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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One) 
(Mark One)
ý
þ

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 20032004

Or
or

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                                     to

Commission
File Number
CommissionExact Name of RegistrantState ofIRS Employer
File Number
as specified in its charter
State of
Incorporation
IncorporationIRS Employer
Identification Number
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)

Pacific Gas and Electric Company
77 Beale Street
P.O. Box 770000
San Francisco, California
(Address of principal executive offices)
94177
(Zip Code)
(415) 973-7000
(Registrant's telephone number, including area code)		PG&E Corporation
One Market, Spear Tower
Suite 2400
San Francisco, California
(Address of principal executive offices)
94105
(Zip Code)
(415) 267-7000
(Registrant's telephone number, including area code)


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

Title of Each Class
Name of Each Exchange on Which Registered
PG&E Corporation

Common Stock, no par value
Preferred Stock Purchase Rights		 New York Stock Exchange and Pacific Exchange
Pacific Gas and Electric Company
First Preferred Stock, cumulative, par value $25 per share:		 American Stock Exchange and 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% American Stock Exchange and Pacific Exchange
7.90% Deferrable Interest Subordinated DebenturesAmerican Stock Exchange and Pacific Exchange


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 þý    No o

        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’sregistrant'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:

PG&E Corporationo

Pacific Gas and Electric Companyþý

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).:

PG&E Corporation YesþýNoo
Pacific Gas and Electric Company Yeso    NoNo þý

        Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2003,2004, the last business day of the second fiscal quarter:

PG&E Corporation Common Stock $8,16411,183 million
Pacific Gas and Electric Company Common Stock Wholly owned by PG&E Corporation

Common Stock outstanding as of February 17, 2004:

Common Stock outstanding as of February 11, 2005:  
PG&E Corporation: 418,976,121396,487,454 (excluding shares held by a wholly owned subsidiary)
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.

Designated portions of the combined Annual Report to Shareholders for the year ended December 31, 20032004 Part I (Item 1), Part II (Items 5, 6, 7, 7A, 8 and 8)9A), Part IV (Item 15)

TABLE OF CONTENTS

Designated portions of the Joint Proxy Statement relating to the 2005 Part III (Items 10, 11, 12, 13 and 14)
Annual Meetings of Shareholders  


TABLE OF CONTENTS



Page
  Units of Measurement iii

PART I
Item 1. Business 1
  Corporate Structure and Business 1
  The Utility 1
  NEGT NEGT12
  Corporate and Other Information 2
  Employees 2
  Forward-Looking Statements and Risk FactorsThe Utility’s3
Appeals of the Utility's Plan of Reorganization and Settlement Agreement 23
  Refinancing Supported by a Dedicated Rate ComponentOperating Environment 3
  Legislative and Regulatory Environment and Pending LitigationForward Looking Statements and Risk Factors4
  4Competition 4
  Electric Utility Operations 65
  Electricity Distribution Operations Electricity Distribution Operations65
  Electricity Resources Electricity Resources87
  Owned Generation Facilities Electricity Transmission7
  12DWR Power Purchases 9
 Third Party Power Purchase Agreements10
Other Power Purchase Agreements11
Electricity Transmission12
  Natural Gas Utility Operations 13
 13Natural Gas Operating Statistics 15
Natural Gas Supplies16
Gas Gathering Facilities16
Interstate and Canadian Natural Gas Transportation Services Agreements16
Competition17
The Electric Industry18
The Natural Gas Industry19
PG&E Corporation's Regulatory Environment20
Federal Energy Regulation20
State Energy Regulation21
The Utility's Regulatory Environment22
Federal Energy Regulation23
State Energy Regulation25
Other Regulation26
Ratemaking Mechanisms27
Overview27
DWR Electricity and DWR Revenue Requirements28
Procurement Resumption and Procurement Plans29
Electricity Transmission31
Natural Gas32
Environmental Matters34
General34
Air Quality35
Water Quality35
Endangered Species37
    Natural Gas Supplies

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  16Hazardous Waste Compliance and Remediation 37
  Nuclear Fuel Disposal Gas Gathering Facilities1639
  Nuclear Decommissioning Interstate and Canadian Natural Gas Transportation Services Agreements1641
  Competition17
The Electric Industry18
The Natural Gas Industry19
PG&E Corporation’s Regulatory Environment20
Federal Energy Regulation20
State Energy Regulation20
The Utility’s Regulatory Environment22
Federal Energy Regulation22
State Energy Regulation24
Other Regulation25
Ratemaking Mechanisms25
Overview25
DWR Electricity and DWR Revenue Requirements27
DWR Allocated Contracts28
Procurement Resumption and Procurement Plans28
Electricity Transmission29
Natural Gas31
Environmental Matters32
General32
Air Quality33
Water Quality34
Endangered Species35
Hazardous Waste Compliance and Remediation35
Nuclear Fuel Disposal37
Nuclear Decommissioning38
Electric and Magnetic Fields 3942
Item 2. Properties 40

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Page
43
Item 3. Legal Proceedings 4043
  Pacific Gas and Electric Company Chapter 11 Filing 4143
  Chapter 11 Filing of NEGT43
Pacific Gas and Electric Company vs. Michael Peevey, et al. 4345
  In. re: Natural Gas Royalties Qui Tam LitigationDiablo Canyon Power Plant 4446
  Diablo Canyon Power Plant44
Complaints Filed by the California Attorney General, City and County of San Francisco and Cynthia Behr 4546
  Compressor Station Chromium Litigation 4748
Item 4. Submission of Matters to a Vote of Security Holders 4849
  Executive Officers of the Registrants 4849

PART II
Item 5. Market for the Registrant’sRegistrant's Common Equity, Related Stockholder Matters and Related Shareholder MattersIssuer Purchases of Equity Securities 5152
Item 6. Selected Financial Data 5154
Item 7. Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations 5154
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 5254
Item 8. Financial Statements and Supplementary Data 5254
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 5254
Item 9A. Controls and Procedures 54
52Item 9B Other Information55
Nomination for Election as Directors55
Amendment of Bylaws55
Approval of Performance Scale under 2005 Short Term Incentive Plan56

PART III
Item 10. Directors and Executive Officers of the Registrant 5256
Directors52
Executive Officers54
Section 16 Beneficial Ownership Reporting Compliance54
Audit Committee Members and Financial Expert54
  Website Availability of Corporate Governance and Other Documents 5456
Item 11. Executive Compensation 55
Compensation of Directors55
Summary Compensation Table56
Option/SAR Grants in 200359
Aggregated Option/SAR Exercises in 2003 and Year-End Option/SAR Values60
Long Term Incentive Program-Awards in 200360
Retirement Benefits61
Termination of Employment and Change in Control Provisions6157
Item 12. Security Ownership of Certain Beneficial Owners and Management 6257
Security Ownership of Management62
Principal Shareholders64
  Equity Compensation Plan Information 6557
Item 13. Certain Relationships and Related Transactions 6557
Item 14. Principal Accountant Fees and Services 6558
Fees Paid to Independent Public Accountants65
Pre-Approval of Services Provided by the Independent Public Accountant66

PART IV
Item 15. Exhibits and Financial Statement Schedules and Reports on Form 8-K 6758
  Signatures 7665
  Report of Independent Auditors’ ReportRegistered Public Accounting Firm 7766
  Financial Statement Schedules 7867

ii


UNITS OF MEASUREMENT

UNITS OF MEASUREMENT
1 Kilowatt (kW) = One thousand watts
1 Kilowatt-Hour (kWh) = One kilowatt continuously for one hour
1 Megawatt (MW) = One thousand kilowatts
1 Megawatt-Hour (MWh) = One megawatt continuously for one hour
1 Gigawatt (GW) = One million kilowatts
1 Gigawatt Hour (GWh) = One gigawatt continuously for one hour
1 Kilovolt (kV) = One thousand volts
1 MVA = One megavolt ampere
1 Mcf = One thousand cubic feet
1 MMcf = One million cubic feet
1Bcf = One billion cubic feet
1MDth = One thousand decatherms

iii


PART I

Item 1.    Business.

GENERAL

Corporate Structure and Business

        PG&E Corporation, incorporated in California in 1995, is an energy-based holding company that conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas distribution, electricity generation, electricityprocurement and transmission, and natural gas procurement, transportation and storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. During 2004, PG&E Corporation also currently ownsowned National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., which engagesengaged in electricity generation and natural gas transportation in the United States, or U.S.


    The Utility

        The Utility served approximately 4.9 million electricity distribution customers and approximately 3.94.1 million natural gas distribution customers at December 31, 2003.2004. The Utility had approximately $29.1$34.3 billion of assets at December 31, 2003,2004, and generated revenues of approximately $10.4$11.1 billion in 2003.2004. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.

        On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California. The factors that causedIn March 2004, in anticipation of its exit from Chapter 11, the Utility issued $6.7 billion of first mortgage bonds, or First Mortgage Bonds, and, together with its consolidated subsidiaries, entered into $2.9 billion of credit facilities. On April 12, 2004, the Utility's plan of reorganization under Chapter 11 became effective. On this date, the effective date, the Utility emerged from Chapter 11. On the effective date, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon their resolution, reinstated certain obligations, and paid other obligations.

        The Utility's plan of reorganization incorporated the terms of the settlement agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to takeresolve the Utility's Chapter 11 proceeding, or Settlement Agreement. The parties agreed that the bankruptcy court has jurisdiction over the parties for all purposes relating to enforcement of the Settlement Agreement over its nine-year term, the plan of reorganization, and the bankruptcy court's December 22, 2003 order confirming the plan of reorganization, or confirmation order. Although the Utility's operations are no longer subject to the oversight of the bankruptcy court, the bankruptcy court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the plan of reorganization, and (3) the confirmation order. In addition, the bankruptcy court retains jurisdiction to resolve remaining disputed claims.

        As discussed further below under Item 3. Legal Proceedings, appeals of the confirmation order and petitions seeking review of the CPUC's approval of the Settlement Agreement remain pending. Under applicable federal precedent, once the plan of reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed. If, notwithstanding this actionfederal precedent, the bankruptcy court's confirmation order or the Settlement Agreement is



subsequently overturned or modified, PG&E Corporation and the Utility's financial condition and results of operations could be materially adversely affected.

        The Utility's plan of reorganization and the Settlement Agreement are discussed in Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations, or the MD&A, and in Note 2 of the Notes to the Consolidated Financial Statements in PG&E Corporation’sCorporation's and the Utility’sUtility's Combined 20032004 Annual Report to Shareholders, or the Annual Report, which is incorporated by reference into this report. The Utility has retained control of its assets and is authorized to operate its business as a debtor-in-possession during its Chapter 11 proceeding.

    On December 19, 2003, the CPUC, PG&E Corporation and the Utility entered into a settlement agreement, or the Settlement Agreement, that contemplated a plan of reorganization, or the Plan of Reorganization, which fully incorporates the Settlement Agreement. The Plan of Reorganization provides that the Utility will pay allowed creditor claims in full, plus applicable interest, and emerge from Chapter 11 as an investment grade entity. On December 22, 2003, the bankruptcy court confirmed the Plan of Reorganization. The Settlement Agreement and Plan of Reorganization are discussed further below, in the MD&A and in Note 2 of the Notes to the Consolidated Financial Statements in the Annual Report.

    NEGT

        NEGT was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. NEGT’s subsidiaries include: Gas Transmission Northwest Corporation (formerly PG&E Gas Transmission Northwest Corporation), North Baja Pipeline, LLC, National Energy Power Company, LLC (formerly PG&E Generating Power Group, LLC) and its subsidiaries, USGen New England, Inc. and its affiliates, and National Energy & Gas Transmission Trading Holdings Corporation and its subsidiaries.

On July 8, 2003, NEGT and certain of its subsidiaries filed a voluntary petitionpetitions for relief under the provisions of Chapter 11 in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. OnFor the same day, each of the following indirect wholly owned subsidiaries of NEGT filed a voluntary petition for relief under Chapter 11: PG&E Energy Trading Holdings Corporation (now NEGT Energy Trading Holdings Corporation), PG&E Energy Trading-Power, L.P. (now NEGT Energy Trading — Power, L.P.), PG&E Energy Trading — Gas Corpora-

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tion (now NEGT Energy Trading — Gas Corporation), and PG&E ET Investments Corporation (now NEGT ET Investments Corporation) and, separately, USGen New England, Inc. On July 29, 2003, two other subsidiaries, Quantum Ventures and PG&E Energy Services Ventures, Inc. (now Energy Services Ventures, Inc.), each filed voluntary Chapter 11 petitions.

     The factors that caused NEGT and its subsidiaries to take this action are discussed in the MD&A andreasons described in Note 5, PG&E Corporation considers NEGT to be an abandoned asset under Statement of Financial Accounting Standards, or SFAS, "Accounting for Impairment or Disposal of Long-Lived Assets," or SFAS No. 144, and, as a result, the Notesoperations of NEGT prior to July 8, 2003 and for all prior periods, are reflected as discontinued operations in the Consolidated Financial StatementsStatements. In addition, as discussed in the Annual Report. Pursuant to Chapter 11, NEGT and its subsidiaries that filed Chapter 11 petitions retain control of their assets and are authorized to operate their businesses as debtors-in-possession while they are subject to the jurisdiction of the bankruptcy court.

NEGT’s proposed plan of reorganization, if implemented, would eliminate PG&E Corporation’s equity interest in NEGT and its subsidiaries. In anticipation of NEGT’s Chapter 11 filing, PG&E Corporation’s representatives, who previously served as directors of NEGT resigned onNote 4, effective July 7,8, 2003, and were replaced with directors who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retains significant influence over NEGT. Accordingly, effective July 8, 2003, NEGT’s resultsconsolidated the earnings and losses of operations no longer are consolidated with those of PG&E Corporation. NEGT’s results of operations through July 7, 2003,NEGT or its subsidiaries and for prior years have been reclassified as discontinued operations and PG&E Corporation now accountsbegan accounting for its investmentownership interest in NEGT using the cost method, under which PG&E Corporation's investment in NEGT is reflected as a single amount on the Condensed Consolidated Balance Sheet of accounting.PG&E Corporation. On October 29, 2004, NEGT's plan of reorganization became effective and NEGT emerged from Chapter 11, at which time PG&E Corporation's equity interest in NEGT was cancelled. For a discussion of the effect of the cancellation of PG&E Corporation's equity ownership in NEGT on PG&E Corporation's earnings from discontinued operations for the quarter and year ended December 31, 2004, see MD&A.


    Corporate and Other Information

The principal executive office of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive office of the Utility is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. PG&E Corporation and the Utility file various reports with the Securities and Exchange Commission, or the SEC. These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available free of charge on both PG&E Corporation’sCorporation's website,www.pge-corp.com, and the Utility’sUtility's website,www.pge.com. The information contained on these websites is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report.


Employees

        At December 31, 2003,2004, PG&E Corporation and its subsidiaries and affiliates (excluding NEGT) had approximately 20,60020,200 employees, including approximately 20,30020,000 employees of the Utility. Of the Utility’sUtility's employees, approximately 13,50013,700 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO, or IBEW; the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC, or ESC; and the Service Employees International Union, of Security Officers/ SEIU, Local 24/7, or SEIU. The ESC and IBEW collective bargaining agreements expire on December 31, 2007. The SEIU collective bargaining agreement expires on February 28, 2008.




The Utility’s Plan of Reorganization and Settlement Agreement

     The Plan of Reorganization provides that the Utility will pay all allowed creditor claims in full (except for the claims of holders of certain pollution control-related bond obligations that will be reinstated) from the proceeds of a public offering of long-term debt, cash on hand, and draws on revolving credit facilities. At December 31, 2003, allowed claims in the Utility’s Chapter 11 proceeding amounted to approximately $12.3 billion.

     The Settlement Agreement permits the Utility to emerge from Chapter 11 as an investment grade entity by generally ensuring that the Utility will have the opportunity to collect in rates reasonable costs of providing its utility service. The Settlement Agreement provides that the Utility’s authorized return on equity will be no less than 11.22% per year and, except for 2004 and 2005, its authorized equity ratio will be no less than 52% until the Utility’s credit rating has increased to a specified level. The Settlement Agreement establishes a

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$2.21 billion after-tax regulatory asset and allows for the recognition of an approximately $800 million after-tax regulatory asset related to generation assets. The Settlement Agreement and related decisions by the CPUC provide that the Utility’s revenue requirement will be collected regardless of sales levels and that the Utility’s rates will be adjusted in a timely manner to accommodate changes in costs that the Utility incurs.

     On January 20, 2004, several parties filed applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the Settlement Agreement. Although the CPUC is not required to act on these applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review. In addition, the two CPUC Commissioners who did not vote to approve the Settlement Agreement and a municipality have appealed the bankruptcy court’s confirmation order in the U.S. District Court for the Northern District of California, or the District Court. On January 5, 2004, the bankruptcy court denied a request to stay the implementation of the Plan of Reorganization until the appeals are resolved. The District Court will set a schedule for briefing and argument of the appeals at a later date. No additional parties may request rehearings or make appeals of the CPUC’s approval of the Settlement Agreement or the bankruptcy court’s confirmation order.

     Implementation of the Plan of Reorganization is subject to various conditions, including the consummation of the public offering of long-term debt, the receipt of investment grade credit ratings and final CPUC approval of the Settlement Agreement. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not subject to any pending appeal or further right of appeal, or approval on behalf of the CPUC that, although subject to a pending appeal or further right of appeal, has been agreed by the Utility and PG&E Corporation to constitute final approval. Thus, the terms of the Plan of Reorganization permit the Utility and PG&E Corporation to cause the Plan of Reorganization to become effective (and permit the Utility to issue the long term debt) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. Until certain conditions or events regarding the effectiveness of the Plan of Reorganization discussed above are resolved further, PG&E Corporation and the Utility cannot conclude that the applicable accounting probability standard needed to record the regulatory assets contemplated by the Settlement Agreement has been met. PG&E Corporation and the Utility believe that the Utility and the long-term debt to be issued will receive investment grade credit ratings. The Utility has targeted April 2004 to complete the sale of the long-term debt, which the Utility expects to be the last condition of the Plan of Reorganization to be satisfied. The Plan of Reorganization provides that the effective date will occur 11 business days after all the conditions have been satisfied or, with respect to all conditions except those relating to investment grade credit ratings, waived by PG&E Corporation and the Utility. There can be no assurance that the Settlement Agreement will not be overturned on rehearing or appeal or that the Plan of Reorganization will become effective.

The Settlement Agreement and Plan of Reorganization are discussed further in the MD&A and in Note 2 of the Notes to the Consolidated Financial Statements in the Annual Report.

Refinancing Supported by a Dedicated Rate Component

     Under the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized pre-tax balance of the $2.21 billion after-tax regulatory asset and related federal, state and franchise taxes, up to a total of $3.0 billion, as expeditiously as practicable after the effective date of the Plan of Reorganization using a securitized financing supported by a dedicated rate component, provided the following conditions are met:

• Authorizing California legislation satisfactory to the CPUC, The Utility Reform Network, or TURN, and the Utility is passed and signed into law allowing securitization of the regulatory asset and associated federal and state income and franchise taxes and providing for the collection in the Utility’s rates of any portion of the associated tax amounts not securitized;
• The CPUC determines that, on a net present value basis, the refinancing would save customers money over the term of the securitized debt compared to the regulatory asset;
• The refinancing will not adversely affect the Utility’s issuer or debt credit ratings; and

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• The Utility obtains, or decides it does not need, a private letter ruling from the Internal Revenue Service, or IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event.

     The Utility would be permitted to complete the refinancing in up to two tranches up to one year apart, and would issue sufficient callable debt or debt with earlier maturities as part of the Plan of Reorganization to accommodate the refinancing supported by a dedicated rate component. Upon refinancing with securitization, the equity and debt components of the Utility’s rate of return on the regulatory asset would be eliminated. Instead the utility would collect from customers amounts sufficient to service the securitized debt. The Utility would use the securitization proceeds to rebalance its capital structure in order to maintain the capital structure provided for under the Settlement Agreement.

Forward-Looking Statements and Risk Factors

        This combined Annual Report on Form 10-K, including the portions of the Annual Report incorporated by reference, contains forward-looking statements that are necessarily subject to various risks and uncertainties.uncertainties the realization or resolution of which are outside of management's control. These statements are based on current expectations and projections about future events, and assumptions which management believes are reasonableregarding these events and onmanagement's knowledge of facts at the information currently available to management.time the statements were made. These forward-looking statements are identified by words such as “estimates,” “expects,” “anticipates,” “plans,” “believes,” “could,” “should,” “would,” “may”"assume," "expect," "intend," "plan," "project," "believe," "estimate," "predict," "anticipate," "may," "might," "will," "should," "would," "could," "goal," "potential" 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, or from historical results, include:

Whether and on What Terms
Appeals of the Utility's Plan of Reorganization is Implementedand Settlement Agreement

    •
    The timing and resolution of the petitions for review that were filed in the California Court of Appeal for the first Appellate District, or the California Court of Appeal, seeking review of the CPUC's approval of the Settlement Agreement; and

    •
    The timing and resolution of the pending appeals of the confirmation order.

• The timing and resolution of the pending applications for rehearing of the CPUC’s approval of the Settlement Agreement and any appeals that may be filed with respect to the disposition of the rehearing applications;
• The timing and resolution of the pending appeals of the bankruptcy court’s confirmation of the Plan of Reorganization;
• Whether the investment grade credit ratings and other conditions required to implement the Plan of Reorganization are obtained or satisfied; and
• Future equity and debt market conditions, future interest rates, and other factors that may affect the Utility’s ability to implement the Plan of Reorganization or affect the amounts and terms of the debt proposed to be issued under the Plan of Reorganization.


Operating Environment

    •
    Unanticipated changes in operating expenses or capital expenditures, which may affect the Utility's ability to earn its authorized rate of return;

    •
    The level and volatility of wholesale electricity and natural gas prices and supplies, the Utility's ability to manage and respond to the levels and volatility successfully and the extent to which the Utility is able to timely recover increased costs related to such volatility;

    •
    Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns and other events or hazards that affect demand, result in power outages, reduce generating output, or cause damage to the Utility's assets or operations or those of third parties on which the Utility relies;

    •
    Unanticipated population growth or decline, changes in market demand and demographic patterns, and general economic and financial market conditions, including unanticipated changes in interest or inflation rates, and the extent to which the Utility is able to timely recover its costs in the face of such events;

    •
    The operation of the Utility's Diablo Canyon nuclear power plant, or Diablo Canyon, which exposes the Utility to potentially significant environmental costs and capital expenditure outlays and, to the extent the Utility is unable to increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close Diablo Canyon and purchase electricity from more expensive sources;

    •
    Actions of credit rating agencies;

    •
    Significant changes in the Utility's relationship with its employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur; and

    •
    Acts of terrorism.

    • Unanticipated changes in operating expenses or capital expenditures;
    • The level and volatility of wholesale electricity and natural gas prices and supplies and the Utility’s ability to manage and respond to the levels and volatility successfully;
    • Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns and other events or hazards that affect demand, result in power outages, reduce generating output, or cause damage to the Utility’s assets or operations or those of third parties on which the Utility relies;
    • Unanticipated population growth or decline, changes in market demand and demographic patterns, and general economic and financial market conditions, including unanticipated changes in interest or inflation rates;

    4

    • The extent to which the Utility’s residual net open position (i.e., the amount of electricity the Utility needs to meet its customers’ electricity demands that is not provided by Utility-owned generation, Utility power purchase contracts, or the electricity provided by the California Department of Water Resources, or DWR, and allocated to the Utility) increases or decreases due to changes in customer and economic growth rates, the periodic expiration or termination of Utility or DWR power purchase contracts, the reallocation of the DWR power purchase contracts, whether various counterparties are able to meet their obligations under their power sale agreements with the Utility or with the DWR; the retirement or other closure of the Utility’s electricity generation facilities, the performance of the Utility’s electricity generation facilities, and other factors;
    • The operation of the Utility’s Diablo Canyon nuclear power plant, which exposes the Utility to potentially significant environmental and capital expenditure outlays, and, to the extent the Utility is unable to increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close its Diablo Canyon power plant and purchase electricity from more expensive sources;
    • Actions of credit rating agencies;
    • Significant changes in the Utility’s relationship with its employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur; and
    • Acts of terrorism.


    Legislative and Regulatory Environment and Pending Litigation

      •
      The impact of current and future ratemaking actions of the CPUC, including the risk of material differences between forecasted costs used to determine rates and actual costs incurred;

      •
      Whether the assumptions and forecasts underlying the Utility's CPUC-approved long-term electricity procurement plan prove to be accurate, the terms and conditions of the generation or procurement commitments the Utility enters into in connection with its plan, and the extent to which the Utility is able to recover the costs it incurs in connection with these commitments, and the extent to which a failure to perform by any of the counterparties to the Utility's electricity purchase contracts or the DWR contracts allocated to the Utility's customers affects the Utility's ability to meet its obligations or to recover its costs;

      •
      Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, the U.S. Congress, the CPUC, the FERC, and the Nuclear Regulatory Commission, or the NRC, with regard to the Utility's allowed rates of return, industry and rate structure, recovery of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities;

      •
      The extent to which the CPUC or the FERC delays or denies recovery of the Utility's costs, including electricity purchase costs, from customers due to a regulatory determination that such costs were not reasonable or prudent or for other reasons resulting in write-offs of regulatory balancing accounts;

      •
      How the CPUC administers the capital structure, stand-alone dividend and first priority conditions of the CPUC's decisions permitting the establishment of holding companies for the California investor-owned electric utilities;

      •
      The terms under which the CPUC authorizes the Utility to issue debt and equity in the future, and in particular the extent to which the conditions adopted by the CPUC, such as those contained in the CPUC's general financing authorization decision issued on October 28, 2004 (under which the Utility is authorized to issue debt and preferred stock in the future within certain amounts and for specific purposes) limit the Utility's ability to issue debt in the future;

      •
      Whether the Utility is in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses;

      •
      Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws, regulations and policies; and

      •
      The outcome of pending litigation.


    Competition

      •
      Increased competition as a result of the takeover by condemnation of the Utility's distribution assets, duplication of the Utility's distribution assets or service by local public utilities, and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and

      •
      The extent to which the Utility's distribution customers switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers, the extent to which cities, counties and others in the Utility's service territory begin directly serving the Utility's customers, and the extent to which the Utility's customers become self-generators, results in stranded generating asset costs and non-recoverable procurement costs.

              For a further discussion of the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation's and the Utility's future results of operations and financial condition, see the section of the Annual Report titled "Risk Factors."

      • The impact of current and future ratemaking actions of the CPUC, including the outcome of the Utility’s 2003 General Rate Case, or the GRC;
      • Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, U.S. Congress, the CPUC, the FERC and the Nuclear Regulatory Commission, or the NRC, with regard to allowed rates of return, industry and rate structure, recovery of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities;
      • The extent to which the CPUC or the FERC delays or denies recovery of the Utility’s costs, including electricity purchase costs from customers due to a regulatory determination that such costs were not reasonable or prudent or for other reasons;
      • How the CPUC administers the capital structure, stand-alone dividend and first priority conditions of the CPUC’s decisions permitting the establishment of holding companies for California investor-owned electric utilities;
      • Whether the Utility is in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses;
      • Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws, regulations, and policies; and
      • The outcome of pending litigation.

      Competition

      • Increased competition as a result of the takeover by condemnation of the Utility’s distribution assets, duplication of the Utility’s distribution assets or services by local public utility districts, self-generation by its customers and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and

      5

      • The extent to which the Utility’s distribution customers switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers and the extent to which cities, counties and others in the Utility’s service territory begin directly serving the Utility’s customers with their own facilities or combine to form community choice aggregators.

      Electric Utility Operations

        Electricity Distribution Operations

        Electricity Distribution Operations

              The Utility’sUtility's electricity distribution network extends throughout all or a part of 46 of California’sCalifornia's 58 counties, comprising most of northern and central California. The Utility’sUtility's network consists of 120,428123,054 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 89 transmission substations and 45 transmission switching48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. There are 609610 distribution substations and 117118 low voltage distribution substations. There are 264290 combined transmission and distribution substations. Combined transmission and distribution substations have both transmission and distribution transformers.

              The Utility’sUtility's distribution network interconnects to the Utility’sUtility's electricity transmission system at 1,0121,118 points. This interconnection between the Utility’sUtility's distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’sUtility's customers. The distribution substations serve as the central hubs of the Utility’sUtility's electricity distribution network and consist of transformers, voltage regulation equipment, protective devices and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or facilities to entities, such as municipal and other utilities, that then resell the electricity.

      20032004 Electricity Deliveries

              The following table shows the percentage of the Utility’sUtility's total 20032004 electricity deliveries represented by each of its major customer classes:

      (80,156 GWhs)

              Total 2004 Electricity Delivered: 82,907 GWhs

      Agricultural and Other Customers 68%
      Industrial Customers 18%
      Residential Customers 3635%
      Commercial Customers 4039%


        6

        Electricity Distribution Operating Statistics

              The following table shows certain of the Utility’sUtility's operating statistics from 19992000 to 20032004 for electricity sold or delivered, including the classification of sales and revenues by type of service.

       
      		 2004
      		 2003
      		 2002
      		 2001
      		 2000
      		 
      Customers (average for the year):                
       Residential  4,366,897  4,286,085  4,171,365  4,165,073  4,071,794 
       Commercial  509,501  493,638  483,946  484,430  471,080 
       Industrial  1,339  1,372  1,249  1,368  1,300 
       Agricultural  80,276  81,378  78,738  81,375  78,439 
       Public street and highway lighting  27,176  26,650  24,119  23,913  23,339 
       Other electric utilities  3  4  5  5  8 
        
      		 
      		 
      		 
      		 
      		 
        Total  4,985,192  4,889,127  4,759,422  4,756,164  4,645,960 
        
      		 
      		 
      		 
      		 
      		 
      Deliveries (in GWh):(1)                
       Residential  29,453  29,024  27,435  26,840  28,753 
       Commercial  32,268  31,889  31,328  30,780  31,761 
       Industrial  14,796  14,653  14,729  16,001  16,899 
       Agricultural  4,300  3,909  4,000  4,093  3,818 
       Public street and highway lighting  2,091  605  674  418  426 
       Other electric utilities  28  76  64  241  266 
        
      		 
      		 
      		 
      		 
      		 
        Subtotal  82,936  80,156  78,230  78,373  81,923 
       DWR  (19,938) (23,554) (21,031) (28,640) — 
        
      		 
      		 
      		 
      		 
      		 
        Total non-DWR electricity  62,998  56,602  57,199  49,733  81,923 
        
      		 
      		 
      		 
      		 
      		 
      Revenues (in millions):                
       Residential $3,718 $3,671 $3,646 $3,396 $3,062 
       Commercial  4,179  4,440  4,588  4,105  3,110 
       Industrial  1,204  1,410  1,449  1,554  1,053 
       Agricultural  491  522  520  525  420 
       Public street and highway lighting  71  69  73  60  43 
       Other electric utilities  22  24  10  39  26 
        
      		 
      		 
      		 
      		 
      		 
        Subtotal  9,685  10,136  10,286  9,679  7,714 
       DWR  (1,933) (2,243) (2,056) (2,173) — 
        Direct access credits  —  (277) (285) (461) (1,055)
       Miscellaneous(2)  (248) (52) 193  244  202 
       Regulatory balancing accounts  363  18  40  37  (7)
        
      		 
      		 
      		 
      		 
      		 
        Total electricity operating revenues $7,867 $7,582 $8,178 $7,326 $6,854 
        
      		 
      		 
      		 
      		 
      		 
      Other Data:                
       Average annual residential usage (kWh)  6,744  6,772  6,577  6,444  7,062 
       Average billed revenues (cents per KWh):                
        Residential  12.62  12.65  13.29  12.65  10.65 
        Commercial  12.95  13.92  14.65  13.34  9.79 
        Industrial  8.14  9.62  9.84  9.71  6.23 
        Agricultural  11.41  13.35  13.00  12.83  11.00 
       Net plant investment per customer $2,790 $2,689 $2,105 $2,018 $1,969 
      (1)
      These amounts include electricity provided to direct access customers who procure their own supplies of electricity.

      (2)
      Miscellaneous revenues in 2003 include a $125 million reduction due to refunds to electricity customers from generation-related revenues in excess of generation-related costs.


                               
        20032002200120001999
        Customers (average for the year):                    
         Residential  4,286,085   4,171,365   4,165,073   4,071,794   4,017,428 
         Commercial  493,638   483,946   484,430   471,080   474,710 
         Industrial  1,372   1,249   1,368   1,300   1,151 
         Agricultural  81,378   78,738   81,375   78,439   85,131 
         Public street and highway lighting  26,650   24,119   23,913   23,339   20,806 
         Other electric utilities  4   5   5   8   12 
           
        		   
        		   
        		   
        		   
        		 
          Total  4,889,127   4,759,422   4,756,164   4,645,960   4,599,238 
           
        		   
        		   
        		   
        		   
        		 
        Deliveries (in GWh):(1)                    
         Residential  29,024   27,435   26,840   28,753   27,739 
         Commercial  31,889   31,328   30,780   31,761   30,426 
         Industrial  14,653   14,729   16,001   16,899   16,722 
         Agricultural  3,909   4,000   4,093 �� 3,818   3,739 
         Public street and highway lighting  605   674   418   426   437 
         Other electric utilities  76   64   241   266   167 
           
        		   
        		   
        		   
        		   
        		 
          Subtotal  80,156   78,230   78,373   81,923   79,230 
         DWR  (23,342)  (21,031)  (28,640)  —   — 
           
        		   
        		   
        		   
        		   
        		 
          Total non-DWR electricity  56,814   57,199   49,733   81,923   79,230 
           
        		   
        		   
        		   
        		   
        		 
        Revenues (in millions):                    
         Residential $3,671  $3,646  $3,396  $3,062  $2,975 
         Commercial  4,440   4,588   4,105   3,110   2,980 
         Industrial  1,410   1,449   1,554   1,053   1,044 
         Agricultural  522   520   525   420   404 
         Public street and highway lighting  69   73   60   43   49 
         Other electric utilities  24   10   39   26   17 
           
        		   
        		   
        		   
        		   
        		 
          Subtotal  10,136   10,286   9,679   7,714   7,469 
         DWR  (2,243)  (2,056)  (2,173)  —   — 
          Direct access credits  (277)  (285)  (461)  (1,055)  (348)
         Miscellaneous(2)  (52)  193   244   202   162 
         Regulatory balancing accounts  18   40   37   (7)  (51)
           
        		   
        		   
        		   
        		   
        		 
          Total electricity operating revenues $7,582  $8,178  $7,326  $6,854  $7,232 
           
        		   
        		   
        		   
        		   
        		 
        Other Data:                    
         Average annual residential usage (kWh)  6,772   6,577   6,444   7,062   6,905 
         Average billed revenues (cents per KWh):                    
          Residential  12.65   13.29   12.65   10.65   10.72 
          Commercial  13.92   14.65   13.34   9.79   9.79 
          Industrial  9.62   9.84   9.71   6.23   6.24 
          Agricultural  13.35   13.00   12.83   11.00   10.81 
         Net plant investment per customer $2,689  $2,105  $2,018  $1,969  $2,388 

        (1) These amounts include electricity provided to direct access customers who procure their own supplies of electricity.
        (2) Miscellaneous revenues in 2003 include a $125 million reduction due to refunds to electricity customers from generation-related revenues in excess of generation-related costs.

        7

        Electricity Resources

              The following table shows the percentage of the Utility’sUtility's total sources of electricity for 20032004 represented by each major electricity resource:

      Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities) 3633%
      DWR 2925%
      Qualifying Facilities/Renewables 23%
      Irrigation Districts 5%
      Other Power Purchases 714%

              The Utility is required to dispatch all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. To the extent the Utility’sUtility's electricity resources are not sufficient to meet the demand of the Utility’sUtility's customers, the Utility purchases the electricity from the wholesale electricity market. At other times, least-cost dispatch requires the Utility to schedule more electricity than is necessary to meet its retail load and to sell this additional electricity on the wholesale electricity market. The Utility typically schedules excess electricity when the expected electricity sales proceeds exceed the variable costs to operate a generation facility or buy electricity on an optional contract.


        Owned Generation Facilities

              At December 31, 2003,2004, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:

      Generation Type
      		 County Location
      		 Number of
      Units
      		 Net Operating
      Capacity (MW)
      Nuclear:      
       Diablo Canyon San Luis Obispo 2 2,174
          
      		 
      Hydroelectric:      
       Conventional 16 counties in northern
      and central California      		 107 2,684
       Helms pumped storage Fresno 3 1,212
          
      		 
        Hydro electric subtotal   110 3,896
      Fossil fuel:      
       Humboldt Bay(1) Humboldt 2 105
       Hunters Point(2) San Francisco 2 215
       Mobile turbines Humboldt 2 30
          
      		 
        Fossil fuel subtotal   6 350
          
      		 
        Total   118 6,420
          
      		 
      (1)
      The Humboldt Bay facilities consist of a retired nuclear generation unit, or Humboldt Bay Unit 3, and two operating fossil fuel-fired plants.

      (2)
      In July 1998, the Utility reached an agreement with the City and County of San Francisco regarding the Utility's Hunters Point fossil fuel-fired plant, which has been designated as a "must run" facility by the California Independent System Operator, or ISO, to support system reliability. The agreement expresses the Utility's intention to retire the plant when it is no longer needed.

                   
      Number ofNet Operating
      Generation TypeCounty LocationUnitsCapacity (MW)
      Nuclear:
      Diablo Canyon      		 San Luis Obispo  2   2,174 
           
      		   
      		 
      Hydroelectric:
      Conventional      		 16 counties in northern and central California  107   2,684 
       Helms pumped storage Fresno  3   1,212 
           
      		   
      		 
        Hydro electric subtotal    110   3,896 
      Fossil fuel:          
       Humboldt Bay(1) Humboldt  2   105 
       Hunters Point(2) San Francisco  2   215 
       Mobile turbines Humboldt  2   30 
           
      		   
      		 
        Fossil fuel subtotal    6   350 
        Total    118   6,420 
           
      		   
      		 

      (1) The Humboldt Bay facilities consist of a retired nuclear generation unit, or Humboldt Bay Unit 3, and two operating fossil fuel-fired plants.
      (2) In July 1998, the Utility reached an agreement with the City and County of San Francisco regarding the Utility’s Hunters Point fossil fuel-fired plant, which has been designated as a “must run” facility by the California Independent System Operator, or ISO, to support system reliability. The agreement expresses the Utility’s intention to retire the plant when it is no longer needed.

      Diablo Canyon Power Plant.The Utility’sUtility's Diablo Canyon power plant consists of two nuclear power reactor units, each capable of generating up to approximately 1,087 MW of electricity. Unit 1 began commercial operation in May 1985 and the operating license for this unit expires in September 2021. Unit 2 began commercial operation in March 1986 and the operating license for this unit expires in April 2025. For the ten-year period ended December 31, 2003,2004, the Utility’sUtility's Diablo Canyon power plant achieved aan average overall capacity factor of approximately 88.5%88.4%.

      8

      The following table outlines the Diablo Canyon power plant’splant's refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 1916 to 21 months. The average length of a refueling outage over the last five years has been approximately 3546 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the replacement of the steam generator replacementsgenerators in Unit 2 in 2008 and 2009in Unit 1 in 2009. The capital expenditures necessary to complete these projects are discussed below.further in the MD&A. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of up to 8045 days to accommodate non-routine tasks, such as expanded steam generator inspection and repair low pressureand low-pressure turbine rotor replacement and the firstreplacement. Outages of two proposedup to 80 days are scheduled for steam generator replacements. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

                            
      20042005200620072008
      Unit 1
      		                    
       Refueling  March   October   —   April   — 
       Duration (days)  48   45   —   35   — 
       Startup  May   November       June     
      Unit 2
      		                    
       Refueling  October       April       February 
       Duration (days)  42   —   42   —   80 
       Startup  December   —   May   —   April 

           During a routine inspection conducted as part of the last refueling of Unit 2 in February 2003, the Utility found indications of steam generator tube cracking in locations and of a size not previously expected. After careful inspection and analysis, Unit 2 was able to safely restart after that outage and the Utility received the approval of the NRC to operate without further steam generator inspection until the next scheduled refueling in the fall of 2004. The Utility, however, is planning to accelerate the replacement of the steam generators in Unit 2 from 2009 to 2008. The Utility plans to replace Unit 1’s steam generators in 2009. The capital expenditures necessary to complete these projects are discussed further in the MD&A.

       
      		 2005
      		 2006
      		 2007
      		 2008
      		 2009
      Unit 1          
       Refueling October — April — January
       Duration (days) 45 — 35 — 80
       Startup December   June   March
      Unit 2          
       Refueling   April   February October
       Duration (days) — 45 — 80 25
       Startup — June — April October

              The Utility has several types of nuclear insurance for its Diablo Canyon power plant and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional annual premiumspremium of up to $36.7 million.$42.5 million per one-year policy term.

              NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts recovered by NEIL for these losses from reinsurance. Under the Terrorism Risk Insurance Act of 2002, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign terrorism. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.

              Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.9$10.8 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for the Diablo Canyon power plant. The balance of the $10.9$10.8 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of nuclear reactors that are licensed to operate, designed for the production of electrical energy, and have a rated capacity of 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $100.6



      $100.6 million per reactor, with payments in each year limited to a maximum of $10 million per incident until the Utility has fully paid its share of the liability. Since the Diablo Canyon power plant has two nuclear reactors each with a rated capacity of over 100 MW, the Utility may be assessed up to

      9

      $201.2 $201.2 million per incident, with payments in each year limited to a maximum of $20 million per incident. Although the Price-Anderson Act expired on December 31, 2003, coverage continues to be provided to all licensees, including the Diablo Canyon power plant, thatwhich had coverage before December 31, 2003. Congress may address renewal of the Price Anderson Act in future energy legislation.

              In addition, the Utility has $53.3 million of liability insurance for the retired nuclear generating unit at the Humboldt Bay Unit 3power plant and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance.

      Hydroelectric Generation Facilities.The Utility’sUtility's hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 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 water rights as specified in 8386 permits andor licenses and 163 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses, all of the Utility’sUtility's powerhouses are licensed by the FERC. Pursuant to the Federal Power Act, the term of a hydroelectric project license issued by the FERC is between 30 and 50 years. In the last threefour years, the Utility has received six renewed hydroelectric project licenses from the FERC.FERC totaling 699 MW. Licenses associated with approximately 928879 MW expire withinnow in relicensing have expired; these projects are being operated on automatically renewed annual licenses pending issuance of renewed licenses. Within the next five years.four years, licenses associated with another 50 MW will expire. Licenses associated with approximately 29592,959 MW expire between 2009 and 2043.

      DWR Power Purchases


        DWR Power Purchases

              In January 2001, because of the deteriorating credit conditions of the California investor-owned electric utilities, the State of California authorized the DWR to purchase electricity to meet the portion of the demand of the utilities’utilities' customers, plus applicable reserve margins, not satisfied from their own generation facilities and existing electricity contracts. California Assembly Bill 1X, or AB 1X, passed in February 2001, authorized the DWR to enter into contracts for the purchase of electricity and to issue revenue bonds to finance electricity purchases. The Utility and the other California investor-owned electric utilities act as the billing and collection agent for the DWR’sDWR's sales of electricity to retail customers.

              On September 19, 2002, the CPUC issued a decision allocating electricity from 19 of the DWR’s contracts, or the DWR allocatedDWR's contracts to the Utility’sUtility's customers. Electricity from DWR allocated contracts represented approximately 29% of the Utility’s total sources of electricity in 2003. In January 2003, the Utility became responsible for scheduling and dispatching the electricity subject to the 19 DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. The contracts terminate at various times through 2012 and consist of must-take and capacity charge contracts. During 2004, a total average capacity of approximately 2,700 MW of the electricity under the DWR allocated contracts is subject to “must take”"must take" provisions that require the DWR to take and pay for the electricity regardless of whether the electricity is needed. A total average capacity for 2004 of approximately 1,200 MW of the electricity under the DWR allocated contracts is subject to provisions that require the DWR to pay a capacity charge, but do not require the purchase of electricity unless that electricity is dispatched and delivered. Electricity from the DWR allocated contracts represented approximately 22% of the Utility's total sources of electricity in 2004.



              The DWR is currently legally and financially responsible for these contracts. The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:

      • After assumption, the Utility’s issuer rating by Moody’s will be no less than A2 and the Utility’s long-term issuer credit rating by Standard & Poor’s will be no less than A;
      • The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and

      10

      • The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

        •
        After assumption, the Utility's issuer rating by Moody's Investors Service, or Moody's, will be no less than A2 and the Utility's long-term issuer credit rating by Standard & Poor's, or S&P, will be no less than A;

        •
        The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and

        •
        The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

              The Settlement Agreement does not limit the CPUC’sCPUC's discretion to review the prudence of the Utility’sUtility's administration and dispatch of the assumed DWR power purchase contracts consistent with applicable law.


        Third Party Power Purchase Agreements
        Qualifying Facility Agreements

        Qualifying Facility Power Purchase Agreements

              The Utility is required by CPUC decisions to purchase energy and capacity from independent power producers that are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA. UnderTo implement PURPA, the CPUC required California investor-owned electric utilities to enter into a series of long-term power purchase agreements with qualifying facilities and approved the applicable terms, conditions, price optionsprices, and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility’sfacility's actual electrical output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility’sfacility's total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the qualifying facility fails to meet or exceeds performance requirements specified in the applicable power purchase agreement.

              As a result of the energy crisis, the Utility owed approximately $1 billion to qualifying facilities when it filed its Chapter 11 proceeding. Through December 31, 2003, the principal payments made to the qualifying facilities amounted to $998 million.

           At December 31, 2003,2004, the Utility had agreements with 300 qualifying facilities for approximately 4,4004,300 megawatts, or MW, that are in operation. Agreements for approximately 4,0003,950 MW expire at various dates between 20042005 and 2028. Qualifying facility power purchase agreements for approximately 400350 MW have no specific expiration dates and will terminate only when the owner of the qualifying facility exercises its termination option. The Utility also has power purchase agreements with approximately 50 inoperative qualifying facilities that are not currently providing or expected to provide electricity.facilities. The total of approximately 4,4004,300 MW consists of approximately 2,600 MW from cogeneration projects, 800700 MW from wind projects and 1,000 MW from projects with other projects,fuel sources, including biomass, waste-to-energy, geothermal, solar and hydroelectric.

              On January 22, 2004, the CPUC adopted a decision that requiresordered the California investor-owned electric utilities to allow owners of qualifying facilities with certain power purchase agreements expiring before the end of 2005 to extend these contracts for five years.years with modified pricing terms. As of December 31, 2004, thirteen qualifying facilities had entered into such five-year contract extensions. Qualifying facility power purchase agreements accounted for approximately 21% of the Utility's 2004 electricity sources, approximately 20% of the Utility’sUtility's 2003 electricity sources, and approximately 25% of the Utility’sUtility's 2002



      electricity sources, and approximately 21% of the Utility’s 2001 electricity resources.sources. No single qualifying facility accounted for more than 5% of the Utility’sUtility's 2004, 2003, 2002 or 20012002 electricity sources.

              In a proceedingThere are proceedings pending at the CPUC that may impact both the Utility has requested refunds in excessamount of $500 million for overpayments from June 2000 through March 2001 madepayments to qualifying facilities. Underfacilities and the Settlement Agreement, the net after-tax amountnumber of any qualifying facilities refunds, whichholding power purchase agreements with the Utility actually realizes in cash, claim offsets or other credits, would reduceUtility. The CPUC will address whether certain payments for short-term power deliveries required by the $2.21 billion after-tax regulatory asset.power purchase agreements comply with the pricing requirements of the PURPA. The CPUC is also considering whether to require the California investor owned electric utilities to enter into new power purchase agreements with existing qualifying facilities with expiring power purchase agreements and with newly-constructed qualifying facilities. PG&E Corporation and the Utility are unable to estimate the outcome of this proceeding.these proceedings.

        Irrigation Districts and Water Agencies

        Irrigation Districts and Water Agencies

              The Utility 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 based on the irrigation districts’districts' and water agencies’agencies' debt service requirements, regardless if any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 20042005 to 2031. The Utility’sUtility's irrigation district and water agency contracts accounted for approximately 4% of 2004 electricity sources, approximately 5% of 2003 electricity sources, and approximately 4% of 2002 electricity sources and approximately 3% of 2001 electricity sources.

        11
        Other Power Purchase Agreements

        Electricity Purchases to Satisfy the Residual Net Open Position

        Other Third Party Power Agreements
        Electricity Purchases to Satisfy the Residual Net Open Position

              On January 1, 2003,In 2004, the Utility resumedcontinued buying electricity to meet its residual net open position. During that year,2004, more than 14,00010,000 Gigawatt hours, or GWh of energy was bought and sold in the wholesale market to manage the 2003Utility's 2004 residual net short/open position. Most of the Utility’sUtility's contracts entered into in 20032004 had terms of less than one year. DuringIn 2004, the Utility plansboth submitted and requested bids in competitive solicitations to enter intomeet intermediate and long-term needs and anticipates procuring electricity under contracts of longer duration to satisfy its near-term residual net open position.with multi-year terms beginning in 2005.

        Renewable Energy Contracts

        Renewable Energy Contracts

              California law requires that, beginning in 2003, each California investor-owned electric utilityretail seller of electricity, except for municipal utilities, must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, the annual procurement target, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. The Utility estimates thewas excused from meeting its annual procurement target under the current law in 2003 and 2004 due to its Chapter 11 proceeding. With its exit from Chapter 11, as of January 1, 2005, the Utility is no longer exempt from complying with its annual procurement target. To meet the 20% goal by the end of 2017, the Utility estimates that it will initially require itneed to purchase about 750700-800 GWh of electricity from renewable resources each year. During 2003 and 2004, the Utility entered into several new renewable power purchase contracts that will help the Utility meet its goals. The Utility met its 2003 commitment and the CPUC has approvedalso is conducting negotiations with several contracts intended to meet its 2004 renewable energy requirement.providers pursuant to a request for offers made by the Utility in July 2004 that should result in the Utility entering into a number of new renewable contracts in 2005. In January 2005, the California Senate introduced a bill proposing to require the goal to be met by the end of 2010 instead of 2017. The CPUC also has suggested that the 20% goal be met by 2010. The Utility estimates that the accelerated goal would require the Utility to increase the amount of its annual renewable energy purchases to approximately 800-900 GWh. Based on the medium load scenario in the Utility's long-term electricity procurement plan, the Utility believes that it can meet the accelerated goal.


        Western Area Power Administration

        Western Area Power Administration

              In 1967, the Utility and the Western Area Power Administration, or WAPA, entered into several long-term power contracts governing the interconnection of the Utility’sUtility's and WAPA’sWAPA's electricity transmission systems, the use of the Utility’sUtility's electricity transmission and distribution system by WAPA, and the integration of the Utility’sUtility's and WAPA’sWAPA's customer demands and electricity resources. The contracts givegave the Utility access to WAPA’sWAPA's excess hydroelectric power and obligateobligated the Utility to provide WAPA with electricity when its own resources arewere not sufficient to meet its requirements. The contracts are scheduled to terminate on December 31, 2004, but termination is subject to FERC approval, whichIn recent years the pricing formula under the contract often resulted in the Utility expects to receive.

           The costs to fulfill the Utility’s obligationsselling power to WAPA underat prices that were below market. On December 3, 2004, the FERC approved termination of the contracts cannot be accurately estimated at this time since bothas of January 1, 2005, and approved the purchase pricenew service contracts that WAPA and the amount of electricity WAPA will need fromUtility executed in October 2004. Under the new contracts, which became effective on January 1, 2005, the Utility in 2004 are uncertain. However, the Utility expects that the cost of meeting its contractual obligationsno longer provides any electric power or transmission services to WAPA will be greater than the price the Utility receives from WAPA under the contracts. Although it is not indicative of future sales commitments or sales-related costs, WAPA’s net amount purchased from the Utility was approximately 4,804 GWh, in 2003, 3,619 GWh in 2002 and 4,823 GWh in 2001.but continues to provide wholesale distribution service.

              For more information regarding the Utility’sUtility's power purchase contracts, see Note 12 of the Notes to the Consolidated Financial Statements of the Annual Report.


      Electricity Transmission

              At December 31, 2003,2004, the Utility owned 18,61218,610 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 42,79846,036 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 120,428123,054 circuit miles of distribution lines and substations with a capacity of 24,21824,877 MVA. In 2003,2004, the Utility delivered 80,15682,936 GWh to its customers, including 8,9799,210 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the Western Electricity Coordinating Council which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

              In connection with electricity industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the ISO, in 1998. The FERC has jurisdiction over these transmission facilities, and the revenue requirements and rates for transmission service are set by the FERC. The ISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The ISO also is responsible for maintaining the reliability of the transmission system.

      12

              The Utility has been working closely with the ISO to continue expanding the capacity on the Utility’sUtility's electric transmission system. In December 2004, construction was completed on a new 500 kV line to expand one segment of the transmission system, known as Path 15, which is located in the southern portion of the Utility's service area, and serves as part of the primary transmission path between northern California and southern California. The improvements are intended to mitigate transmission constraints in this area. The Utility is engagedhas interconnected the new 500 kV line at its existing substations at the line terminals and reconfigured its 230 kV and 115 kV facilities in the following significant expansion projects:area to support a higher transfer capability through this section of the grid. This new 500 kV line became operational in December 2004.

      Path 15 — WAPA and an independent transmission company, Trans-Elect NTD, Inc., are constructing a new 500 kV line to expand one segment of the transmission system, known as Path 15, which is located in the southern portion of the Utility’s service area, and serves as part of the primary transmission path between northern California and southern California. The improvements are intended to mitigate transmission constraints in this area. The Utility will interconnect the new 500 kV line at its existing substations at the line terminals and reconfigure its 230 kV and 115 kV facilities in the area to support a higher transfer capability through this section of the grid. This new 500 kV line is expected to be operational in October 2004.
      Jefferson-Martin — This project entails laying 28 miles of 230 kV underground transmission facilities from Redwood City to Daly City that will provide additional transmission system reliability in San Francisco and northern San Mateo County. This project is expected to be completed in December 2005.
              On August 19, 2004, the CPUC also approved a project to install approximately 28 miles of 230 kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230 kV Line. The improvement is intended to provide additional transmission system reliability in San Francisco and northern San Mateo County. Construction of this project is expected to be completed in early 2006.




      Natural Gas Utility Operations

              The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 38 of California’sCalifornia's 58 counties and includes most of northern and central California. In 2003,2004, the Utility served approximately 3.94.1 million natural gas distribution customers. The total volume of natural gas throughput during 20032004 was approximately 804888 Bcf.

              At December 31, 2003,2004, the Utility’sUtility's natural gas system consisted of 39,51040,123 miles of distribution pipelines, 6,3506,136 miles of transportation pipelines and three storage facilities. The Utility’sUtility's distribution network connects to the Utility’sUtility's transportation and storage system at approximately 2,200 major interconnection points. The Utility’sUtility's Line 400/401 interconnects with the natural gas transportation pipeline of Transcanada's Gas Transmission Northwest Corporation a subsidiary of NEGT, at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.0 Bcf per day. The Utility’sUtility's Line 300, which interconnects with the U.S. southwest and California-Oregon pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity at the California-Arizona border of approximately 1.1 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada and the southwestern United States. The Utility also is supplied by natural gas fields in California.

              The Utility also owns and operates three underground natural gas storage fields located along the Utility’sUtility's transportation and storage system in close proximity to approximately 90% of the Utility’sUtility's end-user demand. These storage fields have a combined annual cycle capacity of approximately 42 Bcf. In addition, two independent storage operators are interconnected to the Utility’sUtility's northern California transportation system.

              Since 1991, the CPUC has divided the Utility’sUtility's natural gas customers into two categories —categories: core and noncore customers. This classification is based largely on a customer’scustomer's annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial and larger commercial natural gas customers. In 2003,2004, core customers represented overmore than 99% of the Utility’sUtility's total customers and 35%32% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility’sUtility's total customers and 65%68% of its total natural gas deliveries.

              The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility’sUtility's system in its service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have the Utility provide both delivery service and natural gas supply. When the Utility provides both supply and delivery, the Utility refers to the service as natural gas bundled service. Currently, over 99% of core customers, representing over 98%97% of core market demand, receive natural gas bundled services from the Utility.

      13

              In accordance with a 1998 ratemaking settlement agreement implemented in 1998 called the Gas Accord, the Utility stopped providing procurement service to noncore customers in March 2001. During the winter of 2000-2001 when there was a steep increase in natural gas prices, many noncore customers switched to core service in order to receive procurement service from the Utility. In December 2003, the CPUC approved the Utility’sUtility's request to prohibit electricity generation, cogeneration, enhanced oil recovery and refinery, and other large noncore customers from electing to transfer to core service, and requiring smaller noncore customers to sign up for a minimum five-year term if they elect to transfer to core service. The Utility made this request because of its concern that large increases in the Utility’sUtility's natural gas supply portfolio demand from significant transfers of noncore customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce it’sits pipeline system to provide core service reliability on a short-term basis to serve this new load.



              The Utility offers transportation, distribution and storage services as separate and distinct services to its noncore customers. These customers may elect to receive storage services from the Utility or competitiveother third party storage providers. Noncore customers interconnected at a transportation level only pay for transportation service, while those interconnected at a distribution level pay for both transportation and distribution service. Noncore customers formerly were able to subscribe for natural gas bundled service as if they were core customers but are no longer allowed to do so. Access to the Utility’sUtility's gas transportation system is available for all natural gas marketers and shippers, as well as noncore customers.

              Customers pay a distribution rate that reflects the Utility’sUtility's costs to serve each customer class. The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility’sUtility's results of operations over the long term are not affected by their consumption levels. The Utility’sUtility's results of operations can, however, be affected by noncore consumption levels because there are no similar regulatory balancing accounts related to noncore customers. Approximately 96% of the Utility’sUtility's natural gas distribution base revenues are recovered from core customers and 4% are recovered from noncore customers.

              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 natural gas utilities. The 20022004 California Gas Report updated the Utility’sUtility's annual natural gas requirements forecast for the years 20022004 through 2023,2025, forecasting average annual growth in the Utility’sUtility's natural gas deliveries of approximately 1.8%1.2%. The natural 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 economic activity, conservation, and the number and location of electricity generation facilities.

        20032004 Natural Gas Deliveries

              The following table shows the percentage of the Utility’sUtility's total 20032004 natural gas deliveries represented by each of the Utility’sUtility's major customer classes:

      (804 Bcf)

              Total 2004 Natural Gas Deliveries: 888 Bcf

      ��
      Residential Customers 2325%%
      Transport only Customers (noncore) 6865%%
      Commercial Customers 910%%


      14


      Natural Gas Operating Statistics

              The following table shows the Utility’sUtility's operating statistics from 19992000 through 20032004 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:

       
      		 2004
      		 2003
      		 2002
      		 2001
      		 2000
      		 
      Customers (average for the year):                
       Residential  3,812,914  3,744,011  3,738,524  3,705,141  3,642,266 
       Commercial  215,547  208,857  206,953  205,681  203,355 
       Industrial  2,178  1,988  1,819  1,764  1,719 
       Other gas utilities  6  6  5  6  6 
        
      		 
      		 
      		 
      		 
      		 
        Total  4,030,645  3,954,862  3,947,301  3,912,592  3,847,346 
        
      		 
      		 
      		 
      		 
      		 
      Gas supply (MMcf):                
       Purchased from suppliers in:                
        Canada  205,180  196,278  210,716  209,630  216,684 
        California  (9,108) (7,421) 19,533  20,352  32,167 
        Other states  103,801  102,941  67,878  76,589  75,834 
        
      		 
      		 
      		 
      		 
      		 
         Total purchased  299,873  291,798  298,127  306,571  324,685 
       Net (to storage) from storage  (532) 1,359  (218) (27,027) 19,420 
        
      		 
      		 
      		 
      		 
      		 
         Total  299,341  293,157  297,909  279,544  344,105 
       Utility use, losses, etc.(1)  (19,287) (14,307) (16,393) (8,988) (62,960)
        
      		 
      		 
      		 
      		 
      		 
         Net gas for sales  280,054  278,850  281,516  270,556  281,145 
        
      		 
      		 
      		 
      		 
      		 
      Bundled gas sales (MMcf):                
       Residential  201,601  198,580  202,141  197,184  210,515 
       Commercial  78,080  79,891  78,812  72,528  66,443 
       Industrial  373  379  563  831  4,146 
       Other gas utilities  —  —  —  13  41 
        
      		 
      		 
      		 
      		 
      		 
         Total  280,054  278,850  281,516  270,556  281,145 
        
      		 
      		 
      		 
      		 
      		 
      Transportation only (MMcf):  597,706  525,353  508,090  646,079  606,152 
      Revenues (in millions):                
       Bundled gas sales:                
        Residential $1,944 $1,836 $1,379 $2,308 $1,681 
        Commercial  712  697  499  783  513 
        Industrial  —  1  3  16  35 
        Other gas utilities  —  1  1  —  — 
       Miscellaneous  (29) (31) 127  (93) 84 
       Regulatory balancing accounts  316  68  11  (253) 132 
        
      		 
      		 
      		 
      		 
      		 
        Bundled gas revenues  2,943  2,572  2,020  2,761  2,445 
       Transportation service only revenue  270  284  316  375  338 
        
      		 
      		 
      		 
      		 
      		 
        Operating revenues $3,213 $2,856 $2,336 $3,136 $2,783 
        
      		 
      		 
      		 
      		 
      		 
      Selected Statistics:                
      Average annual residential usage (Mcf)  53  53  54  53  59 
      Average billed bundled gas sales revenues per Mcf:                
       Residential $9.64 $9.25 $6.82 $11.70 $7.98 
       Commercial  9.12  8.73  6.33  10.80  7.72 
       Industrial  (0.56) 2.48  4.35  19.15  8.53 
      Average billed transportation only revenue per Mcf  0.45  0.54  0.62  0.58  0.56 
       Net plant investment per customer $1,266 $1,261 $1,006 $970 $1,003 
      (1)
      Includes fuel for the Utility's fossil fuel-fired generation plants.


                               
        20032002200120001999
        Customers (average for the year):                    
         Residential  3,744,011   3,738,524   3,705,141   3,642,266   3,593,355 
         Commercial  208,857   206,953   205,681   203,355   203,342 
         Industrial  1,988   1,819   1,764   1,719   1,625 
         Other gas utilities  6   5   6   6   4 
           
        		   
        		   
        		   
        		   
        		 
          Total  3,954,862   3,947,301   3,912,592   3,847,346   3,798,326 
           
        		   
        		   
        		   
        		   
        		 
                                
        20032002200120001999
        Gas supply (MMcf):                    
         Purchased from suppliers in:                    
          Canada  196,278   210,716   209,630   216,684   230,808 
          California  (7,421)  19,533   20,352   32,167   18,956 
          Other states  102,941   67,878   76,589   75,834   107,226 
           
        		   
        		   
        		   
        		   
        		 
           Total purchased  291,798   298,127   306,571   324,685   356,990 
         Net (to storage) from storage  1,359   (218)  (27,027)  19,420   (980)
           
        		   
        		   
        		   
        		   
        		 
           Total  293,157   297,909   279,544   344,105   356,010 
         Utility use, losses, etc.(1)  (14,307)  (16,393)  (8,988)  (62,960)  (47,152)
           
        		   
        		   
        		   
        		   
        		 
           Net gas for sales  278,850   281,516   270,556   281,145   308,858 
           
        		   
        		   
        		   
        		   
        		 
        Bundled gas sales (MMcf):                    
         Residential  198,580   202,141   197,184   210,515   233,482 
         Commercial  79,891   78,812   72,528   66,443   70,093 
         Industrial  379   563   831   4,146   5,255 
         Other gas utilities  —   —   13   41   28 
           
        		   
        		   
        		   
        		   
        		 
           Total  278,850   281,516   270,556   281,145   308,858 
           
        		   
        		   
        		   
        		   
        		 
        Transportation only (MMcf):  525,353   508,090   646,079   606,152   484,218 
        Revenues (in millions):                    
         Bundled gas sales:                    
          Residential $1,836  $1,379  $2,308  $1,681  $1,543 
          Commercial  697   499   783   513   449 
          Industrial  1   3   16   35   24 
          Other gas utilities  1   1   —   —   — 
         Miscellaneous  (31)  127   (93)  84   (47)
         Regulatory balancing accounts  68   11   (253)  132   (260)
           
        		   
        		   
        		   
        		   
        		 
           Bundled gas revenues  2,572   2,020   2,761   2,445   1,709 
         Transportation service only revenue  284   316   375   338   287 
           
        		   
        		   
        		   
        		   
        		 
           Operating revenues $2,856  $2,336  $3,136  $2,783  $1,996 
           
        		   
        		   
        		   
        		   
        		 
        Selected Statistics:                    
        Average annual residential usage (Mcf)  53   54   53   59   65 
        Average billed bundled gas sales revenues
        per Mcf:        		                    
          Residential $9.25  $6.82  $11.70  $7.98  $6.61 
          Commercial  8.73   6.33   10.80   7.72   6.40 
          Industrial  2.48   4.35   19.15   8.53   4.69 
        Average billed transportation only revenue
        per Mcf        		  0.54   0.62   0.58   0.56   0.59 
         Net plant investment per customer $1,261  $1,006  $970  $1,003  $1,011 
        Natural Gas Supplies

        (1) Includes fuel for the Utility’s fossil fuel-fired generation plants.

        15

        Natural Gas Supplies

              The Utility purchases natural gas to serve the Utility’sUtility's core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility’sUtility's portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. During 2003,2004, the Utility purchased approximately 292,000300,000 MMcf of natural gas (net of the sale of excess supply) from 4851 suppliers. Substantially all this natural gas was purchased under contracts with a term of less than one year. The Utility’sUtility's largest individual supplier represented approximately 9.6%10.3% of the total natural gas volume the Utility purchased during 2003.2004.

              The following table shows the total volume and the average price of natural gas in dollars per Mcf of the Utility’sUtility's natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In 2004 and 2003, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

       
      		 2004
      		 2003
      		 2002
      		 2001
      		 2000
       
      		 MMcf
      		 Avg.
      Price
      		 MMcf
      		 Avg.
      Price
      		 MMcf
      		 Avg.
      Price
      		 MMcf
      		 Avg.
      Price
      		 MMcf
      		 Avg.
      Price
      Canada 205,180 $5.37 196,278 $4.73 210,716 $2.42 209,630 $4.43 216,684 $4.05
      California(1) (9,108)$4.89 (7,421)$3.39 19,533 $2.88 20,352 $11.55 32,167 $8.20
      Other states (substantially all U.S southwest) 103,801 $5.44 102,941 $4.63 67,878 $3.04 76,589 $10.41 75,834 $5.99
      Total/weighted average 299,873 $5.41 291,798 $4.73 298,127 $2.59 306,571 $6.40 324,685 $4.92
      (1)
      California purchases include supplies from various California producers and supplies transported into California by others.


                                                 
        20032002200120001999
        Avg.Avg.Avg.Avg.Avg.
        MMcfPriceMMcfPriceMMcfPriceMMcfPriceMMcfPrice
        Canada  196,278  $4.73   210,716  $2.42   209,630  $4.43   216,684  $4.05   230,808  $2.50 
        California(1)  (7,421) $3.39   19,533  $2.88   20,352  $11.55   32,167  $8.20   18,956  $2.45 
        Other states (substantially all U.S southwest)  102,941  $4.63   67,878  $3.04   76,589  $10.41   75,834  $5.99   107,226  $2.42 
        Total/weighted average  291,798  $4.73   298,127  $2.59   306,571  $6.40   324,685  $4.92   356,990  $2.47 
        Gas Gathering Facilities

        (1) California purchases include supplies from various California producers and supplies transported into California by others.

        Gas Gathering Facilities

              The Utility’sUtility's gas gathering system collects and processes natural gas from third-party wells in California. During 2003,2004, approximately 4% of the Utility’s natural gas suppliestransported on the Utility's system came from various California producers, andwith the balance coming from supplies transported into California by others. The natural gas is processed to remove various impurities from the natural gas stream and to odorize the natural gas so that it may be detected in the event of a leak. The facilities include 475440 miles of gas gathering pipelines, as well as dehydration, separation, regulation, odorization and metering equipment located at 6263 stations. The gas gathering system is geographically dispersed and is located in 14 California counties. Approximately 120103 MMcf per day of natural gas flows through the Utility’sUtility's gas gathering system.


        Interstate and Canadian Natural Gas Transportation Services Agreements

              In 2003,2004, approximately 67%68% of the Utility’s natural gas suppliestransported on the Utility's system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers’customers' service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- Canadian border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System. These companies’companies' pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest Corporation which provides natural gas transportation services to interconnection points with the Utility’sUtility's natural gas transportation system in the area of California near Malin, Oregon. The Utility has a firm transportation agreement with Gas Transmission Northwest Corporation for these services.

              During 2003,2004, approximately 29%28% of the Utility’s natural gas suppliestransported on the Utility's system came from the western United States, excluding California. The Utility has firm transportation agreements with



      Transwestern Pipeline Co.,

      16

      or Transwestern, and El Paso Natural Gas Company, or El Paso, to transport this natural gas from supply points in this region to interconnection points with the Utility’sUtility's natural gas transportation system in the area of California near Topock, Arizona.

              The following table shows certain information about the Utility’sUtility's firm natural gas transportation agreements, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System, and the FERC in all other cases. The Utility recovers these demand charges through the CPIM. The Utility may, upon prior notice and with the CPUC approval, extend each of these natural gas transportation agreements for additional minimum terms ranging, depending on the particular agreement, from one to ten years.agreements. On the FERC-regulated pipelines, the Utility has either a right of first refusal or evergreen rights allowing it to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.

      Pipeline
      		 Expiration
      Date
      		 Quantity
      MDth per day
      		 Demand Charges
      for the Year Ended
      December 31, 2004
       
      		  
      		  
      		 (In millions)

      El Paso Natural Gas Company 12/31/2004 64 4.1
      TransCanada NOVA Gas Transmission, Ltd. 12/31/2006 593 26.8
      TransCanada PipeLines Ltd., B.C. System 10/31/2006 584 10.3
      Gas Transmission Northwest Corporation 10/31/2006 610 55.1
      Transwestern Pipeline Co. 03/31/2007 150 17.7
      El Paso Natural Gas Company 03/31/2007 40 3.8
      El Paso Natural Gas Company 04/30/2005 100 8.2
      El Paso Natural Gas Company 03/31/2006 64 —


                   
      Demand Charges
      ExpirationQuantityfor the Year Ended
      PipelineDateMDth per dayDecember 31, 2003
      (In millions)
      El Paso Natural Gas Company  10/31/2003   100  $9.5 
      El Paso Natural Gas Company  12/31/2004   64   4.5 
      TransCanada NOVA Gas Transmission, Ltd.   12/31/2005   593   23.6 
      TransCanada PipeLines Ltd., B.C. System  10/31/2005   584   10.6 
      Gas Transmission Northwest Corporation  10/31/2005   610   55.0 
      Transwestern Pipeline Co.   03/31/2007   150   15.8 
      El Paso Natural Gas Company  03/31/2007   40   3.8 
      El Paso Natural Gas Company  04/30/2005   100   1.1 

      Competition

              Historically, energy utilities operated as regulated monopolies within service territories where they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport and distribute energy. Services were priced on a combined, or bundled, basis with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities undertake a continuing obligation to serve their customers, in return for which the utilities were authorized to charge regulated rates sufficient to recover their costs of service, including timely recovery of their operating expenses and a reasonable return on their invested capital. 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 have faced intensifying pressures to unbundle, or price separately, those services that are no longer considered natural monopolies. The most significant of these services are the commodity components — components—the supply of electricity and natural gas.

              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 these forces by providing for more competition in the energy industry. Regulators and legislators, to varying degrees, have required utilities to unbundle rates in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.


      17


        The Electricity Industry

        The Electricity Industry

              The FERC’sFERC's policies have supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities’utilities' transmission grids. The FERC’sFERC's subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations and advanced the view that a regulated, unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. The FERC’sFERC's standard market design proposal issued in July 2002 encourages unbundled transmission. The ISO also issued its own comprehensive market design proposal to effect changes to the structure and operation of the California electricity market, subject to the FERC’sFERC's approval. The FERC has approved the first phase of the ISO’sISO's new rules and implementation of the first phase is expected to bewas substantially completed in the secondfourth quarter of 2004. A later phase to establish integrated forward markets and locational marginal pricing and revise congestion management would be implemented in the future, assuming FERC approval. The ISO is expected to file proposed tariff language with the FERC later in 20042005 to address these issues.issues, with implementation of a new market design in 2007. Both the timing and substance of the FERC’sFERC's regional transmission organization policy and the FERC’sFERC's and the ISO’sISO's market design processes may be affected by any energy legislation Congress may pass.

              In July 2003, in order to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generator and transmission infrastructure, the FERC issued final rules on the interconnection of generators larger than 20 MW with a transmission system. The rules will require regulated transmission providers, such as the Utility or the ISO, generally to use standard interconnection procedures and a standard agreement for generator interconnections. These rules would require the Utility and the ISO to revise the existingcurrent form of agreements and procedures used when constructing facilities to interconnect new generators. Numerous parties have requested rehearing and a stay of the generator interconnection rules. Although the FERC has not yet ruled on the requests for rehearing, theThe FERC has ordered that the rules will not become effective until after the FERC accepts new tariff changes to implement the rules. The Utility, along with other transmission owners and the ISO, initially, filed proposed tariffs changes on January 20, 2004. In July 2004, the FERC summarily rejected those filings, based on a finding that the ISO did not satisfy the FERC's standards for an "Independent Entity" within the meaning of the FERC's rules. The FERC directed the ISO and the transmission owners to make a new filing with stronger justification for any California-specific deviations from the FERC's generally applicable rules. In January 2005, the Utility, along with other transmission owners and the ISO, re-filed with the FERC the proposed tariff changes and procedures, as required by the FERC. It is uncertain when the FERC will act on the rehearing requests or the proposed tariff changes. Further, portions of the FERC’s rulemaking may be affected by any energy legislation Congress may pass.

      In 1998, California implemented AB 1890, which mandated the restructuring of the California electricity industry and established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity. AB 1890 also gave customers the choice of continuing to buy electricity from the California investor-owned electric utilities or, beginning in April 1998, entering into contracts to purchase electricity from alternate energy service providers(providers (i.e., becoming direct access customers). The CPUC suspended the right of retail end-user customers to become direct access customers on September 20, 2001. The CPUC has assessed an additional charge on certain direct access customers to avoid a shift of costs from direct access customers to customers who receive bundled service.

              In October 2003, the CPUC instituted a rulemaking implementing AB 117, which permits California cities and counties to purchase and sell electricity for their residents once they have registered as community choice aggregators. Under AB 117, the Utility would continue to provide distribution, metering and billing services to the community choice aggregators’aggregators' customers and be those customers’customers' provider of electricity of last resort. However, once registration has occurred, each



      community choice aggregator would procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. To prevent a shifting of costs to customers of a utility who receive bundled services, AB 117 requires the CPUC to determine a cost-recovery mechanism so that retail end-users of the community choice aggregator will pay an appropriate share of the DWR’sDWR's and the Utility’sUtility's costs. AB 117 also authorized the Utility to recover from each community choice aggregator any costs of implementing the program that are reasonably attributable to the community choice aggregator, and to recover from ratepayerscustomers any costs of implementing the program not reasonably attributable to a community choice aggregator.

      18

              The Utility faces competition in the electricity distribution business as a result of the construction of duplicate distribution facilities to serve specific existing or new customers, condemnation of the Utility’sUtility's distribution facilities by local governments or districts, self-generation by the Utility’s customers and technological developments. These and other forms of competition may result in stranded investment capital, loss of customer growth and additional barriers to cost recovery. In addition, self-generation by the Utility's customers may result in stranded investment capital, loss of customer growth and additional barriers to cost recovery. As customers and local public officials explore their energy options in light of the recent California energy crisis, these bypass risks are increasing and may increase further if the Utility’sUtility's rates exceed the cost of other available alternatives.

              A number of local governments and districts in California are considering various forms of providing electric distribution services within the Utility’sUtility's service territory. The City and County of San Francisco (along with other California communities) have been considering municipalization of the Utility’sUtility's electricity distribution system within their jurisdictions. In addition, the Sacramento Municipal Utility District currently is considering annexing portions of the Utility’sUtility's service territory, with the objective of enabling the district to replace the Utility within these areas. Some existing public power entities, such as the Modesto and Merced Irrigation Districts, also are expanding their services in the Utility’sUtility's service area. Finally, some districts that are not currently distributing electricity, including the El Dorado Irrigation District and the South San Joaquin Irrigation District, are considering building facilities that would duplicate the Utility’sUtility's facilities. In May 2003, the South San Joaquin Irrigation District revealed its plans to invest over $40 million to duplicate the Utility’sUtility's distribution facilities and begin serving existing and new customers in and around Manteca. In 2002, the City of Hercules formed its own municipal utility for the purpose of competing with the Utility to serve new customers within the city. In 2003, the City of Hercules began providing electricity service to a 200-home subdivision and a large commercial customer, and has been actively pursuing additional residential and commercial customers. The Utility cannot currently predict the impact of these actions on the Utility’sUtility's business, although one possible outcome is a decline in the demand for the electricity that the Utility provides, which would result in a decline in the Utility’sUtility's revenues.


        The Natural Gas Industry

              FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service regardless of whether the customer (often a local gas distribution company) buys the natural gas commodity from these companies.

              In 1998, the Utility implemented the Gas Accord under which the natural gas transportation and storage services the Utility provides were separated for ratemaking purposes from the Utility’sUtility's distribution services. The Gas Accord changed the terms of service and rate structure for natural gas transportation, allowing the Utility’sUtility's core customers greater flexibility to purchase natural gas from competing suppliers. The Utility’sUtility's noncore customers purchase their natural gas from producers, marketers and brokers, and purchase their preferred mix of transportation, storage and distribution services from the Utility. Although they can select the gas suppliers of their choice, substantially all



      core customers buy natural gas, as well as transportation and distribution services, from the Utility as bundled service. The Gas Accord market structure has been extended by the CPUC through 2005.2007.

              The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas and the quality and reliability of transportation services. The most important competitive factor affecting the Utility’sUtility's market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian natural gas relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility’sUtility's case, includes the cost of transportation of the natural gas from Canada to the California border and the amount that the Utility charges for transportation from the border to southern California. In general, when the total cost of western Canadian natural gas increases relative to other competing natural gas sources, the Utility’sUtility's market share of transportation services into southern California decreases. In addition, Kern River Pipeline Company completed a major expansion of its pipeline system in May 2003 that increased its capacity to

      19

      deliver natural gas into the southern California market by approximately 900 MMcf per day. As a result this expansion, the volume of natural gas that the Utility delivers to the southern California market may decrease, although to date the Utility has not experienced any significant decrease in its volumes shipped. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

              From time to time, existing pipeline companies propose to expand their pipeline systems for delivery of natural gas into northern and central California. As a result of the California energy crisis, several new natural gas pipeline proposals were initiated to serve proposed new generation facilities for northern and central California. Many of the electricity generation projects have been cancelled or delayed, making it difficult for sponsors of the various gas pipeline projects to acquire enough firm capacity commitments to go forward with construction.


      PG&E Corporation’sCorporation's Regulatory Environment

        Federal Energy Regulation

        Federal Energy Regulation

              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, or PUHCA. Currently, PG&E Corporation has no expectation of becoming a registered holding company under PUHCA. TheIn 2001, the California Attorney General has filed a petition with the SEC requesting the SEC to review and revoke PG&E Corporation’sCorporation's exemption from PUHCA and to begin fully regulating the activities of PG&E Corporation and its affiliates. PG&E Corporation responded in detail to the California Attorney General petition demonstrating that PG&E Corporation qualified for an exemption from PUHCA and that there was no basis for action by the SEC. To date, the SEC has neither instituted an investigation nor ordered hearings regarding the matters raised in the California Attorney General’sGeneral's petition.

              During 2003 and 2004, proposed federal energy legislation was considered by the U.S. Senate.Congress. If it had been adopted, the legislation would, among other things, repealhave repealed PUHCA. PUHCA currently imposes significant regulatory barriers to mergers and acquisitions involving public utilities and public utility holding companies. The repeal of PUHCA could trigger a period of consolidation among public utilities, as well as acquisitions of public utilities by other businesses. As a result, the repeal of PUHCA could increase competitive pressures on the energy utility industry, including competition from sources the Utility does not currently view as competitors. The proposed effective date for the repeal of PUHCA, as well as the proposed effective date for proposed legislation that would replace PUHCA, is December 1, 2004.was 12 months after the passage of the legislation. Under the proposed legislation that would replace PUHCA, public utilities and public utility holding companies would



      remain under the regulatory oversight of the FERC, but not the SEC. Similar legislation is likely to be considered in 2005.


        State Energy Regulation

              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 the Utility to form a holding company was granted subject to various conditions set forth in CPUC decisions issued in 1996 and 1999 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 must continue to be established by the Utility’s Board of Directors as though the Utility were a stand-alone utility company;
      • the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation’s Board of Directors, or (known as the first priority condition); and

      20

      • the Utility must maintain on average its CPUC-authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition if an adverse financial event reduces the Utility’s equity ratio by 1% or more.

        •
        the Utility is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC;

        •
        the Utility's dividend policy must continue to be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company;

        •
        the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation's Board of Directors, (known as the first priority condition); and

        •
        the Utility must maintain on average its CPUC-authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition if an adverse financial event reduces the Utility's equity ratio by 1% or more.

              The CPUC also has adopted complex and detailed rules governing transactions between California’sCalifornia's electricity and natural gas distribution companies and their non-regulated affiliates. The rules permit non-regulated affiliates of regulated utilities to compete in the affiliated utility’sutility'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 each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility’sutility's non-regulated affiliates. In January 2004, the CPUC adopted rules that prohibit regulated utility electric procurement from entering into power procurement related transactions with an affiliate, subject to the following exceptions:

        •
        anonymous transactions through approved interstate brokers and exchanges, provided that the solicitation/bidding process is structured so that the identity of the seller is not known to the buyer until agreement is reached, and vice-versa;

        •
        transactions for natural gas services between the regulated utility and affiliates or operating divisions that are found necessary and beneficial for ratepayer interests, subject to the receipt and review of a management audit; and

        •
        transactions that occur pursuant to contracts with affiliates that were already existing on January 22, 2004.

      • anonymous transactions through approved interstate brokers and exchanges, provided that the solicitation/bidding process is structured so that the identity of the seller is not known to the buyer until agreement is reached, and vice-versa;
      • transactions for natural gas services between the regulated utility and affiliates or operating divisions that are found necessary and beneficial for ratepayer interests, subject to the receipt and review of a management audit; and
      • transactions that occur pursuant to contracts with affiliates that were already existing on January 22, 2004.
              In December 2004, the CPUC lifted its ban on affiliate transactions for long-term electricity procurement through all source competitive solicitations but retained the ban on short-term electricity procurement transactions.

              The CPUC also has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.



              On April 3, 2001, the CPUC issued an order instituting an investigation into whether the California investor-owned electric utilities, including the Utility, have complied with past CPUC decisions, rules and orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will, among other matters, investigate the utilities’utilities' transfer of money to their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties; the failure of the holding companies to financially assist the utilities when needed; the transfer by the holding companies of assets to unregulated subsidiaries; and the holding companies’companies' actions to “ringfence”"ringfence" their unregulated subsidiaries. TheUnder the Settlement Agreement the CPUC will also determine whether additional rules, conditions or changes are neededhas agreed to adequately protect ratepayersdismiss with prejudice PG&E Corporation and the public from dangers of abuse stemmingUtility from the holding company structure. The CPUC will investigate whether it should modify, change or add conditionsCPUC's investigation as 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, prospective rules, or conditions, as appropriate.past practices.

              On January 9, 2002, the CPUC issued two decisions in its pending investigation. In one decision, the CPUC, for the first time, adopted a broad interpretation of the first priority condition and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies “infuse"infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve.” The three major California investor owned electric utilities and their parent" Nevertheless, the CPUC dismissed PG&E Corporation (but no other utility holding companies had opposed this broader interpretation as being inconsistent withcompany) from the prior 15 years’ understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The CPUC also interpreted the first priority condition as prohibiting a holding company from acquiring assets of its utility subsidiary for inadequate consideration and acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility’s ability to fulfill its obligation to serve or to operate in a prudent and efficient manner.investigation. In the othersecond decision, the CPUC asserted that it maintains jurisdiction to enforce the conditions against PG&E Corporation and similar holding companies and to modify, clarify or add to the conditions.

      21

              In a related decision, the CPUC denied the motions filed by the California utility holding companies to dismissNovember 2003, PG&E Corporation and the holding companies fromof the pending investigation onother major California investor-owned electric utilities filed petitions for review of the basisCPUC's decisions with the California Court of Appeal. On May 21, 2004, the California Court of Appeal issued an opinion finding that the CPUC lackshas limited jurisdiction over the holding companies. However, incompanies to enforce the interimconditions imposed by the CPUC when the CPUC authorized the formation of the holding companies, but that the CPUC's decision interpreting the first priority condition discussed above, the CPUC separately dismissedwas not ripe for review. PG&E Corporation (but no other utility holding company) as a respondent toappealed the proceeding. In its written decision adopted on January 9, 2002, the CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum could decide expeditiously whether adoption of the Utility’s original proposed plan of reorganization would violate the first priority condition. On November 26, 2003, the California Court of AppealsAppeal finding that the CPUC had limited jurisdiction to the California Supreme Court. On September 1, 2004, the California Supreme Court denied the petition. On February 11, 2005, a CPUC administrative law judge issued a ruling noting that the pending CPUC investigation had been dormant for some time and requesting comments on whether the First Appellate District in San Francisco agreed to hearinvestigation should remain open. The ruling also stated that if no comments were received, a draft decision would be prepared for CPUC consideration closing the petitions for review of the CPUC’s decisions. Oral argument before the appellate court is set for March 5, 2004.proceeding.

              PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules and orders. Under the Settlement Agreement the CPUC has agreed to dismiss PG&E Corporation from the CPUC’s investigation as to past practices.

              On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against the directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200. Among other allegations, the California Attorney General alleges that PG&E Corporation violated the various conditions established by the CPUC in decisions approving the holding company formation. After the California Attorney General’sA similar complaint was filed, two other complaints containing substantially similar allegations were filed by the City and County of San Francisco and by a private plaintiff.also is pending. These complaints are not affected by the Settlement Agreement. For more information, see “Item 3 — "Item 3—Legal Proceedings”Proceedings" below.


      The Utility’sUtility's Regulatory Environment

              Various aspects of the Utility’sUtility's business are subject to a complex set of energy, environmental and other governmental laws, regulations and regulatory proceedings at the federal, state and local levels. This section and the “Ratemaking Mechanisms”"Ratemaking Mechanisms" section below summarize some of the more significant energy laws, regulations and regulatory mechanisms affecting the Utility. These sections are not an exhaustive description of all the energy laws, regulations and regulatory proceedings that affect the Utility. The energy laws, regulations and regulatory proceedings may change or be implemented or applied in a way that



      the Utility does not currently anticipate. For discussion of specific regulatory proceedings affecting the Utility, see the MD&A.


        Federal Energy Regulation
        The FERC

        The FERC

              The FERC is an independent agency within the U.S. Department of Energy, or DOE, that regulates the transmission of electricity in interstate commerce and the sale for resale of electricity in interstate commerce. The FERC regulates electricity transmission, interconnections, tariffs and conditions of service of the ISO and the terms and rates of wholesale electricity sales. The ISO is responsible for providing open access transmission service on a non-discriminatory basis, meeting applicable reliability criteria, planning transmission system additions and assuring the maintenance of adequate reserves of generation capacity. In addition, the FERC has jurisdiction over the Utility’sUtility's electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility’sUtility's hydroelectric generation facilities and the interstate sale and transportation of natural gas.

              In response to the California energy crisis, the FERC issued a series of orders in the spring and summer of 2001 and July 2002 aimed at prospectively mitigating extreme wholesale energy prices like those that prevailed in 2000 and 2001. These orders established a cap on bids for real-time electricity and ancillary services of $250 per MWh (unless a generator could demonstrate that its costs justified a rate in excess of $250 per MWh) and established various automatic mitigation procedures. As of December 2003, all sellers

      22

      with market-based rate authority became subject to, and incorporated in their market-based rate tariffs, behavioral conditions designed to prevent market manipulation.

              In February 2004,2005, the FERC is expected to consider ISO market monitoring and oversight in connection with the FERC’sFERC's review of the ISO’s standardISO's market design proposals. Market monitoring and mitigation also may be affected by any energy legislation Congress may pass.

              Various entities, including the Utility and the Statestate of California are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity purchasers from JanuaryMay 2000 to June 2001.2001 through a proceeding pending at the FERC. This FERC proceeding, the "Refund Proceeding," commenced on August 2, 2000 when a complaint was filed against all suppliers in the ISO and PX markets. On July 25, 2001, the FERC held that refunds would be available for certain overcharges, and established a process to determine the amount of the overcharges that will be refunded. The FERC asserted that it would not order market-wide refunds for periods before October 2, 2000, because under a federal statute it can only order refunds beginning 60 days after a complaint for overcharges was filed and the first complaint for overcharges was not filed with the FERC until August 2, 2000. In December 2002, a FERC administrative law judgeALJ issued an initial decision in the Refund Proceeding finding that power suppliers overcharged the utilities, the Statestate of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001, (the only time period for which the FERC permitted refund claims), but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

              DuringIn March 2003, the FERC confirmed most of the administrative law judge’sALJ's findings in the Refund Proceeding, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the California Power Exchange, or PX which(which operates solely to reconcile remaining refund amounts owed,owed) to make compliance filings establishing refund amounts by March 2004. The ISO calculation process has been continuing, and the ISO has indicated that it plans to make its compliance filing by August 2004.the first half of 2005. The actualPX cannot make its compliance filing until after the ISO has made its filing. In October 2003, the FERC affirmed its March 2003 decision. Various parties have filed appeals with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, of the various FERC orders in the



      Refund Proceeding. Although the Ninth Circuit originally held those appeals in abeyance while the FERC process continued, on October 22, 2004, the Ninth Circuit ordered that the appeals should proceed. According to a schedule developed by the Ninth Circuit, the parties are required to submit all briefs by March 2005 to address the issues of which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds. These matters will be considered at oral argument before the Ninth Circuit on April 12 and 13, 2005, and a decision is expected in the following months.

              The final refunds will not be determined until the FERC issues a final decision in the Refund Proceeding, following the ISO and PX compliance filings.filings and the resolution of the appeals of the FERC's orders. The FERC is uncertain when it will issue a final decision in this proceeding.the Refund Proceeding, after which further appellate review is expected. In addition, future refunds could increase or decrease as a result of an alternative calculationretroactive adjustments proposed by the ISO, which incorporatesincorporate revised data provided by the Utility and other entities.

              UnderAs noted above, the Settlement Agreement,FERC asserted in the Utility and PG&E Corporation agreedRefund Proceeding that it does not have the power to continuedirect the power suppliers to cooperate withmake comprehensive market-wide refunds to customers for the CPUCperiod before October 2, 2000. However, in the FERC's separate proceedings to investigate whether tariff violations occurred in the period before October 2, 2000, the FERC has asserted that it has the power to order power suppliers to disgorge any profits if the FERC finds that the tariffs in force at that time were violated or subject to manipulation. In addition, in September 2004, acting in a separate case from the Refund Proceeding and the State ofFERC's investigative proceedings, the Ninth Circuit found that the FERC has the authority to provide refunds for tariff violations involving inadequate transaction reporting for sales into the California in seeking refunds from generators and other energy suppliers.spot markets throughout the period before October 2, 2000. The net after-tax amount of any refunds, claim offsets or other credits from generators or other energy suppliers relatingNinth Circuit remanded the case to the Utility’s ISO, PX, qualifying facilities or energy service provider costs that are actually realized in cash or by offsetFERC to determine the appropriate remedy. Pending a decision on the suppliers' request for a rehearing of creditor claims in its Chapter 11 proceeding would reducethis Ninth Circuit decision, the balance ofFERC has not yet acted on the $2.21 billion after-tax regulatory asset createdSeptember 2004 remand order. It is uncertain whether the Ninth Circuit's decision interpreting the FERC's power to order refunds will be upheld and how it will be applied by the Settlement Agreement.FERC.

              The Utility has recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to compromise. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. Under a bankruptcy court order, the aggregate allowable amount of ISO, PX and generator claims was limited to approximately $1.6 billion. The Utility currently estimates that the claims filed would have been reduced to approximately $1.2$1.0 billion based on the refund methodology recommended in the administrative law judge’sFERC ALJ's initial decision, resulting in a net liability of approximately $1.0 billion after the approximately $200 million pre-petition offset.decision. The recalculation of market prices according to the revised methodology adopted by the FERC in its OctoberMarch 2003 decision could further reduce the amount of the suppliers’suppliers' claims by several hundred million dollars. However, thisThis reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology. The FERC has directed that sellers claiming a fuel cost allowance should submit their claims to an independent auditor before inclusion of any amounts in an ISO calculation of refunds and offsets for such fuel costs.

              The Utility has entered into various settlements with power suppliers resolving the Utility's claims against these power suppliers. Although settlement discussions with a number of other major sellers and other market participants are continuing, the Utility cannot predict whether these settlement negotiations will be successful. The net after-tax amounts received by the Utility under settlements reduced the amount of the Settlement Regulatory Asset. Customers also will receive the benefit of any future energy supplier refunds received by the Utility. See discussion entitled "Contingencies" in MD&A.



              On November 25, 2003, the FERC issued Order No. 2004, its final rule on standards of conduct for interstate natural gas pipelines and public utilities (jointly referred to as transmission providers). The standards of conduct are designed to ensure that transmission providers do not provide affiliated market participants with preferential access to service or information. In Order No. 2004, the FERC consolidated the previously separate standards of conduct for interstate natural gas pipelines and electric transmission providers and expanded the range of affiliates covered by the standards. In accordance with Order No. 2004, on September 22, 2004, the Utility posted its plan for compliance with the standards of conduct on its internet website,

      The NRCwww.pge.com.

        The NRC

              The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility’sUtility's Diablo Canyon power plant and Humboldt Bay Unit 3. NRC regulations require extensive monitoring and review of the safety, radiological, environmental and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. Safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at the Utility’sUtility's Diablo Canyon power plant and additional significant capital expenditures could be required in the future.

        23
        State Energy Regulation

        The CPUC

        State Energy Regulation
        The CPUC

              The CPUC has jurisdiction to set the rates, terms and conditions of service for the Utility’sUtility's electricity distribution, natural gas distribution and natural gas transportation and storage services in California. The CPUC also has jurisdiction over the Utility’sUtility's issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility’sUtility's electricity and natural gas retail customers, rate of return, rates of depreciation, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning and aspects of the siting of the electricity transmission system. Ratemaking for retail sales from the Utility’sUtility's generation facilities is under the jurisdiction of the CPUC. To the extent this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC 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 of California and confirmed by the California State Senate for staggered six-year terms.

        California Legislature

        California Legislature

              Over the last several years, the Utility’sUtility's operations have been significantly affected by statutes passed by the California legislature, including:

      • Assembly Bill 1890.
        •
        Assembly Bill 1890.AB 1890 mandated the restructuring of the California electricity industry, commencing in 1998 with the implementation of a market framework for electricity generation in which generators and other energy providers were permitted to charge market-based rates for wholesale electricity and the Utility’s customers were given the choice of becoming direct access customers;
      • Assembly Bill 6X.AB 6X, enacted in January 2001 in response to the California energy crisis, prohibited disposition of utility-owned generation facilities before January 1, 2006;
      • Assembly Bill 1X.AB 1X authorized the DWR, beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities’ retail customers. AB 1X required the California investor-owned electric utilities, including the Utility, to deliver that electricity and act as the DWR’s billing and collection agent;
      • Senate Bill 1976.SB 1976, enacted in September 2002, required the CPUC to allocate electricity from contracts that the DWR entered into under AB 1X among the customers of the California investor-owned electric utilities, required the utilities to file short- and long-term procurement plans with the CPUC, contemplated that the utilities would resume buying electricity pursuant to these plans by January 1, 2003, and mandated new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under approved procurement plans; and
      • Senate Bill 1078. SB 1078, enacted in September 2002, creates a renewable portfolio standard for investor-owned utilities that requires annual 1% increases of renewable electrical procurement purchases until renewable resources equal 20% of total retail sales in 2017.

           One of PG&E Corporation and the Utility’s obligationsUtility's customers were given the choice of becoming direct access customers;

      •
      Assembly Bill 6X.  AB 6X, enacted in January 2001 in response to the California energy crisis, prohibited disposition of utility-owned generation facilities before January 1, 2006;

      •
      Assembly Bill 1X.  AB 1X authorized the DWR, beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities' retail customers.

          AB 1X required the California investor-owned electric utilities, including the Utility, to deliver that electricity and act as the DWR's billing and collection agent;

        •
        Senate Bill 1976.  SB 1976, enacted in September 2002, required the CPUC to allocate electricity from contracts that the DWR entered into under AB 1X among the customers of the California investor-owned electric utilities, required the utilities to file short- and long-term procurement plans with the CPUC, contemplated that the utilities would resume buying electricity pursuant to these plans by January 1, 2003, and mandated new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under approved procurement plans;

        •
        Senate Bill 1078.  SB 1078, enacted in September 2002, creates a renewable portfolio standard for investor-owned utilities that requires annual 1% increases of renewable electrical procurement purchases until renewable resources equal 20% of total retail sales in 2017; and

        •
        Senate Bill 772.  SB 772, enacted in June 2004, (1) authorized the CPUC to approve the issuance of energy recovery bonds, or ERBs, to refinance the $2.21 billion regulatory asset established under the Settlement Agreement, is seeking to refinance the remaining unamortized pre-tax balance of the regulatory asset and related federal, state and franchise taxes using a securitized financing supported by a dedicated rate component that would require enactment of authorizing California legislation. On January 22, 2004, the CPUC approved proposed legislation, Senate Bill 772, that would authorizeor Settlement Regulatory Asset, (2) established a dedicated rate component to securitize the regulatory assetERBs, and (3) authorized the related taxes. The California Assembly’s UtilitiesCPUC to impose a charge for the dedicated rate component on the Utility's electricity distribution customers, subject to certain limited exceptions. On February 10, 2005, PG&E Energy Recovery Funding LLC, or PERF, a limited liability company which is wholly owned and Commerce Committee approved the proposed legislation on February 2, 2004. The proposed legislation will next be consideredconsolidated by the California Assembly’s Appropriations Committee. UnderUtility (but legally separate from the Settlement Agreement, any adopted legislation must be satisfactoryUtility), issued $1.9 billion of ERBs that are secured by this dedicated rate component. The proceeds of the issuance of ERBs were paid by PERF to the CPUC, the Utility and will be used by the Utility to refinance the remaining unamortized after-tax balance of the Settlement Regulatory Asset.

        The Utility Reform Network, or TURNCalifornia Energy Resources Conservation and the securitization must not adversely affect the Utility’s credit ratings among other conditions.Development Commission

        24

        The California Energy Resources Conservation and Development Commission

              The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission, or CEC, is the state’sstate's primary energy policy and planning agency. The CEC is responsible for the sitinglicensing of all thermal power plants over 4950 MW, and administersoverseeing funding programs that support public interest energy research; advance energy science and technology through research, development and development funds, as well asdemonstration; and provide market support to existing, new and emerging renewable resource programs, includingtechnologies. In addition, the renewableCEC is responsible for forecasting future energy portfolio standard program.needs that will be used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.


        Other Regulation

              The Utility obtains a number of permits, authorizations and licenses in connection with the construction and operation of the Utility’sUtility's generation facilities, electricity transmission lines, natural gas transportation pipelines and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the more 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 seven hydroelectric projects and one transmission line project undergoing FERC relicensing. The Utility will begin relicensing proceedings on two additional hydroelectric projects within the next two years.


              The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate and maintain the Utility’sUtility's electric, natural gas, oil and water facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties under the franchises. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. However, there are 38 charter cities that can set a fee of their own determination. The Utility also periodically obtains permits, authorizations and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations and licenses the Utility has rights to occupy and/or use public property for the operation of the Utility’sUtility's business and to conduct certain related operations.


      Ratemaking Mechanisms

        Overview

        Overview
        Transition from Frozen Rates to Cost of Service Ratemaking

             FrozenCost of Service Ratemaking

              In January 2004, the CPUC determined that the retail electric rate freeze implemented as part of electric industry restructuring in 1998 ended on January 18, 2001. In February 2004, the CPUC approved a rate design settlement to implement an annual electricity rates, which beganrate reduction of approximately $799 million to begin on January 1, 1998, were designed to allow the Utility to recover its authorized utility costs, and to the extent frozen rates generated revenues in excess of these costs, to recover the Utility’s transition costs. Although the surcharges implemented in 2001 effectively increased the actual rate, under the frozen rate structure, increases in the Utility’s authorized revenue requirements did not increase the Utility’s revenues. In addition, DWR revenue requirements reduced the Utility’s revenues under the frozen rate structure.2004. As a result of revised electricitythe Settlement Agreement and these CPUC decisions, the Utility's rates discussed below and a January 2004 CPUC decision determining that the rate freeze endedare now determined based on January 18, 2001, the Utility expects that once approved by the CPUC, its rates will reflect its costs of service wherebyservice. Electric rates reflect the Utility’s rates are calculated based onsum of individual revenue requirement components, including base revenue requirements set by general rate cases as described below, revenue requirements for the aggregate of various authorized rate components.regulatory assets provided under the Settlement Agreement, electricity procurement costs, and the DWR's requirement, among others. Changes in any individual revenue requirement will change customers’ electricity rates.

           On January 26, 2004, the Utility filed revisedcustomers' electricity rates with the CPUC based on the Utility’s 2004 forecast revenue requirements and requested implementation of the rate changes. These rates reflect allocation of the Utility’s revenue requirements in accordance with a January 20, 2004 rate design settlement agreement entered into with a number of consumer groups and government agencies, including TURN and the CPUC’s Office of Ratepayer Advocates, or ORA. The rate design settlement agreement has been submitted to theUtility's revenues.

        25Revenue Requirements

        CPUC for approval. The revised rates and forecast revenue requirements are based on, and ultimately will be adjusted to reflect, pending or final CPUC decisions including:

        • The Utility’s 2003 GRC;
        • The allocation of the DWR’s 2004 revenue requirements;
        • Pending energy supplier refunds, claim offsets or other credits pursuant to the Settlement Agreement; and
        • The calculation of any over-collection of the surcharge revenues for 2003.

              Based on the revised rates filed by the Utility on January 26, 2004, current electricity revenues are expected to be reduced by approximately $860 million as compared to revenues generated at current rates. On February 11, 2004, a proposed decision was issued which, if ultimately approved by the CPUC, instead is expected to reduce the Utility’s current electricity revenues by $799 million. The most significant portion of the difference between the $799 million included in the draft decision and the $860 million filed by the Utility relates to a proposed decrease in the DWR’s revenue requirement included in the Utility’s January 26, 2004 rate filing. In the January 26, 2004 rate filing, the Utility had estimated that the DWR’s revenue requirement would be reduced by approximately $79 million related to the DWR’s share of the settlement agreement of CPUC litigation reached with El Paso. However, the DWR protested the Utility’s rate filing, indicating that the amount of its share of the El Paso settlement was unknown and that the DWR had not changed its revenue requirement as a result of the El Paso settlement.

      The February 11, 2004 proposed decision orders the Utility to amend its January 26, 2004 filing containing the revised electricity rates before March 1, 2004. The CPUC is expected to consider the rate design settlement at its meeting on February 26, 2004. If approved, the new rates will be effective March 1, 2004 or shortly thereafter, and the revenue reduction will be retroactive to January 1, 2004.

      Revenue Requirements

      Before the rates for the Utility’sUtility's electricity and natural gas utility services can be set, revenue requirements must first be determined. The components of revenue requirements for electricity and natural gas utility service include depreciation, operating, administrative and general expenses, taxes and return on investment, as applicable, for each area of these services, including distribution, transmission, transportation, generation, procurement and public purpose programs. Revenue requirements are designed to allow a utility an opportunity to recover its reasonable costs of providing utility services, including a return of, and a fair rate of return on, its investment in utility facilities, or rate base. Revenue requirements are then allocated among customer classes and specific rates designed to produce the required revenue are established. In the Utility’sUtility's rate cases, intervenors have the opportunity to comment on the Utility’sUtility's application. The issues raised by these comments are then resolved by the appropriate regulatory agency. If the Utility and the intervenors can settle these issues, these settlements are submitted to the regulatory agency for approval.

        General Rate Cases

        General Rate Cases

              The Utility’sUtility's primary revenue requirement proceeding is the general rate case, or GRC, filed with the CPUC. In the GRC, the CPUC authorizes the Utility to collect from customers an amount known as base revenues to recover base business and operational costs related to the Utility’sUtility's electricity and natural gas distribution and electricity generation operations. The GRC typically sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in GRC proceedings based on a forecast of costs for the first, or test, year. After authorizing the revenue requirements, the CPUC allocates revenue requirements among customer classes (mainly residential, commercial, industrial and agricultural) and establishes specific rate levels. Typical intervenors in the Utility’sUtility's GRC include the ORA and TURN. The next GRC will cover the period of 2007-2009.


        26Attrition Rate Adjustments

        Attrition Rate Adjustments

              The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations.

        Cost of Capital Proceedings

        Cost of Capital Proceedings

              The CPUC generally conducts an annual cost of capital proceeding to determine the Utility’sUtility's authorized capital structure and the authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The cost of capital proceeding establishes the percentage components that common equity, preferred equity and debt will represent in the Utility’sUtility's total authorized capital structure for a specific year. The CPUC then establishes the authorized return on common equity, preferred equity and debt that the Utility will have the opportunity to collect in its authorized rates. For 2005, this proceeding also will set the authorized rate of return for the Utility’sUtility's gas transportation and storage assets.

        Baseline Allowance

        Baseline Allowance

              The CPUC sets and periodically revises a baseline allowance for the Utility’sUtility's residential gas and electricity customers. A customer’scustomer's baseline allowance is the amount of its monthly usage that is covered under the lowest possible natural gas or electric rate. Electricity baseline usage is also exempt from certain surcharges. Natural gas or electricity usage in excess of the baseline allowance is covered by higher rates that increases with usage.


        DWR Electricity and DWR Revenue Requirements

              As a consequence of the California energy crisis, on January 17, 2001, the Governor of California signed an order declaring an emergency and authorizing the DWR to purchase electricity to maintain the continuity of supply to retail customers. This was followed by AB 1X, which authorized the DWR to purchase electricity and sell that electricity directly to the California investor-owned utilities’utilities' retail end-user customers and to issue revenue bonds to finance electricity purchases. AB 1X also required the Utility to deliver the electricity purchased by the DWR over the Utility’sUtility's distribution systems and to act as a billing and collection agent for the DWR, without taking title to DWR purchased electricity or reselling it to the Utility’sUtility's customers.

              AB 1X allows the DWR to recover its costs of electricity and associated transmission and related services, principal and interest on bonds issued to finance the purchase of electricity, administrative costs and certain other amounts associated with purchasing electricity through a revenue requirement. AB 1X also authorizes the CPUC to set rates to cover the DWR’sDWR's revenue requirements, but prohibits the CPUC from increasing electricity rates for residential customers who use less electricity than 130% of their existing baseline quantities.

              Under AB 1X, the DWR was prohibited after December 31, 2002 from entering into new electricity purchase contracts and from purchasing electricity on the spot market. SB 1976, which became law in September 2002, required the CPUC to allocate electricity from existing DWR contracts among the customers of the California investor-owned electric utilities, including the Utility’sUtility's customers. On September 19, 2002, the CPUC issued a decision allocating electricity from the DWR contracts to the customers of the three California investor-owned electric utilities. The DWR continues to be legally and financially responsible for these contracts. The electricity provided under 19 of the DWR contracts was allocated to the Utility’sUtility's customers. The Utility is responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with these contracts.


              The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricity customers of the three California investor-owned electric utilities through what is known as a power

      27

      charge. The Utility’sUtility's customers also must pay what is known as a bond charge to pay a share of the DWR’sDWR's revenue requirements to recover costs associated with the DWR’sDWR's $11.3 billion bond offering completed in November 2002. The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR’sDWR's revenue requirement and to provide the DWR with funds to make its electricity purchases. Because the Utility acts as a billing and collection agent for the DWR, amounts collected for the DWR and any adjustments are not included in the Utility’sUtility's revenues.
      DWR Allocated Contracts

             The DWR provided approximately 29% of the electricity delivered to the Utility’s customers for the year ended December 31, 2003. The DWR purchased the electricity under contracts with various generators
        Procurement Resumption and through open market purchases. The Utility is responsible for administration and dispatch of the DWR’s electricity procurement contracts allocated to the Utility, for purposes of meeting a portion of the Utility’s net open position. The DWR remains legally and financially responsible for the electricity procurement contracts.Procurement Plans

           The contracts terminate at various times through 2012 and consist of must-take and capacity charge contracts. Under must-take contracts, the DWR must take and pay for electricity generated by the applicable generating facility regardless of whether the electricity is needed. Under capacity charge contracts, the DWR must pay a capacity charge but is not required to purchase electricity unless that electricity is dispatched and delivered.

           The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:

      • After assumption, the Utility’s issuer rating by Moody’s Investors Services will be no less than A2 and the Utility’s long-term issuer credit rating by Standard & Poors will be no less than A;
      • The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and
      • The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

      Procurement Resumption and Procurement Plans

              On January 1, 2003, the California investor-owned electric utilities resumed responsibility for procuring electricity to meet their residual net open positions.positions (i.e., that portion of the Utility's electricity customers' demand not satisfied by electricity that the Utility generates or has under contract, or by electricity provided under the DWR allocated contracts). They also became responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. The utilities also were required by SB 1976 to submit short-term and long-term procurement plans to the CPUC for approval. In December 2002, the CPUC adopted a 2003 short-term procurement plan for the Utility. The CPUC also authorized the California investor-owned electric utilities to extend their planning into the first quarter of 2004 and directed the Utility to hedge its 2004 first quarter residual net open position with transactions entered into in 2003.

              In December 2003, the CPUC approved the Utility’s short-term 2004 procurement plan. In the January 2004 CPUC decision discussed below, the CPUC also adopted short-term procurement authority for 2005 for the utilities in order to allow them to begin the normal cycle for procuring products required for summer 2005, but contracts for 2005 cannot exceed one year.

           On January 22, 2004, the CPUC adopted an interim decision establishing the long-term regulatory framework under which the California investor-owned electric utilities are required to plan for and procure

      28

      energy resources. The utilities are directed to meet resource needs first through cost effective energy efficiency, demand response, and renewable resources before considering the addition of conventional supply or transmission resources. The utilities are encouraged to have a diversified resource portfolio. The utilities are required to submit new long-term procurement plans in 2004 following workshops and the CPUC’s adoption of specific resource adequacy criteria. The procurement plans are required to include a range of load forecasts for distributed generation and varying levels of community choice aggregation. The CPUC adopted a planning reserve requirement of 15% to 17% applicable to all load-serving entities, including the utilities, energy service providers and future community choice aggregators. The planning reserve requirement will be phased in by January 1, 2008, and intermediate benchmarks are to be established. In addition, beginning in 2005, the utilities and other load-serving entities are required to secure 90% of their electricity needs during the peak energy months of May through September through forward contracts at least one year in advance. The CPUC also indicated that it will consider procurement incentive mechanisms for the utilities. The CPUC also continued the 5% target limitation on the utilities’ reliance on the spot market to meet their energy needs.

      Effective January 1, 2003, under California law, the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the recorded electricity procurement revenues and actual costs incurred under the Utility’sUtility's authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. TheSB 1976 requires the CPUC mustto review the revenues and costs associated with an investor-owned utility’sa utility's electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate when the aggregate over-collections or under-collections exceed 5% of the utility’sutility's prior year electricity procurement revenues,, excluding amounts collected for the DWR. These

              All load-serving entities, including the utilities, energy service providers and future community choice aggregators, must achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements by June 1, 2006. Also, beginning in 2006, the utilities and other load-serving entities are required to secure 90% of their electricity needs during the peak energy months of May through September through forward contracts at least one year in advance.

              On December 16, 2004, the CPUC issued a final decision which approved, with certain modifications, each California investor-owned electric utility's long-term electricity procurement plan, or LTPP, in order to authorize each utility to plan for and procure the resources necessary to provide reliable service to their customers for the ten-year period 2005-2014. The decision recognizes that each utility will have capacity needs over the ten-year period, especially in 2011 when most of the DWR contracts expire. The decision states that a major issue in the proceeding is the extent to which the utilities will be compensated for investments or purchases that they must make in order to meet their obligation to provide reliable service to their customers, noting that the implementation of community choice aggregation, departing municipal load, and the potential for allowing new direct access all create a great degree of uncertainty as to the amount of load the existing utilities will be responsible for serving in the future. The decision includes the following key points:

        •
        The decision finds that the Utility's strategy of adding 1,200 MW of capacity and new peaking generation in 2008 and an additional 1,000 MW of new peaking and dispatchable generation in 2010 through requests for offers, or RFOs, is reasonable and compatible with the Utility's resource needs under its medium load preferred case scenario, does not crowd out policy-preferred resources, and is a reasonable level of commitment given load uncertainty.

          •
          To meet the utilities' resource requirements, the utilities are required to solicit bids from providers of all potential sources of new generation (e.g. conventional or renewable resources to be provided under turnkey developments, buyouts, or power purchase agreements, or PPAs) through a single, open, transparent and competitive RFO process, although an utility can tailor a RFO to meet specific resource needs. In particular, bids for long-term generation resources (whether PPAs or utility-owned) would be evaluated side-by-side. In evaluating bids, the IOUs are required to:

          •
          procure the maximum amount of renewable generation resources, and be prepared to defend any selection of fossil-fuel generation resources over renewable resources,

          •
          employ the Least-Cost Best-Fit methodology when evaluating bids for PPAs and utility-owned generation resources, taking into account the qualitative and quantitative attributes (such as performance risk, credit risk, price diversity, term, and operational flexibility) associated with each bid, and

          •
          employ a "greenhouse gas adder" to evaluate fossil-fuel generation bids as a method to recognize the cost of greenhouse gas emissions to develop a more accurate price comparison between fossil-fuel, renewable and demand-side bids (the greenhouse gas adder would be used for analytical purposes only and would not be paid to a generator).

          •
          The CPUC has agreed that it will consider the debt equivalence impact of procurement contracts on credit ratings in future cost of capital proceedings. The Utility is required to employ Standard & Poor's method for assessing the debt equivalence of power purchase agreements when evaluating bids in an all-source solicitation, except that the debt equivalence factor should be 20% instead of 30%.

          •
          The utilities are prohibited from recovering initial capital costs in excess of their final bid price for utility-owned generation resources. If final project costs are less than the final bid price, the savings would be shared with customers and any cost overruns would be absorbed by the utilities. Costs of future plant additions and annual operating and maintenance costs and similar costs incurred by an utility would be eligible for cost-of service ratemaking treatment.

          •
          Affiliates of the utilities are permitted to participate in the bidding process for long-term generation resources, subject to certain guidelines and safeguards, including a requirement that the utility use an independent third party evaluator in resource solicitations where there are bids that involve affiliates or utility-built or utility-turnkey development projects. The independent evaluator will not be able to make binding decisions on behalf of the utility.

          •
          The utilities are permitted to recover their net stranded costs of all new fossil-fuel generation resources from all customers, including departing customers, for a period of 10 years or the life of the PPA, whichever is less, provided that the CPUC will allow the utilities an opportunity to justify a longer recovery period on a case-by-case basis. Stranded costs arising from renewable generation procurement activities can be collected from all customers, including departing load, over the life of the contract. The utilities are required to take appropriate steps to minimize potential stranded costs by selling excess energy and capacity needs into the marketplace and crediting the revenues from these sales against the utilities' costs.

          •
          The mandatory adjustments will continue untilrate adjustment mechanism under SB 1976, which otherwise would cease on January 1, 2006.2006, has been extended to the length of a resource commitment or 10 years, whichever is longer.

          •
          With respect to the utilities' contracting authority, the decision permits the utilities to enter into short-term, mid-term and long-term contracts with starting delivery dates through 2014, provided the utilities submit necessary compliance filings and provided that contracts with terms five years

            or longer are submitted to the CPUC for pre-approval. The decision adopts a rolling 10-year procurement period, noting that the LTPPs cover a 10-year period and will be updated and reviewed every 2 years. The decision grants the Utility's petition for modification of its existing short-term procurement plan to permit all utilities to conduct procurement using negotiated bilateral agreements for transactions up to 3 calendar months, or one quarter, forward. The decision notes that ultimately the CPUC will eliminate short-term procurement plans and the utilities will act in accordance with a single CPUC-approved plan; but until then, the utilities' existing short-term plans remain in effect and any updates or modifications should be filed with an advice letter within 30 days after the issuance of the decision. The Utility filed an update to its short-term plan on January 18, 2005. The decision requires the utilities to submit a compliance filing updating their procurement plans to reflect the changes and modifications in the decision by March 25, 2005.

          •
          The decision directs the utilities to meet CPUC-mandated energy efficiency goals over the 10-year period, but defers consideration of the $245 million incremental revenue requirement requested by the Utility to fund energy efficiency programs for 2006 through 2008 to the CPUC's energy efficiency rulemaking proceeding.


          Electricity Transmission

                The Utility’sUtility's electricity transmission revenues and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two sources of transmission revenues,revenues: charges under the Utility’sUtility's transmission owner tariff and charges under specific contracts with existing wholesale transmission customers that pre-date the Utility’sUtility's participation in the ISO. Customers that receive transmission services under these pre-existing contracts, referred to as existing transmission contract customers, are charged individualized rates based on the terms of their contracts. Transmission rates established by the FERC in the Utility's transmission owner rate cases are included by the CPUC in the Utility’sUtility's retail electricity rates and collected from retail electricity customers receiving bundled service under the federal filed rate doctrine.

          Transmission Owner Rate Cases

          Transmission Owner Rate Cases

                Under the FERC’sFERC's regulatory regime, the Utility is able to file a new base transmission rate case under the Utility’sUtility's transmission owner tariff whenever the Utility deems it necessary to increase its rates within certain guidelines set forth by the FERC. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.

                The Utility’sUtility's transmission owner tariff includes two rate components:

        • Base transmission rates, which are intended to recover the Utility’s operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity; and
        • Rates to recover ISO charges for both reliability service costs and an ISO charge associated with a ten-year shift from utility-specific transmission charges to an ISO grid-wide charge, both of which are discussed below.

          •
          Base transmission rates, which are intended to recover the Utility's operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity; and

          •
          Rates to recover ISO charges for both reliability service costs and an ISO charge associated with a ten-year shift from utility-specific transmission charges to an ISO grid-wide charge, both of which are discussed below.

                The Utility derives the majority of the Utility’sUtility's transmission revenue from base transmission rates.

          29Transmission Control Agreement

          Transmission Control Agreement

                The Utility is a party tohas entered into a Transmission Control Agreement, or TCA, with the ISO and other participating transmission owners. As aowners (including Southern California Edison, or SCE, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owner,owners have


        assigned operational control of their electricity transmission systems to the ISO. The Utility is required to give two years notice and receive regulatory approval if it wishes to withdraw from the TCA. Under this agreement,

          Reliability Must Run Agreements

                The ISO also has entered into reliability must run, or RMR, agreements with various power plant owners, including the Utility, that require designated units in certain power plants, known as RMR units, to remain available to generate electricity upon the ISO's demand when needed for local transmission owners, which also include Southern California Edison, or SCE, San Diego Gas & Electric Company and several municipal utilities, assign operational control of their electricitysystem reliability. As a participating transmission systems to the ISO. In addition, as a party toowner under the TCA, the Utility is responsible for a share of the ISO's costs of reliability must-run, orpaid under RMR agreements betweento power plant owners within or adjacent to the ISO and owners of the power plants subject to RMR agreements, or RMR Plants. The Utility also is an owner of some of these RMR Plants for which the Utility receives revenue from the ISO. Under the RMR agreements, RMR Plants must remain available to generate electricity when needed for local transmission system reliability upon the ISO’s demand.Utility's service territory.

                At December 31, 2003,2004, the ISO had RMR agreements for which the Utility estimated that it could be obligated to pay the ISO an estimated $446approximately $570 million in net costs incurred under these RMR agreements during the period January 1, 20042005 to December 31, 2005.2006. Of this amount, the Utility estimates that it would receive approximately $42 million under its RMR agreements during the same period. These costs and revenues are recoverable undersubject to applicable ratemaking mechanisms.

        It is possible For a discussion of a proposed settlement agreement entered into in January 2005 with Mirant Corporation and various of its subsidiaries to resolve the Utility's claims that it was overcharged under Mirant's RMR agreements and other RMR-related issues that could affect the Utility, may receive a refund of RMR costs thatsee the Utility previously paid to the ISO. In June 2000, a FERC administrative law judge issued an initial decision approving rates that, if affirmed by the FERC, would require the subsidiaries of Mirant Corporation, or Mirant, that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments of approximately $340 million, including interest, for availability of Mirant’s RMR Plants under these agreements. However, on July 14, 2003, Mirant filed a petition for reorganization under Chapter 11 and on December 15, 2003, the Utility filed claimssection titled "Reliability Must Run Agreements" in Mirant’s Chapter 11 proceeding including a claim for an RMR refund. The Utility is unable to predict at this time when the FERC will issue a final decision on this issue, what the FERC’s decision will be, and the amount of any refunds, which may be impacted by Mirant’s Chapter 11 filing. It is uncertain how the resolution of this matter would be reflected in rates.MD&A.

          Reliability Services Costs

          Reliability Services Costs

                The ISO bills the Utility for reliability services based on payments that the ISO makes to generators under reliability must run agreements and to others to support reliability of the Utility’sUtility's transmission system. The costs of reliability must run agreements attributed to supporting the Utility’sUtility's historic transmission control area are charged to the Utility as a participating transmission owner. These costs were approximately $330$425 million in 2003.2004. Under the Utility’sUtility's transmission owner tariff, the Utility charges its customers rates designed to recover these reliability service charges, without mark-up or service fees. The Utility tracks costs and revenues related to reliability services in the reliability services balancing account. Periodically, the Utility’sUtility's electricity transmission rates are adjusted to refund over-collections to the Utility’sUtility's customers or to collect any under-collections from customers.

          Transmission Access Charge

          Transmission Access Charge

                In March 2000, the ISO filed an application with the FERC seeking to establish its own transmission access charge as directed by AB 1890. The ISO’sISO's transmission access charge methodology provides for transition to a uniform statewide high-voltage transmission rate, based on the revenue requirements of all participating transmission owners associated with facilities operated at 200 kV and above. The transmission access charge methodology also requires the Utility and other transmission owners, during a ten-year transition period, to pay a charge intended to reimburse other transmission owners (who are generally new ISO participants) whose costs are higher than that embedded in the uniform rate. Under the ISO’sISO's application, the Utility’sUtility's obligation for this cost differential would be capped at $32 million per year during the ten-year transition period. A hearingIn December 2004, the FERC issued an Order in this matter was conducted atproceeding accepting the FERC in October and November 2003 and an initial decision from the presiding administrative law judge is scheduled to be issued in March 2004.ISO's transmission access charge methodology.


          Natural Gas

          30The Gas Accord

          Natural Gas
          The Gas Accord

                In 1998, the Utility implemented a ratemaking pact called the Gas Accord, under which the Utility’sUtility's natural gas transportation and storage services were separated for ratemaking purposes from its distribution services. The Gas Accord established natural gas transportation rates and natural gas


        storage rates. On December 18, 2003,16, 2004, the CPUC approved the Utility’s applicationa multi-party settlement agreement to retain the Gas Accord market structure, for 2004 and 2005, and resolvedresolve the rates, and terms and conditions of service for the Utility’sUtility's natural gas transportation and storage system for 2004.the three-year period of 2005-2007. The Utility continues to be at risk of not recovering its natural gas transportation and storage costs and does not have regulatory balancing account protection for over-collections or under-collections of most of its natural gas transportation or storage revenues.revenues, except for core local transmission revenue.

          Biennial Cost Allocation Proceeding

          Biennial Cost Allocation Proceeding

                The Utility’sUtility's natural gas distribution costs and balancing account balances are allocated to customers in the Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any overcollection, in the balancing accounts. Balancing accounts for gas distribution and public purpose program revenue requirementsother authorized expenses accumulate differences between authorized revenue requirementsamounts and actual base revenues.

          Natural Gas Procurement

          Natural Gas Procurement

                The Utility sets the natural gas procurement rate for core customers monthly based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.

                Under the core procurement incentive mechanism, or the CPIM, the Utility’sUtility's natural gas purchase costs (including Canadian and interstate capacity and volumetric transportation charges) are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is currently between 99% and 102% of the benchmark, are considered reasonable and fully recoverable, in customers’customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers’customers' rates, and the Utility’sUtility's customers receive three-fourths of the savings when the costs are below 99% of the benchmark. Any awards associated with the CPIM are reflected annually in the purchased natural gas balancing account after the close of the annual period ending October 31 that is used to measure the CPIM. These awards are not included in earnings until approved by the CPUC.

                On January 22,September 2, 2004, the CPUC openedissued an order establishing a rulemaking proceeding to establish policies and rules to ensure reliable, long-term supplies of natural gas to California. The order poses a series of questions and requires all gas utilities in California to provide information related to their natural gas procurement activities and their transportation and storage facilities. Among other things, the CPUC indicated that it may adopt rulesprocess, whereby utilities could receive CPUC pre-approval of contracts for interstate and Canadian pipeline capacity to support their natural gas procurement activities.

          Gas Public Purpose Program Surcharges

          Interstate and Canadian Natural Gas Transportation and Storage

                Authorized amounts for gas public purpose programs have been recovered through gas rate surcharges since January 1, 2001, pursuant to AB 1002, and are set on an annual basis. Effective March 1, 2005, the Utility intends to change its treatment of these gas surcharges to remove them from revenues and treat the surcharges as taxes, in accordance with a recent CPUC decision.

          Interstate and Canadian Natural Gas Transportation and Storage

                The Utility’sUtility's interstate and Canadian natural gas transportation agreements with third party service providers are governed by tariffs that detail rates, rules and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process and the applicable Canadian tariffs by the Alberta Energy and


        Utilities Board and the National Energy Board. The Utility’sUtility's agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utility’sUtility's core natural gas procurement business. Their purpose is to

        31

        transport natural gas from the points at which the Utility takes delivery of natural gas — typically(typically in Canada and the southwestern United States —States) to the points at which the Utility’sUtility's natural gas transportation system begins.
        Capacity Purchases on El Paso and Transwestern Pipelines


        Environmental Matters

                In July 2002, the CPUC ordered California investor-owned electric utilities to contract for additional amounts of El Paso pipeline capacity to gain firm access to the southwest natural gas producing basins. The CPUC believed that if the utilities had firm access rights, they would have been able to mitigate the gas price spikes that occurred during the energy crisis when shippers raised the price of gas at the California border. The CPUC pre-approved the costs of these contracts as just and reasonable. Since the July 2002 decision, the Utility has signed contracts for capacity on the El Paso pipeline costing approximately $50.8 million for the period from November 2002 to December 2007. The July 2002 decision also ordered the California investor-owned electric utilities to retain their then-current interstate pipeline capacity levels and sell any excess capacity to third parties under short-term capacity release arrangements. It also ordered that, to the extent the California investor-owned electric utilities comply with the decision, they will be able to fully recover their costs associated with existing capacity contracts.

             Under a previous CPUC decision, the Utility could not recover in rates any costs paid to Transwestern for natural gas pipeline capacity through 1997. The Utility pays approximately $22 million in annual reservation charges under the Transwestern contract. The Gas Accord provided for partial recovery of Transwestern costs after 1997. In January 2004, the CPUC approved a settlement with TURN that allows the Utility to fully recover Transwestern costs retroactive to July 2003.

             In December 2002, the CPUC granted the Utility’s request to recover in rates El Paso pipeline capacity costs and prepayments made to El Paso from all natural gas customers. The Utility began recovering these costs from all natural gas customers in March 2003. In January 2004, the CPUC re-allocated all the costs, including Transwestern costs incurred since July 2003, to the Utility’s core customers, because the pipeline capacity is used to serve core customers. The Utility’s noncore customers and core aggregation customers will receive a refund or bill credit for El Paso capacity costs paid by these customers between March 2003 and January 2004.

        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. The information below reflects current estimates that 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’sowner's responsibility and the availability of recoveries or contributions from third parties.


          General

                The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility’sUtility's personnel and the public. These laws and requirements relate to a broad range of activities, including:

        • The discharge of pollutants into air, water and soil;
        • The identification, generation, storage, handling, transportation, disposal, record keeping, labeling, reporting of, remediation of and emergency response in connection with, hazardous, and radioactive substances; and
        • Land use, including endangered species and habitat protection.

        32

          •
          The discharge of pollutants into air, water and soil;

          •
          The identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting of, remediation of and emergency response in connection with, hazardous, and radioactive substances; and

          •
          Land use, including endangered species and habitat protection.

                The penalties for violation of these laws and requirements can be severe, and may include significant fines, damages and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify or replace equipment, acquire permits and/or marketable allowances or other emission credits for facility operations and clean up or decommission waste disposal areas at the Utility’sUtility's current or former facilities and at third-party sites where the Utility may have disposed of wastes.

                Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility’sUtility's rates, subject to reasonableness review. Environmental costs associated with the clean up of sites that contain hazardous wastessubstances are subject to a special ratemaking mechanism.

        In 1994, the CPUC established a ratemaking mechanism under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims (e.g., for cleaning up the Utility’sUtility's facilities and sites where the Utility has sent hazardous substances) from customers. That mechanism allows the Utility to include 90% of the hazardous waste remediation costs in the Utility’sUtility's rates without review. Hazardous waste remediation costs in the future are likely to be significant. However, based on the Utility’sUtility's past experience, it believes that it can recover most of these costs in rates and through insurance claims.

                Ten percent of any net insurance recoveries associated with hazardous waste remediation sites are assigned to the Utility’sUtility's customers. The balance of any insurance recoveries, (90%) are retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. There also is a special sharing of the costs incurred pursuing recovery under insurance contracts. In



        connection with electricity industry restructuring, this mechanism may no longer be used to recover electricity generation-related clean-up costs for contamination caused by events occurring after January 1, 1998. The Utility cannot provide assurance, however, that these costs will not be material, or that the Utility will be able to recover its costs in the future.


          Air Quality

                The Utility’sUtility's generation plants and natural gas pipeline operations are subject to numerous air pollution control laws, including the Federalfederal Clean Air Act and similar state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen oxide and particulate matter. Fossil fuel-fired electric utility plants and gas compressor stations used in the Utility’sUtility's pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies.

                VariousDuring 2003 and 2004, various multi-pollutant initiatives have beenwere introduced in the U.S. Senate and House of Representatives. These initiatives include limits on the emissions of nitrogen oxide, sulfur dioxide, mercury and carbon dioxide, and some would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules. Hearings on legislation to amend the federal Clean Air Act have been held in the U.S. Senate but not in the House of Representatives. Similar legislation is expected to be introduced in 2005.

                As a result of the Utility’sUtility's divestiture of most of its fossil fuel-fired and geothermal generation facilities, the Utility’sUtility's nitrogen oxide emission reduction compliance costs have been reduced significantly. Two of the local air districts in which the Utility owns and operates fossil fuel-fired generation facilities have adopted final rules under the California Clean Air Act and the federal Clean Air Act that required reductions in nitrogen oxide emissions from the facilities of approximately 90% by 2004. The Utility is in compliance with these rules. The Utility is permitted to recover in customer rates through 2004 the Utility’sUtility's costs for its nitrogen oxide retrofit projects related to natural gas compressor stations on the Utility’sUtility's Line 300, which delivers gas from the southwest. Several air districts are considering nitrogen oxide rules that would apply to the Utility’sUtility's other natural gas compressor stations in California. Eventually, the rules are likely to require nitrogen oxide reductions of up to 80% at many of these natural gas compressor stations. Substantially all these costs will be capital costs which the Utility expects to recover through rates.

        33

        In addition, current federal and state regulatory initiatives particularly at the federal level, could increase the Utility’sUtility's compliance costs and capital expenditures primarily with respect to the Utility’sUtility's gas transportation facilities, fleet and fuel storage tanks, to comply with laws relating to emissions of carbon dioxide and other greenhouse gases, particulates and other toxic pollutants. If enacted, these laws could require the Utility to replace equipment, install additional pollution controls, purchase various emission allowances, or curtail operations. Although associated costs and capital expenditures could be material, the Utility expects that it would be able to recover these costs and capital expenditures in rates.


          Water Quality

                The federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or the U.S. Environmental Protection Agency, or the EPA. The Utility’sUtility's generation facilities are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Utility’sUtility's steam-electric generation facilities comply in all material respects with the discharge constituents standards and the thermal standards. In addition, under the federal Clean Water Act, the Utility is required to demonstrate that the location, design, construction and capacity of generation facility cooling water intake structures reflect the best


        technology available for minimizing adverse environmental impacts at its existing water-cooled thermal plants. The Utility has submitted detailed studies of each steam-electric generation facility’sfacility's intake structure to various governmental agencies and each power plant’splant's existing intake structure was found to meet the best technology available requirements.

                The Utility’sUtility's Diablo Canyon power plant employs a “once-through”"once-through" cooling water system that is regulated under a National Pollutant Discharge Elimination System, or NPDES, permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at aan average temperature of no more than 22 degrees above the temperature of the 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, the Diablo Canyon power plant’splant's discharge was not protective of beneficial uses.

                In October 2000, the Utility and the Central Coast Board reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility’sUtility's discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology meets the best technology available requirements. As part of the Central Coast settlement agreement, the Utility has agreed to take measures to preserve certain acreage north of the plant and will fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the Central Coast settlement agreement. On June 17, 2003, the Central Coast settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General’sGeneral's Office. A condition to the effectiveness of this settlement agreement is that the Central Coast Board renew Diablo Canyon’sCanyon's NPDES permit. However, at

                At its July 10, 2003 meeting, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported thisthe Central Coast settlement agreement accepted in March 2003, and the Central Coast Board requested its staffa team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures. The California Attorney General filed a claim in the Utility’s Chapter 11 proceeding on behalf ofmeasures for Central Coast Board staff. In January 2005, the Central Coast Board seeking unspecified penaltiespublished the scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and other reliefif the Utility ultimately is required to implement the projects proposed in connection with the Diablo Canyon power plant’s operationdraft report, it could incur costs of its cooling water system.up to approximately $30 million. The Utility is seeking withdrawal of this claim from the Utility’s Chapter 11 proceeding.would seek to recover these costs through rates charged to customers.

                In addition, on AprilJuly 9, 2002,2004, the EPA proposedpublished regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing electricity generation facilities using over 50 million gallons per day, typically including some form of “once-through”"once-through" cooling. The Utility’sUtility's Diablo Canyon, Hunters Point and Humboldt Bay power plants are among an estimated 539 generation

        34

        facilities nationwide that would beare affected by this rulemaking. The proposed regulations call forestablish a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. Significant capital investment may be required to achieve the standardsstandards. The regulations allow site-specific compliance determinations if a facility's cost of compliance is significantly greater than either the regulations are adopted as proposed.benefits achieved or the compliance costs considered by the EPA. The final regulations are scheduled to be issued in February 2004.
        Utility is developing compliance strategies for each plant.

                In mid-January 2004, hexavalent chromium was detected inThe Utility has a sample taken fromcomprehensive program to monitor a network of groundwater monitoring wellwells near the Utility’sUtility's Topock natural gas compressor station located near Topock, Arizona. This Needles, California. In mid-January 2004 and again in mid-February 2005, hexavalent chromium was detected in samples taken from groundwater



        monitoring well iswells located approximately 15065 feet from the Colorado River. While hexavalent chromium had been detected during previous sampling of other monitoring wells located further from the river, previous samples from this well had not shown any detectable hexavalent chromium. The Utility is cooperating with the California Department of Toxic Substances Control, or DTSC, other state agencies, and appropriate federal agencies, and other interested parties, to develop a plan to ensure that the hexavalent chromium does not impact the Colorado River. In 2004, the Utility took interim measures to control the chromium plume via extracting impacted groundwater and spent approximately $23.6 million. The Utility plans to continue these activities and work toward the development of a final plan to address the plume in 2005. The Utility currently estimates that it will spend at least $25 million in 2005 with respect to this matter. The Utility is currently in the process of obtaining additional samples from these and other wells and testing these additional samples. Although implementation of the planwork at this site poses several technical and regulatory obstacles, the Utility does not expect the outcome inof this matter to have a material adverse effect on its results of operations or financial condition.


          Endangered Species

                Many of the Utility’sUtility's facilities and operations are located in or pass through areas that are designated as critical habitats for federal or state-listed endangered, threatened or sensitive species. The Utility may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated near the Utility’sUtility's facilities or operations. The Utility is seeking to secure “habitat"habitat conservation plans”plans" to ensure long-term compliance with the state and federal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.


          Hazardous Waste Compliance and Remediation

                The Utility’sUtility's facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act, or RCRA, and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of required health studies. In the ordinary course of the Utility’sUtility's operations, the Utility generates waste that falls within CERCLA’sCERCLA's definition of a hazardous substance and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

                The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state and local 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 issued by the EPA under RCRA and CERCLA, state hazardous waste laws and other environmental requirements.

                The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, compressor stations and sites where the Utility stores, recycles and disposes 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.

        35



                Operations at the Utility’sUtility's current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal generation facilities and most of its fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies.

                In addition, the federal Toxic Substances Control Act regulates the use, disposal and cleanup of polychlorinated biphenyls, or PCBs, which are used in certain electrical equipment. During the 1980s, the Utility initiated two major programs to remove from service all of the distribution capacitors and network transformers containing high concentrations of PCBs. These programs removed the vast majority of PCBs existing in the Utility’sUtility's electricity distribution system.

                The Utility is 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 from the mid-1800s through the early 1900s, manufactured gas plants produced lampblack and tar residues. The lampblack and tar residues are byproducts of a process that the Utility, 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’sUtility'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 owns all or a portion of 28 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 these sites. The Utility spent approximately $8$5.8 million in 20032004 and expects to spend approximately $6$7.2 million in 20042005 on these projects. The Utility expects that expenses will increase as remedial actions related to these sites are approved by regulatory agencies. In addition, approximately 68 other manufactured gas plants in the Utility’sUtility's service territory are now owned by others. The Utility has not incurred any significant costs associated with these non-owned sites, but it is possible that the Utility may incur additional cleanup costs related to these sites in the future if hazardous substances for which the Utility has liability are found.

                Under environmental laws such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of waste from the Utility’sUtility's facilities, or to pay for associated cleanup costs or natural resource damages. The Utility is currently aware of eight such sites where investigation or cleanup activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility has been directed to perform site studies and any necessary remedial measures by regulatory agencies. At the Casmalia disposal facility 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 the Utility and the other parties to perform certain site investigation and mitigation measures.

                In addition, the Utility 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 that it no longer owns or never owned. Remedial actions may include investigations, health and ecological assessments and removal of wastes.

                The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and the Utilityit can estimate a range of reasonably likely cleanupclean-up costs. The Utility reviews its remediation liability on a quarterly basis for each site where the Utilityit may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, enacted laws and regulations, experience gained at similar sites, and an assessment of 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 costs at the lower end of this range. It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the Utility’sUtility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper end of the cost range using reasonably possible outcomes least favorable to the Utility.

        36

                The Utility had an undiscounted environmental remediation liability of approximately $327 million at December 31, 2004, and approximately $314 million at December 31, 2003, and $331 million at2003. During the year ended December 31, 2002. During 2003,2004, the liability was reducedincreased by approximately $17$13 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately $314$327 million accrued at December 31, 2003,2004, includes approximately $104$102 million related to the pre-closing remediation liability associated with divested generation facilities and approximately $210$225 million related to remediation costs for those generation facilities that the Utility still owns, natural gas gathering sites, compressor stations, third-party disposal sites, and manufactured gas plant sites that either are either owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites. Of the approximately $314$327 million environmental remediation liability, approximately $147$144 million has been included in prior rate-settingrate setting proceedings and the Utility expects that approximately $116$141 million will be allowable for inclusion in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’sUtility's ultimate obligations may be subject to refund to ratepayers.customers.

                The Utility’sUtility's undiscounted future costs could increase to as much as $422$480 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than anticipated. The $422amount of approximately $480 million amount does not include an estimate for the costscost of remediation at known sites owned or operated in the past by the Utility’sUtility's predecessor corporations for which the Utility has not been able to determine whether a liability exists.

          The California Attorney General, on behalf of various state environmental agencies, filed claims in the Utility’s Chapter 11 proceeding for environmental remediation at numerous sites totaling approximately $770 million. For most of these sites, remediation is ongoing in the ordinary course of business or the Utility is in the process of remediation in cooperation with the relevant agencies and other parties responsible for contributing to the cleanup. Other sites identified in the California Attorney General’s claims may not, in fact, require remediation or cleanup actions. The Utility’s Plan of Reorganization provides that the Utility intends to respond to these types of claims in the ordinary course of business and since the Utility has not argued that the Chapter 11 proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the California Attorney General’s claims seeking specific cash recoveries are unenforceable. Environmental claims in the ordinary course of business will not be discharged in the Utility’s Chapter 11 proceeding and will pass through the Chapter 11 proceeding unimpaired.

          Nuclear Fuel Disposal

                Under the Nuclear Waste Policy Act of 1982, or 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 permanent disposal sites be in operation by 1998. Consistent with the law, the Utility entered into a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Utility’sUtility's nuclear power facilities beginning not later than January 1998. The DOE has been unable to meet its contractual commitment to begin accepting spent fuel. First, there was a delay in identifying a storage site. Then, after the DOE selected Yucca Mountain, Nevada for the site, protracted litigation has prevented the DOE from constructing the storage facility. The DOE’sDOE's current estimate for an available site to begin accepting physical possession of the spent nuclear fuel is 2010. However, considerable uncertainty exists regarding when the DOE will begin to accept spent fuel for storage or disposal. Under the Utility’sUtility's contract with the DOE, if the DOE completes a storage facility by 2010, the earliest Diablo Canyon’sCanyon's spent fuel would be accepted for storage or disposal would be 2018.

                On January 22, 2004, the Utility filed separate complaints in the U.S. Court of Federal Claims against the DOE alleging that the DOE has breached its contractual obligation to move used nuclear fuel from Diablo Canyon and Humboldt Bay Unit 3 to a national repository beginning in 1998. The complaints seek recovery of the Utility’sUtility's costs incurred for the planning and development of on-site storage at both facilities as a result of the DOE’sDOE's failure to meet its obligations. The Utility’sUtility's complaints are similar to complaints filed by at least 20 other utilities with nuclear facilities.


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                Under current operating procedures,At the Utility believes that theprojected level of operation for Diablo Canyon, Diablo Canyon power plant’splant's existing spent fuel pools have sufficient capacity to enable it to operate through approximately 2007. It is unlikely that an interim or permanent DOE storage facility will be available by 2007. Therefore,The NRC granted authorization to the Utility has applied to the NRC for a licensein March 2004 to build an on-site dry cask storage facility to store spent fuel atthrough approximately 2021 for Unit 1 and to 2024 for Unit 2. Several intervenors appealed the NRC's decision to the U.S. Court of Appeals for the Ninth Circuit. Oral arguments on that appeal are expected in the first quarter of 2005 with a decision anticipated in the second half of 2005. PG&E Corporation and the Utility cannot predict the outcome of these appeals.

                In April 2004, San Luis Obispo County (the California county where Diablo Canyon power plant, pending disposal oris located) issued a permit under the California Coastal Act, subject to a number of conditions. The Utility, along with several other interested parties, filed appeals of the County's decision with the California Coastal Commission. The Utility's appeal challenged one of the conditions pertaining to the granting of public access to the coast and other portions of the Utility's property surrounding Diablo Canyon. On December 8, 2004, the California Coastal Commission granted the Utility's application for a coastal development permit authorizing it to proceed with its planned construction of an on-site dry cask storage at a DOE facility. The NRC has provided initial approvals forCommission granted the Utility's appeal, denied the appeals of other parties and conducted a de novo review of the application. The Commission's December 8, 2004 decision requires that the Utility provide expanded public access to the coast and other lands surrounding Diablo Canyon, although such public access is less expansive than the County had originally required and will be subject to a one-year study process. Construction of the on-site dry cask storage facility and is expected to complete its authorization processstart in early 2004. The Utility also has initiated the process for obtaining a required California Costal Commission permit forsecond quarter of 2005 after grading permits are obtained from the facility. IfCounty of San Luis Obispo.

                To provide another storage alternative in the event construction of the dry cask storage facility is not approved or is delayed, the Utility also is pursuinghas requested that the NRC approval ofapprove another storage option to install a temporary storage rack in each unitunit's existing spent fuel storage pool that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 to 2011. During this additional period of time, the Utility alsoThis temporary option would pursue NRC approval for a high density reracking of both units, which, if approved, would allow the Utilitynot require local or California Coastal permission permits to operate both units until shortly before the licenses expire in 2021 for Unit 1 and 2025 for Unit 2.be obtained. If the Utility is unsuccessful in permitting and constructing the on-site dry cask storage facility is not completed and itthe Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operations of Diablo Canyon may have to be curtailed or halted until such time as additional spent fuel can be safely stored.

                In July 1988, the NRC gave the Utility final approval to store radioactive waste from the Utility’sUtility's retired nuclear generating facility, Humboldt Bay Unit 3, at the plant until 2015 before ultimately decommissioning the unit. The Utility has agreed to remove all spent fuel when the federal disposal site is available. In 1988, the Utility completed the first step in the decommissioning of Humboldt Bay Unit 3 and placed the unit into SAFSTOR, a condition of monitored safe storage in which the unit will be maintained until the spent nuclear fuel is removed from the spent fuel pool and the facility is dismantled. The used fuel assemblies currently are stored in metal racks submerged in a pool of water called a wet storage pool. The specially designed storage pool is constructed of steel-reinforced concrete and lined with stainless steel.

                In June 2004, the Utility reported to the NRC that the Utility was unable to account for all of the used fuel segments from Humboldt Bay Unit 3 that the Utility's records indicate were sent to storage and that the Utility was evaluating whether the used fuel was placed in the storage pool. Although the used fuel segments have not been found after an initial search of the pool, the Utility is continuing its efforts to search other, less accessible locations in the pool. It is possible that a complete search may not be concluded until the 390 used fuel assemblies, along with other components, are removed from the pool, as part of the plant decommissioning process currently set for 2009.

        The Utility has filed an application in December 2003 with the NRC seeking authorization to build an on-site dry cask storage facility at Humboldt Bay Unit 3. The Utility plans to file an application with the California Coastal Commission for a permit to build the facility. Transfer of spent fuel to a dry cask facility would



        allow early decommissioning of Humboldt Bay Unit 3. The Utility anticipates that, if it were licensed to employ an on-site dry cask storage facility, the Utility would receive a 20-year initial license for on-site dry cask storage with the opportunity to receive a 20-year renewal term.


          Nuclear Decommissioning

                Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility’sUtility's nuclear power facilities consist of two units at the Diablo Canyon power plant and the retired facility at Humboldt Bay Unit 3. For ratemaking purposes, the eventual decommissioning of Diablo Canyon Unit 1 is scheduled to begin in 2021 and to be completed in 2040. Decommissioning of Diablo Canyon Unit 2 is scheduled to begin in 2025 and to be completed in 2041, and decommissioning of Humboldt Bay Unit 3 is scheduled to begin in 20062009 and be completed in 2015.

                The estimated nuclear decommissioning costscost for the Diablo Canyon power plant and Humboldt Bay Unit 3 areis approximately $1.83 billion in 20032004 dollars (or approximately $5.25 billion in future dollars). These estimates are based on a 2002 decommissioning cost study and are prepared in accordance with CPUC requirements and are used in the Utility’sUtility's Nuclear Decommissioning Costs Triennial Proceeding discussed below. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’sUtility's nuclear plants. Actual decommissioning costs are expected to vary from this estimate because of changes in assumed dates of decommissioning, regulatory requirements, technology, costs of labor, materials and equipment.

                The estimated nuclear decommissioning cost described above is used for regulatory purposes. Under generally accepted accounting principles, or GAAP, the decommissioning cost estimate is calculated using a different method. In accordance with Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," the Utility adjusts its nuclear decommissioning obligation to reflect the fair value of decommissioning its nuclear power facilities. In addition, the Utility records the Utility's total nuclear decommissioning obligation as an asset retirement obligation on the Utility's Consolidated Balance Sheet. The total nuclear decommissioning obligation accrued in accordance with GAAP was approximately $1.2 billion at December 31, 2004 and $1.1 billion at December 31, 2003.

                The CPUC has established the Nuclear Decommissioning Costs Triennial Proceeding to determine the Utility’sUtility's estimated decommissioning costs and to establish the associated annual revenue requirement and escalation factors for consecutive three-year periods. In October 2003, the CPUC issued a decision in the 2002 Nuclear Decommissioning Costs Triennial Proceeding (covering 2003 through 2005) finding that the funds in the Diablo Canyon nuclear decommissioning trusts are sufficient to pay for the Diablo Canyon power plant’s eventual decommissioning. The decision also set the annual decommissioning fund revenue requirement for

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        Humboldt Bay Unit 3 at approximately $18.5 million and granted the Utility’s request to begin decommissioning Humboldt Bay Unit 3 in 2006 instead of 2015. The decision further granted the Utility’s request of approximately $8.3 million for Humboldt Bay Unit 3 SAFSTOR operating and maintenance costs. The total adopted annual revenue requirement of approximately $26.7 million represents a $4.5 million decrease from the previously adopted revenue requirement of approximately $31.2 million, which included amounts for both Humboldt Bay Unit 3 and Diablo Canyon. The CPUC also ordered the Utility to partially fund its 2004 revenue requirement with approximately $10 million that the Utility collected in rates in 2000 for its nuclear decommissioning revenue requirement but that the Utility did not contribute to the trusts due to the Utility’s cash conservation needs during the energy crisis.

             The Utility’sUtility's revenue requirements for nuclear decommissioning costs are recovered from ratepayerscustomers through a nonbypassable charge that will continue until those costs are fully recovered.

                Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The Utility has three decommissioning trusts for its Diablo Canyon and Humboldt Bay Unit 3 nuclear facilities. The Utility has elected that two of these trusts be treated under the Internal Revenue Code as qualified trusts. If certain conditions are met, the Utility is allowed a deduction for the payments made to the qualified trusts. These payments cannot exceed the amount collected from ratepayerscustomers through the decommissioning charge. The qualified trusts are subject to a lower tax rate on income and capital gains, thereby increasing the trusts’trusts' after-tax returns. Among other requirements, to maintain the qualified trust status, the Internal Revenue Service, or IRS, must approve the amount to be contributed to the qualified trusts for any taxable year. The remaining non-qualified trust is exclusively for decommissioning Humboldt Bay Unit 3. The Utility cannot deduct amounts contributed to the non-qualified trust until the decommissioning costs are actually incurred.

                In 2003,2004, the Utility collected approximately $22.6$18.4 million in rates and contributed approximately $21.3$18.4 million, on an after-tax basis, to the nuclear decommissioning trusts. For 2004,2005, the Utility is



        authorized to collect approximately $18.5$18.4 million in rates for decommissioning Humboldt Bay Unit 3. Of this amount, the Utility expects to contribute approximately $13.3$18.4 million, on an after-tax basis, to the qualified and non-qualified trusts for Humboldt Bay Unit 3. The Utility has requested the IRS approve the new amounts to be contributed to the qualified trusts for Humboldt Bay Unit 3. If the IRS does not approve the request, the Utility must withdraw any contributions it made to the qualified trusts for 2003 and 2004 and contribute the withdrawn amounts, on an after-tax basis, to the non-qualified trust. The Utility would likely request that the CPUC approve an increase in revenue requirements to make up for the reduced amount contributed to the non-qualified trust due to the reduced rate of return attributable to taxestaxes.

                The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility’sUtility's nuclear facilities. The trusts maintain substantially all of their investments in debt and equity securities. All earnings on the fundsassets held in the trusts, net of authorized disbursements from the trusts and investment management and administrative fees, are reinvested. Amounts may not be released from the decommissioning trusts until authorized by the CPUC. At December 31, 2003,2004, the Utility had accumulated decommissioning trust funds with an estimated fair value of approximately $1.4$1.6 billion, based on quoted market prices and net of deferred taxes on unrealized gains.

                For more information about nuclear decommissioning, see Note 9 of the Notes to the Consolidated Financial Statements in the Annual Report.


          Electric and Magnetic Fields

                Electric magnetic fields, or EMFs, naturally result from the generation, transmission, distribution and use of electricity. In January 1991, the CPUC opened an investigation to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with EMFs 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 EMFs, 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 EMFs from new or upgraded utility facilities. California energy utilities were required to fund an EMF education program and

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        an EMF research program managed by the California Department of Health Services. As part of the Utility’sUtility's effort to educate the public about EMFs, the Utility 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.

                In October 2002, the California Department of Health Services released its report, based primarily on its review of studies by others, evaluating the possible risks from EMFs, to the CPUC and the public. The report’sreport's conclusions contrast with other recent reports by authoritative health agencies in that the California Department of Health Services’Services' report has assigned a higher probability to the possibility that there is a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis and miscarriages.

                It is not yet clear what actions the CPUC will take to respond to this report. In August 2004, the CPUC opened a rulemaking proceeding to determine if there are improvements that should be made to the CPUC's existing rules and regulations concerning EMFs. Possible outcomes include, but are not limited to, continuation of current policies and imposition of more stringent measures to mitigate EMF exposures. The Utility cannot estimate the costs of such mitigation measures with any certainty at this



        time. However, such costs could be significant, depending on the particular mitigation measures undertaken, especially if the Utility must ultimately relocate existing power lines.

                The Utility currently is not involved in third-party litigation concerning EMFs. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMFs 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 EMFs are similarly barred. The Utility was one of the defendants in civil litigation in which plaintiffs alleged personal injuries resulting from exposure to EMFs. 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 EMFs and barred plaintiffs’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.


        Item 2.Properties.
        		Properties.

                The Utility’sUtility's corporate headquarters consist of approximately 1.8 million square feet of office space located in several buildings in San Francisco, California. In addition to this corporate office space, the Utility owns or has obtained the right to occupy and/or use real property comprising the Utility’sUtility's electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, all of which are described above under “— Electricity"Electricity Utility Operations”Operations" and “— Gas"Gas Utility Operations.”" In total, the Utility occupies 9.3 million square feet, including approximately 975,000 square feet of leased office space. The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits or licenses from private landowners or governmental authorities.

                The Utility currently owns approximately 170,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements or donate to public agencies or non-profit conservation organizations under the settlement agreement with the CPUC.Settlement Agreement. Approximately 44,000 acres of this land may be either donated or encumbered with conservation easements. The remaining land contains the Utility’sUtility's or a joint licensee’slicensee's hydroelectric generation facilities and may only be encumbered with conservation easements. As contemplated in the Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council, or the Council. The Utility has appointed one out of 18 members of the board of directors of the Council. Other board members include representatives of federal and state agencies, non-governmental organizations, and tribal interests. The Council will recommend a plan to preserve the 140,000 acres to the Utility by April��2007. If the Council reaches consensus on the plan, the Utility will seek regulatory approval of the transactions required to implement the plan. If the Council is unable to reach consensus on all or part of the plan, the Utility will seek regulatory approval of the transactions required to implement its own plan, along with a description of the positions of the disputing board members.

                PG&E Corporation also leases approximately 74,000 square feet of office space from a third party in San Francisco, California. This lease expires in 2005.2012.


        Item 3.Legal Proceedings.
        		Legal Proceedings.

                In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business.

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        Pacific Gas and Electric Company Chapter 11 Filing

                On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California. The factors that causedOn April 12, 2004, the Utility's plan of reorganization under Chapter 11 became effective.



        On this date, the effective date, the Utility to take this action are discussed in MD&A and in Note 2 ofemerged from Chapter 11. On the Notes to the Consolidated Financial Statements in the Annual Report, which is incorporated by reference into this report. During the Utility’s Chapter 11 proceeding,effective date, the Utility has retained controlpaid all valid claims, deposited funds into escrow accounts for the payment of its assetsdisputed claims upon their resolution, reinstated certain obligations, and is authorized to operate its business as a debtor-in-possession while it is subject to the jurisdiction of the bankruptcy court.paid other obligations.

                David A. Coulter, a director of the Utility, is Vice Chairman of J.P. Morgan Chase & Co. and J.P. Morgan Chase Bank. J.P. Morgan Trust Co. of Delaware submitted a proof of claim in the Utility’sUtility's Chapter 11 case for approximately $1.45 million relating to its ownership interest in shares of the Utility’sUtility's preferred stock. The bankruptcy court disallowed this claim. J.P. Morgan Chase Bank submitted a proof of claim for approximately $173 million, related to its provision of a stand-by letter of credit which provides credit and liquidity support for certain of the Utility’sUtility's pollution control bonds. This claim was paid upon the Effective Date of the Utility's plan of reorganization. Both entities are subsidiaries of J.P. Morgan Chase & Co.

                In September 2001, PG&E Corporation and the Utility submitted aThe Utility's plan of reorganization that proposed to disaggregateincorporated the Utility’s current businesses. The CPUC, later joinedterms of the settlement agreement approved by the Official Committee of Unsecured Creditors, or OCC, submitted a competing proposed plan of reorganization that did not provide for disaggregation ofCPUC on December 18, 2003, and entered into among the Utility’s businesses. As discussed above,CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the CPUC, PG&E Corporation and the Utility entered into the Settlement Agreement that contemplated a new plan of reorganization to supercede the competing plans. Under the Settlement Agreement, the Utility remains vertically integrated. On December 22, 2003, the bankruptcy court confirmed the Plan of Reorganization that fully incorporates theUtility's Chapter 11 proceeding, or Settlement Agreement.

             On December 30, 2003, the City of Palo Alto filed a motion with the bankruptcy court for a stay of the bankruptcy court’s order confirming the Plan of Reorganization pending the City of Palo Alto’s appeal of the confirmation order to the U.S. District Court for the Northern District of California, or District Court. The two CPUC Commissioners who did not vote to approve the Settlement Agreement joined in the City of Palo Alto’s motion. On January 5, 2004, the bankruptcy court denied the request for a stay. In January 2004, the City of Palo Alto and the two CPUC Commissioners filed appeals in the District Court of the bankruptcy court’s confirmation order.

             On January 20, 2004, the City of Palo Alto, the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, filed separate applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the Settlement Agreement. CCSF, Aglet and the ORA also filed a joint application for rehearing. Although the CPUC is not required to act on the applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review.

        Under the Settlement Agreement, the CPUC has waived all existing and future rights of sovereign immunity, and all other similar immunities, as a defense in connection with any action or proceeding concerning the enforcement of, or other determination of the parties’parties' rights under the Settlement Agreement, the Planplan of Reorganizationreorganization or the confirmation order. The CPUC also consented to the jurisdiction of any court or other tribunal or forum for those actions or proceedings, including the bankruptcy court. The CPUC’sCPUC's waiver is irrevocable and applies to the jurisdiction of any court, legal process, suit, judgment, attachment in aid of execution of a judgment, attachment before judgment, set-off or any other legal process with respect to the enforcement of, or other determination of the parties’parties' rights under, the Settlement Agreement, the Planplan of Reorganizationreorganization or the confirmation order. The Settlement Agreement contemplates that neither the CPUC nor any other California entity acting on its behalf may assert immunity in an action or proceeding concerning the parties’parties' rights under the Settlement Agreement, the Planplan of Reorganizationreorganization or the confirmation order.

                The Settlement Agreement generally terminates nine years after the effective date of the Planplan of Reorganization,reorganization, except that the rights of the parties to the Settlement Agreement that vest on or before termination, including any rights arising from any default under the Settlement Agreement, will survive termination for the purpose of enforcement. The parties agreed that the bankruptcy court will have jurisdiction

        41

        over the parties for all purposes relating to enforcement of the Settlement Agreement, the Planplan of Reorganizationreorganization and the confirmation order. The bankruptcy court retains jurisdiction to resolve remaining disputed claims. The parties also agreed that the Settlement Agreement, the Planplan of Reorganizationreorganization or any order entered by the bankruptcy court contemplated or required to implement the Settlement Agreement or the Planplan of Reorganizationreorganization will be irrevocable and binding on the parties and enforceable under federal law notwithstanding any future decisions or orders of the CPUC.

                As requiredOn March 16, 2004, the CPUC denied separate applications that had been filed by the City of Palo Alto, the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, requesting that the CPUC rehear and reconsider its December 18, 2003 decision approving the Settlement Agreement. CCSF, Aglet and the CPUC's Office of Ratepayer Advocates, or ORA, also filed a joint application for rehearing. On April 15, 2004, CCSF and Aglet each filed a petition with the California Court of Appeal seeking review of the CPUC's December 18, 2003 decision approving the Settlement Agreement and the Utility has requestedCPUC's March 16, 2004 decision denying applications for rehearing of its December 18, 2003 decision. CCSF and Aglet allege that the Settlement Agreement violates California law, among other claims. CCSF requests that the appellate court hear and review the CPUC's decisions, approving the Settlement Agreement and Aglet requests that the CPUC's decisions be overturned. Three California state senators have filed a stay of all proceedings before the FERC, the NRC, the SEC and other regulatory agencies relating to approvals sought to implement the original plan of reorganization. The Utility also has suspended all actions to obtain or transfer licenses, permits and franchises to implement the original plan of reorganization. On the effective datebrief in support of the confirmed PlanCCSF and Aglet petitions. The California Court of Reorganization or as soon thereafter as practicable,Appeal has not yet acted on the Utility andpetitions. PG&E Corporation will withdrawand the Utility believe the petitions are without merit and should be denied.



                On July 15, 2004, the U.S. District Court for the Northern District of California, or abandon all applications for these regulatory approvals.

             There are several legal proceedings still pending in connectionthe District Court, dismissed the appeals of the bankruptcy court's confirmation order that had been filed by the two CPUC commissioners who did not vote to approve the Settlement Agreement. These two commissioners also appealed the District Court's order with the original plan of reorganization. On May 14, 2003, the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, heard oral argument inCircuit. An appeal of the appealconfirmation order filed by the CPUC and other partiesCity of an order issued byPalo Alto remains pending at the District Court finding that the U.S. Bankruptcy Code expressly preempts “non-bankruptcy laws that would otherwise apply to bar, among other things, transactions necessary to implement the reorganization plan.” The District Court’s order had reversed an earlier ruling by the bankruptcy court that found that bankruptcy law did not expressly preempt certain non-bankruptcy laws in connection with the original plan of reorganization, but that it could be implied to preempt non-bankruptcy laws in certain circumstances.

             On November 19, 2003, the Ninth Circuit issued a decision agreeing with the District Court’s finding that a Chapter 11 reorganization plan expressly preempts otherwise applicable non-bankruptcy laws. However, the Ninth Circuit ruled that the scope of such express preemption is limited to those non-bankruptcy laws relating to financial condition. The Ninth Circuit determined that neither the bankruptcy court nor the District Court had applied the proper standard of express preemption. It therefore reversed the District Court’s August 30, 2002, decision and remanded the matter back to the bankruptcy court for further proceedings to determine whether the Utility’s and PG&E Corporation’s original plan of reorganization satisfied the express preemption standard announced by the Ninth Circuit.

             Although the Ninth Circuit stated that the question of implied preemption was not before it in the appeal, it reaffirmed that implied preemption could apply under the Bankruptcy Code, even if express preemption did not. On December 10, 2003, the Utility and PG&E Corporation filed a petition to rehear the Ninth Circuit’s decision with the panel that issued the decision, and suggested that the full Ninth Circuit should rehear the issue, since it conflicts with other Ninth Circuit cases and cases from other Circuits.

             The Utility’s current Settlement Agreement and the confirmed Plan of Reorganization do not rely on the bankruptcy law preemption issues addressed in the Ninth Circuit decision.

        Implementation of the Plan of Reorganization is subject to various conditions, including the consummation of the public offering of long-term debt, the receipt of investment grade credit ratings and final CPUC approval of the Settlement Agreement. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not subject to any pending appeal or further right of appeal, or approval on behalf of the CPUC that, although subject to a pending appeal or further right of appeal, has been agreed by the Utility and PG&E Corporation to constitute final approval. Thus, the terms of the Plan of Reorganization permit the Utility and PG&E Corporation to cause the Plan of Reorganization to become effective (and permit the Utility to issue the long term debt) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. Until certain conditions or events regarding the effectiveness of the Plan of Reorganization discussed above are resolved further, PG&E Corporation and the Utility cannot conclude that the applicable accounting probability standard needed to record the regulatory assets contemplated by the Settlement Agreement has been met.Court. PG&E Corporation and the Utility believe that the Utility and the long-term debt to be issued will receive investment grade credit ratings.The Utility has targeted April 2004 to complete the saleappeals of the long-term debt, whichconfirmation order are without merit.

                Under applicable federal precedent, once the Utility expects to be the last conditionplan of reorganization has been "substantially consummated," any pending appeals of the Plan of Reorganization toconfirmation order should be satisfied. The Plan of Reorganization provides thatdismissed. If, notwithstanding this federal precedent, the effective date will occur 11 business days after allbankruptcy court's confirmation order or the conditions have been satisfiedSettlement Agreement is subsequently overturned or with respect to all conditions except those relating

        42

        to investment grade credit ratings, waived bymodified, PG&E Corporation and the Utility. There can be no assurance that the Settlement Agreement will not be modified on rehearing or appeal or that the Plan of Reorganization will become effective.

        Chapter 11 Filing of NEGT

             On July 8, 2003, NEGTUtility's financial condition and certain of its subsidiaries filed voluntary petitions for relief under the provisions of Chapter 11 in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. On July 29, 2003, two additional subsidiaries of NEGT also filed voluntary Chapter 11 petitions. NEGT also has filed a proposed plan of reorganization with the bankruptcy court that, if implemented, would eliminate PG&E Corporation’s equity interest in NEGT and its subsidiaries.

             In anticipation of NEGT’s Chapter 11 filing, PG&E Corporation’s representatives who previously served as directors of NEGT resigned on July 7, 2003 and were replaced with directors who are not affiliated with PG&E Corporation. As a result, PG&E no longer retains significant influence over NEGT. Accordingly, effective July 8, 2003, NEGT’s results of operations are no longer consolidated with those of PG&E Corporation and its results of operations through July 7, 2003 and for prior years have been reclassified as discontinued operations.could be materially adversely affected.

             For more information, see Note 5 of the Notes to the Consolidated Financial Statements in the Annual Report, which is incorporated by reference and filed as Exhibit 13 to this report.


        Pacific Gas and Electric Company vs. Michael Peevey, et al.

                On November 8, 2000, the Utility filed a lawsuit in the District Court against the CPUC commissioners. In this lawsuit, the Utility seeks a declaration that the federally tariffed wholesale electricity costs that the Utility had incurred to serve the Utility’sUtility's customers are recoverable in retail rates under the federal filed rate doctrine.

                The Utility’sUtility's complaint alleges that the wholesale electricity costs that the Utility has prudently incurred are paid pursuant to filed tariffs that the FERC has authorized and approved, and that, under the U.S. Constitution and numerous court decisions, such costs cannot be disallowed by state regulators. The Utility’sUtility's complaint also alleges that, to the extent that the Utility is denied recovery of these wholesale electricity costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of the Utility’sUtility's property. The Utility argues that the CPUC’sCPUC's decisions are preempted by federal law under the filed rate doctrine, which requires the CPUC to allow the Utility to recover in full it’sits reasonable purchase costs incurred under lawful rates and tariffs approved by the FERC, a federal governmental agency. The complaint also asserts claims under the Commerce Clause and the Due Process Clause of the U.S. Constitution. On January 29, 2001, the Utility’sUtility'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 Company was pending. On May 2, 2001, the court dismissed the Utility’sUtility's complaints without prejudice to re-filing at a later date, on the ground that the lawsuit was premature, since two CPUC decisions referenced in the complaint had not become final under California law. The court rejected all of the CPUC’sCPUC's other arguments for dismissal of the Utility’sUtility's complaint.

                In August 2001, the Utility re-filed the Utility’sUtility's complaint in the District Court based on the Utility’sUtility's belief that the CPUC decisions referenced in the court’scourt's May 2001 order had become final under California law. On October 31, 2001, the CPUC moved to dismiss the action. While the motion was under submission, the parties filed cross-motions for summary judgment.

                On July 25, 2002, the court denied the CPUC’sCPUC's motion to dismiss on all grounds, as well as the parties’parties' motions for summary judgment. While the court agreed with the Utility’sUtility's position that the filed rate doctrine applies to the federally-tariffed wholesale costs at which the Utility had purchased electricity, it held that certain triable issues of fact precluded entry of summary judgment in the Utility’sUtility's favor.

                On August 23, 2002, the CPUC filed an appeal to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. Pursuant to the Utility’sUtility's request, the District Court certified the appeal as “wholly"wholly without merit and, therefore, frivolous,”" and rejected the CPUC’sCPUC's request to stay the proceedings. On November 21,

        43

        2002, the Ninth Circuit stayed the District Court’sCourt's proceedings pending the CPUC’sCPUC's appeal. The appeal was fully briefed and the Ninth Circuit heard oral argument on March 10, 2003.



                Under the Settlement Agreement, the Utility willagreed to dismiss the filed rate case with prejudice on or as soon as practicable after the later of the effective date of the Planplan of Reorganizationreorganization and the date on which CPUC approval of the Settlement Agreement is no longer subject to appeal. Therefore, the Utility filed a motion to stay consideration of the appeal of the filed rate case. On August 11, 2003, the Ninth Circuit issued an order staying proceedings in the filed rate case. The Ninth Circuit has ordered the parties to file a status reportcase as requested by July 30, 2004.

        In re: Natural Gas Royalties Qui Tam Litigation

             This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (referred to as a relator in the terminology of the False Claims Act) on behalf of the United States of America against more than 330 defendants, including the Utility. The cases were consolidated for pretrial purposes inUtility has not yet dismissed its complaint, pending the U.S. District Court for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998.

             Under procedures established by the False Claims Act, the United States, acting through the DOJ, is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the DOJ declined to intervene in any of the cases.

             The complaints allege that the various defendants, most of whom are natural gas pipeline companies or their affiliates, incorrectly measured the volume and heating content of natural gas produced from federal or Indian leases. As a result, the relator alleges that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases.

             The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties and reasonable expenses associated with the litigation. The relator has filed a claim in the Utility’s Chapter 11 case for $2.5 billion, $2.0 billion of which is based upon the relator’s calculation of penalties against the Utility.

             The Utility believes the allegations to be without merit and intends to present a vigorous defense. The Utility believes that the ultimate outcome of the litigation will not have a material adverse effect onappeals of the Utility’s financial condition or resultsCPUC's approval of operations.the Settlement Agreement discussed above.


        Diablo Canyon Power Plant

                The Utility’sUtility's Diablo Canyon power plant employs a “once-through”"once-through" cooling water system, which is regulated under a NPDES permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the 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, 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, the Utility’sUtility's Diablo Canyon power plant’splant's discharge was not protective of beneficial uses.

                In October 2000, the Utility reached a tentative settlement of this matter with the Central Coast Board pursuant to which the Central Coast Board agreed to find that the Utility’sUtility's discharge of cooling water from the Utility’sUtility's Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available as defined in the Federal Clean Water Act. As part of the Central Coast settlement agreement, the Utility agreed to take measures to preserve certain acreage north of the plant and willto fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the Central Coast settlement agreement. On June 17, 2003, the Central Coast settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General’sGeneral's Office. A condition to the effectiveness of the

        44

        settlement agreement is that the Central Coast Board renew Diablo Canyon’sCanyon's NPDES permit. However, at

                At its July 10, 2003 meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the Central Coast settlement agreement accepted in March 2003, and the Central Coast Board requested its staffa team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures.

             The California Attorney General has filed a claim in the Utility’s Chapter 11 case on behalf ofmeasures for Central Coast Board staff. In January 2005, the Central Coast Board seeking unspecified penaltiespublished the scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and other reliefif the Utility ultimately is required to implement the projects proposed in connection with the Diablo Canyon power plant’s operationdraft report, it could incur costs of its cooling water system.up to approximately $30 million. The Utility is seeking withdrawal of this claim.

             On June 13, 2002, the Utility received a draft enforcement order from the California Department of Toxic Substances Control, or DTSC, alleging that the Utility’s Diablo Canyon power plant failedwould seek to maintain an adequate financial assurance mechanismrecover these costs through rates charged to cover closure costs for its hazardous waste storage facility for several months after the Utility’s Chapter 11 filing in 2001. The draft order sought $340,000 in civil penalties for the period during which the Utility were unable to comply with the DTSC’s requirements. The draft order also directed the Utility to maintain appropriate financial assurance on a going forward basis. On September 4, 2002, the Utility received a draft enforcement order from DTSC alleging a variety of hazardous waste violations at the Utility’s Diablo Canyon power plant. This draft order sought $24,330 in civil penalties.

             In April 2003, the Utility signed a final settlement agreement with DTSC, under which the Utility agreed to pay approximately $165,000 in civil penalties and approximately $30,000 in costs. The Utility paid these amounts in May 2003. The California Attorney General filed a claim in the Utility’s Chapter 11 case on behalf of DTSC, and the Utility is currently seeking withdrawal of those portions of the claim relating to financial assurance and hazardous waste matters.customers.

                The Utility believes that the ultimate outcome of these mattersthis matter will not have a material adverse impact on the Utility’sUtility's financial condition or results of operations.


        Complaints Filed by the California Attorney General and the City and County of San Francisco and Cynthia Behr

                On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court, or Superior Court, against PG&E Corporation and its directors, as well as against directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200, or Section 17200. Among other allegations, the California Attorney General alleged that past transfers of money from the Utility to PG&E Corporation, and allegedly from PG&E Corporation to other affiliates of PG&E Corporation,



        violated various conditions established by the CPUC in decisions approving the holding company formation. The California Attorney General alleged that the defendants violated these conditions when PG&E Corporation allegedly failed to provide adequate financial support to the Utility during the California energy crisis. The California Attorney General also alleged that the December 2000 and January and February 2001 ringfencing transactions, by which PG&E Corporation subsidiaries complied with credit rating agency criteria to establish independent credit ratings, violated the holding company conditions. (On January 9, 2002, the CPUC issued a decision interpreting the holding company condition regarding capital requirements (which it terms the “first priority condition”) and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies “infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve.” The three major California investor-owned energy utilities and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years’ understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The three major California investor-owned utilities and their parent holding companies appealed the CPUC’s interpretation of the first priority condition to various state appellate courts. The CPUC moved to consolidate all proceedings in the San Francisco state appellate court. The CPUC’s request for consolidation was granted and all the petitions are now before the California Court of Appeal for the First Appellate District in San Francisco, California. Oral argument is scheduled for March 5, 2004.

                The complaint seeks injunctive relief, the appointment of a receiver, restitution in an amount according to proof, civil penalties of $2,500 against each defendant for each violation of Section 17200, a total penalty of

        45

        not less than $500 million and costs of suit. The California Attorney General’sGeneral's complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility. In February 2002, PG&E Corporation filed a notice of removal in the bankruptcy court to transfer the California Attorney General’sGeneral's complaint to the bankruptcy court, as well as a motion to dismiss the lawsuit, or in the alternative, to stay the suit with the bankruptcy court. Subsequently, the California Attorney General filed a motion to remand the action to state court. In June 2002, the bankruptcy court held that federal law preempted the California Attorney General’sGeneral's allegations concerning PG&E Corporation’sCorporation's participation in the Utility’sUtility's Chapter 11 proceedings. The bankruptcy court directed the California Attorney General to file an amended complaint omitting these allegations and remanded the amended complaint to the San Francisco Superior Court. Both parties appealed the bankruptcy court’scourt's June 2002 order to the District Court.

                On August 9, 2002, the California Attorney General filed its amended complaint in the San Francisco Superior Court, omitting the allegations concerning PG&E Corporation’sCorporation's participation in the Utility’sUtility's Chapter 11 proceedings. PG&E Corporation and the directors named in the complaint have filed motions to strike certain allegations of the amended complaint. On February 28, 2003, the court denied the three motions to strike on the grounds that they were premature and stated that it would defer making a judgment on the merits of the defendants’ arguments until the factual context of the cases was more fully developed.

        On February 11, 2002, a complaint entitledCity and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in San Franciscothe Superior Court. The complaint contains some of the same allegations contained in the California Attorney General’sGeneral's complaint, including allegations of unfair competition. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation “took"took at least $5.2 billion from the Utility,”" and for unjust enrichment. The City seeks injunctive relief, the appointment of a receiver, payment to customers, disgorgement, the imposition of a constructive trust, civil penalties and costs of suit.

                After removing the City’sCity's action to the bankruptcy court in February 2002, PG&E Corporation filed a motion to dismiss the complaint. Subsequently, the City filed a motion to remand the action to state court. In June 2002, the bankruptcy court issued an amended order on motion to remand stating that the bankruptcy court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by the City and County, but remanding the Section 17200 cause of action to state court. Both parties appealed the bankruptcy court’scourt's remand order to the District Court.

        In addition, a third case, entitledCynthia Behr v. PG&E Corporation, et al., was filed on February 14, 2002, by a private plaintiff (who also has filed a claim under Chapter 11) in Santa Clara Superior Court also alleging a violation of Section 17200. The Behr complaint also names the directors of PG&E Corporation and the Utility as defendants. The allegations of the complaint are similar to the allegations contained in the California Attorney General’s complaint, but also include allegations of conspiracy, fraudulent transfer and violation of the California bulk sales laws. The plaintiff requests the same remedies as the California Attorney General, and, in addition, requests damages, attachment and restraints upon the transfer of defendants’ property. In March 2002, PG&E Corporation filed a notice of removal in the bankruptcy court to transfer the complaint to the bankruptcy court. Subsequently, the plaintiff filed a motion to remand the action to state court. In its June 2002 ruling mentioned above as to the California Attorney General’s and the City’s cases, the bankruptcy court retained jurisdiction over Behr’s fraudulent transfer claim and bulk sales claim, finding them to belong to the Utility’s estate. The bankruptcy court remanded Behr’s Section 17200 claim to the Santa Clara Superior Court. Both parties appealed the bankruptcy court’s remand order to the District Court.

             The San Francisco Superior Court has coordinated the California Attorney General’s case with the cases filed by the City and County of San Francisco and Cynthia Behr.

             On July 24, 2003, the District Court heard oral argument on the appeal and cross-appeal of the bankruptcy court’s remand order in the three cases.        On October 8, 2003, the District Court reversed, in part, the bankruptcy court’scourt's June 2002 decision and ordered the California Attorney General’sGeneral's restitution claims sent back to the bankruptcy court. The District Court found that these claims, estimated along with the City and County of San Francisco’sFrancisco's claims at approximately $5 billion, are the property of the Utility’sUtility's Chapter 11

        46

        estate and therefore are properly within the bankruptcy court’scourt's jurisdiction. Under the Plan of Reorganization, the Utility would releasehas released these claims. The District Court also affirmed, in part, the bankruptcy court’scourt's June 2002 decision and found that the California Attorney General’sGeneral's civil penalty and injunctive relief claims under Section 17200 could be resolved in San Francisco Superior Court, where a status conference has been scheduled for February 24, 2004.Court. The California Attorney General and the City and County of San Francisco have appealed this ruling to the Ninth Circuit.Circuit, where the appeal is currently pending.



                The defendants have filed motions to dismiss the appeals. No proceedings have been scheduled in bankruptcy court regarding the restitution claims. Under Section 17200,Superior Court has coordinated the California Attorney General is entitled to seek civil penalties of $2,500 against each defendant for each violation of Section 17200. The California Attorney General’s complaint asserted thatGeneral's case with the total civil penalties would be not less than $500 million. The bankruptcy court’s confirmation order provides that the California Attorney General’s andcase filed by the City and County of San Francisco’s claims are not released in connection with implementation of the Plan of Reorganization.

        Francisco.

             The defendants filed a motion to seek clarification from the District Court regarding whether the District Court’s October 2003 order reaches the restitution claims against the director defendants, as distinct from PG&E Corporation.        At a hearing on December 8, 2004, the Superior Court heard argument on the issue of how to determine the number of violations of Section 17200 for purposes of calculating the amount of potential civil penalties at issue. Under Section 17200, the Superior Court can impose a civil penalty for each violation of up to $2,500. On January 21, 2005, the Superior Court issued a tentative decision rejecting the "per victim" and "per [customer] bill" approaches advocated by the plaintiffs, standards that potentially could have resulted in November 2003, the Districtmillions of separate "violations." The Superior Court confirmed that its October 2003 order holdsfound that the defendants’ restitution claims againstappropriate standard was each transfer of money from the directors are alsoUtility to PG&E Corporation that plaintiffs allege violated Section 17200.

                The Superior Court stated that it would consider any non-substantive revisions to the property oftentative decision proposed by the Utility’s estate.parties at a case management conference to be held on February 25, 2005.

                PG&E Corporation believes that the applicable calculation methodology for civil penalties, if any violations were found, would not result in a material adverse effect on its financial condition or results of operations.


        Compressor Station Chromium Litigation

        The following 14 civil suits are pending in several California courts against the Utility relating to alleged chromium contamination: (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 July 25, 2000, in Los Angeles County Superior Court, (5) Baldonado v. Pacific Gas and Electric Company, filed October 25, 2000, in Los Angeles County Superior Court, (6) Gale v. Pacific Gas and Electric Company, filed January 30, 2001, in Los Angeles County Superior Court, (7) Fordyce v. Pacific Gas and Electric Company, filed March 16, 2001, in San Bernardino Superior Court, (8) Puckett v. Pacific Gas and Electric Company, filed March 30, 2001, in Los Angeles County Superior Court, (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 County Superior Court, (10) Bowers, et al. v. Pacific Gas and Electric Company, et al., filed April 20, 2001, in Los Angeles County Superior Court, (11) Boyd, et al. v. Pacific Gas and Electric Company, et al., filed May 2, 2001, in Los Angeles County Superior Court, (12)Martinez, et al. v. Pacific Gas and Electric Company, filed June 29, 2001, in San Bernardino County Superior Court, (13) Miller v. Pacific Gas and Electric Company, filed November 21, 2001, in Los Angeles County Superior Court, and (14) Lytle v. Pacific Gas and Electric Company, filed March 22, 2002, in Yolo County Superior Court.

                All of these civil actions are now pending in the Los Angeles Superior Court, except the Lytle case, which is pending in Yolo County. Currently there are approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals have filed proofs of claim in the Utility’sUtility's Chapter 11 case, most of whom are plaintiffs in the chromium litigation. Approximately 1,035 claimants have filed proofs of claim requesting approximately $580 million in damages and another approximately 225 claimants have filed claims for an “unknown"unknown amount.”"

                In general, plaintiffs and claimants allege that exposure to chromium at or near the Utility’sUtility's gas compressor stations located at Kettleman and Hinkley, California, and the area of California near Topock, Arizona caused personal injuries, wrongful death, or other injury and seek related damages. The bankruptcy court has granted certain claimants’ motionclaimants' motions for relief from stay so that the state court lawsuits pending before the Utility’sUtility's Chapter 11 filing can proceed.

        47



                The Utility is responding to the suits in which the Utility has been served and is asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including the statute of limitations, exclusivity of workers’workers' compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged.

        To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select plaintiffs from theAguayo, AcostaandAguilar cases for a test trial. Plaintiffs’Plaintiffs' counsel selected ten of these initial trial plaintiffs,, defense counsel selected seven of the plaintiffs, and one plaintiff and two alternates were selected at random. The Utility has filed 1314 summary judgment motions or motions in limine (motions to exclude potentially prejudicial information) challenging the claims of the trial test plaintiffs. TwoThe Los Angeles Superior Court began hearing argument on two of the motions in February 2004. At a hearing on February 14, 2005, the court indicated that it had signed orders denying these two motions, are scheduledbut the orders have not been delivered to the parties. The court set a trial date of January 9, 2006 for hearing in the first quarter of 2004, with the others toeighteen plaintiffs. The other motions will be scheduled thereafter. The trial of the test cases is scheduled to begin in March 2004. The Utility’s motion to dismiss the complaint in theAdamscase was granted. The plaintiffs in that case have until April 12, 2004 to file an amended complaint.heard throughout 2005.

                The Utility has recorded a reserve in the Utility’sUtility's financial statements in the amount of $160 million for these matters. The Utility believes that, in light of the reserves that have already been accrued with respect to this matter, the ultimate outcome of this matter will not have a material adverse impact on the Utility’sUtility's financial condition or future results of operations.


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

                Not applicable.


        EXECUTIVE OFFICERS OF THE REGISTRANTS

                “The"The names, ages and positions of PG&E Corporation executive officers,”" as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, or Exchange Act at December 31, 20032004 are as follows:

        Name
        		Age
        		Position
        R. D. Glynn, Jr. 6162 Chairman of the Board, Chief Executive Officer, and President
        P. A. Darbee 5051 Senior Vice President and Chief Financial Officer
        L. H. Everett54Senior Vice President and Assistant to the Chairman
        R. A. Jackson47Senior Vice President, Human Resources
        C. P. Johns 4344 Senior Vice President and Controller
        T. B. King43Executive Vice President and Chief of Utility Operations, Pacific Gas and Electric Company
        D. D. Richard, Jr. 5354 Senior Vice President, Public Affairs; Senior Vice President, Public Affairs Pacific Gas and Electric Company
        G. R. Smith 5556 Senior Vice President; President and Chief Executive Officer, Pacific Gas and Electric Company
        G. B. Stanley57Senior Vice President, Human Resources
        B. R. Worthington 5455 Senior Vice President and General Counsel

                All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through December 31, 2004, 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.

        48        Effective January 1, 2005, Peter A. Darbee became President and Chief Executive Officer of PG&E Corporation replacing Mr. Glynn, who continues to serve as Chairman of the Board of Directors of each of PG&E Corporation and Pacific Gas and Electric Company. Mr. Darbee also became a director of PG&E Corporation and Pacific Gas and Electric Company on January 1, 2005. Also, effective January 1, 2005, Christopher P. Johns became Senior Vice President and Chief Financial Officer replacing Mr. Darbee. Mr. Johns continues to be the Controller of PG&E Corporation. Effective January 1, 2005, Ms. Everett became Senior Vice President and Assistant to the Chief Executive Officer.


        Name
        		Position
        		Period Held Office
        R. D. Glynn, Jr. Chairman of the Board, Chief Executive Officer and President of PG&E Corporation January 1, 1998 to presentDecember 31, 2004
          Chairman of the Board, PG&E Corporation and Pacific Gas and Electric Company January 1, 1998 to present

        P. A. Darbee
         
        Senior Vice President and Chief Financial Officer
         
        July 9, 2001 to presentDecember 31, 2004
          Senior Vice President, Chief Financial Officer, and Treasurer September 20, 1999 to July 8, 2001

        L. H. Everett

        Senior Vice President and Assistant to the Chairman

        August 2, 2004 to December 31, 2004
          Vice President and Chief Financial Officer, Advance Fibre Communications, Inc.Assistant to the Chairman June 30,1, 2001 to August 1, 2004
        Vice President, Corporate Secretary, and Assistant to the ChairmanMay 1, 2001 to May 31, 2001
        Vice President and Corporate SecretaryJuly 1, 1997 to September 19, 1999April 30, 2001
        Vice President and Corporate Secretary, Pacific Gas and Electric CompanyNovember 1, 1996 to April 30, 2001

        R. A. Jackson

        Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric Company

        August 2, 2004 to present
        Vice President, Human Resources, PG&E CorporationJune 1, 2004 to August 1, 2004
        Vice President, Human Resources, Pacific Gas and Electric CompanyJune 1, 1999 to August 1, 2004

        C. P. Johns
         
        Senior Vice President and Controller
         
        September 19, 2001 to presentDecember 31, 2004
          Vice President and Controller July 1, 1997 to September 18, 2001
          Vice President and Controller, Pacific Gas and Electric Company June 1, 1996 to December 31, 1999
        D. D. Richard, Jr. 
        T. B. King
                 		Senior
        Executive Vice President Public Affairs        		October 18, 2000 to present
        Vice President, Governmental RelationsJuly 1, 1997 to October 17, 2000
        Senior Vice President, Public Affairs,and Chief of Utility Operations, Pacific Gas and Electric Company
                 		May 1, 1998
        August 2, 2004 to present
        Senior Vice President, Governmental and Regulatory Relations, Pacific Gas and Electric CompanyJuly 1, 1997 to April 30, 1998
        G. B. StanleySenior Vice President, Human ResourcesJanuary 1, 1998 to present
        Senior Vice President, National Energy & Gas Transmission, Inc.July 1, 2000 to July 7, 2003
        Vice President, Human ResourcesJune 1, 1997 to December 31, 1997
        B. R. WorthingtonSenior Vice President and General CounselJune 1, 1997 to present
        Vice President, National Energy & Gas Transmission, Inc.January 20, 1999 to July 1, 2000

        49

        “The names, ages and position’s of the Utility’s executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at December 31, 2003 are as follows:

        NameAgePosition
        G. R. Smith55President and Chief Executive Officer
        K. M. Harvey45Senior Vice President — Chief Financial Officer, and Treasurer
        T. B. King42  Senior Vice President and Chief of Utility Operations,
        R. J. Peters53Senior Vice President Pacific Gas and General Counsel
        D. D. Richard, Jr. 53Senior Vice President, Public Affairs
        G. M. Rueger53Senior Vice President, Generation and Chief Nuclear Officer

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

        NamePositionPeriod Held Office
        G. R. SmithPresident and Chief Executive OfficerJune 1, 1997 to present
        Senior Vice President, PG&E CorporationJanuary 1, 1999 to present
        K. M. HarveySenior Vice President — Chief Financial Officer, and TreasurerNovember 1, 2000 to present
        Senior Vice President, Chief Financial Officer, Controller, and TreasurerJanuary 1, 2000 to October 31, 2000
        Senior Vice President, Chief Financial Officer, and TreasurerJuly 1, 1997 to December 31, 1999
        T. B. KingSenior Vice President and Chief of Utility OperationsElectric Company November 1, 2003 to presentAugust 1, 2004
          Senior Vice President, PG&E Corporation January 1, 1999 to October 31, 2003
          President, PG&E National Energy Group, Inc. November 15, 2002 to July 8, 2003
          President and Chief Operating Officer, PG&E Gas Transmission Corporation August 27, 2002 to July 8, 2003
          President and Chief Operating Officer, Gas Transmission, PG&E National Energy Group, Inc. August 9, 2002 to November 14, 2002
          President and Chief Operating Officer, West Region, PG&E National Energy Group, Inc. July 1, 2000 to August 8, 2002
          President and Chief Operating Officer, PG&E Gas Transmission Corporation November 23, 1998 to September 10, 2002*2002
        R. J. Peters
        D. D. Richard, Jr
         
        Senior Vice President, and General CounselPublic Affairs
                 		January 1, 1999
        October 18, 2000 to present

        50

          Vice President, Governmental Relations July 1, 1997 to October 17, 2000
        NamePositionPeriod Held Office
        D. D. Richard, Jr.  Senior Vice President, Public Affairs, (Please refer to description of business experience for executive officers of PG&E Corporation above.)Pacific Gas and Electric Company May 1, 1998 to present


        G.R. Smith

        Senior Vice President

        January 1, 1999 to present
        President and Chief Executive Officer, Pacific Gas and Electric CompanyJune 1, 1997 to present

        B. R. Worthington

        Senior Vice President and General Counsel

        June 1, 1997 to present

                The names, ages and positions of the Utility's "executive officers," as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at December 31, 2004 are as follows:

        Name
        		Age
        		Position
        R.D. Glynn, Jr.62Chairman of the Board of Directors
        G. R. Smith56President and Chief Executive Officer
        T. B. King43Executive Vice President and Chief of Utility Operations
        P.A. Darbee51Senior Vice President and Chief Financial Officer of PG&E Corporation
        L.H. Everett54Senior Vice President and Assistant to the Chairman, PG&E Corporation
        K. M. Harvey46Senior Vice President—Chief Financial Officer, and Treasurer
        R.M. Jackson47Senior Vice President, Human Resources
        R. J. Peters54Senior Vice President and General Counsel
        D. D. Richard, Jr.54Senior Vice President, Public Affairs
        G. M. Rueger54 Senior Vice President, Generation and Chief Nuclear Officer
        B. R. Worthington 55Senior Vice President and General Counsel, PG&E Corporation

                All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through December 31, 2004, the executive officers of the Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.

        Name
        		Position
        		Period Held Office
        R. D. Glynn, Jr.Chief Executive Officer and President, PG&E CorporationJanuary 1, 1998 to December 31, 2004
        Chairman of the Board, Pacific Gas and Electric Company and PG&E CorporationJanuary 1, 1998 to present

        G. R. Smith

        President and Chief Executive Officer Senior Vice President, PG&E Corporation

        June 1, 1997 to present
        January 1, 1999 to present

        T. B. King

        Executive Vice President and Chief of Utility Operations

        August 2, 2004 to present
        Senior Vice President and Chief of Utility OperationsNovember 1, 2003 to August 1, 2004
        Senior Vice President, PG&E CorporationJanuary 1, 1999 to October 31, 2003
        President, PG&E National Energy Group, Inc.November 15, 2002 to July 8, 2003
        President and Chief Operating Officer,August 27, 2002 to July 8, 2003
        PG&E Gas Transmission Corporation
        President and Chief Operating Officer, GasAugust 9, 2002 to November 14, 2002
        Transmission, PG&E National Energy Group, Inc.
        President and Chief Operating Officer,July 1, 2000 to August 8, 2002
        West Region, PG&E National Energy Group, Inc.
        President and Chief Operating Officer, PG&E Gas Transmission CorporationNovember 23, 1998 to September 10, 2002



        P. A. Darbee

        Senior Vice President and Chief Financial Officer, PG&E Corporation

        July 9, 2001 to December 31, 2004
        Senior Vice President, Chief Financial Officer, and Treasurer, PG&E CorporationSeptember 20, 1999 to July 8, 2001

        L. H. Everett

        Senior Vice President and Assistant to the Chairman, PG&E Corporation

        August 2, 2004 to December 31, 2004
        Vice President and Assistant to the Chairman, PG&E CorporationJune 1, 2001 to August 1, 2004
        Vice President, Corporate Secretary, and Assistant to the Chairman, PG&E CorporationMay 1, 2001 to May 31, 2001
        Vice President and Corporate Secretary, PG&E CorporationJuly 1, 1997 to April 30, 2001
        Vice President and Corporate SecretaryNovember 1, 1996 to April 30, 2001

        K. M. Harvey

        Senior Vice President, Chief Financial Officer, and Treasurer

        November 1, 2000 to present
        Senior Vice President, Chief Financial Officer, Controller, and TreasurerJanuary 1, 2000 to October 31, 2000

        R. A. Jackson

        Senior Vice President, Human Resources, Pacific Gas and Electric Company and PG&E Corporation

        August 2, 2004 to present
        Vice President, Human Resources, PG&E CorporationJune 1, 2004 to August 1, 2004
        Vice President, Human ResourcesJune 1, 1999 to August 1, 2004

        R. J. Peters

        Senior Vice President and General Counsel

        January 1, 1999 to present

        D. D. Richard, Jr.

        Senior Vice President, Public Affairs

        May 1, 1998 to present
        Senior Vice President, Public Affairs, PG&E CorporationOctober 18, 2000 to present
        Vice President, Governmental Relations, PG&E CorporationJuly 1, 1997 to October 17, 2000

        G. M. Rueger

        Senior Vice President, Generation and Chief Nuclear Officer

        April 2, 2000 to present
          Senior Vice President and General Manager, Nuclear Power Generation Business Unit November 1, 1991 to April 1, 2000

        B. R. Worthington

        Senior Vice President and General Counsel, PG&E Corporation

        June 1, 1997 to present


        PART II

        Item 5.Market for the Registrant’s Common Equity and Related Shareholder Matters.

        Item 5.    Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

                (a)   Information responding to part of Item 5, for each of PG&E Corporation and Pacific Gas and Electric Company, is set forth under the heading “Quarterly"Quarterly Consolidated Financial Data (Unaudited)”" in the 20032004 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. As of February 17, 2004,15, 2005, there were 110,740103, 707 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed principally on the New York Stock Exchange. PG&E Corporation common stock also is listed on the Pacific Exchange and the Swiss stock exchanges. The discussion of dividends with respect to PG&E Corporation’sCorporation's common stock is hereby incorporated by reference from “Management’s"Management's Discussion and Analysis of Financial Condition and Results of Operations — Operations—Liquidity and Financial Resources — Dividend Policy”Resources—Dividends" of the 20032004 Annual Report.


                On July 2, 2003,As previously disclosed, in connection with its entry into certain credit agreements, in June 2002 and October 2002, PG&E Corporation completed the offer and sale of $600 million of 6 7/8% Senior Secured Notes due 2008 pursuantissued warrants to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act of 1933, or Act. The net proceeds of the offering, approximately $581 million, together with cash on hand, were used to repay the principal balance outstanding under PG&E Corporation’s October 2002 credit agreement of approximately $720 million, plus $15 million of accrued in-kind interest and a $52 million prepayment premium. The payment resulted in the termination of PG&E Corporation’s existing credit agreement and the release of liens on PG&E Corporation’spurchase 5,066,931 shares of NEGT. Lehman Brothers acted as principal underwriters. The notes were offered and sold only to “qualified institutional buyers” as defined in Rule 144A under the Act in compliance with Rule 144A under the Act, and in offers and sales that occur outside the U.S. to persons other than U.S. persons, or foreign purchasers, which include dealers or other professional fiduciaries in the U.S. acting on a discretionary basis for foreign beneficial owners, other than an estate or trust, in offshore transactions meeting the requirements of Rule 903 of Regulation S under the Act. For more information, see Note 3 to the “Notes to Consolidated Financial Statements”common stock of PG&E Corporation contained inat an exercise price of $0.01 per share. During the 2003 Annual Report, which information is hereby incorporated by referencequarter ended December 31, 2004, warrant holders exercised, on a net exercise basis, warrants to purchase 961,480 shares, and filed as partreceived 961,183 shares of Exhibit 13PG&E Corporation common stock. As of December 31, 2004, warrant holders had exercised, on a net exercise basis, warrants to this report.purchase 4,719,019 shares, and had received 4,717,290 shares of PG&E Corporation common stock since the warrants were issued.

                Pacific Gas and Electric Company did not make any sales of unregistered equity securities during 2003,2004, the period covered by this report.

                (b)   Issuer Purchases of Equity Securities

        Period
        		 Total Number of
        Shares Purchased
        		 Average Price
        Paid Per Share
        		 Total Number of Shares
        Purchased as Part of
        Publicly Announced
        Plans or Programs(1)(2)(3)
        		 Approximate Dollar
        Value that may yet
        be Purchased Under
        the Plans or
        Programs
        October 1 through October 31, 2004 —  — — $350,000,000
        November 1 through November 30, 2004 340,000 $33.5676 340,000 $350,000,000
        December 1 through December 31, 2004 11,293,200 $32.4493 11,293,200  —
          
        		 
        		 
        		 
         Total 11,633,200(4)$32.4820 11,633,200 $—
          
        		 
        		 
        		 
        (1)
        On September 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase shares of PG&E Corporation's common stock with an aggregate purchase price not to exceed PG&E Corporation's net cash proceeds from sales of PG&E Corporation's common stock upon exercise of options granted under PG&E Corporation's Stock Option Plan. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. Repurchases may be made from time until the program expires on December 31, 2005. Amounts remaining under this program are not determinable as PG&E Corporation cannot predict how many options will be exercised before December 31, 2005.

        (2)
        Also on September 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase up to $350 million in shares of PG&E Corporation's common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. As of December 13, 2004, when PG&E Corporation terminated its open market stock purchase program, PG&E Corporation had used approximately $32 million of the previously announced $350 million authorization to repurchase shares. As disclosed in a Form 8-K filed on December 16, 2004, PG&E Corporation entered into accelerated share repurchase arrangements with a broker on December 15, 2004, under which PG&E Corporation used the remaining approximately $318 million to repurchase shares of its common stock on an accelerated basis.

        (3)
        On December 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase up to $975 million in shares of PG&E Corporation's common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on December 16, 2004. As disclosed in a Form 8-K filed on December 23, 2004, PG&E Corporation entered into accelerated share repurchase arrangements with a broker on December 23, 2004, but provided notice of termination of these arrangements on January 31, 2005, effective on February 1, 2005. PG&E Corporation did not repurchase any shares of its common stock under this program.

        (4)
        Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation, purchased 850,000 shares of PG&E Corporation common stock during the fourth quarter. These shares remain outstanding under California law although for accounting purposes they are treated as if they were treasury shares.


        Item 6.Selected Financial Data

        		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"Selected Financial Data”Data" in the 20032004 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


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

                A discussion of PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's consolidated results of operations and financial condition is set forth on under the heading “Management’s"Management's Discussion and Analysis

        51

        of Financial Condition and Results of Operations”Operations" in the 20032004 Annual Report, 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

        		Quantitative and Qualitative Disclosures About Market Risk.

                Information responding to Item 7A appears in the 20032004 Annual Report under the heading “Management’s"Management's Discussion and Analysis of Financial Condition and Results of Operations — Operations—Risk Management Activities,”" and under Notes 1 and 8 of the “Notes"Notes to the Consolidated Financial Statements”Statements" of the 20032004 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


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

                Information responding to Item 8 appears in the 20032004 Annual Report under the following headings for PG&E Corporation: “Consolidated"Consolidated Statements of Operations,” “Consolidated" "Consolidated Balance Sheets,” “Consolidated" "Consolidated Statements of Cash Flows,”" and “Consolidated"Consolidated Statements of Common Shareholders’Shareholders' Equity;”" under the following headings for Pacific Gas and Electric Company: “Consolidated"Consolidated Statements of Operations,” “Consolidated" "Consolidated Balance Sheets,” “Consolidated" "Consolidated Statements of Cash Flows,”" and “Consolidated"Consolidated Statements of Shareholders’Shareholders' Equity;”" and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: “Notes"Notes to the Consolidated Financial Statements,” “Quarterly" "Quarterly Consolidated Financial Data (Unaudited),” “Independent Auditors’" "Independent Auditors' Report,”" and “Responsibility"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
        		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

                Not applicable.


        Item 9A.Controls and Procedures
        		Controls and Procedures

                Based on an evaluation of PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's, or the Utility's, disclosure controls and procedures as of December 31, 2003,2004, PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sthe Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and Pacific Gas and Electric Company’sthe Utility in reports the companies file or submit under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms.



                As of January 1, 2004, PG&E Corporation and the Utility adopted the Financial Accounting Standards Board's, or FASB, revision to FASB Interpretation No. 46, "Consolidation of Variable Interest Entities," or FIN 46R. In accordance with FIN 46R, the Utility consolidated the assets, liabilities and non-controlling interests of low-income housing partnerships that were determined to be variable interest entities, or VIEs, under FIN 46R. PG&E Corporation and the Utility do not have the legal right or authority to assess the internal controls of VIEs. Therefore, PG&E Corporation and the Utility's evaluation of disclosure controls and procedures performed as of December 31, 2004 did not include these entities in that evaluation. PG&E Corporation and the Utility have not designed, established, or maintained disclosure controls and procedures for consolidated VIEs.

                There were no changes in internal controls over financial reporting that occurred during the quarter ended December 31, 2003,2004 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’sCorporation's or Pacific Gas and Electric Company’sthe Utility's controls over financial reporting.

        PART III

        Item 10.Directors and Executive Officers of the Registrant.

        Directors

             The authorized number of directors of PG&E Corporation currently is 10, and the authorized number of directors of the Utility currently is 11. On February 18, 2004, each Board of Directors approved amendments to the respective company’s bylaws to reduce the authorized number of directors effective upon adjournment of the 2004 Joint Annual Meeting of shareholders. After these amendments become effective, the bylaws will provide that the authorized number of directors of PG&E Corporation will be eight, and the authorized number of directors of Pacific Gas and Electric Company will be nine.

             Information is provided below about the directors        Management of PG&E Corporation and the Utility including their principal occupationshave prepared an annual report on internal control over financial reporting. Management's report, together with the report of the independent registered public accounting firm, appears in the 2004 Annual Report under the heading "Management's Report on Internal Control Over Financial Reporting" and "Report of Independent Registered Public Accounting Firm," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


        Item 9B.    Other Information

        Nomination for Election as Directors

                On February 16, 2005, the past five years, certain other directorships, age,Nominating, Compensation and lengthGovernance Committee of service as a director

        52

        the Board of Directors of PG&E Corporation, andor the Utility. TheCommittee, nominated the following individuals for election as directors of PG&E Corporation to be voted on at the 2005 annual meeting of shareholders: David R. Andrews, Leslie S. Biller, David A. Coulter, C. Lee Cox, Peter A. Darbee, Robert D. Glynn, Jr., Mary S. Metz, Barbara L. Rambo, and Barry Lawson Williams. The Committee also nominated the same nine individuals for election as directors of the Utility, are the same, except thatin addition to Gordon R. Smith is a directorSmith. One of the Utility only.

        current members of the Boards of Directors, David R. Andrews. Mr. Andrews is Senior Vice President Government Affairs, General Counsel, and SecretaryM. Lawrence, MD, will retire from the Board of PepsiCo, Inc. (food and beverage businesses), and has held that position since February 2002. Prior to joining PepsiCo, Inc., Mr. Andrews was a partner in the law firm of McCutchen, Doyle, Brown & Enersen, LLP from May 2000 to January 2002 and from 1981 to July 1997. From August 1997 to April 2000, he served as the legal advisor to the U.S. Department of State and former Secretary Madeleine Albright. Mr. Andrews, 62, has been a directorDirectors of PG&E Corporation and the Utility since 2000. He also serves as a directoreffective at the adjournment of UnionBanCal Corporation.the 2005 joint annual meeting of the shareholders of PG&E Corporation and Utility, and has not been nominated for re-election to the Boards.


        Amendment of Bylaws

                Leslie S. Biller.On February 16, 2005, the Board of Directors of PG&E Corporation adopted resolutions to amend the PG&E Corporation bylaws to decrease the authorized number of directors from ten to nine, effective at the adjournment of the annual meeting of shareholders to be held on April 20, 2005. Under PG&E Corporation's bylaws, the authorized number of directors may not be less than 7 nor more than 13, but within that range the Board of Directors may set the exact number of directors by an amendment to the bylaws. The text of the bylaw amendment follows:

                  Mr. Biller is retired Vice Chairman and Chief Operating Officer1.    Number.    As stated in paragraph I of Wells Fargo & Company (financial services and retail banking)Article Third of this Corporation's Articles of Incorporation, the Board of Directors of this Corporation shall consist of such number of directors, not less than seven (7) nor more than thirteen (13). HeThe exact number of directors shall be nine (9) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders.

        On February 16, 2005, the Board of Directors of the Utility also adopted resolutions to amend the Utility bylaws to decrease the authorized number of directors from eleven to ten, effective at the adjournment of the annual meeting of shareholders to be held on April 20, 2005. Under the Utility's


        bylaws, the authorized number of directors may not be less than 9 nor more than 17, but within that position from November 1998range the Board of Directors may set the exact number of directors by an amendment to the bylaws. The text of the bylaw amendment follows:

                  1.    Number.    The Board of Directors of this Corporation shall consist of such number of directors, not less than nine (9) nor more than seventeen (17). The exact number of directors shall be ten (10) until his retirement in October 2002. Mr. Biller was President and Chief Operating Officerchanged, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Norwest Corporation (bank holding company) from 1997 until it merged with Wells Fargo & Company in 1998. Mr. Biller, 55,Directors or the shareholders.


        Approval of Performance Scale under 2005 Short Term Incentive Plan

                As previously disclosed, the Committee has been an advisory directorapproved the structure of the 2005 Short-Term Incentive Plan (STIP) under which officers of PG&E Corporation and the Utility since January 2003, and was elected a director ofare provided an opportunity to receive annual incentive cash payments. For PG&E Corporation andexecutive officers, the UtilitySTIP award will be based entirely on February 18, 2004. He also servesthe achievement of financial objectives, as a director of Ecolab Inc.

        David A. Coulter. Mr. Coulter is Vice Chairman of J.P. Morgan Chase & Co. and J.P. Morgan Chase Bank, responsible for its investment bank, investment management, and private banking., and has held that position since January 2001. Prior to the merger with J.P. Morgan & Co. Incorporated, he was Vice Chairman ofmeasured by earnings from operations. The Chase Manhattan Corporation (bank holding company) from August 2000 to December 2000. He was a partner in the Beacon Group, L.P. (investment banking firm) from January 2000 to July 2000, and was Chairman and Chief Executive Officer of BankAmerica Corporation and Bank of America NT&SA from May 1996 to October 1998. Mr. Coulter, 56, has been a director of PG&E Corporation and the Utility since 1996. He also serves as a director of Strayer Education, Inc.

        C. Lee Cox. Mr. Cox is retired Vice Chairman of AirTouch Communications, Inc. and retired President and Chief Executive Officer of AirTouch Cellular (cellular telephone and paging services). He was an executive officer of AirTouch Communications, Inc. and its predecessor, PacTel Corporation, from 1987 until his retirement in April 1997. Mr. Cox, 62, has served as a director of PG&E Corporation and the Utility since 1996.

        William S. Davila. Mr. Davila is President Emeritus of The Vons Companies, Inc. (retail grocery). He was President of The Vons Companies, Inc. from 1986 until his retirement in May 1992. Mr. Davila, 72, has been a directorofficers of the Utility since 1992will have an opportunity to receive annual cash incentives based on three criteria: the achievement of financial objectives as measured by PG&E Corporation's earnings from operations (weighted 25%), the Utility's contribution to PG&E Corporation's earnings from operations (weighted 50%), and a directorthe success of key strategic initiatives (weighted 25%). At its meeting on February 16, 2005, the Committee approved the specific performance scale that will be used to determine the extent to which the corporate financial objective, as measured by earnings from operations, has been met.

                The Committee used the same methodology to establish the performance scale for the 2005 STIP as was used for the 2004 STIP. The corporate financial performance measure is based on PG&E Corporation since 1996. He also serves as a director of The Home Depot, Inc.

        Robert D. Glynn, Jr. Mr. Glynn is Chairman of the Board, Chief Executive Officer, and President of PG&E Corporation and Chairman ofCorporation's budgeted earnings from operations that were previously approved by the Board of Directors, consistent with the Utility. He has been anbasis for reporting and guidance to the financial community. As with previous earnings performance scales, unbudgeted items impacting comparability such as changes in accounting methods, workforce restructuring, and one-time occurrences will be excluded. The Committee will continue to retain full discretion as to the determination of final officer of PG&E Corporation since December 1996STIP awards.


        PART III

        Item 10.    Directors and an officerExecutive Officers of the Utility since January 1988. Mr. Glynn, 61, has been a director of the Utility since 1995 and a director of PG&E Corporation since 1996.Registrant

        David M. Lawrence, MD Dr. Lawrence is retired Chairman and Chief Executive Officer of Kaiser Foundation Health Plan, Inc. and Kaiser Foundation Hospitals, and was an executive officer of those companies from 1991 until his retirement in 2002. Dr. Lawrence, 63, has been a director of the Utility since 1995 and a director of PG&E Corporation since 1996. He also serves as a director of Agilent Technologies Inc. and McKesson Corporation.

        Mary S. Metz. Dr. Metz is President of S. H. Cowell Foundation, and has held that position since January 1999. Prior to that date, she was Dean of University Extension, University of California, Berkeley from July 1991 to June 1998. Dr. Metz, 66, has been a director of the Utility since 1986 and a director of PG&E Corporation since 1996. She also serves as a director of Longs Drug Stores Corporation, SBC Communications Inc., and UnionBanCal Corporation.

        Carl E. Reichardt. Mr. Reichardt served as Vice Chairman of Ford Motor Company from October 2001 to July 2003. He is retired Chairman of the Board and Chief Executive Officer of Wells Fargo &

        53

        Company (bank holding company) and Wells Fargo Bank, N.A. He was an executive officer of Wells Fargo Bank from 1978 until his retirement in December 1994. Mr. Reichardt, 72, has been a director of the Utility since 1985 and a director of PG&E Corporation since 1996. He also serves as a director of ConAgra Foods, Inc. and Ford Motor Company.

        Gordon R. Smith. Mr. Smith is President and Chief Executive Officer of the Utility, and has been an officer of the Utility since 1980. Mr. Smith, 56, has been a director of the Utility since 1997.

        Barry Lawson Williams. Mr. Williams is President of Williams Pacific Ventures, Inc. (business investment and consulting), and has held that position since 1987. He also served as interim President and Chief Executive Officer of the American Management Association (management development organization) from November 2000 to June 2001. Mr. Williams, 59, has been a director of the Utility since 1990 and a director of PG&E Corporation since 1996. He also serves as a director of CH2M Hill Companies, Ltd., The Northwestern Mutual Life Insurance Company, R.H. Donnelley Corporation, The Simpson Manufacturing Company Inc., and SLM Corporation.

        Executive Officers

                Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included in a separate item captioned “Executive"Executive Officers of the Registrants”Registrants" contained on pages 4849 through 5052 in Part I of this report.

        Section 16 Beneficial Ownership Reporting Compliance

             In accordance with Section 16(a) of Other information responding to Item 10 is included under the Securities Exchange Act of 1934 and Securities and Exchange Commission (SEC) regulations, PG&E Corporation’s and the Utility’s directors and certain officers, and persons who own greater than 10 percent of PG&E Corporation’s or the Utility’s equity securities must file reports of ownership and changes in ownership of such equity securities with the SEC and the principal national securities exchange on which those securities are registered, and must furnish PG&E Corporation or the Utility with copies of all such reports they file.

             Based solely on its review of copies of such reports received or written representations from certain reporting persons, PG&E Corporation and the Utility believe that during 2003 all filing requirements applicable to their respective directors, officers, and 10 percent shareholders were satisfied, except that a Statement of Changes of Beneficial Ownership of Securities on Form 4 was filed late for Thomas B. King due to internal corporate administrative delays. No information is reported for individuals during periods in which they were not directors, officers, or 10 percent shareholders of the respective company.

        Audit Committee Members and Financial Expert

             The members of the Audit Committees for each of PG&E Corporation and the Utility are C. Lee Cox, David R. Andrews, William S. Davila, Mary S. Metz, and Barry Lawson Williams.

             The Boardsheading "Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company" and under the Utility each have determined that both C. Lee Cox and Barry Lawson Williams, membersheading "Section 16(a) Beneficial Ownership Reporting Compliance" in the Joint Proxy Statement relating to the 2005 Annual Meetings of each company’s Audit Committee, each are “audit committee financial experts” as definedShareholders, which information is hereby incorporated by the SEC regulations, implementing Section 407 of the Sarbanes-Oxley Act of 2002. Each Board of Directors has determined that Mr. Cox and Mr. Williams each are “independent” as defined by current listing standards of the New York Stock Exchange and the American Stock Exchange, as applicable.reference.


          Website Availability of Corporate Governance and Other Documents

        The following documents are available both on PG&E Corporation’sCorporation's websitewww.pgecorp.com, and Pacific Gas and Electric Company’sCompany's website,www.pge.com: (1) the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company applicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers, and other executive officers, (2) PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's corporate

        54

        governance guidelines, and (3) key Board Committee charters, including charters for the companies’companies' Audit Committees and the PG&E Corporation Nominating, Compensation, and Governance Committee. Shareholders also may obtain print copies of these documents by submitting a written request to Linda Y.H. Cheng, Corporate Secretary of both PG&E Corporation and Pacific Gas and Electric Company, One Market, Spear Tower, Suite 2400, San Francisco, California 94105.

                If any amendments are made to, or any waivers are granted with respect to, provisions of the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company that apply to their respective Chief Executive Officers, Chief Financial Officers or Controllers, the company whose code is so affected will disclose the nature of such amendment or waiver on its respective website.

        Item 11.Executive Compensation.

        Compensation of Directors

             Each director who is not an officer or employee of PG&E Corporation or the Utility receives a quarterly retainer of $7,500 plus a fee of $1,000 for each Board or Board committee meeting attended. Non-employee directors who chair Board committees receive an additional quarterly retainer of $625. Under the Deferred Compensation Plan for Non-Employee Directors, directors of PG&E Corporation or the Utility may elect to defer all or part of such compensation for varying periods. Directors who participate in the Deferred Compensation Plan may convert their deferred compensation into common stock equivalents, the value of which is tiedwebsite and any waivers to the market value of PG&E Corporation common stock. Alternatively, participating directors may elect that their deferred compensationcode will be investeddisclosed in the Utility Bond Fund.

             No director who servesa Current Report on both the PG&E Corporation and Utility Boards and corresponding committees is paid additional compensation for concurrent service on the Utility’s Board or its committees, except that separate meeting fees are paid for each meetingForm 8-K filed within 5 days of the Utility Board, or a Utility Board committee, that is not held concurrently or sequentially with a meeting of the PG&E Corporation Board or a corresponding PG&E Corporation Board committee. It is the usual practicewaiver.



        Item 11.    Executive Compensation

                Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the Utility that meetingsheading "Compensation of Directors" and under the respective Boardsheadings "Summary Compensation Table," "Option/SAR Grants in 2004," "Aggregated Option/SAR Exercises in 2004 and corresponding committees are held concurrentlyYear-End Option/SAR Values," "Long-Term Incentive Program—Awards in 2004," "Retirement Benefits," "Employment ContractsTermination of Employment, and therefore, that a single meeting feeChange In Control Provisions" in the Joint Proxy Statement relating to the 2005 Annual Meetings of Shareholders, which information is paidhereby incorporated by reference.


        Item 12.    Security Ownership of Certain Beneficial Owners and Management

                Information responding to each directorItem 12, for each set of meetings.

             Directors of PG&E Corporation or the Utility are reimbursed for reasonable expenses incurred for participating in Board meetings, committee meetings, or other activities undertaken on behalf of PG&E Corporation or the Utility.

             Effective January 1, 1998, the PG&E Corporation Retirement Plan for Non-Employee Directors was terminated. Directors who had accrued benefits under the Plan were given a one-time option of receiving at retirement the benefit accrued through 1997, or of converting the present value of their accrued benefit into a PG&E Corporation common stock equivalent investment held in the Deferred Compensation Plan for Non-Employee Directors. The payment of frozen accrued retirement benefits, or distributions from the Deferred Compensation Plan attributable to the conversion of retirement benefits, cannot be made until the later of age 65 or retirement from the Board.

             Under the Non-Employee Director Stock Incentive Plan, which is a component of the PG&E Corporation Long-Term Incentive Program, on the first business day of January of each year, each non-employee director of PG&E Corporation is entitled to receive stock-based grants with a total aggregate equity value of $30,000, composed of (1) restricted shares of PG&E Corporation common stock valued at $10,000 (based on the closing price of PG&E Corporation common stock on the first business day of the year), and (2) a combination, as elected by the director, of non-qualified stock options and common stock equivalents with a total equity value of $20,000, based on equity value increments of $5,000. The exercise price of stock options is equal to the market value of PG&E Corporation common stock (i.e., the closing price) on the date of grant. Restricted stock and stock options vest over the five-year period following the date of grant, except that restricted stock and stock options will vest immediately upon mandatory retirement from the Board, upon a director’s death or disability, or in the event of a change in control. Common stock equivalents awarded to non-employee directors are payable only in the form of PG&E Corporation common stock following a

        55

        director’s retirement from the Board, upon a director’s death or disability, or in the event of a change in control. Unvested awards are forfeited if the recipient ceases to be a director for any other reason.

        On January 2, 2003, each non-employee director received 684 restricted shares of PG&E Corporation common stock. In addition, directors who were granted stock options received options to purchase 1,101 shares of PG&E Corporation common stock for each $5,000 increment of equity value (subject to the aggregate $20,000 limit) at an exercise price of $14.61 per share, and directors who were granted common stock equivalents received 342 common stock equivalent units for each $5,000 increment of equity value (subject to the aggregate $20,000 limit).

        Summary Compensation Table

        This table summarizes the principal components of compensation paid to the Chief Executive Officers and the other most highly compensated executive officers of PG&E Corporation and Pacific Gas and Electric Company, is included under the Utility duringheading "Security Ownership of Management" and under the past year.

                                          
        Annual CompensationLong-Term Compensation
        AwardsPayouts
        Other
        AnnualRestrictedSecuritiesAll Other
        Compen-StockUnderlyingLTIPCompen-
        SalaryBonussationAward(s)Options/SARsPayoutssation
        Name and Principal PositionYear($)($)(1)($)(2)($)(3)(# of Shares)($)(4)($)(5)
        Robert D. Glynn, Jr.   2003  $1,050,000  $0  $3,154,268  $2,169,950   486,000  $9,879,911  $666,050 
         Chairman of the Board, Chief  2002   1,050,000   787,500   4,833,389   0   150,000   632,461   79,777 
         Executive Officer, and  2001   900,000   1,181,700   4,817   3,000,000   470,800   74,588   413,196 
         President of PG&E Corporation; Chairman of the Board of Pacific Gas and Electric Company                                
        Peter A. Darbee  2003  $490,000  $0  $2,368  $678,269   101,300  $4,023,098  $329,140 
         Senior Vice President and  2002   490,000   220,500   4,862   0   0   115,244   62,355 
         Chief Financial Officer  2001   455,000   328,578   4,817   1,125,000   183,800   26,105   613,596 
         of PG&E Corporation                                
        Bruce R. Worthington  2003  $425,000  $0  $836,295  $530,708   79,300  $2,310,713  $306,575 
         Senior Vice President and  2002   425,000   175,313   1,220,913   0   0   205,801   43,893 
         General Counsel of PG&E  2001   400,000   288,860   4,817   625,000   145,000   24,617   171,353 
         Corporation                                
        G. Brent Stanley  2003  $305,000  $0  $2,368  $353,927   52,900  $2,141,176  $204,782 
         Senior Vice President —  2002   305,000   114,375   4,862   0   0   84,311   18,010 
         Human Resources of PG&E  2001   285,000   187,103   4,817   625,000   102,800   15,385   110,691 
         Corporation                                
        P. Chrisman Iribe  2003  $450,000  $0  $0  $471,903   70,400  $3,017,831  $151,934 
         Senior Vice President of  2002   450,000   93,163   0   0   0   94,863   75,620 
         PG&E Corporation; Executive  2001   425,000   306,914   0   1,125,000   186,400   25,355   57,846 
         Vice President of National Energy & Gas Transmission, Inc.                                
        Gordon R. Smith  2003  $735,000  $0  $2,402,048  $943,441   140,900  $5,842,500  $453,723 
         Senior Vice President of  2002   735,000   519,278   4,310,520   0   0   182,009   37,173 
         PG&E Corporation; President  2001   630,000   664,808   937   1,750,000   272,000   40,282   241,302 
         and Chief Executive Officer of Pacific Gas and Electric Company                                
        Thomas B. King  2003  $500,000  $0  $23,780  $530,708   79,300  $2,938,351  $659,488 
         Senior Vice President and  2002   450,000   93,163   0   0   0   94,863   89,263 
         Chief of Utility Operations  2001   425,000   306,914   0   1,125,000   186,400   41,020   1,090,207 
         of Pacific Gas and Electric Company (November 1, 2003) Senior Vice President of PG&E Corporation (January 1, 1999 - October 31, 2003)                                

        56

                                          
        Annual CompensationLong-Term Compensation
        AwardsPayouts
        Other
        AnnualRestrictedSecuritiesAll Other
        Compen-StockUnderlyingLTIPCompen-
        SalaryBonussationAward(s)Options/SARsPayoutssation
        Name and Principal PositionYear($)($)(1)($)(2)($)(3)(# of Shares)($)(4)($)(5)
        Gregory M. Rueger  2003  $358,000  $0  $642,860  $272,477   40,700  $1,563,204  $243,325 
         Senior Vice President —  2002   358,000   194,215   1,007,117   0   0   42,166   16,646 
         Generation and Chief Nuclear  2001   340,000   257,550   0   625,000   79,400   15,385   129,145 
         Officer of Pacific Gas and Electric Company                                
        Kent M. Harvey  2003  $302,000  $0  $0  $272,477   40,700  $1,557,466  $209,703 
         Senior Vice President,  2002   302,000   173,952   0   0   0   41,434   18,812 
         Chief Financial Officer, and  2001   285,000   213,465   0   625,000   76,000   15,385   113,462 
         Treasurer of Pacific Gas and Electric Company                                
        Roger J. Peters  2003  $302,000  $0  $0  $272,477   40,700  $1,557,466  $204,502 
         Senior Vice President and  2002   302,000   166,402   0   0   0   41,434   19,385 
         General Counsel of Pacific Gas  2001   285,000   212,753   0   625,000   76,000   15,385   112,619 
         and Electric Company                                
        James K. Randolph  2003  $337,000  $0  $669,741  $265,537   39,700  $1,557,466  $233.943 
         Senior Vice President and  2002   337,000   165,130   1,282,378   0   0   41,434   15,602 
         Chief of Utility Operations of  2001   325,000   218,725   0   625,000   72,600   15,385   123,028 
         Pacific Gas and Electric Company (retired October 31, 2003)                                

        (1) Represents payments received or deferred in 2003 and 2002 for achievement of corporate and organizational objectives in 2002 and 2001, respectively, under the Short-Term Incentive Plan. No decision has been made with respect to the 2003 Short-Term Incentive Plan.
        (2) Amounts reported consist of (i) reportable officer perquisite allowances and, for 2002 and 2003, amounts for non-business related travel (Mr. Glynn $35,000 and $62,998, respectively), (ii) payments of related taxes, and (iii) for 2002 and 2003, the cost of annuities to replace existing retirement benefits, at the time they are due under the Supplemental Executive Retirement Plan (SERP). The annuities will not change the after-tax benefits that would have been provided upon retirement under the existing arrangements. The cost of the annuity and associated tax restoration payments during 2003 for retirement obligations as of December 31, 2002, are: Mr. Glynn $3,048,972, Mr. Worthington $833,927, Mr. Smith $2,402,048, Mr. Rueger $642,860, and Mr. Randolph $669,741.
        (3) As of the end of the year, the aggregate number of shares or units of restricted stock held by each named executive officer, and the value using the year-end closing price of a share of PG&E Corporation common stock, were: Mr. Glynn 148,525 (with a value of $4,124,539), Mr. Darbee 46,425 (with a value of $1,289,222), Mr. Worthington 36,325 (with a value of $1,008,745), Mr. Stanley 24,225 (with a value of $672,728), Mr. Iribe 32,300 (with a value of $896,971), Mr. Smith 64,575 (with a value of $1,793,248), Mr. King 36,325 (with a value of $1,008,745), Mr. Rueger 18,650 (with a value of $517,911), Mr. Harvey 18,650 (with a value of $517,911), Mr. Peters 18,650 (with a value of $517,911), and Mr. Randolph 18,175 (with a value of $504,720). The restrictions lapse in annual increments of up to 25 percent on the first business day of 2004, 2005, 2006, and 2007, subject to the recipient’s continued employment. In general, 20 percent of each year’s increment is subject to forfeiture if PG&E Corporation fails to be in the top quartile of the comparator group as measured by relative annual total shareholder return at the end of the prior year. With respect to the Chairman, Chief Executive Officer, and President of PG&E Corporation, 25 percent of each year’s increment is subject to forfeiture if PG&E Corporation fails to be in the top quartile of the comparator group as measured by total shareholder return at the end of the prior year, and an additional 25 percent is subject to forfeiture if PG&E Corporation fails to be in the top half of the comparator group. The shares of restricted stock have the same dividend rights as unrestricted shares of PG&E Corporation common stock.
        (4) Represents (i) payments received or deferred in 2004, 2003, and 2002 for achievement of corporate performance objectives for the periods 2001 through 2003, 2000 through 2002, and 1999 through 2001,

        57

        respectively, under the Performance Unit Plan (Mr. Glynn $1,292,837, Mr. Darbee $669,876, Mr. Worthington $522,915, Mr. Stanley $325,427, Mr. Iribe $533,063, Mr. Smith $799,143, Mr. King $533,063, Mr. Rueger $234,201, Mr. Harvey $228,463, Mr. Peters $228,463, and Mr. Randolph $228,463), (ii) common stock equivalents called Special Incentive Stock Ownership Premiums (SISOPs) earned by executive officers under the Executive Stock Ownership Program and vested during 2003, and additional common stock equivalents reflecting dividends accrued on those SISOPs as follows: Mr. Glynn 2,948 (with a value of $42,453), Mr. Darbee 10,346 (with a value of $148,981), Mr. Worthington 533 (with a value $7,672), Mr. Stanley 2,474 (with a value of $35,623), Mr. Iribe 6,430 (with a value of $92,591), Mr. Smith 4,096 (with a value of $58,989), and Mr. King 910 (with a value of $13,111), and (iii) amounts representing one-half of the phantom restricted stock units granted in 2001 under the Senior Executive Retention Program that were subject to a performance measure (Mr. Glynn 307,692.5 units with a value of $8,544,621, Mr. Darbee 115,385 units with a value of $3,204,241, Mr. Worthington 64,102.5 units with a value of $1,780,126, Mr. Stanley 64,102.5 units with a value of $1,780,126, Mr. Iribe 86,142.5 units with a value of $2,392,177, Mr. Smith 179,487.5 units with a value of $4,984,368, Mr. King 86,142.5 units with a value of $2,392,177, Mr. Rueger 47,857.5 units with a value of $1,329,003, Mr. Harvey 47,857.5 units with a value of $1,329,003, Mr. Peters 47,857.5 units with a value of $1,329,003, and Mr. Randolph 47,857.5 units with a value of $1,329,003). The value of all phantom restricted units granted under the Senior Executive Retention Program is based solely on the closing price of PG&E Corporation common stock on the date that the units vested, December 31, 2003. As previously reported, the total number of phantom restricted stock units granted under the Program and their value as of their vesting date of December 31, 2003, inclusive of the performance-based units described above, were: Mr. Glynn 615,385 units with a value of $17,089,241, Mr. Darbee 230,770 units with a value of $6,408,483, Mr. Worthington 128,205 units with a value of $3,560,253, Mr. Stanley 128,205 units with a value of $3,560,253, Mr. Iribe 172,285 units with a value of $4,784,354, Mr. Smith 358,975 units with a value of $9,968,736, Mr. King 172,285 units with a value of $4,784,354, Mr. Rueger 95,715 units with a value of $2,658,006, Mr. Harvey 95,715 units with a value of $2,658,006, Mr. Peters 95,715 units with a value of $2,658,006, and Mr. Randolph 95,715 units with a value of $2,658,006.
        (5) Amounts reported for 2003 consist of: (i) contributions to defined contribution retirement plans (Mr. Glynn $9,000, Mr. Darbee $16,125, Mr. Worthington $3,953, Mr. Stanley $3,853, Mr. Iribe $20,000, Mr. Smith $9,000, Mr. King $20,000, Mr. Rueger $9,000, Mr. Harvey $9,000, Mr. Peters $9,000, and Mr. Randolph $9,000), (ii) contributions received or deferred under excess benefit arrangements associated with defined contribution retirement plans (Mr. Glynn $38,250, Mr. Darbee $5,925, Mr. Worthington $15,172, Mr. Stanley $9,872, Mr. Iribe $25,000, Mr. Smith $24,075, Mr. King $2,500, Mr. Rueger $7,110, Mr. Harvey $4,590, Mr. Peters $4,590, and Mr. Randolph $6,165), (iii) above-market interest on deferred compensation (Mr. Glynn $18,800, Mr. Darbee $3,757, Mr. Worthington $350, Mr. Stanley $1,057, Mr. Iribe $203, Mr. Smith $648, Mr. King $1,285, Mr. Rueger $548, Mr. Harvey $306, Mr. Peters $331, and Mr. Randolph $167), (iv) relocation allowances and other one-time payments, Mr. King $374,645, (v) sale of vacation (Mr. Worthington $20,433, Mr. Iribe $69,231, Mr. King $36,058, Mr. Harvey $5,807, Mr. Peters $581, and Mr. Randolph $1,944), and (vi) amounts received pursuant to management retention programs (Mr. Glynn $600,000, Mr. Darbee $303,333, Mr. Worthington $266,667, Mr. Stanley $190,000, Mr. Iribe $37,500, Mr. Smith $420,000, Mr. King $225,000, Mr. Rueger $226,667, Mr. Harvey $190,000, Mr. Peters $190,000, and Mr. Randolph $216,667).

        58

        Option/SAR Grants in 2003

        This table summarizes the distribution and the terms and conditions of stock options granted to the executive officers namedheading "Principal Shareholders" in the Summary Compensation Table during the past year.

                             
        Grant
        Individual GrantsDate Value
        Number of% of Total
        SecuritiesOptions/SARs
        UnderlyingGranted toExercise orGrant Date
        Options/SARsEmployees inBase PriceExpirationPresent
        NameGranted (#)(1)(2)2003(2)($/Sh)(3)Date(4)Value ($)(5)
        Robert D. Glynn, Jr.  486,000   13.32%  14.61   01-03-2013  $2,760,480 
        Peter A. Darbee  101,300   2.78%  14.61   01-03-2013   575,384 
        Bruce R. Worthington  79,300   2.17%  14.61   01-03-2013   450,424 
        G. Brent Stanley  52,900   1.45%  14.61   01-03-2013   300,472 
        P. Chrisman Iribe  70,400   1.93%  14.61   01-03-2013   399,872 
        Gordon R. Smith  140,900   3.86%  14.61   01-03-2013   800,312 
        Thomas B. King  79,300   2.17%  14.61   01-03-2013   450,424 
        Gregory M. Rueger  40,700   1.12%  14.61   01-03-2013   231,176 
        Kent M. Harvey  40,700   1.12%  14.61   01-03-2013   231,176 
        Roger J. Peters  40,700   1.12%  14.61   01-03-2013   231,176 
        James K. Randolph  39,700   1.09%  14.61   01-03-2013   225,496 

        (1) All options granted to executive officers in 2003 are exercisable as follows: 25 percent of the options may be exercised on or after the first anniversary of the date of grant, 50 percent on or after the second anniversary, 75 percent on or after the third anniversary, and 100 percent on or after the fourth anniversary, provided that options will vest immediately upon the occurrence of certain events. No options were accompanied by tandem dividend equivalents.
        (2) No stock appreciation rights (SARs) have been granted since 1991.
        (3) The exercise price is equal to the closing price of PG&E Corporation common stock on the date of grant.
        (4) All options granted to executive officers in 2003 expire ten years and one day from the date of grant, subject to earlier expiration in the event of the officer’s termination of employment with PG&E Corporation, the Utility, or one of their respective subsidiaries.
        (5) Estimated present values are based on the Black-Scholes Model, a mathematical formula used to value options traded on stock exchanges. The Black-Scholes Model considers a number of factors, including the expected volatility and dividend rate of the stock, interest rates, and time of exercise of the option. The following assumptions were used in applying the Black-Scholes Model to the 2003 option grant shown in the table above: volatility of 45.0 percent, risk-free rate of return of 3.94 percent, dividend yield of $0.00 (the annual dividend rate on the grant date), and an exercise date ten years after the date of grant. The ultimate value of the options will depend on the future market price of PG&E Corporation common stock, which cannot be forecast with reasonable accuracy. That value will depend on the future success achieved by employees for the benefit of all shareholders. The estimated grant date present value for the options shown in the table was $5.68 per share.

        59

        Aggregated Option/SAR Exercises in 2003 and Year-End Option/SAR Values

        This table summarizes exercises of stock options and tandem stock appreciation rights (granted in prior years) by the executive officers named in the Summary Compensation Table during the past year, as well as the number and value of all unexercised options held by such named executive officers at the end of 2003.

                         
        Value of
        Number of SecuritiesUnexercised
        Underlying UnexercisedIn-the-Money
        Options/SARs atOptions/SARs at
        Shares AcquiredEnd of 2003 (#)End of 2003 ($)(1)
        on ExerciseValue Realized(Exercisable/(Exercisable/
        Name(#)($)Unexercisable)Unexercisable)
        Robert D. Glynn, Jr.   0   0   1,363,492/1,057,232  $5,306,585/$12,720,407 
        Peter A. Darbee  0   0   309,402/272,898  $1,608,109/$3,371,912 
        Bruce R. Worthington  0   0   369,268/215,232  $1,633,980/$2,656,447 
        G. Brent Stanley  0   0   204,902/149,798  $1,069,201/$1,843,813 
        P. Chrisman Iribe  31,000   323,537   315,034/235,566  $1,203,811/$2,923,614 
        Gordon R. Smith  0   0   612,302/393,098  $2,824,560/$4,857,529 
        Thomas B. King  0   0   293,934/244,466  $1,486,781/$3,040,738 
        Gregory M. Rueger  82,402   210,363   135,132/113,598  $139,168/$1,406,559 
        Kent M. Harvey  31,334   378,715   151,734/111,332  $359,225/$1,376,076 
        Roger J. Peters(2)  2,000  $(12,740)  183,568/111,332  $736,723/$1,376,076 
        James K. Randolph(2)  4,500  $(30,375)  189,267/108,066  $773,373/$1,332,432 

        (1) Based on the difference between the option exercise price (without reduction for the amount of accrued dividend equivalents, if any) and a fair market value of $27.77, which was the closing price of PG&E Corporation common stock on December 31, 2003.
        (2) The options exercised would have expired on January 4, 2004. After accounting for accrued dividend equivalents, Mr. Peters realized $8,240 and Mr. Randolph realized $16,830.

        Long-Term Incentive Program — Awards in 2003

        This table summarizes the long-term incentive grants made to the executive officers named in the Summary Compensation Table during the past year.

        Awards
        Performance or
        Other Period
        Number of Shares,Until Maturation
        NameUnits, or Other Rightsor Payout
        Gregory M. Rueger2,601(1)3 years
        Kent M. Harvey3,915(1)3 years
        Roger J. Peters631(1)3 years
        James K. Randolph177(1)3 years

        (1) Represents common stock equivalents called Special Incentive Stock Ownership Premiums (SISOPs) earned under the Executive Stock Ownership Program. SISOPs are earned by eligible officers who achieve and maintain minimum PG&E Corporation common stock ownership levels as set by the Nominating, Compensation, and Governance Committee. All of the officers named in the Summary Compensation Table are eligible officers. Each SISOP represents a share of PG&E Corporation common stock that vests at the end of three years. Units can be forfeited prior to vesting if an eligible officer fails to maintain his or her minimum stock ownership level. Upon retirement or termination, vested SISOPs are distributed in the form of an equivalent number of shares of PG&E Corporation common stock.

        60

        Retirement Benefits

             PG&E Corporation and the Utility provide retirement benefits to some of the executive officers named in the Summary Compensation Table. The benefit formula for eligible executive officers is 1.7 percent of the average of the three highest combined salary and annual Short-Term Incentive Plan payments during the last ten years of service multiplied by years of credited service. During 2002 and 2003, annuities were purchased to replace a significant portion of the unfunded retirement benefits for certain officers whose entire accrued benefit could not be provided under the Retirement Plan due to tax code limits. The annuities will not change the amount or timing of the after-tax benefits that would have been provided upon retirement under the Supplemental Executive Retirement Plan (SERP) or similar arrangements. In connection with the annuities, tax restoration payments were made such that the annuitization was tax-neutral to the executive officer. Effective July 1, 2003, Mr. Darbee and Mr. King became participants in the SERP with five years of credited service. Mr. Darbee and Mr. King will each earn an additional five years of credited service provided that they are employed by PG&E Corporation or a subsidiary on July 1, 2008. As of December 31, 2003, the estimated pre-tax annual retirement benefits payable under the SERP or similar arrangements (assuming credited service to age 65), adjusted to reflect the effect of the annuities, for the most highly compensated executive officers were as follows: Mr. Glynn $309,602, Mr. Darbee $286,570, Mr. Worthington $285,740, Mr. Stanley $117,610, Mr. Smith $430,326, Mr. King $421,200, Mr. Rueger $287,450, Mr. Harvey $330,436, Mr. Peters $306,808, and Mr. Randolph $220,617. The estimated annual retirement benefits are single life annuity benefits and would not be subject to any Social Security offsets.

        Termination of Employment and Change in Control Provisions

             The PG&E Corporation Officer Severance Policy, which covers most officers of PG&E Corporation and its subsidiaries, including the executive officers named in the Summary Compensation Table, provides benefits if a covered officer is terminated without cause. In most situations, benefits under the policy include (1) a lump sum payment of one and one-half or two times annual base salary and Short-Term Incentive Plan target (the applicable severance multiple being dependent on an officer’s level), (2) continued vesting of equity-based incentives for 18 months or two years after termination (depending on the applicable severance multiple), (3) accelerated vesting of up to two-thirds of the common stock equivalents granted under the Executive Stock Ownership Program (depending on an officer’s level), and (4) payment of health care insurance premiums for 18 months or two years after termination (depending on the applicable severance multiple). In lieu of all or a portion of the lump sum payment, a terminated officer who is covered by PG&E Corporation’s Supplemental Executive Retirement Plan can elect additional years of service and/or age for purposes of calculating pension benefits. Effective July 21, 1999, the policy was amended to provide covered officers with alternative benefits that apply upon actual or constructive termination following a change in control or potential change in control. For these purposes, “change in control” has the same definition as under the Long-Term Incentive Program (see below). Constructive termination includes certain changes to a covered officer’s responsibilities. In the event of a change in control or potential change in control, the policy provides for a lump sum payment of the total of (1) unpaid base salary earned through the termination date, (2) Short-Term Incentive Plan target calculated for the fiscal year in which termination occurs (Target Bonus), (3) any accrued but unpaid vacation pay, and (4) three times the sum of Target Bonus and the officer’s annual base salary in effect immediately before either the date of termination or the change in control, whichever base salary is greater. Change in control termination benefits also include reimbursement of excise taxes levied upon the severance benefit pursuant to Internal Revenue Code Section 4999.

             The Long-Term Incentive Program (LTIP) permits the grant of various types of stock-based incentives, including performance shares, stock options, restricted stock, performance units, and incentives granted under the Non-Employee Director Stock Incentive Plan. The LTIP and the component plans provide that, upon the occurrence of a change in control, (1) any time periodsJoint Proxy Statement relating to the exercise or realization2005 Annual Meetings of any incentive (including common stock equivalents granted under the Executive Stock Ownership Program) will be accelerated so that such incentive may be exercised or realized in full immediately upon the change in control, (2) all shares of restricted stock will immediately cease to be forfeitable, and (3) all conditions relating to the realization of any stock-based incentive will terminate immediately. Under the LTIP, a “change in control”Shareholders, which information is hereby incorporated by reference.

        61

        will be deemed to have occurred if any of the following occurs: (1) any “person” (as such term is used in Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, but excluding any benefit plan for employees or any trustee, agent, or other fiduciary for any such plan acting in such person’s capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of PG&E Corporation representing 20 percent or more of the combined voting power of PG&E Corporation’s then outstanding securities, (2) during any two consecutive years, individuals who at the beginning of such a period constitute the Board of Directors cease for any reason to constitute at least a majority of the Board of Directors, unless the election, or the nomination for election by the shareholders of the Corporation, of each new director was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of the period, or (3) the shareholders of the Corporation shall have approved (i) any consolidation or merger of the Corporation other than a merger or consolidation that would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the combined voting power of the Corporation, such surviving entity, or the parent of such surviving entity outstanding immediately after the merger or consolidation, (ii) any sale, lease, exchange, or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Corporation, or (iii) any plan or proposal for the liquidation or dissolution of the Corporation. For purposes of this definition, the term “combined voting power” means the combined voting power of the then outstanding voting securities of the Corporation or the other relevant entity.

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

        Security Ownership of Management

        The following table sets forth the number of shares of PG&E Corporation common stock beneficially owned (as defined in the rules of the Securities and Exchange Commission) as of January 31, 2004, by the respective directors of PG&E Corporation and the Utility, the executive officers of PG&E Corporation and the Utility named in the Summary Compensation Table, and all directors and executive officers of PG&E Corporation and the Utility as a group. As of January 31, 2004, no director, nominee for director, or executive officer owned shares of any class of the Utility’s securities. The table also sets forth common stock equivalents credited to the accounts of directors and executive officers under PG&E Corporation’s deferred compensation and equity plans.

                         
        PercentCommon
        Beneficial StockofStock
        NameOwnership(1)(2)(3)Class(4)Equivalents(5)Total
        David R. Andrews(6)  4,054   *   767   4,821 
        Leslie S. Biller(6)  1,051   *   4,083   5,134 
        David A. Coulter(6)  5,681   *   22,897   28,578 
        C. Lee Cox(6)  47,207   *   3,609   50,816 
        William S. Davila(6)  21,517   *   12,949   34,466 
        Robert D. Glynn, Jr.(7)  1,901,961   *   99,181   2,001,142 
        David M. Lawrence, MD(6)  45,197   *   3,041   48,238 
        Mary S. Metz(6)  24,276   *   4,366   28,642 
        Carl E. Reichardt(6)  26,197   *   14,335   40,532 
        Gordon R. Smith(8)  804,073   *   20,059   824,132 
        Barry Lawson Williams(6)  22,109   *   5,689   27,798 
        Peter A. Darbee(9)  437,150   *   10,346   447,496 
        Bruce R. Worthington(9)  416,605   *   7,917   424,522 
        G. Brent Stanley(9)  289,592   *   4,262   293,854 
        P. Chrisman Iribe(9)  428,890   *   99,008   527,898 
        Thomas B. King(10)  435,614   *   49,366   484,980 

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        PercentCommon
        Beneficial StockofStock
        NameOwnership(1)(2)(3)Class(4)Equivalents(5)Total
        Gregory M. Rueger(10)  227,225   *   0   227,225 
        Kent M. Harvey(10)  138,918   *   0   138,918 
        Roger J. Peters(10)  262,930   *   86,144   349,074 
        James K. Randolph(11)  268,569   *   141   268,710 
        All PG&E Corporation directors and executive officers as a group (16 persons)  4,436,002   1.1   227,291   4,663,293 
        All Pacific Gas and Electric Company directors and executive officers as a group (16 persons)  4,192,772   1.1   328,184   4,520,956 

        *Less than 1 percent

        (1) Includes any shares held in the name of the spouse, minor children, or other relatives sharing the home of the director or executive officer and, in the case of executive officers, includes shares of PG&E Corporation common stock held in the defined contribution retirement plans maintained by PG&E Corporation, Pacific Gas and Electric Company, and their respective subsidiaries. Except as otherwise indicated below, the directors, nominees for director, and executive officers have sole voting and investment power over the shares shown. Voting power includes the power to direct the voting of the shares held, and investment power includes the power to direct the disposition of the shares held.

        Also includes the following shares of PG&E Corporation common stock in which the beneficial owners share voting and investment power: Mr. Andrews 2,076 shares, Mr. Biller 1,051 shares, Mr. Coulter 5,681 shares, Mr. Cox 24,192 shares, Mr. Davila 200 shares, Dr. Lawrence 15,676 shares, Dr. Metz 7,681 shares, Mr. Smith 3,884 shares, Mr. Darbee 69,818, Mr. Worthington 2,288 shares, Mr. Rueger 13,987 shares, Mr. Peters 184 shares, all PG&E Corporation directors and executive officers as a group 132,547 shares, and all Pacific Gas and Electric Company directors and executive officers as a group 74,612 shares.

        (2) Includes shares of PG&E Corporation common stock which the directors and executive officers have the right to acquire within 60 days of January 31, 2004, through the exercise of vested stock options granted under the PG&E Corporation Long-Term Incentive Program, as follows: Mr. Andrews 1,978 shares, Mr. Cox 23,015 shares, Mr. Glynn 1,713,325 shares, Dr. Lawrence 23,015 shares, Dr. Metz 14,368 shares, Mr. Reichardt 20,141 shares, Mr. Smith 702,392 shares, Mr. Williams 16,254 shares, Mr. Darbee 353,159 shares, Mr. Iribe 404,601 shares, Mr. Stanley 263,626 shares, Mr. Worthington 374,701 shares, Mr. King 385,726 shares, Mr. Rueger 178,506 shares, Mr. Harvey 97,300 shares, Mr. Peters 226,376 shares, Mr. Randolph 231,258 shares, all PG&E Corporation directors and executive officers as a group 3,845,092 shares, and all Pacific Gas and Electric Company directors and executive officers as a group 3,589,855 shares. The directors and executive officers have neither voting power nor investment power with respect to shares shown unless and until such shares are purchased through the exercise of the options, pursuant to the terms of the PG&E Corporation Long-Term Incentive Program.
        (3) Includes restricted shares of PG&E Corporation common stock awarded under the PG&E Corporation Long-Term Incentive Program. As of January 31, 2004, directors and executive officers of PG&E Corporation and Pacific Gas and Electric Company held the following numbers of restricted shares that may not be sold or otherwise transferred until certain vesting conditions are satisfied: Mr. Andrews 2,076 shares, Mr. Biller 1,051 shares, Mr. Coulter 3,703 shares, Mr. Cox 3,703 shares, Mr. Davila 4,056 shares, Mr. Glynn 163,393 shares, Dr. Lawrence 4,056 shares, Dr. Metz 4,056 shares, Mr. Reichardt 4,056 shares, Mr. Smith 70,321 shares, Mr. Williams 4,056 shares, Mr. Darbee 48,498 shares, Mr. Iribe 24,225 shares, Mr. Stanley 25,008 shares, Mr. Worthington 39,553 shares, Mr. King 39,553 shares, Mr. Rueger 18,777 shares, Mr. Harvey 19,797 shares, Mr. Peters 19,797 shares, Mr. Randolph 13,631 shares, all PG&E Corporation directors and executive officers as a group 417,498 shares, and all Pacific Gas and Electric Company directors and executive officers as a group 381,892 shares.

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        (4) The percent of class calculation is based on the number of shares of PG&E Corporation common stock outstanding as of January 31, 2004, excluding shares held by a subsidiary.
        (5) Reflects the number of stock units purchased by directors and executive officers through salary and other compensation deferrals or awarded under equity compensation plans. The value of each stock unit is equal to the value of a share of PG&E Corporation common stock and fluctuates daily based on the market price of PG&E Corporation common stock. The directors and officers who own these stock units share the same market risk as PG&E Corporation shareholders, although they do not have voting rights with respect to these stock units.
        (6) Mr. Andrews, Mr. Biller, Mr. Coulter, Mr. Cox, Mr. Davila, Dr. Lawrence, Dr. Metz, Mr. Reichardt, and Mr. Williams are directors of both PG&E Corporation and Pacific Gas and Electric Company.
        (7) Mr. Glynn is a director and executive officer of PG&E Corporation, and also is a director of Pacific Gas and Electric Company. He is named in the Summary Compensation Table.
        (8) Mr. Smith is a director and an executive officer of Pacific Gas and Electric Company, and also is an executive officer of PG&E Corporation. He is named in the Summary Compensation Table.
        (9) Mr. Darbee, Mr. Iribe, Mr. Stanley, and Mr. Worthington are executive officers of PG&E Corporation named in the Summary Compensation Table.

        (10) Mr. Harvey, Mr. King, Mr. Peters, and Mr. Rueger are executive officers of Pacific Gas and Electric Company named in the Summary Compensation Table.
        (11) Mr. Randolph retired as an executive officer of Pacific Gas and Electric Company in 2003. He is named in the Summary Compensation Table.

        Principal Shareholders

        The following table presents certain information regarding shareholders that PG&E Corporation and the Utility know are the beneficial owners of more than 5 percent of any class of voting securities of PG&E Corporation or the Utility as of January 31, 2004:

                     
        Amount and Nature
        of BeneficialPercent
        Class of StockName and Address of Beneficial OwnerOwnershipof Class
        Pacific Gas and  PG&E Corporation(2)   321,314,760   94.90%
        Electric Company stock(1)  One Market, Spear Tower, Suite 2400         
           San Francisco, CA 94105         
        PG&E Corporation  State Street Bank and Trust Company(3)   31,626,606   8.01%
        Common stock  225 Franklin Street         
           Boston, MA 02110         

        (1) Pacific Gas and Electric Company’s common stock and preferred stock vote together as a single class. Each share is entitled to one vote.
        (2) As a result of the formation of the holding company on January 1, 1997, PG&E Corporation became the holder of all issued and outstanding shares of Pacific Gas and Electric Company common stock. As of January 31, 2004, PG&E Corporation and a subsidiary held 100 percent of the issued and outstanding shares of Pacific Gas and Electric Company common stock, and neither PG&E Corporation nor any of its subsidiaries held shares of Pacific Gas and Electric Company preferred stock.
        (3) The information relating to State Street Bank and Trust Company is based on beneficial ownership as of December 31, 2003, as reported in a Schedule 13G, dated February 5, 2004, filed with the Securities and Exchange Commission. The bank held 19,204,598 shares in its capacity as Trustee of the Pacific Gas and Electric Company Savings Fund Plan. The Trustee may not vote these shares in the absence of voting instructions from the Plan participants. The bank also held 12,422,008 shares of PG&E Corporation common stock in various other fiduciary capacities. The bank has sole voting power with respect to 11,500,089 of these shares, shared voting power with respect to 13,495 of these shares, sole investment

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        power with respect to 12,386,522 of these shares, and shared investment power with respect to 31,486 of these shares.

        Equity Compensation Plan Information

                The following table provides information as of December 31, 2003,2004, concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation’sCorporation's existing equity compensation plans.

        Plan Category
        		 (a)
        Number of Securities to
        be Issued Upon Exercise
        of Outstanding Options,
        Warrants, and Rights
        		 (b)
        Weighted Average
        Exercise Price of
        Outstanding Options,
        Warrants, and Rights
        		 (c)
        Number of Securities
        Remaining Available for
        Future Issuance Under
        Equity Compensation Plans
        (Excluding Securities
        Reflected in Column(a))
        		 
        Equity compensation plans approved by shareholders 21,021,916 $22.76 10,439,785(1)

        Equity compensation plans not approved by shareholders
         
        —
         
        $
        —
         
        —
         

        Total equity compensation plans
         
        21,021,916
         
        $
        22.76
         
        10,439,785
         
        (1)
        Represents the total number of shares available for issuance under PG&E Corporation's Long-Term Incentive Program (LTIP) as of December 31, 2004. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock, and phantom stock payable in an equal number of shares upon termination of employment or service as a director. No more than 5,000,000 of the reserved shares under the LTIP may be awarded as restricted stock. For a description of the LTIP, see Note 10 of the Notes to the Consolidated Financial Statements in the Annual Report.


                     
        (c)
        Number of Securities
        (a)(b)Remaining Available for
        Number of Securities toWeighted AverageFuture Issuance Under
        be Issued Upon ExerciseExercise Price ofEquity Compensation Plans
        of Outstanding Options,Outstanding Options,(Excluding Securities
        Plan CategoryWarrants and RightsWarrants and RightsReflected in Column(a))
        Equity compensation plans approved by shareholders  27,541,6291  $21.26   12,572,096(1)
        Equity compensation plans not approved by shareholders  —  $—   — 
        Total equity compensation plans  27,541,629  $21.26   12,572,096 

        (1) Represents the total number of shares available for issuance under PG&E Corporation’s Long-Term Incentive Program (LTIP) as of December 31, 2003. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock, performance shares, and phantom stock payable in an equal number of shares upon termination of employment or service as a director. No more than 5,000,000 of the reserved shares under the LTIP may be awarded as restricted stock. For a description of the LTIP, see Note 14 to the Consolidated Financial Statements.

        Item 13.    Certain Relationships and Related Transactions.Transactions

             Not applicable.

        Item 14.     Principal Accountant Fees and Services

        Fees Paid to Independent Public Accountants

             The Audit Committees have reviewed the audit and non-audit fees that PG&E Corporation, Pacific Gas and Electric Company, and their respective subsidiaries have paid to the independent public accountants for purposes of considering whether such fees are compatible with maintaining the auditor’s independence.

        Audit Fees.Estimated fees billed for services rendered by Deloitte & Touche LLP for the reviews of Forms 10-Q and for the audits of the financial statements of PG&E Corporation and its subsidiaries were $9.8 million for 2002 and $6.5 million for 2003. These amounts include fees for stand-alone audits of various subsidiaries, including estimated fees of $4.4 million for 2002 and $2.8 million for 2003 for Pacific Gas and Electric Company and its subsidiaries.

                Audit-Related Fees.Aggregate fees billedInformation responding to Item 13, for all audit-related services rendered by Deloitte & Touche LLP to PG&E Corporation and its subsidiaries consistedeach of $0.9 million of fees in 2002 and $0.7 million of fees for 2003. These amounts include $206,000 of audit-related fees in 2002 and $351,000 of audit-related fees in 2003 for Pacific Gas and Electric Company and its subsidiaries. Specific services for both PG&E Corporation and its subsidiaries and Pacific Gas and Electric Company and its subsidiaries in both years include employee benefit plan audits, consultations on financial accounting and reporting standards, a required transition property procedures report, and nuclear decommissioning trust audits. Amounts in 2003 also include Sarbanes-Oxley Section 404 readiness work.

        Tax Fees.Aggregate fees billed for permissible tax services rendered by Deloitte & Touche LLP to PG&E Corporation and its subsidiaries consisted of $2.2 million of fees during 2002 and $1.1 million of fees during 2003. These amounts for 2002 include $4,000 for Pacific Gas and Electric Company and its subsidiaries. Specific services in both years include services to support IRS audit appeals and questions, tax

        65

        strategy services, and review of tax returns. Amounts in 2002 also include a review of a private letter ruling request.

        All Other Fees.Aggregate fees billed for all other services rendered by Deloitte & Touche LLP to PG&E Corporation and its subsidiaries consisted of $1.1 million in 2002. These services were consulting services for the implementation of risk management software. None of these services were for Pacific Gas and Electric Company. No such services were rendered in 2003.

        Pre-Approval of Services Provided by the Independent Public Accountant

             As of June 2002, PG&E Corporation and its controlled subsidiaries have entered into new engagements with Deloitte & Touche LLP and its affiliate, Deloitte Consulting, only for audit services, audit-related services, or tax services, which Deloitte & Touche LLP and its affiliates may provide to Deloitte & Touche LLP’s audit clients under the Sarbanes-Oxley Act of 2002. PG&E Corporation and its subsidiaries traditionally have obtained these types of services from its independent public accountants.

        Since November 2002, the Audit Committees have been responsible for pre-approving all audit and non-audit services provided by Deloitte & Touche LLP to PG&E Corporation, Pacific Gas and Electric Company, or their controlled subsidiaries, pursuant to Committee pre-approval procedures that are reviewed and amended from time to time. At the beginning of each fiscal year, the PG&E Corporation and Pacific Gas and Electric Company, Audit Committees approve the selection of the independent public accountants for that fiscal year, and approve obtaining from the auditors a detailed list of (1) audit services, (2) audit-related services, and (3) tax services, up to specified fee amounts.“Audit services”generally includes audit and review of annual and quarterly financial statements and services that only the external auditors reasonably can provide (e.g., comfort letters, statutory audits, attest services, consents, and assistance with and review of documents filed with the Securities and Exchange Commission).“Audit-related services”generally include assurance and related services that traditionally are performed by the independent public accountants (e.g., employee benefit plan audits, due diligence related to mergers and acquisitions, accounting consultations and audits in connection with acquisitions, internal control reviews, and attest services that are not required by statute or regulation).“Tax services”generally includes compliance, tax strategy, tax appeals, and specialized tax issues, all of which also must be permissibleis included under the Sarbanes-Oxley Actheading "Certain Relationships and Related Transactions" in the Joint Proxy Statement relating to the 2005 Annual Meetings of 2002. In determining whether to pre-approve any services from the independent public accountants, the Audit Committees assess, among other things, the impact of that service on the auditor’s independence.Shareholders, which information is hereby incorporated by reference.




        Item 14.    Principal Accountant Fees and Services

                Following the initial annual pre-approval, the Audit Committees must pre-approve any proposed engagementInformation responding to Item 14, for each of the independent public accountants for any audit, audit-related, and tax services that are not included on the list of pre-approved services, and must pre-approve any listed pre-approved services that would cause PG&E Corporation or Pacific and Electric Company to exceed the authorized fee amounts. Other services may be obtained from the independent public accountants only following review and approval from the applicable company’s management and review and pre-approval by the applicable Audit Committee.

             Each Audit Committee has delegated to one or more members of the Committee the authority to pre-approve audit and non-audit services provided by the respective company’s independent public accountants. Any pre-approvals granted pursuant to this authority must be presented to the full Audit Committee at the next regularly scheduled Committee meeting. No such pre-approvals were granted for 2003.

             At each regular meeting of the Audit Committees, management reports the specific non-audit services being performed by Deloitte & Touche LLP for the respective company and its subsidiaries, the dollar amounts associated with these services, and a comparison of fees paid to date to the pre-approved amounts.

             During 2003, all services provided by Deloitte & Touche LLP to PG&E Corporation, Pacific Gas and Electric Company, is included under the heading "Information Regarding the Independent Public Accountants of PG&E Corporation and their consolidated affiliates were approved pursuantPacific Gas and Electric Company" in the Joint Proxy Statement relating to the applicable pre-approval procedures.2005 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

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        Item 15.    Exhibits and Financial Statement Schedules and Reports on Form 8-K.

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

          1.
          The following consolidated financial statements, supplemental information, and independent auditors' report are contained in the 2004 Annual Report, which have been incorporated by reference in this report:

            Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003, and 2002, for each of PG&E Corporation and Pacific Gas and Electric Company.

            Consolidated Balance Sheets at December 31, 2004, and 2003 for each of PG&E Corporation and Pacific Gas and Electric Company.

            Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2004, 2003, and 2002, for PG&E Corporation.

            Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2004, 2003, and 2002 for Pacific Gas and Electric Company.

            Notes to Consolidated Financial Statements.

            Quarterly Consolidated Financial Data (Unaudited).

            Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

          2.
          Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP) included at page 66 of this Form 10-K.

          3.
          Financial statement schedules:

            I—Condensed Financial Information of Parent as of December 31, 2004 and 2003 and for the Years Ended December 31, 2004, 2003, and 2002.

            II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2004, 2003, and 2002.

                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.

          4.
          Exhibits required to be filed by Item 601 of Regulation S-K:

        Exhibit
        Number
        		Exhibit Description
        2.1 1.The following consolidated financial statements, supplemental information,Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and independent auditors’ report are contained inElectric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the 2003 Annual Report, which have been incorporatedPlan of Reorganization omitted) (incorporated by reference in this report:

        to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
          Consolidated Statements


        2.2Order of Operationsthe U.S. Bankruptcy Court for the Years Ended December 31, 2003, 2002, and 2001, for eachNorthern District of PG&E Corporation and Pacific Gas and Electric Company.
        Consolidated Balance Sheets at December 31, 2003, and 2002 for eachCalifornia dated February 27, 2004 Approving Technical Corrections to Plan of PG&E Corporation and Pacific Gas and Electric Company.
        Consolidated StatementsReorganization of Common Shareholders’ Equity for the Years Ended December 31, 2003, 2002, and 2001, for PG&E Corporation.
        Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2003, 2002, and 2001 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 77 of this Form 10-K.
        3.Financial statement schedules:

        I — Condensed Financial Information of Parent as of December 31, 2003 and 2002 and for the Years Ended December 31, 2003, 2002, and 2001.
        II — Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2003, 2002, and 2001.

        Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
             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.

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

             
        Exhibit
        NumberExhibit Description
         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 Bylaws of PG&E Corporation amended as of February 18, 2004
         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 Bylaws of Pacific Gas and Electric Company amended as of February 18, 2004

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        Exhibit
        NumberExhibit Description
         4.1 First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (incorporated by reference to Registration No. 2-1324, Exhibits B-1, B-2, and 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; and Pacific Gas and Electric Company’s Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2)
         4.2 Indenture related to PG&E Corporation’s 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
         4.3 Supplemental Indenture related to PG&E Corporation’s 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
         4.4 Warrant Agreement, dated as of June 25, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation’s Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.9).
         4.5 Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)
         4.6 Form of Rights Agreement dated as of December 22, 2000, between PG&E Corporation and Mellon Investor Services LLC, including the Form of Rights Certificate as Exhibit A, the Summary of Rights to Purchase Preferred Stock as Exhibit B, and the Form of Certificate of Determination of Preferences for the Preferred Stock as Exhibit C (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)
         4.7 Amendment to Rights Agreement dated February 18, 2004, between PG&E Corporation and Mellon Investor Services LLC (incorporated by reference to PG&E Corporation’s Form 8-K filed February 19, 2004 (File No. 1-12609), Exhibit 99)
         4.8 Indenture dated as of July 2, 2003, by and between PG&E Corporation and Bank One, N.A. (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (File No. 1-12609), Exhibit 4.1)
         4.9 Utility Stock Base Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.2)
         4.10 Utility Stock Protective Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.3)
         4.11 Form of 6 7/8 percent Senior Secured Note due 2008 (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.4)

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        Exhibit
        NumberExhibit Description
         10.1 The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055 (incorporated by reference to PG&E Corporation’s 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 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 PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10); and the Gas Accord II Settlement Agreement, approved by the California Public Utilities Commission on August 22, 2002, in Decision 01-09-016 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)
         10.2 Commitment Letter dated March 5, 2003, between PG&E Corporation and Lehman Brothers, Inc. (incorporated by reference to PG&E Corporation’s Form 8-K filed March 6, 2003 (File No. 1-12609), Exhibit 99.2)
         10.3 Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 8-K filed December 22, 2003 (File No. 1-12609 and File No. 1-2348) Exhibit 99)
         10.4 Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions
         10.5 Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996
         10.6 PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999
         10.7 Electronic Commerce System User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation, effective as of September 28, 2001
         10.8 Operating Agreement effective as of April 1, 2003, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348) Exhibit 10.1)
         *10.9 PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.4)
         *10.10 Agreement and Release between PG&E Corporation and Thomas G. Boren dated December 18, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.23)
         *10.11 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)
         *10.12 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)

        69

        3.1 
        Exhibit
        NumberExhibit Description
        *10.13Letter regarding Compensation Arrangement betweenRestated Articles of Incorporation of PG&E Corporation and Lyn E. Maddox dated April 25, 1997effective as of May 29, 2002 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
        3.2Certificate 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 10.7)3.2)
        3.3Bylaws of PG&E Corporation amended as of January 1, 2005
        3.4Bylaws of PG&E Corporation amended as of April 20, 2005
        3.5Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
        3.6Bylaws of Pacific Gas and Electric Company amended as of January 1, 2005
        3.7Bylaws of Pacific Gas and Electric Company amended as of April 20, 2005
        4.1Indenture of Mortgage, dated as of March 11, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
        4.2First Supplemental Indenture, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.2)
        4.3Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4)
        4.4Escrow Deposit and Disbursement Agreement, dated as of March 23, 2004, among Pacific Gas and Electric Company and BNY Western Trust Company as escrow agent and trustee (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.3)
        4.5Calculation Agency Agreement, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.4)
        4.6Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
         *10.14


        4.7Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
        4.8Warrant Agreement, dated as of June 25, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.9).
        4.9Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)
        10.1Credit Agreement dated as of March 5, 2004, among Pacific Gas and Electric Company, as borrower, the Several Lenders from time to time parties thereto, Citicorp North America, Inc., as Administrative Agent, Banc One Capital Markets, Inc., as Syndication Agent, and Lehman Commercial Paper Inc., Credit Suisse First Boston, acting through its Cayman Islands Branch, and UBS Securities LLC, as Co- Documentation Agents (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 10, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
        10.2Credit Agreement, dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities, as syndication agent, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, and The Bank of New York (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed December 15, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99.)
        10.3Master Confirmation dated December 15, 2004, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
        10.4Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
        10.5Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.4)
        10.6Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.5)

        10.7PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.6)
        10.8Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, initially effective March 31, 1998, as amended to date (CAISO, FERC Electric Tariff No. 7)
        10.9Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company
        *10.10PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004
        *10.11PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005
        *10.12Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)
        *10.13Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
        *10.14Letter 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)
        *10.15 Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)
        *10.15Description 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)
        *10.1610.16 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.3)
        *10.17Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609) Exhibit 10.4)
        *10.1810.17 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)
        *10.19.1Letter 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)
        *10.19.2Letter regarding retention award to Gordon R. Smith dated January 22, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.2)
        *10.19.3Letter 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)
        *10.19.4Letter 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)
        *10.19.5Letter 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)
        *10.19.6Letter regarding retention award to Daniel D. Richard, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.6)
        *10.19.7Letter regarding retention award to James K. Randolph dated February 27, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.7)
        *10.19.8Letter regarding retention award to Gregory M. Rueger dated February 27, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.8)
        *10.19.9Letter regarding retention award to Kent M. Harvey dated February 27, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.9)

        70

        Exhibit
        NumberExhibit Description
        *10.19.10Letter regarding retention award to Roger J. Peters dated February 27, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.10)
        *10.19.11Letter 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)
        *10.19.12Letter 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)
        *10.19.13Letter 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)
        *10.20Pacific Gas and Electric Company Management Retention Program (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)
        *10.21PG&E Corporation Management Retention Program (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.2)
        *10.22PG&E Corporation2005 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)January 1, 2005
        *10.2310.18 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.35)2005
        *10.2410.19 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2004 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.24)
        *10.2510.20 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of September 19, 2001 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2001 (File No. 1-2248), Exhibit 10.16)2004, and frozen as of January 1, 2005
        *10.21*10.26.1Supplemental Executive Retirement Plan of PG&E Corporation effective January 1, 2005
        *10.22.1 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.1)
         *10.26.2


        *10.22.2 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2)
        *10.26.310.22.3 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.3)
        *10.26.410.22.4 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.4)

        71

        Exhibit
        NumberExhibit Description
        *10.26.510.22.5 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.5)
        *10.26.6Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Thomas G. Boren dated December 20, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.6)
        *10.27.110.23.1 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609);, Exhibit 10.2.1)
        *10.27.210.23.2 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348);, Exhibit 10.2.2)
        *10.27.3Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated April 18, 2003 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348); Exhibit 10.2.3)
        *10.27.410.23.3 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348);, Exhibit 10.2.4)
        *10.27.510.23.4 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609);, Exhibit 10.2.5)
        *10.2810.24 Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
        *10.2910.25 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
        *10.30PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 1997 (File No. 1-12609), Exhibit 10.13)
        *10.3110.26 PG&E Corporation Long-Term Incentive Program as amended May 16, 2001, including(including the PG&E Corporation Stock Option Plan and Performance Unit Plan, and Non-Employee Director Stock Incentive PlanPlan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
         *10.32

        *10.27PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004)
        *10.28Resolution of the PG&E Corporation Board of Directors dated June 16, 2004, adopting director compensation arrangement (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12609 and File No. 12348), Exhibit 10.1)
        *10.29Resolution of the Pacific Gas and Electric Company Board of Directors dated June 16, 2004, adopting director compensation arrangement (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12609 and File No. 12348), Exhibit 10.2)
        *10.30Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46)
        *10.31Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37)
        *10.32Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3)
        *10.33Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
        *10.34Form of Performance Share Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2)
        *10.35Form of Performance Share Award Agreement granted under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.38)
        *10.36 PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609) Exhibit 10.2))
        *10.3310.37 PG&E Corporation Officer Severance Policy, as amended effective as of December 19, 2001January 1, 2005
        *10.38PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-K10-Q for the yearquarter ended DecemberMarch 31, 20021998 (File No. 1-12609), Exhibit 10.43)

        72

             
        Exhibit
        NumberExhibit Description
         *10.34 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)
         *10.35 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)
         *10.36 PG&E Corporation Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46)
         *10.37 Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program
         *10.38 Form of Performance Share Award Agreement granted under the PG&E Corporation Long-Term Incentive Program
         *10.39 PG&E National Energy Group, Inc. Management Retention/ Performance Award Program (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609) Exhibit 10.47)
         *10.39.1 Letter regarding retention award to Thomas B. King dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609) Exhibit 10.47.1)
         *10.39.2 Letter regarding retention award to P. Chrisman Iribe dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609), Exhibit  10.47.2)
         *10.39.3 Letter regarding retention award to Lyn E. Maddox dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609) Exhibit 10.47.3)
         11  Computation of Earnings Per Common Share
         12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
         12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
         13  The following portions of the 2003 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Independent Auditors’ Report,” “Responsibility for Consolidated Financial Statements,” financial statements of PG&E Corporation entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Common Shareholders’ Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” “Consolidated Statements of Shareholders’ Equity,” “Notes to Consolidated Financial Statements,” and “Quarterly Consolidated Financial Data (Unaudited)”
         21  Subsidiaries of the Registrant
         23  Independent Auditors’ Consent (Deloitte & Touche LLP)
         24.1 Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
         24.2 Powers of Attorney

        73

             
        Exhibit
        NumberExhibit Description
         31.1 Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
         31.2 Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
         **32.1 Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
         **32.2 Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

        * Management contract or compensatory agreement.

        ** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

        (b) The following Current Reports on Form 8-K(1) were filed, or furnished as indicated, during the quarter ended December 31, 2003, and through the date hereof:

        1.October 3, 2003Item 9.Regulation FD Disclosure (furnished to the SEC)
        Exhibit 1 — Pacific Gas and Electric Company Income Statement for the month ended August 31, 2003 and Balance Sheet dated August 31, 2003
        2.October 15, 2003Item 5.Other Events
        District Court ruling regarding California Business and Professions Code Section 17200 lawsuits10.1)
           


        Item 9.*10.39 Regulation FD Disclosure (furnished to the SEC)
        ExhibitPG&E Corporation Officer Grantor Trust Agreement dated April 1, — Revised Financial Projections Relating to the Settlement Plan1998, as updated effective January 1, 2005
        3.*10.40 October 24, 2003Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996
        *10.41 Item 5.Other Events
        A. Credit Rating Change
        B. DepartmentResolution of Water Resources’ (DWR) 2001-2002 Revenue Requirement True-Up Proceeding
        4.November 12, 2003Item 12.Resultsthe Board of Operations and Financial Condition (furnished to the SEC)
        ReleaseDirectors of Third Quarter Earnings Results
        5.November 20, 2003Item 5.Other Events
        A. Proposed Decisions Regarding Proposed Settlement Agreement
        B. Conclusion of Confirmation Trial Testimony in Utility’s Chapter 11 Proceeding
        C. Ninth Circuit Preemption Decision
        6.December 2, 2003Item 9.Regulation FD Disclosure (furnished to the SEC)
        Exhibit 1 — Pacific Gas and Electric Company Income Statement for the month ended October 31, 2003regarding indemnification of officers and Balance Sheetdirectors dated October 31, 2003July 19, 1995
        7.11 December 9, 2003Computation of Earnings Per Common Share
        12.1 Item 5.Other Events
        A. Additional Proposed Decisions Regarding Proposed Settlement Agreement
        B. Credit Rating Agency Announcement

        74

        8.December 12, 2003Item 5.Other Events
        Proposed Decision Issued in the California DepartmentComputation of Water Resources” (DWR) 2001-2002 Revenue Requirement True-Up Proceeding and the DWR 2004 Revenue Requirement Proceeding
        9.December 15, 2003Item 5.Other Events
        Bankruptcy Court Decision Approving Proposed Chapter 11 Settlement Agreement and PlanRatios of Reorganization
        10.December 16, 2003Item 5.Other Events
        Comments Regarding Proposed Settlement Agreement Filed by the Utility and TURN
        11.December 22, 2003Item 5.Other Events
        A. California Public Utilities Commission Approves Proposed Settlement Agreement as RecommendedEarnings to be Modified byFixed Charges for Pacific Gas and Electric Company and The Utility Reform Network
        B. CPUC Approves Gas Accord II
        12.2 Item 7.Financial Statements, Pro Forma Financial Information,Computation of Ratios of Earnings to Combined Fixed Charges and Exhibits Exhibit 99 — Settlement Agreement among California Public Utilities Commission,Preferred Stock Dividends for Pacific Gas and Electric Company and
        13The following portions of the 2004 Annual Report to Shareholders of PG&E Corporation dated as of December 19, 2003, together with appendices
        12.December 23, 2003Item 5.Other Events
        Bankruptcy Court Confirms Utility’s Plan of Reorganization
        13.December 31, 2003Item 9.Regulation FD Disclosure (furnished to the SEC) Exhibit 1 —and Pacific Gas and Electric Company Income Statementare included: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)," "Management's Report on Internal Control Over Financial Reporting," "Report of Independent Registered Public Accounting Firm," "Report of Independent Registered Public Accounting Firm," "Responsibility for the month ended November 30, 2003 and Balance Sheet dated November 30, 2003Consolidated Financial Statements"
        14.21 January 22, 2004Subsidiaries of the Registrant
        23 Item 5.Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
        24.1 Other Events
        Applications Filed for RehearingResolutions of CPUC Decision Approving Chapter 11 Settlement Agreement
        Item 7.Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99 — Notice tothe Boards of Directors and Executive Officers, dated January 22, 2004
        Item 11.Temporary Suspension of Trading Under Registrant’s Employee Benefits Plan
        15.February 3, 2004Item 5.Other Events
        Implementation of Chapter 11 Settlement Rate Reduction
        16.February 19, 2004Item 5.Other Events
        Item 7.Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99 — Amendment to Rights Agreement dated February 18, 2004, between PG&E Corporation and Mellon Investor Services LLC
        Item 12.Results of Operations and Financial Condition (furnished to the SEC)
        Release of Third Quarter Earnings Results

        (1) Unless otherwise noted, all reports were filed under Commission File Number 1-2348 (PacificPacific Gas and Electric Company)Company authorizing the execution of the Form 10-K
        24.2Powers of Attorney
        31.1Certifications of the Chief Executive Officer and Commission File Number 1-12609 (PGthe Chief Financial Officer of PG&E Corporation).Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
        31.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
        **32.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
        **32.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

        *
        Management contract or compensatory agreement.

        **
        Pursuant to Item 601(b) (32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

        75


        SIGNATURES

                Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 20032004 to be signed on their behalf by the undersigned, thereunto duly authorized, in the City and County of San Francisco, on the 19th18th day of February, 2004.2005.

         PG&E CORPORATION   PACIFIC GAS AND ELECTRIC COMPANY
        (Registrant)(Registrant)
        By(Registrant)
        /s/          BRUCE R. WORTHINGTON      
        (Bruce R. Worthington, Attorney-in-Fact)        		 By 
        GARY P. ENCINASGARY P. ENCINAS
        (Registrant)
        /s/          BRUCE R. WORTHINGTON      
        (Gary P. Encinas,Bruce R. Worthington, Attorney-in-Fact)        		(Gary P. Encinas, Attorney-in-Fact)

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

        Signature
        		Title
        		Date
        A.Principal Executive OfficersChief Executive Officer, and PresidentFebruary 18, 2005
              *PETER A. DARBEE     (PG&E Corporation)  
        SignatureTitleDate
        A.  Principal Executive Officers
        *ROBERT D. GLYNN, JR.        		 Chairman of the Board, Chief Executive Officer, and President (PG&E Corporation)February 19, 2004
            *GORDON R. SMITH President and Chief Executive OfficerFebruary 18, 2005
            (Pacific Gas and Electric Company) February 19, 2004
        B.Principal Financial Officers
        *PETER A. DARBEE        		 Senior Vice President, and Chief FinancialFebruary 18, 2005
            *CHRISTOPHER P. JOHNSOfficer and Controller
            (PG&E Corporation)        		 February 19, 2004
         
            *KENT M. HARVEY Senior Vice President, Chief FinancialFebruary 18, 2005
        Officer, and Treasurer
            (Pacific Gas and Electric Company)
        C.Principal Accounting OfficersSenior Vice President, Chief FinancialFebruary 18, 2005
            *CHRISTOPHER P. JOHNSOfficer, and Controller
            (PG&E Corporation)
            *DINYAR B. MISTRYVice President-Controller
            (Pacific Gas and Electric Company)        		 February 19, 200418, 2005
        C.  Principal Accounting Officers
        *CHRISTOPHER P. JOHNSD.        		 Senior Vice President and Controller (PG&E Corporation)February 19, 2004
             *DINYAR B. MISTRYVice President-Controller (Pacific Gas and Electric Company)February 19, 2004
        D.  Directors    
         *DAVID R. ANDREWS
        *LESLIE S. BILLER
        *DAVID A. COULTER
        *C. LEE COX
        *WILLIAM S. DAVILAPETER A. DARBEE
        *ROBERT D. GLYNN, JR.
        *DAVID M. LAWRENCE, M.D.
        *MARY S. METZ
        *CARL E. REICHARDTBARBARA L. RAMBO
        *GORDON R. SMITH
             (Director(Director of Pacific Gas and
            Electric Company only)
        *BARRY LAWSON WILLIAMS        		 




        Directors of PG&E Corporation and
        Pacific Gas and Electric Company,
        except as noted
        		February 18, 2005



        *By

        /s/          BRUCE R. WORTHINGTON      
        (Bruce R. Worthington, Attorney-in-Fact)





        REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

        To the Boards of Directors and Shareholders of
        PG&E Corporation and Pacific Gas and Electric Company except as noted



        February 19, 2004

        *By GARY P. ENCINAS
        (Gary P. Encinas, Attorney-in-Fact)

        76

        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 (the "Company") and of Pacific Gas and Electric Company (a Debtor-in-Possession) and subsidiaries (collectively, the “Companies”(the "Utility") as of December 31, 20032004 and 2002,2003, and for each of the three years in the period ended December 31, 20032004, management's assessment of the effectiveness of the Company's and the Utility's internal control over financial reporting as of December 31, 2004, and the effectiveness of the Company's and the Utility's internal control over financial reporting as of December 31, 2004, and have issued our reportreports thereon dated February 18, 200416, 2005 (which report expresses an unqualified opinion and includes an explanatory paragraphsparagraph relating to accounting changes, a revision to the 2002 and 2001 financial statements of PG&E Corporation and going concern uncertainties). Suchchanges); such consolidated financial statements of each of the Companiesand reports are included in the combined 2003your 2004 Annual Report to Shareholders (of PG&E Corporationof the Company and Pacific Gas and Electric Company)the Utility and are incorporated herein by reference. Our audits also included the respective consolidated financial statement schedules of PG&E Corporationthe Company and Pacific Gas and Electric Company,the Utility listed in Item 15(a)15 (a) 2. These consolidated financial statement schedules are the responsibility of the respective managements of PG&E CorporationCompany's and Pacific Gas and Electric Company.the Utility's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the respective basic consolidated financial statements of PG&E Corporation and Pacific Gas and Electric Company taken as a whole, present fairly, in all material respects, the information set forth therein.

        DELOITTE & TOUCHE LLP

        San Francisco, California


        February 18, 200416, 2005


        77

        SCHEDULE I — I—CONDENSED FINANCIAL INFORMATION OF PARENT

        CONDENSED BALANCE SHEETS
        (in millions)

                   
        Balance at December 31,
        20032002
        (In millions)
        ASSETS
        Cash and cash equivalents $673  $182 
        Restricted cash  —   377 
        Advances to affiliates  398   479 
        Note receivable from subsidiary  —   208 
        Other current assets  9   1 
           
        		   
        		 
          Total current assets  1,080   1,247 
           
        		   
        		 
        Equipment  20   20 
        Accumulated depreciation  (15)  (12)
           
        		   
        		 
          Net equipment  5   8 
           
        		   
        		 
        Restricted Cash  361   — 
        Investments in subsidiaries  4,810   2,870 
        Other investments  24   33 
        Deferred income taxes  478   702 
        Other  32   34 
           
        		   
        		 
          Total Assets $6,790  $4,894 
           
        		   
        		 
        LIABILITIES AND SHAREHOLDERS’ EQUITY
        Current Liabilities        
         Accounts payable — related parties $2  $31 
         Accounts payable — other  28   38 
         Income taxes payable  258   133 
         Other  158   57 
           
        		   
        		 
          Total current liabilities  446   259 
           
        		   
        		 
        Noncurrent Liabilities:        
         Long-term debt  883   976 
         Net investment in NEGT  1,216   — 
         Other  30   46 
           
        		   
        		 
          Total noncurrent liabilities  2,129   1,022 
           
        		   
        		 
        Preferred Stock  —   — 
           
        		   
        		 
        Common Shareholders’ Equity        
         Common stock  6,468   6,274 
         Common stock held by subsidiary  (690)  (690)
         Unearned compensation  (20)  — 
         Accumulated deficit  (1,458)  (1,878)
         Accumulated other comprehensive income  (85)  (93)
           
        		   
        		 
          Total common shareholders’ equity  4,215   3,613 
           
        		   
        		 
          Total Liabilities and Shareholders’ Equity $6,790  $4,894 
           
        		   
        		 

         
        		 Balance at December 31,
        		 
         
        		 2004
        		 2003
        		 
        ASSETS       
         Cash and cash equivalents $183 $673 
         Advances in affiliates  22  398 
         Other current assets  3  9 
          
        		 
        		 
          Total current assets  208  1,080 
          
        		 
        		 
         Equipment  15  20 
         Accumulated depreciation  (13) (15)
          
        		 
        		 
          Net equipment  2  5 
          
        		 
        		 
         Restricted cash  —  361 
         Investments in subsidiaries  8,848  4,810 
         Other investments  31  24 
         Deferred income taxes  104  478 
         Other  14  32 
          
        		 
        		 
          Total Assets $9,207 $6,790 
          
        		 
        		 
        LIABILITIES AND SHAREHOLDERS' EQUITY       
        Current Liabilities       
         Accounts payable—related parties $3 $2 
         Accounts payable—other  15  28 
         Income taxes payable  83  258 
         Other  53  158 
          
        		 
        		 
          Total current liabilities  154  446 
          
        		 
        		 
        Noncurrent Liabilities:       
         Long-term debt  280  883 
         Net investment in NEGT  —  1,216 
         Other  140  30 
          
        		 
        		 
          Total noncurrent liabilities  420  2,129 
          
        		 
        		 
        Preferred stock  —  — 
        Common Shareholders' Equity       
         Common stock  6,518  6,468 
         Common stock held by subsidiary  (718) (690)
         Unearned compensation  (26) (20)
         Accumulated earnings (deficit)  2,863  (1,458)
         Accumulated other comprehensive loss  (4) (85)
          
        		 
        		 
          Total common shareholders' equity  8,633  4,215 
          
        		 
        		 
          Total Liabilities and Shareholders' Equity $9,207 $6,790 
          
        		 
        		 

        78


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

        CONDENSED STATEMENTS OF OPERATIONS


        For the Years Ended December 31, 2004, 2003, 2002 and 20012002
        (in millions, except per share amounts)

         
        		 2004
        		 2003
        		 2002
        		 
        Administrative service revenue $85 $101 $96 
        Equity in earnings of subsidiaries  3,959  917  1,842 
        Operating expenses  (110) (133) (141)
        Interest income  15  20  30 
        Interest expense  (132) (200) (253)
        Other income (expense)  (91) 2  81 
          
        		 
        		 
        		 
        Income before income taxes  3,726  707  1,655 
        Less: Income tax benefit  (94) (84) (68)
          
        		 
        		 
        		 
        Income from continuing operations  3,820  791  1,723 
        Gain on disposal of NEGT  684  —  — 
        Discontinued operations  —  (365) (2,536)
        Cumulative effect of changes in accounting principles  —  (6) (61)
          
        		 
        		 
        		 
        Net income (loss) before intercompany eliminations $4,504 $420 $(874)
          
        		 
        		 
        		 
        Weighted average common shares outstanding $398 $385 $371 
          
        		 
        		 
        		 
        Earnings (loss) per common share, basic(1) $10.80 $1.04 $(2.30)
          
        		 
        		 
        		 
        Earnings (loss) per common share, diluted(1) $10.57 $1.02 $(2.27)
          
        		 
        		 
        		 


        SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)

                     
        200320022001
        (In millions except
        per share amounts)
        Administrative service revenue $101  $96  $95 
        Equity in earnings of subsidiaries  917   1,842   1,087 
        Operating expenses  (133)  (141)  (108)
        Interest income  20   30   35 
        Interest expense  (200)  (253)  (132)
        Other income  2   81   4 
           
        		   
        		   
        		 
        Income before income taxes  707   1,655   981 
        Less: Income tax benefit  (84)  (68)  (40)
           
        		   
        		   
        		 
        Income from continuing operations  791   1,723   1,021 
        Discontinued operations  (365)  (2,536)  69 
        Cumulative effect of changes in accounting principles  (6)  (61)  9 
           
        		   
        		   
        		 
        Net income (loss) before intercompany elimination $420  $(874) $1,099 
           
        		   
        		   
        		 
        Weighted Average Common Shares Outstanding  385   371   363 
           
        		   
        		   
        		 
        Earnings (Loss) Per Common Share, Basic $1.09  $(2.36) $3.03 
           
        		   
        		   
        		 
        Earnings (Loss) Per Common Share, Diluted $1.06  $(2.26) $3.02 
           
        		   
        		   
        		 

        CONDENSED STATEMENTS OF CASH FLOWS


        For the Years Ended December 31, 2004, 2003, and 2002
        (in millions)

         
        		 2004
        		 2003
        		 2002
        		 
        Cash Flows from Operating Activities:          
        Net income (loss) $4,504 $420 $(874)
        Gain on disposal of NEGT (net of $30 million payment to NEGT)  (684) —  — 
        Loss from discontinued operations  —  365  2,536 
        Cumulative effect of changes in accounting principles  —  6  61 
          
        		 
        		 
        		 
        Net income from continuing operations  3,820  791  1,723 
        Adjustments to reconcile net income (loss) to net cash provided by operating activities:          
         Equity in earnings of subsidiaries  (3,959) (917) (1,842)
         Restricted cash  361  —  — 
         Deferred taxes  27  265  (660)
         NEGT settlement payment  (30) —  — 
         Other—net  160  391  458 
          
        		 
        		 
        		 
        Net cash provided (used) by operating activities  379  530  (321)
          
        		 
        		 
        		 
        Cash Flows From Investing Activities:          
         Capital expenditures  —  —  (1)
         Investment in subsidiaries  (28) —  — 
          
        		 
        		 
        		 
        Net cash used by investing activities  (28) —  (1)
          
        		 
        		 
        		 
        Cash Flows From Financing Activities(2):          
         Common stock issued  162  166  217 
         Common stock repurchased  (350) —  — 
         Long-term debt issued  —  581  847 
         Long-term debt redeemed  (652) (787) (908)
         Other—net  (1) 1  — 
          
        		 
        		 
        		 
        Net cash provided (used) by financing activities  (841) (39) 156 
          
        		 
        		 
        		 
        Net change in cash and cash equivalents  (490) 491  (166)
        Cash and cash equivalents at January 1  673  182  348 
          
        		 
        		 
        		 
        Cash and cash equivalents at December 31  183  673  182 
          
        		 
        		 
        		 
        (1)
        PG&E Corporation adopted the consensus reached by Emerging Issues Task Force, or EITF, in EITF issue No. 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06, as ratified by the Financial Accounting Standards Board on March 31, 2004.

          PG&E Corporation currently has outstanding $280 million principal amount of convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes, which were issued in June 2002, meet the criteria of a participating security in the calculation of earnings per share using the "two-class" method.

          Accordingly, the basic and 2001diluted earnings per share calculations for each of the years in the three year period ended December 31, 2004 reflect the allocation of earnings between PG&E Corporation common stock and the participating security.

        (2)
        PG&E Corporation did not receive any cash dividends during 2004, 2003 and 2002

                      
        200320022001
        (In millions)
        Cash Flows from Operating Activities:            
        Net income (loss) $420  $(874) $1,099 
        Loss (income) from discontinued operations  365   2,536   (69)
        Cumulative effect of changes in accounting principles  6   61   (9)
           
        		   
        		   
        		 
        Net income from continuing operations  791   1,723   1,021 
        Adjustments to reconcile net income (loss) to net cash provided by operating activities:            
         Equity in earnings of subsidiaries  (917)  (1,842)  (1,087)
         Deferred taxes  265   (660)  (51)
         Other-net  391   458   237 
           
        		   
        		   
        		 
        Net cash provided (used) by operating activities  530   (321)  120 
           
        		   
        		   
        		 
        Cash Flows From Investing Activities:            
         Capital expenditures  —   (1)  (4)
           
        		   
        		   
        		 
        Net cash used by investing activities  —   (1)  (4)
           
        		   
        		   
        		 
        Cash Flows From Financing Activities:            
         Common stock issued  166   217   15 
         Common stock repurchased  —   —   (1)
         Long-term debt issued  581   847   907 
         Long-term debt redeemed  (787)  (908)  — 
         Short-term debt issued redeemed  —   —   (931)
         Dividends paid  —   —   (109)
         Other-net  1   —   — 
           
        		   
        		   
        		 
        Net cash provided (used) by financing activities  (39)  156   (119)
           
        		   
        		   
        		 
        Net Change in Cash & Cash Equivalents  491   (166)  (3)
        Cash & Cash Equivalents at January 1  182   348   351 
           
        		   
        		   
        		 
        Cash & Cash Equivalents at December 31 $673  $182  $348 
           
        		   
        		   
        		 

        79


        PG&E CORPORATION

        SCHEDULE II — II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS


        For the Years Ended December 31, 2004, 2003 2002 and 20012002

         
        		  
        		 Additions
        		  
        		  
        Description
        		 Balance
        at Beginning of Period
        		 Charged to Costs and
        Expenses
        		 Charged to Other
        Accounts
        		 Deductions(3)
        		 Balance
        at End of Period
         
        		 (in millions)

        Valuation and qualifying accounts deducted from assets:               
         2004               
          Allowance for uncollectible accounts(1)(2) $68 $85 $— $60 $93
          
        		 
        		 
        		 
        		 
         2003:               
          Allowance for uncollectible accounts(1)(2) $59 $42 $— $33 $68
          
        		 
        		 
        		 
        		 
         2002:               
          Allowance for uncollectible accounts(1)(2) $48 $36 $(2)$23 $59
          
        		 
        		 
        		 
        		 
        (1)
        Allowance for uncollectible accounts is deducted from "Accounts receivable Customers, net."

        (2)
        Allowance for uncollectible accounts does not include NEGT.

        (3)
        Deductions consist principally of write-offs, net of collections of receivables previously written off.

                               
        Additions
        Balance atCharged toChargedBalance at
        BeginningCosts andto OtherEnd of
        Descriptionof PeriodExpensesAccountsDeductionsPeriod
        (in millions)
        Valuation and qualifying accounts deducted from assets:                
         2003:                    
          
        Allowance for uncollectible accounts(1)(2)
        		 $59  $42  $—  $33(3) $68 
           
        		   
        		   
        		   
        		   
        		 
         2002:                    
          
        Allowance for uncollectible accounts(1)(2)
        		 $48  $34  $(2) $23(3) $59 
           
        		   
        		   
        		   
        		   
        		 
         2001:                    
          
        Allowance for uncollectible accounts(1)(2)
        		 $52  $24  $—  $28(3) $48 
           
        		   
        		   
        		   
        		   
        		 
          
        Provision for loss on generation-related regulatory assets and undercollected purchased power costs(4)
        		 $6,939  $—  $—  $6,939  $— 
           
        		   
        		   
        		��  
        		   
        		 


        (1)        		Allowance for uncollectible accounts is deducted from “Accounts receivable Customers, net.”
        (2)Allowance for uncollectible accounts does not include NEGT.
        (3)Deductions consist principally of write-offs, net of collections of receivables previously written off.
        (4)Provision was deduction from “Regulatory Assets.”

        80

        PACIFIC GAS AND ELECTRIC COMPANY A DEBTOR IN POSSESSION

        SCHEDULE II — II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS


        For the Years Ended December 31, 2004, 2003 2002 and 20012002

         
        		  
        		 Additions
        		  
        		  
        Description
        		 Balance
        at Beginning of Period
        		 Charged to Costs and
        Expenses
        		 Charged to Other Accounts
        		 Deductions(2)
        		 Balance
        at End of Period
         
        		 (in millions)

        Valuation and qualifying accounts deducted from assets:               
         2004               
          Allowance for uncollectible accounts(1) $68 $85 $— $60 $93
          
        		 
        		 
        		 
        		 
         2003:               
          Allowance for uncollectible accounts(1) $59 $42 $— $33 $68
          
        		 
        		 
        		 
        		 
         2002:               
          Allowance for uncollectible accounts(1) $48 $36 $(2)$23 $59
          
        		 
        		 
        		 
        		 
        (1)
        Allowance for uncollectible accounts is deducted from "Accounts receivable Customers, net."

        (2)
        Deductions consist principally of write-offs, net of collections of receivables previously written off.


        EXHIBIT INDEX

                               
        Additions
        Balance atCharged toChargedBalance at
        BeginningCosts andto OtherEnd of
        Descriptionof PeriodExpensesAccountsDeductionsPeriod
        (in millions)
        Valuation and qualifying accounts deducted from assets:                
         2003:                    
          
        Allowance for uncollectible accounts(1)
        		 $59  $42  $—  $33(2) $68 
           
        		   
        		   
        		   
        		   
        		 
         2002:                    
          
        Allowance for uncollectible accounts(1)
        		 $48  $34  $(2) $23(2) $59 
           
        		   
        		   
        		   
        		   
        		 
         2001:                    
          
        Allowance for uncollectible accounts(1)
        		 $52  $24  $—  $28(2) $48 
           
        		   
        		   
        		   
        		   
        		 
          
        Provision for loss on generation-related regulatory assets and undercollected purchased power costs(3)
        		 $6,939  $—  $—  $6,939  $— 
           
        		   
        		   
        		   
        		   
        		 

        Exhibit
        Number
        		Exhibit Description
        2.1Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
        (1) 2.2AllowanceOrder of the U.S. Bankruptcy Court for uncollectible accounts is deducted from “Accounts receivable Customers, net.”the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
        3.1Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
        (2) 3.2Deductions consist principallyCertificate of write-offs, net of collections of receivables previously written off.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)
        3.3Bylaws of PG&E Corporation amended as of January 1, 2005
        (3) 3.4Provision was deduction from “Regulatory Assets.”Bylaws of PG&E Corporation amended as of April 20, 2005

        81

        EXHIBIT INDEX

             
        Exhibit
        NumberExhibit Description
         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 Bylaws of PG&E Corporation amended as of February 18, 2004
         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 Bylaws of Pacific Gas and Electric Company amended as of February 18, 2004
         4.1 First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (incorporated by reference to Registration No. 2-1324, Exhibits B-1, B-2, and 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; and Pacific Gas and Electric Company’s Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2)
         4.2 Indenture related to PG&E Corporation’s 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
         4.3 Supplemental Indenture related to PG&E Corporation’s 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
         4.4 Warrant Agreement, dated as of June 25, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation’s Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.9).
         4.5 Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)
         4.6 Form of Rights Agreement dated as of December 22, 2000, between PG&E Corporation and Mellon Investor Services LLC, including the Form of Rights Certificate as Exhibit A, the Summary of Rights to Purchase Preferred Stock as Exhibit B, and the Form of Certificate of Determination of Preferences for the Preferred Stock as Exhibit C (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)
         4.7 Amendment to Rights Agreement dated February 18, 2004, between PG&E Corporation and Mellon Investor Services LLC (incorporated by reference to PG&E Corporation’s Form 8-K filed February 19, 2004 (file No. 1-12609), Exhibit 99)
         4.8 Indenture dated as of July 2, 2003, by and between PG&E Corporation and Bank One, N.A. (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.1)
         4.9 Utility Stock Base Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.2)

             
        Exhibit
        NumberExhibit Description
         4.10 Utility Stock Protective Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.3)
         4.11 Form of 6 7/8 percent Senior Secured Note due 2008 (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.4)
         10.1 The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055 (incorporated by reference to PG&E Corporation’s 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 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 PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10); and the Gas Accord II Settlement Agreement, approved by the California Public Utilities Commission on August 22, 2002, in Decision 01-09-016 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)
         10.2 Commitment Letter dated March 5, 2003, between PG&E Corporation and Lehman Brothers, Inc. (incorporated by reference to PG&E Corporation’s Form 8-K filed March 6, 2003) (File No. 1-12609), Exhibit 99.2)
         10.3 Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348); Exhibit 99)
         10.4 Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions
         10.5 Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996
         10.6 PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999
         10.7 Electronic Commerce System User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation, effective as of September 28, 2001
         10.8 Operating Agreement effective as of April 1, 2003, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348); Exhibit 10.1)
         *10.9 PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.4)
         *10.10 Agreement and Release between PG&E Corporation and Thomas G. Boren, dated December 18, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.23)
         *10.11 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)
         *10.12 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)
         *10.13 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)

        3.5Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
        3.6Bylaws of Pacific Gas and Electric Company amended as of January 1, 2005
        3.7Bylaws of Pacific Gas and Electric Company amended as of April 20, 2005
        4.1Indenture of Mortgage, dated as of March 11, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
        4.2First Supplemental Indenture, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.2)
        4.3Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4)
        4.4Escrow Deposit and Disbursement Agreement, dated as of March 23, 2004, among Pacific Gas and Electric Company and BNY Western Trust Company as escrow agent and trustee (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.3)
        4.5Calculation Agency Agreement, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.4)
           

        4.6Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
        4.7Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
        4.8Warrant Agreement, dated as of June 25, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.9).
        4.9Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)
        10.1Credit Agreement dated as of March 5, 2004, among Pacific Gas and Electric Company, as borrower, the Several Lenders from time to time parties thereto, Citicorp North America, Inc., as Administrative Agent, Banc One Capital Markets, Inc., as Syndication Agent, and Lehman Commercial Paper Inc., Credit Suisse First Boston, acting through its Cayman Islands Branch, and UBS Securities LLC, as Co- Documentation Agents (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 10, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
        10.2Credit Agreement, dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities, as syndication agent, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, and The Bank of New York (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed December 15, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99.)
        10.3Master Confirmation dated December 15, 2004, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
        10.4Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
        10.5Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.4)
        10.6Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.5)
          

        Exhibit10.7PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.6)
        Number10.8Exhibit DescriptionTransmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, initially effective March 31, 1998, as amended to date (CAISO, FERC Electric Tariff No. 7)
        10.9
        Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company
        *10.10*10.14PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004
        *10.11PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005
        *10.12Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)
        *10.13Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
        *10.14Letter 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)
        *10.15 Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)
        *10.15Description 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)
        *10.1610.16 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609);, Exhibit 10.3)
        *10.17Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609); Exhibit 10.4)
        *10.1810.17 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)]
        *10.19.1Letter 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)
        *10.19.2Letter regarding retention award to Gordon R. Smith dated January 22, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.2)
        *10.19.3Letter 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)
        *10.19.4Letter 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)
        *10.19.5Letter 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)
        *10.19.6Letter regarding retention award to Daniel D. Richard, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.6)
        *10.19.7Letter regarding retention award to James K. Randolph dated February 27, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.7)
        *10.19.8Letter regarding retention award to Gregory M. Rueger dated February 27, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.8)
        *10.19.9Letter regarding retention award to Kent M. Harvey dated February 27, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.9)
        *10.19.10Letter regarding retention award to Roger J. Peters dated February 27, 2001 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10.10.10)
        *10.19.11Letter 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)
        *10.19.12Letter 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)

        Exhibit
        NumberExhibit Description
        *10.19.13Letter 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)
        *10.20Pacific Gas and Electric Company Management Retention Program (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)
        *10.21PG&E Corporation Management Retention Program (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.2)
        *10.22PG&E Corporation2005 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)January 1, 2005
        *10.2310.18 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.35)2005
        *10.2410.19 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2004 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.24)
        *10.2510.20 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of September 19, 2001 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2001 (File No. 1-2248), Exhibit 10.16)2004, and frozen as of January 1, 2005
        *10.21*10.26.1Supplemental Executive Retirement Plan of PG&E Corporation effective January 1, 2005
        *10.22.1 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.1)
        *10.26.210.22.2 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2)
         *10.26.3

        *10.22.3 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.3)
        *10.26.410.22.4 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.4)
        *10.26.510.22.5 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.5)
        *10.26.6Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Thomas G. Boren dated December 20, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.6)
        *10.27.110.23.1 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609);, Exhibit 10.2.1)
        *10.27.210.23.2 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348);, Exhibit 10.2.2)

        Exhibit
        NumberExhibit Description
        *10.27.3Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated April 18, 2003 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348); Exhibit 10.2.3)
        *10.27.410.23.3 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348);, Exhibit 10.2.4)
        *10.27.510.23.4 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609);, Exhibit 10.2.5)
        *10.2810.24 Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
        *10.2910.25 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
        *10.30PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 1997 (File No. 1-12609), Exhibit 10.13)
        *10.3110.26 PG&E Corporation Long-Term Incentive Program as amended May 16, 2001, including(including the PG&E Corporation Stock Option Plan and Performance Unit Plan, and Non-Employee Director Stock Incentive PlanPlan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
        *10.3210.27 PG&E Corporation ExecutiveNon-Employee Director Stock Ownership Program Guidelines datedIncentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of February 19, 2003July 1, 2004 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004)

        *10.28Resolution of the PG&E Corporation Board of Directors dated June 16, 2004, adopting director compensation arrangement (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003June 30, 2004 (File No. 1-12609);1-12609 and File No. 12348), Exhibit 10.2)10.1)
        *10.3310.29 PG&E Corporation Officer Severance Policy, amended asResolution of December 19, 2001the Pacific Gas and Electric Company Board of Directors dated June 16, 2004, adopting director compensation arrangement (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.43)
        *10.34PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998June 30, 2004 (File No. 1-12609), Exhibit 10.1)
        *10.35PG&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 (File1-12609 and File No. 1-12609)12348), Exhibit 10.2)
        *10.3610.30 PG&E Corporation Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46)
        *10.3710.31 Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37)
        *10.32*10.38Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3)
        *10.33Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
        *10.34Form of Performance Share Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2)
        *10.35 Form of Performance Share Award Agreement granted under the PG&E Corporation Long-Term Incentive Program
        *10.39PG&E National Energy Group, Inc. Management Retention/ Performance Award Program (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K/A Amendment No. 210-K for the year ended December 31, 20022003 (File No. 1-12609);, Exhibit 10.47)10.38)
        *10.39.110.36 Letter regarding retention award to Thomas B. KingPG&E Corporation Executive Stock Ownership Program Guidelines dated September 9, 2002as of February 19, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-K/ A Amendment No. 210-Q for the yearquarter ended DecemberMarch 31, 20022003 (File No. 1-12609);)
        *10.37PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2005
        *10.38PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.47.1)10.1)

             
        Exhibit
        NumberExhibit Description
         *10.39.2 Letter regarding retention award to P. Chrisman Iribe dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609); Exhibit 10.47.2)
         *10.39.3 Letter regarding retention award Lyn E. Maddox dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609); Exhibit 10.47.3)
         11  Computation of Earnings Per Common Share
         12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
         12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
         13  The following portions of the 2003 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Independent Auditors’ Report,” “Responsibility for Consolidated Financial Statements,” financial statements of PG&E Corporation entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Common Shareholders’ Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” “Consolidated Statements of Shareholders’ Equity,” “Notes to Consolidated Financial Statements,” and “Quarterly Consolidated Financial Data (Unaudited)”
         21  Subsidiaries of the Registrant
         23  Independent Auditors’ Consent (Deloitte & Touche LLP)
         24.1 Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
         24.2 Powers of Attorney
         31.1 Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
         31.2 Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
         **32.1 Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
         **32.2 Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

        *10.39PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005
        *10.40Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996
        *10.41Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995
        11Computation of Earnings Per Common Share
        12.1Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
         * Management contract or compensatory agreement.

        12.2Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
        13The following portions of the 2004 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)," "Management's Report on Internal Control Over Financial Reporting," "Report of Independent Registered Public Accounting Firm," "Report of Independent Registered Public Accounting Firm," "Responsibility for Consolidated Financial Statements"
        21Subsidiaries of the Registrant
        23Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
        24.1Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
        24.2Powers of Attorney
        31.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
        31.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
        **32.1Pursuant to Item 601(b)(32)Certifications of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
        **32.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

        *
        Management contract or compensatory agreement.

        **
        Pursuant to Item 601(b) (32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.



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        Securities registered pursuant to Section 12(b) of the Act
        Securities registered pursuant to Section 12(g) of the Act: None
        DOCUMENTS INCORPORATED BY REFERENCE
        TABLE OF CONTENTS
        UNITS OF MEASUREMENT
        PART I
        EXECUTIVE OFFICERS OF THE REGISTRANTS
        PART II
        PART III
        SIGNATURES
        CONDENSED BALANCE SHEETS (in millions)
        SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)
        SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)
        PG&E CORPORATION
        SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2004, 2003 and 2002
        PACIFIC GAS AND ELECTRIC COMPANY
        SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2004, 2003 and 2002
        EXHIBIT INDEX