retention Program
                     approved December 20, 2000 (incorporated by reference to
                     PG&E Corporation's Form 10-K for the year ended December
                     31, 2000 (File No. 1-12609), Exhibit 10.10)

          *10.10.1   Letter regarding retention award to Robert D. Glynn, Jr.
                     dated January 22, 2001 (incorporated by reference to PG&E
                     Corporation's Form 10-K for the year ended December 31,
                     2000 (File No. 1-12609), Exhibit 10.10.1)

          *10.10.2   Letter regarding retention award to Gordon R. Smith dated
                     January 22, 2001 (incorporated by reference to PG&E
                     Corporation's Form 10-K for the year ended December 31,
                     2000 (File No. 1-12609), Exhibit 10.10.2)

          *10.10.3   Letter regarding retention award to Peter A. Darbee dated
                     January 22, 2001 (incorporated by reference to PG&E
                     Corporation's Form 10-K for the year ended December 31,
                     2000 (File No. 1-12609), Exhibit 10.10.3.)

          *10.10.4   Letter regarding retention award to Bruce R. Worthington
                     dated January 22, 2001 (incorporated by reference to PG&E
                     Corporation's Form 10-K for the year ended December 31,
                     2000 (File No. 1-12609), Exhibit 10.10.4)

          *10.10.5   Letter regarding retention award to G. Brent Stanley dated
                     January 22, 2001 (incorporated by reference to PG&E
                     Corporation's Form 10-K for the year ended December 31,
                     2000 (File No. 1-12609), Exhibit 10.10.5)

          *10.10.6   Letter regarding retention award to Daniel D. Richard dated
                     January 22, 2001 (incorporated by reference to PG&E
                     Corporation's Form 10-K for the year ended December 31,
                     2000 (File No. 1-12609), Exhibit 10.10.6)

          *10.10.7   Letter regarding retention award to James K. Randolph dated
                     February 27, 2001 (incorporated by reference to Pacific Gas
                     and Electric Company's Form 10-K for the year ended
                     December 31, 2000 (File No. 1-2348), Exhibit 10.10.7)

          *10.10.8   Letter regarding retention award to Gregory M. Rueger dated
                     February 27, 2001 (incorporated by reference to Pacific Gas
                     and Electric Company's Form 10-K for the year ended
                     December 31, 2000 (File No. 1-2348), Exhibit 10.10.8)

          *10.10.9   Letter regarding retention award to Kent Harvey dated
                     February 27, 2001 (incorporated by reference to Pacific Gas
                     and Electric Company's Form 10-K for the year ended
                     December 31, 2000 (File No. 1-2348), Exhibit 10.10.9)

          *10.10.10  Letter regarding retention award to Roger J. Peters dated
                     February 27, 2001 (incorporated by reference to Pacific Gas
                     and Electric Company's Form 10-K for the year ended
                     December 31, 2000 (File No. 1-2348), Exhibit 10.10.10)

                                       57

<PAGE>

          *10.10.11  Letter regarding retention award to Thomas G. Boren dated
                     February 27, 2001 (incorporated by reference to PG&E
                     Corporation's Form 10-K for the year ended December 31,
                     2000 (File No. 1-12609), Exhibit 10.10.11)

          *10.10.12  Letter regarding retention award to Lyn E. Maddox dated
                     February 27, 2001 (incorporated by reference to PG&E
                     Corporation's Form 10-K for the year ended December 31,
                     2000 (File No. 1-12609), Exhibit 10.10.12)

          *10.10.13  Letter regarding retention award to P. Chrisman Iribe dated
                     February 27, 2001 (incorporated by reference to PG&E
                     Corporation's Form 10-K for the year ended December 31,
                     2000 (File No. 1-12609), Exhibit 10.10.13)

          *10.10.14  Letter regarding retention award to Thomas B. King dated
                     February 27, 2001 (incorporated by reference to PG&E
                     Corporation's Form 10-K for the year ended December 31,
                     2000 (File No. 1-12609), Exhibit 10.10.14)

          *10.11     Agreement and Release between PG&E Corporation and Thomas
                     W. High dated December 8, 2000 (incorporated by reference
                     to PG&E Corporation's Form 10-K for the year ended December
                     31, 2000 (File No. 1-12609), Exhibit 10.11)

          *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 (incorporated by reference to PG&E Corporation's Form
                     10-K for the year ended December 31, 2000 (File No.
                     1-12609), Exhibit 10.14)

          *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)

          *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 (incorporated by reference to
                       PG&E Corporation's Form 10-K for the year ended December
                       31, 2000 (File No. 1-12609), Exhibit 10.20)

          *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)

                                       58

<PAGE>

         *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 (incorporated by
                       reference to PG&E Corporation's Form 10-K for the year
                       ended December 31, 2000 (File No. 1-12609), Exhibit 11)

          12.1       Computation of Ratios of Earnings to Fixed Charges for
                       Pacific Gas and Electric Company (incorporated by
                       reference to Pacific Gas and Electric Company's Form 10-K
                       for the year ended December 31, 2000, Exhibit 12.1)

          12.2       Computation of Ratios of Earnings to Combined Fixed Charges
                       and Preferred Stock Dividends for Pacific Gas and
                       Electric Company (incorporated by reference to Pacific
                       Gas and Electric Company's Form 10-K for the year ended
                       December 31, 2000, Exhibit 12.2)

          13.        2000 Amended 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 Registrants (incorporated by reference
                       to Form 10-K filed by PG&E Corporation and Pacific Gas
                       and Electric Company for the year ended December 31,
                       2000, Exhibit 21)

          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 (incorporated by reference to
                       Form 10-K filed by PG&E Corporation and Pacific Gas and
                       Electric Company for the year ended December 31, 2000,
                       Exhibit 24.1)

          24.2       Powers of Attorney (incorporated by reference to Form 10-K
                       filed by PG&E Corporation and Pacific Gas and Electric
                       Company for the year ended December 31, 2000, Exhibit
                       24.2)

____________

*    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:

                                       59

<PAGE>

     1.   October 25, 2000

     Item 5. Other Events--

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

     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

                                       60

<PAGE>

     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

     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

                                       61

<PAGE>

          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).

                                       62

<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 Amendment No. 1 to
the their Annual Report on Form 10-K/A for the year ended December 31, 2000 to
be signed on their behalf by the undersigned, thereunto duly authorized, in the
City and County of San Francisco, on the 5th day of March, 2002.

            PG&E CORPORATION                PACIFIC GAS AND ELECTRIC COMPANY
             (Registrant)                             (Registrant)


By /s/ Gary P. Encinas                  By /s/ Gary P. Encinas
  ------------------------------------    --------------------------------------
   (Gary P. Encinas, Attorney-in-Fact)      (Gary P. Encinas, Attorney-in-Fact)

                                       63

<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, February 26, 2002 as to Note 17, which report includes
explanatory paragraphs concerning the ability of Pacific Gas and Electric
Company to continue as a going concern and the revision of PG&E Corporation's
1999 and 2000 financial statements to consolidate the assets and liabilities
associated with certain leases; 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, February 26, 2002 as to Note 17

                                       64


<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

                                       65

<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

                                       66

<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>

                                       67

<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
                                                                    =======    =======    =======
</TABLE>

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

<TABLE>
<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>

                                       68

<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."

                                       69

<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."

                                       70

<PAGE>

                                 EXHIBIT INDEX
                                 -------------

          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 (incorporated by
                 reference to PG&E Corporation's Form 10-K for the year ended
                 December 31, 2000 (File No. 1-12609), Exhibit 3.2)

          3.3    By-Laws of PG&E Corporation amended as of February 21, 2001
                 (incorporated by reference to PG&E Corporation's Form 10-K for
                 the year ended December 31, 2000 (File No. 1-12609), Exhibit
                 3.3)

          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 (incorporated by reference to Pacific Gas and
                 Electric Company's Form 10-K for the year ended December 31,
                 2000 (File No. 1-2348), Exhibit 3.5)

                 First and Refunding Mortgage of Pacific Gas and Electric
          4.1    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

                 Form of Rights Agreement dated as of December 22, 2000 between
          4.2    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 (incorporated by reference to PG&E
                 Corporation's Form 10-K for the year ended December 31, 2000
                 (File No. 1-12609), Exhibit 4.2)

                 The Gas Accord Settlement Agreement, together with accompanying
          10.    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
                 (incorporated by reference to Form 10-K filed by PG&E
                 Corporation and Pacific Gas and Electric Company for the year
                 ended December 31, 2000 (File No. 1-12609 and File No. 1-2348),
                 Exhibit 10)

                 Stock Purchase Agreement By and Between PG&E National Energy
          10.1   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)

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


<PAGE>

         *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, 1999
                    (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
                    (incorporated by reference to PG&E Corporation's Form 10-K
                    for the year ended December 31, 2000 (File No. 1-12609),
                    Exhibit 10.6)

         *10.7      Letter regarding Compensation Arrangement between PG&E
                    Corporation and Lyn E. Maddox dated April 25, 1997
                    (incorporated by reference to PG&E Corporation's Form 10-K
                    for the year ended December 31, 2000 (File No. 1-12609),
                    Exhibit 10.7)

         *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 (incorporated by reference to
                    PG&E Corporation's Form 10-K for the year ended December 31,
                    2000 (File No. 1-12609), Exhibit 10.9)

         *10.10     PG&E Corporation Senior Executive Officer Retention Program
                    approved December 20, 2000 (incorporated by reference to
                    PG&E Corporation's Form 10-K for the year ended December 31,
                    2000 (File No. 1-12609), Exhibit 10.10)

         *10.10.1   Letter regarding retention award to Robert D. Glynn, Jr.
                    dated January 22, 2001 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31, 2000
                    (File No. 1-12609), Exhibit 10.10.1)

         *10.10.2   Letter regarding retention award to Gordon R. Smith dated
                    January 22, 2001 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31, 2000
                    (File No. 1-12609), Exhibit 10.10.2)

         *10.10.3   Letter regarding retention award to Peter A. Darbee dated
                    January 22, 2001 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31, 2000
                    (File No. 1-12609), Exhibit 10.10.3.)

         *10.10.4   Letter regarding retention award to Bruce R. Worthington
                    dated January 22, 2001 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31,
                    2000 (File No. 1-12609), Exhibit 10.10.4)

         *10.10.5   Letter regarding retention award to G. Brent Stanley dated
                    January 22, 2001 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31, 2000
                    (File No. 1-12609), Exhibit 10.10.5)

         *10.10.6   Letter regarding retention award to Daniel D. Richard dated
                    January 22, 2001 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31, 2000
                    (File No. 1-12609), Exhibit 10.10.6)

         *10.10.7   Letter regarding retention award to James K. Randolph dated
                    February 27, 2001 (incorporated by reference to Pacific Gas
                    and Electric Company's Form 10-K for the year ended December
                    31, 2000 (File No. 1-2348), Exhibit 10.10.7)

         *10.10.8   Letter regarding retention award to Gregory M. Rueger dated
                    February 27, 2001 (incorporated by reference to Pacific Gas
                    and Electric Company's Form 10-K for the year ended December
                    31, 2000 (File No. 1-2348), Exhibit 10.10.8)




<PAGE>

         *10.10.9   Letter regarding retention award to Kent Harvey dated
                    February 27, 2001 (incorporated by reference to Pacific Gas
                    and Electric Company's Form 10-K for the year ended December
                    31, 2000 (File No. 1-2348), Exhibit 10.10.9)

         *10.10.10  Letter regarding retention award to Roger J. Peters dated
                    February 27, 2001 (incorporated by reference to Pacific Gas
                    and Electric Company's Form 10-K for the year ended December
                    31, 2000 (File No. 1-2348), Exhibit 10.10.10)

         *10.10.11  Letter regarding retention award to Thomas G. Boren dated
                    February 27, 2001 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31, 2000
                    (File No. 1-12609), Exhibit 10.10.11)

         *10.10.12  Letter regarding retention award to Lyn E. Maddox dated
                    February 27, 2001 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31, 2000
                    (File No. 1-12609), Exhibit 10.10.12)

         *10.10.13  Letter regarding retention award to P. Chrisman Iribe dated
                    February 27, 2001 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31, 2000
                    (File No. 1-12609), Exhibit 10.10.13)

         *10.10.14  Letter regarding retention award to Thomas B. King dated
                    February 27, 2001 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31, 2000
                    (File No. 1-12609), Exhibit 10.10.14)

         *10.11     Agreement and Release between PG&E Corporation and Thomas
                    W. High dated December 8, 2000 (incorporated by reference to
                    PG&E Corporation's Form 10-K for the year ended December 31,
                    2000 (File No. 1-12609), Exhibit 10.11)

         *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 (incorporated by reference to PG&E Corporation's Form
                    10-K for the year ended December 31, 2000 (File No.
                    1-12609), Exhibit 10.14)

         *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)

         *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)


<PAGE>

         *10.20     PG&E Corporation Executive Stock Ownership Program, amended
                    as of September 19, 2000 (incorporated by reference to PG&E
                    Corporation's Form 10-K for the year ended December 31, 2000
                    (File No. 1-12609), Exhibit 10.20)

         *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 (incorporated by
                    reference to PG&E Corporation's Form 10-K for the year ended
                    December 31, 2000 (File No. 1-12609), Exhibit 11)

          12.1      Computation of Ratios of Earnings to Fixed Charges for
                    Pacific Gas and Electric Company (incorporated by reference
                    to Pacific Gas and Electric Company's Form 10-K for the year
                    ended December 31, 2000, Exhibit 12.1)

          12.2      Computation of Ratios of Earnings to Combined Fixed Charges
                    and Preferred Stock Dividends for Pacific Gas and Electric
                    Company (incorporated by reference to Pacific Gas and
                    Electric Company's Form 10-K for the year ended December 31,
                    2000, Exhibit 12.2)

          13.       2000 Amended 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 Registrants (incorporated by reference
                    to Form 10-K filed by PG&E Corporation and Pacific Gas and
                    Electric Company for the year ended December 31, 2000,
                    Exhibit 21)

          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 (incorporated by reference to
                    Form 10-K filed by PG&E Corporation and Pacific Gas and
                    Electric Company for the year ended December 31, 2000,
                    Exhibit 24.1)

          24.2      Powers of Attorney (incorporated by reference to Form 10-K
                    filed by PG&E Corporation and Pacific Gas and Electric
                    Company for the year ended December 31, 2000, Exhibit 24.2)

____________

*    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.

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13
<SEQUENCE>3
<FILENAME>dex13.txt
<DESCRIPTION>2000 AMENDED ANNUAL REPORT TO SHAREHOLDERS
<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                                                         $ 26,220    $  20,819   $ 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                                                                 36,152       29,588     33,234     31,115       26,237
Long-term debt (excluding current portions)                                   5,550        6,785      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.

                                                                               1

<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.

     Subsequent to the issuance of PG&E Corporation's 2000 and 1999 Consolidated
Financial Statements, management determined that the assets and liabilities
relating to certain leases should have been consolidated. The facilities
associated with the leases were under construction during 2000 and 1999 (See
Note 17 of the Notes to the Consolidated Financial Statements).

     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;

                                                                               2

<PAGE>

     .    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;

     .    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),

                                                                               3

<PAGE>

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 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

                                                                               4

<PAGE>


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.

     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

                                                                               5

<PAGE>

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
        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%.

                                                                               6

<PAGE>

     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 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,

                                                                               7

<PAGE>

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

Cash Flows from Operating Activities

     Net cash (used) provided by PG&E Corporation's operating activities totaled
$(742) million, $2,170 million, and $3,388 million in 2000, 1999, and 1998,
respectively. The decrease of $2,912 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 $2.3 billion, $1.7
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 $3.1 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 $1.9 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,

                                                                               8

<PAGE>

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.

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.

                                                                               9

<PAGE>

     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.

     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 $(43) million, $(26)
million, and $(348) million for the years ended December 31, 2000, 1999, and
1998, respectively. The increase in cash flows generated from operations in 1999
as compared to 1998 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; 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.

                                                                              10

<PAGE>

     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 lease with a third-party trust. PG&E Gen will operate the plant under
a lease arrangement. The estimated cost to construct these plants is
approximately $1.4 billion. These trusts are consolidated in the accompanying
financial statements.

     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, 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.

                                                                              11

<PAGE>

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                                                  $2,754
Long-term debt
           Variable rate obligations                              $   16    $   94   $  584   $  189     $  170       $  553
           Fixed rate obligations                                 $    1    $   34   $    7   $    1     $  251       $  325

           Average interest rate                                     6.8%      4.3%     6.1%     7.3%       7.5%         7.9%
</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

     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

                                                                              12

<PAGE>

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
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.)

                                                                              13

<PAGE>

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
                                                                           -------
                                                                                                         Eliminations &
(in millions)                                Utility     PG&E Gen     NW          Texas     PG&E ET        Other/(1)/     Total
<S>                                         <C>        <C>        <C>          <C>        <C>           <C>              <C>
2000:
Operating revenues                          $  9,637   $  1,199   $    239     $     873     $ 16,054       $  (1,782)    $ 26,220
Operating expenses                            14,838      1,061        105           869       15,974          (1,820)      31,027
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                                                                                         (742)
Net cash used by investing activities                                                                                       (1,690)
Net cash provided by financing activities                                                                                    3,075
EBITDA/(2)/                                 $ (1,244)  $    227   $    176     $     108     $     91       $     (55)    $   (697)
1999:
Operating revenues                          $  9,228   $  1,121   $    224     $   1,148     $ 10,521       $  (1,423)    $ 20,819
Operating expenses                             7,235      1,006        104         2,446       10,582          (1,432)      19,941
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                                                                                    2,170
</TABLE>

                                                                              14

<PAGE>

<TABLE>
<S>                                         <C>        <C>        <C>          <C>        <C>           <C>              <C>
Net cash used by investing activities                                                                                         (234)
Net cash used by financing activities                                                                                       (1,940)
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 activities                                                                                    3,388
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.

     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

                                                                              15

<PAGE>

          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.

     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.

                                                                              16

<PAGE>

     .    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

     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).

                                                                              17

<PAGE>

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.

     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

                                                                              18

<PAGE>

(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>


         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

                                                                              19

<PAGE>

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

     The NEG operating revenues increased $4,992 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.

                                                                              20

<PAGE>

     The NEG's 1999 operating revenues increased $938 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 $3,483 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 $2,275 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.

                                                                              21

<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 "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
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

                                                                              22

<PAGE>

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.

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

                                                                              23

<PAGE>

     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 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

                                                                              24

<PAGE>
         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

         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

                                                                              25

<PAGE>

"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.

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.

                                                                              26

<PAGE>

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 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.

                                                                              27

<PAGE>
         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:

<TABLE>
<CAPTION>
                                                     2000                          1999
                                                     ----                          ----
                                             Trading      Non-Trading      Trading     Non-Trading
                                                             (Dollars in millions)
   <S>                                       <C>          <C>    <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%.

                                                                              28

<PAGE>

         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.

         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.
                                                                              29

<PAGE>

                                PG&E Corporation
                      STATEMENTS OF CONSOLIDATED OPERATIONS
                     (in millions, except per share amounts)

<TABLE>
<CAPTION>
                                                                                                       Year ended December 31,
                                                                                                       -----------------------
                                                                                                     2000        1999        1998
                                                                                                  (As revised, see Note 17)
<S>                                                                                              <C>            <C>         <C>
Operating Revenues
Utility                                                                                           $  9,637    $  9,228     $ 8,924
Energy commodities and services                                                                     16,583      11,591      10,653
                                                                                                  --------    --------     -------

         Total operating revenues                                                                   26,220      20,819      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                                                                            3,508       3,150       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                                                                   31,027      19,941      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.

                                                                              30

<PAGE>

                                PG&E Corporation
                           CONSOLIDATED BALANCE SHEETS
                       (in millions, except share amounts)

<TABLE>
<CAPTION>
                                                                                                         Balance at
                                                                                                        December 31,
                                                                                                        ------------
                                                                                                     2000          1999
                                                                                                   (As revised, see Note 17)
<S>                                                                                                      <C>              <C>
ASSETS

Current Assets

     Cash and cash equivalents                                                                       $    925        $   282
                                                                                                     --------        -------
     Short-term investments                                                                             1,634            187
     Accounts receivable
       Customers (net of allowance for doubtful accounts of $71 million and $65 million,
         respectively)                                                                                  2,129          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                                                                          11,199          3,575
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                                                                      1,605            553
     Other                                                                                                147            184
                                                                                                     --------        -------

         Total property, plant, and equipment (at original cost)                                       29,174         28,184
         Accumulated depreciation and decommissioning                                                 (11,878)       (11,291)
                                                                                                     --------        -------
         Net property, plant, and equipment                                                            17,296         16,893
Other Noncurrent Assets
     Regulatory assets                                                                                  1,773          4,957
     Nuclear decommissioning funds                                                                      1,328          1,264
     Price risk management                                                                              2,026            329
     Other                                                                                              2,530          2,570
                                                                                                     --------        -------

         Total noncurrent assets                                                                        7,657          9,120
                                                                                                     --------        -------

TOTAL ASSETS                                                                                         $ 36,152        $29,588
                                                                                                     ========        =======
</TABLE>

                                                                              31


<PAGE>

                                PG&E Corporation
                           CONSOLIDATED BALANCE SHEETS
                       (in millions, except share amounts)

<TABLE>
<CAPTION>
                                                                                                          Balance at
                                                                                                         December 31,
                                                                                                         -----------
                                                                                                       2000         1999
                                                                                                    (As revised, see Note 17)
<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                                                                                 3,800         722
         Energy marketing                                                                                2,096         480
         Regulatory balancing accounts                                                                     196         384
         Other                                                                                             459         559
     Accrued taxes                                                                                          --         211
     Price risk management                                                                               1,999         323
     Other                                                                                               1,570       1,059
                                                                                                       -------     -------
         Total current liabilities                                                                      17,331       6,085

Noncurrent Liabilities
     Long-term debt                                                                                      5,550       6,785
     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                                                                   14,869      15,837
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                                                             $36,152     $29,588
                                                                                                       =======     =======
</TABLE>

The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.

                                                                              32

<PAGE>

                                PG&E Corporation
                      STATEMENTS OF CONSOLIDATED CASH FLOWS
                                  (in millions)

<TABLE>
<CAPTION>
                                                                                            For the year ended December 31,
                                                                                            -------------------------------
                                                                                           2000          1999          1998
                                                                                        (As revised, see Note 17)
<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                                       (2,322)          370          (342)
                           Inventories                                                          41            23           (33)
                           Income tax receivable                                            (1,241)           --            --
                           Price risk management assets and liabilities, net                    30           (28)          (16)
                           Accounts payable                                                  4,594          (279)          247
                           Regulatory balancing accounts                                      (410)          305           537
                           Accrued taxes                                                      (211)          108          (123)
                           Other working capital                                               324           209           199
                  Other--net                                                                  (398)         (822)         (470)
                                                                                           -------       -------      --------

Net cash (used) provided by operating activities                                              (742)        2,170         3,388
                                                                                           -------       -------      --------
Cash Flows From Investing Activities

Capital expenditures                                                                        (2,346)       (1,701)       (1,619)
Acquisitions                                                                                    --            --        (1,779)
Proceeds from sale of assets                                                                   415         1,014         1,106
Other--net                                                                                     241           453            66
                                                                                           -------       -------      --------

Net cash used by investing activities                                                       (1,690)         (234)       (2,226)
                                                                                           -------       -------      --------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities                                          2,846          (145)        2,115
Long-term debt issued                                                                        1,734           103            --
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                                             3,075        (1,940)       (1,113)
                                                                                           -------       -------      --------

Net Change in Cash and Cash Equivalents                                                        643            (4)           49

Cash and Cash Equivalents at January 1                                                         282           286           237
                                                                                           -------       -------      --------

Cash and Cash Equivalents at December 31                                                   $   925       $   282      $    286
                                                                                           =======       =======      ========
Supplemental disclosures of cash flow information
               Cash paid for:
               Interest (net of amounts capitalized)                                       $   749       $   729      $    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.

                                                                              33

<PAGE>

                                PG&E Corporation
                 STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
                       (in millions, except share amounts)

<TABLE>
<CAPTION>
                                                    Common       Reinvested                             Total
                                                    Stock         Earnings          Accumulated        Common    Comprehensive
                                      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.

                                                                              34

<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.

                                                                              35

<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>

                                                                              36


<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.


                                                                              37

<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.

                                                                              38

<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.

                                                                              39

<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.

                                                                              40

<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
                                                     (As revised, see Note 17)
                  Utility                                 $50          $42

                  National Energy Group                    79           82


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,
                                                                                         -----------------------
       (in millions)                                                                 2000           1999          1998
       <S>                                                                         <C>            <C>          <C>
       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
                                                                                   =======        =======      ========
</TABLE>

                                       41






<PAGE>


<TABLE>
            <S>                                                        <C>            <C>         <C>
            Earnings (Loss) per common share, Basic and Diluted:
            Weighted average common shares outstanding                    362            368          382
                                                                       ------         ------      -------

            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 $48 million, $20
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.

                                                                              42

<PAGE>


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 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
</TABLE>

                                                                              43

<PAGE>


           PG&E GTN                                             57        62
                                                            ------    ------

           Total PG&E Corporation regulatory assets         $1,773    $4,957
                                                            ======    ======


(1) See Note 2 of the Notes to the Consolidated Financial Statements for further
discussion.

     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 not 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

                                                                              44

<PAGE>

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 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

                                                                              45

<PAGE>

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.

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.

                                                                              46

<PAGE>


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 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

                                                                              47

<PAGE>

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.

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

                                                                              48

<PAGE>

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
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.

                                                                              49

<PAGE>

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 (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.

                                                                              50

<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

                                                                              51

<PAGE>

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
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 on 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

                                                                              51

<PAGE>

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 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

                                                                              53

<PAGE>

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.

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.

                                                                              54

<PAGE>

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:

<TABLE>
<CAPTION>
                                                         Year Ended December 31,
                                                         -----------------------
          (in millions)                                2000       1999          1998
          <S>                                        <C>         <C>          <C>
          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
                                                     =======     ======       =======
</TABLE>


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:

          Standard & Poors                                      Current Ratings

          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

PG&E Corporation

                                                                              55

<PAGE>

     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-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.

                                                                              56

<PAGE>

     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

     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:

                                                                      Amount
                                                                   (in millions)
      Description                                                   (unaudited)

      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*

                                                                              57

<PAGE>

         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


*    Loans that lenders have agreed to forbear through April 13, 2001.

     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

                                                                              58

<PAGE>

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:

<TABLE>
<CAPTION>
                                                                              Maximum
          Electricity, Natural Gas,                      Purchase      Sale    Term in
          and Natural Gas Liquids Contracts              (Long)      (Short)    Years
          <S>                                            <C>          <C>     <C>
          (billions of MMBtu equivalents(1))

          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.

                                                                              59

<PAGE>


     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
                                                        ----                       ----
                                                Notional       Contract    Notional       Contract
                  (in millions)                   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)
                  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>

                                                                              60

<PAGE>


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.

      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
                                                                             ----                    ----
                                                                               (As revised, see Note 17)
                  PG&E Corporation                                   Carrying                Carrying
                  (in millions)                                        Amount    Fair Value    Amount    Fair Value
                  <S>                                                <C>         <C>         <C>         <C>
                  Long-term receivables                               $   611       $   526   $   680       $   680

                  Long-term debt                                        9,971         9,824     9,664         9,496
                  Interest rate swaps                                      --           (73)       --            (9)
</TABLE>

                                                                              61

<PAGE>


          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                Carrying
            (in millions)                                        Amount   Fair Value     Amount    Fair Value
<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

          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.

                                                                              62

<PAGE>


          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:

<TABLE>
<CAPTION>
             (in millions)                                          2000          1999      1998
             <S>                                                  <C>           <C>       <C>
             Revenue                                              $   873       $ 1,753   $ 2,064
             Operating expenses                                       869         3,058     2,115
                                                                  -------       -------   -------

             Operating income (loss)                                    4        (1,305)      (51)
             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)
                                                                  =======       =======   =======
</TABLE>

          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

                                                                              63

<PAGE>


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 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

                                                                              64

<PAGE>


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 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

                                                                              65

<PAGE>

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.

          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

                                                                              66

<PAGE>

          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.

          Long-term debt at December 31, 2000, and 1999, consisted of the
following:

<TABLE>
<CAPTION>
                                                                                                     Balance at
                                                                                                    December 31,
                                                                                                    ------------
(in millions)                                                                                    2000         1999
                                                                                             (As revised, see Note 17)
<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, 2009-2022                                                      921          219
                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                                                        2,225        2,001
Current portion of long-term debt                                                                    17           93
                                                                                               --------     --------

Total National Energy Group long-term debt, net of current portion                             $  2,208     $  1,908
                                                                                               --------     --------

Total long-term debt                                                                           $  5,550     $  6,785
                                                                                               ========     ========
</TABLE>

                                                                              67

<PAGE>


PG&E Corporation

Utility

          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.

                                                                              68

<PAGE>

     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

     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 occurred 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

                                                                              69

<PAGE>

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.

     During 2000 and 1999, two indirect wholly owned subsidiaries of the NEG
entered into two commitments relating to the acquisition of turbine equipment
and two commitments relating to generation projects that are under construction,
for which they act as the construction agent for the owners. Upon completion of
the construction projects, expected to be in 2001 and 2002, the NEG will lease
these facilities under lease terms of five years and three years, respectively.
At the conclusion of each of the 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. In addition, the NEG entered into
operative agreements with a special purpose entity that will own and finance
construction of another 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 PG&E Corporation's
equity support commitments with substitute commitments of NEG. The trusts
associated with these projects are included in the accompanying financial
statements. As of December 31, 2000, and 1999, project costs subject to these
agreements totaled $837 million and $117 million, respectively, financing for
these projects totaled $814 million and $103 million as of December 31, 2001 and
2000, respectively.

     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
(dollars in millions)                              2001   2002     2003   2004      2005      Thereafter   Total
<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    $189     $  170      $  553     $1,606
               Fixed rate obligations             $  1    $ 34     $  7    $  1     $  251      $  325     $  619

               Average interest rate               6.8%    4.3%     6.1%    7.3%       7.5%        7.9%       7.0%
</TABLE>

                                                                              70

<PAGE>

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
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
                                        -----------------     -----------------
                                    Revolving               Revolving
Lines of Credit                       Credit   Outstanding   Credit    Outstanding
(in millions)                         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:
</TABLE>

                                                                              71



<PAGE>

<TABLE>
<S>                                                 <C>      <C>        <C>        <C>
                  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
              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
                                                             ======               ======
</TABLE>

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

                                                                              72

<PAGE>

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).

     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:

                                                              For the year ended
                                                                 December 31,
                                                                 ------------
          (in millions)                         Maturity Date    2000    1999

          U.S. government and agency issues      2001-2030       $409    $380
          Equity securities                                       239     223
          Municipal bonds and other              2001-2034        252     201

                                                                              73

<PAGE>

     Gross unrealized holding gains            447        474
                                               (19)       (14)
                                            ------     ------
     Fair value                             $1,328     $1,264
                                            ======     ======


     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 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
                                                         ----------------           --------------
        (in millions)                                   2000         1999          2000       1999
        <S>                                         <C>          <C>             <C>        <C>
        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)          --            --         --
</TABLE>

                                                                              74

<PAGE>

<TABLE>
         <S>                                              <C>          <C>         <C>        <C>
         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.

     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,
                                                               -----------                  -----------
     (in millions)                                        2000       1999      1998    2000      1999    1998
     <S>                                                <C>         <C>       <C>      <C>       <C>     <C>
     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.

                                                                              75

<PAGE>

     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>

     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:

                                            1-Percentage          1-Percentage
(in millions)                              Point Increase        Point Decrease

Effect on total service and interest cost
components                                     $ 5                   $ (4)
Effect on postretirement benefit
obligation                                     $45                   $(42)

     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,

                                                                              76

<PAGE>

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:

                                                         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

     The following table summarizes the Program's activity as of and for the
years ended December 31:

<TABLE>
<CAPTION>
                                    2000              1999                 1998
                                    ----              ----                 ----
                                         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.

                                                                              77

<PAGE>


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,
                                                  -----------------------             -----------------------
            (in millions)                         2000        1999       1998         2000         1999       1998
<S>                                          <C>          <C>         <C>        <C>          <C>         <C>
            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,
                                                                  ------------            ------------

                                                                   2000        1999       2000         1999
                                                                                (in millions)
<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>

                                                                              78

<PAGE>


          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 $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.

                                                                              79

<PAGE>

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
                 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

                                                                              80

<PAGE>

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

     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
                                               ======

                                                                              81

<PAGE>

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
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

                                                                              82

<PAGE>

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
                                               ======

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.

     The approximate obligations under these operating lease agreements as of
December 31, 2000 were as follows:

          (in millions)

                                                                              83

<PAGE>

          2001                                 $   72

          2002                                     72

          2003                                     69

          2004                                     79


          2005                                     79
          Thereafter                              965
                                               ------

          Total                                $1,336
                                               ======


     Operating lease expense amounted to $58 million, $67 million, and $35
million in 2000, 1999, and 1998, respectively.

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

                                                                              84

<PAGE>

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
                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

                                                                              85

<PAGE>

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 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.

                                                                              86

<PAGE>

         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.

         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, 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).

                                                                              87

<PAGE>

         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 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:

                                                                              88

<PAGE>



                                                     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 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.

                                                                              89

<PAGE>

         Segment information for the years 2000, 1999, and 1998 was as follows:


                           National Energy Group/(4)/
                            -------------------------
                                     PG&E GT
                                     -------
<TABLE>
<CAPTION>
                                                                                                       Eliminations &
(in millions)                 Utility         PG&E Gen/(4)/    Northwest      Texas/(4)/   PG&E ET     Other/(5)/        Total
<S>                           <C>             <C>              <C>            <C>          <C>         <C>
2000

Operating revenues           $  9,623           $  1,189       $    188       $    817   $  14,414        $    (11)    $ 26,220
Intersegment revenues/(1)/         14                 10             51             56       1,640          (1,771)          --
                             --------           --------       --------       --------    --------        --------     --------

Total operating revenues        9,637              1,199            239            873      16,054          (1,782)      26,220
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              1,083             15             --           3              --        2,346
Total assets at
year-end/(5)(6)/             $ 21,988           $  5,429       $  1,204       $     --   $   7,098        $    433     $ 36,152
1999

Operating revenues           $  9,084           $  1,115       $    172       $  1,034   $   9,404        $     10     $ 20,819
Intersegment revenues/(1)/        144                  6             52            114       1,117          (1,433)          --
                             --------           --------       --------       --------    --------        --------     --------

Total operating revenues        9,228              1,121            224          1,148      10,521          (1,423)      20,819
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                440             30             19          14              17        1,701
Total assets at
year-end/(5)(6)/             $ 21,470           $  3,970       $  1,160       $  1,217   $   1,876        $   (105)    $ 29,588
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>


(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.

                                                                              90

<PAGE>

(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.

Note 17:  Revision Footnote

Subsequent to the issuance of PG&E Corporation's 2000 and 1999 consolidated
financial statements, management determined that the assets and liabilities
relating to certain leases should have been consolidated. The facilities
associated with the leases were under construction during 2000 and 1999. A
summary of the significant effects of the revisions to the Statements of
Consolidated Operations, Consolidated Balance Sheets and Consolidated Statements
of Cash Flows is as follows (in millions):

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
Year ended December 31,                          2000                    1999
------------------------------------------------------------------------------------
Statements of Consolidated                  As                    As
Operations                              Previously    As      Previously      As
                                         Reported   Revised    Reported     Revised
------------------------------------------------------------------------------------
<S>                                     <C>         <C>       <C>           <C>
Operating revenues                       $26,232    $26,220    $20,820      $20,819
------------------------------------------------------------------------------------
Operating expenses                        31,039     31,027     19,942       19,941
------------------------------------------------------------------------------------
------------------------------------------------------------------------------------
Consolidated Balance Sheets
------------------------------------------------------------------------------------
Cash and cash equivalents                $   899    $   925    $   281      $   282
------------------------------------------------------------------------------------
Trade accounts receivable (net of          2,131      2,129      1,486        1,486
$71M and $65M)
------------------------------------------------------------------------------------
Property, plant and equipment (net of
accumulated depreciation)                 16,591     17,296     16,776       16,893
------------------------------------------------------------------------------------
Other non-current assets                   2,398      2,530      2,570        2,570
------------------------------------------------------------------------------------
Total assets                              35,291     36,152     29,470       29,588
------------------------------------------------------------------------------------
------------------------------------------------------------------------------------
Accounts payable- Trade Creditors          3,760      3,800        708          722
------------------------------------------------------------------------------------
Other current liabilities                  1,563      1,570      1,058        1,059
------------------------------------------------------------------------------------
Total current liabilities                 17,284     17,331      6,070        6,085
------------------------------------------------------------------------------------
Long-term debt                             4,736      5,550      6,682        6,785
------------------------------------------------------------------------------------
Total non-current liabilities             14,055     14,869     15,734       15,837
------------------------------------------------------------------------------------
------------------------------------------------------------------------------------
Statements of Consolidated Cash
Flows
------------------------------------------------------------------------------------
Capital expenditures                     $(1,758)   $(2,346)   $(1,584)     $(1,701)
------------------------------------------------------------------------------------
Long-term debt issued                      1,023      1,734          -          103
------------------------------------------------------------------------------------
Other-net, from investing activities         373        241        453          453
------------------------------------------------------------------------------------
------------------------------------------------------------------------------------
Footnote 14
------------------------------------------------------------------------------------
Operating lease commitments
(total 5 years)                            1,637      1,336        N/A          N/A
------------------------------------------------------------------------------------
------------------------------------------------------------------------------------
</TABLE>

                                                                              91

<PAGE>

                QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>
Quarter ended
(in millions, except per share amounts)                                    December 31       September 30      June 30     March 31

<S>                                                                        <C>               <C>               <C>         <C>
2000
PG&E Corporation

Operating revenues                                                             $ 8,079              $7,502       $5,637       $5,002
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                                                             $ 4,794              $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

                                                                              92

<PAGE>

         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.

                                                                              93

<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.

         As discussed in Note 17 of the Notes to the Consolidated Financial
Statements, PG&E Corporation has revised its 1999 and 2000 financial statements
to consolidate the assets and liabilities of certain leased facilities.

DELOITTE & TOUCHE LLP
San Francisco, California
April 6, 2001, February 26, 2002 as to Note 17

                                                                              94

<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.

                                                                              95





</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23.1
<SEQUENCE>4
<FILENAME>dex231.txt
<DESCRIPTION>INDEPENDENT AUDITORS' CONSENT, DELOITTE AND TOUCHE
<TEXT>
<PAGE>

                                                                    EXHIBIT 23.1

                     [LETTERHEARD OF DELOITTE & TOUCHE LLP]



                          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,
February 26, 2002 as to Note 17 (which express an unqualified opinion and
include explanatory paragraphs relating to items discussed in Notes 2, 3, and 17
of the notes to the consolidated financial statements), appearing in and
incorporated by reference in this Annual Report on Form 10-K/A of PG&E
Corporation and Pacific Gas and Electric Company for the year ended December 31,
2000.

DELOITTE & TOUCHE LLP

San Francisco, California
March 5, 2002

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23.2
<SEQUENCE>5
<FILENAME>dex232.txt
<DESCRIPTION>CONSENT OF ARTHUR ANDERSEN LLP
<TEXT>
<PAGE>

                                                                    EXHIBIT 23.2

                       [LETTERHEAD OF ARTHUR ANDERSEN LLP]


                    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/A,
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).

It should be noted that we have not audited any financial statements of the
Company subsequent to December 31, 1998 or performed any audit procedures
subsequent to the date of our report.

ARTHUR ANDERSEN LLP


San Francisco, California
March 4, 2002

</TEXT>
</DOCUMENT>
</SUBMISSION>
