UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FormFORM 10-K
(Mark One)
 
(Mark One)x
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 20032006
or
oOr
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
Commission
Exact Name of Registrant
State of
IRS Employer
File Numberas specified in its charter
State or Other Jurisdiction of
Incorporation or Organization
IncorporationIRS Employer
Identification Number




1-12609PG&E CORPORATIONCalifornia94-3234914
1-2348PACIFIC GAS AND ELECTRIC COMPANYCalifornia94-0742640
PG&E Corporation
One Market, Spear Tower
Suite 2400
San Francisco, California 94105
(Address of principal executive offices) (Zip Code)
(415) 267-7000
(Registrant's telephone number, including area code)
Pacific Gas and Electric Company
77 Beale Street
P.O. Box 770000
San Francisco, California 94177
(Address of principal executive offices) (Zip Code)
(415) 973-7000
(Registrant's telephone number, including area code)
   
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)

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange on Which Registered


PG&E CorporationCorporation:
Common Stock, no par value
Preferred Stock Purchase Rights
New York Stock Exchange and Pacific Exchange
Pacific Gas and Electric Company
Company:
First Preferred Stock,
cumulative, par value $25 per share:
American Stock 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
PG&E Corporation
Yes x No o
Pacific Gas and Electric Company
Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
PG&E Corporation
Yes ¨ No x
Pacific Gas and Electric Company
Yes o No x

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 þ No o

PG&E Corporation
Yes x No o
Pacific Gas and Electric Company
Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’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 Corporation    o

Pacific Gas and Electric Company    þ
PG&E Corporation
x
Pacific Gas and Electric Company
x


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, (as definedor a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act Rule 12b-2).Act. (Check one):
PG&E Corporation
Large accelerated filer x
Yes Accelerated filer þ¨
No Non-accelerated filer o¨
Pacific Gas and Electric Company
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer x



Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation
Yes ¨ No x
Pacific Gas and Electric Company
Yes o
No þx


Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2003,2006, the last business day of the second fiscal quarter:
PG&E Corporation Common Stock$8,16413,640 million
Pacific Gas and Electric Company Common StockWholly owned by PG&E Corporation
Common Stock outstanding as of February 20, 2007:
PG&E Corporation:350,817,275 (excluding shares held by a wholly owned subsidiary)
Pacific Gas and Electric Company:Wholly owned by PG&E Corporation


Common Stock outstanding as of February 17, 2004:
PG&E Corporation:418,976,121
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.
involved:
Designated portions of the combined 2006 Annual Report to Shareholders for the year ended December 31, 2003Part I (Item 1)1, Item 1.A.), Part II (Items 5, 6, 7, 7A, 8 and 8), 9A)
Designated portions of the Joint Proxy Statement relating to the 2007Part IV (Item 15)III (Items 10, 11, 12, 13 and 14)
Annual Meetings of Shareholders







TABLE OF CONTENTS

  
Page

 iiiiv
Item 1.Business1
 General1
 1
 1
 1
 Corporate and Other Information21
 Employees23
 The Utility’s Plan of Reorganization and Settlement Agreement23
 3
 Forward Looking Statements and Risk Factors4
 Electric Utility Operations64
 Electricity Distribution Operations65
 Electricity Resources87
 Electricity Transmission127
 7
 9
10
10
10
10
11
11
11
11
Energy Efficiency Programs
11
Demand Response Programs
12
Self-Generation Incentive, California Solar Initiative
12
Low-Income Energy Efficiency Programs and California Alternate Rates for Energy
12
12
12
12
13
13
14
14
14
15
15
15
15
15
16
16
16

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17
17
17
18
18
19
20
20
21
21
1322
 1623
 Gas Gathering Facilities1623
 24
 25
1625
 Competition1726
 The Electric Industry1826
 The Natural Gas Industry1927
 PG&E Corporation’s Regulatory Environment2027
 Federal Energy Regulation2029
 State Energy Regulation2029
 The Utility’s Regulatory Environment22
22
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 Remediation3529
 3731
 3831
 3931
Properties40

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32
Page32

32
4032
 Pacific Gas and Electric Company Chapter 11 Filing4133
 43
Pacific Gas and Electric Company vs. Michael Peevey, et al. 43
In. re: Natural Gas Royalties Qui Tam Litigation44
Diablo Canyon Power Plant44
Complaints Filed by the California Attorney General, City and County of San Francisco and Cynthia Behr4533
 Compressor Station Chromium Litigation4734
35
 4835
  Executive Officers of the Registrants48 
5138
5139
Management’s5139
5239
5239
40
40
40
  52
Item 9A.Controls and Procedures52
PART III
Item 10.Directors and Executive Officers of the Registrant52 
   
Directors52
5442
Section 16 Beneficial Ownership Reporting Compliance5442
Audit Committee Members and Financial Expert54
Website Availability of Corporate Governance and Other Documents54
Item 11.Executive Compensation55
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 Provisions61
43

ii



6243
43
   
Security Ownership of Management
6244
 Principal Shareholders6450
 Equity Compensation Plan Information65
Item 13.Certain Relationships and Related Transactions65
Item 14.Principal Accountant Fees and Services6551
 Fees Paid to Independent Public Accountants65
Pre-Approval of Services Provided by the Independent Public Accountant66
PART IV
Item 15.Exhibits, 67
Signatures76
Independent Auditors’ Report77
Financial Statement Schedules7852

ii



iii




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 HourGigawatt-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
1Bcf1 Bcf=One billion cubic feet
1MDth1 MDth=One thousand decatherms

iii



iv



PART I


Item 1. Business.


GENERALGeneral 


Corporate Structure and Business


PG&E Corporation, incorporated in California in 1995, is an energy-baseda holding company thatwhose primary purpose is to hold interests in energy-based businesses. PG&E Corporation 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. The Utility was incorporated in California in 1905. 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. PG&E Corporation also currently owns National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., which engages in electricity generation and natural gas transportation in the United States, or U.S.

The Utility

The Utility served approximately 4.95.1 million electricity distribution customers and approximately 3.94.2 million natural gas distribution customers at December 31, 2003.2006. The Utility had approximately $29.1$34.4 billion of assets at December 31, 2003,2006, and generated revenues of approximately $10.4$12.5 billion in 2003.2006. 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 caused the Utility to take this action are discussed in Management’s Discussion


Corporate 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’s and the Utility’s Combined 2003 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.Other Information


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 filed a voluntary petition for relief under the provisions of Chapter 11 in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. On 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-

1


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 and in Note 5 of the Notes to the Consolidated Financial Statements 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 on July 7, 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 results of operations no longer are consolidated with those of PG&E Corporation. NEGT’s results of operations through July 7, 2003, and for prior years have been reclassified as discontinued operations and PG&E Corporation now accounts for its investment in NEGT using the cost method of accounting.

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.comwww.pgecorp.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, 2003,2006, PG&E Corporation and its subsidiaries and affiliates (excluding NEGT) had approximately 20,60020,400 employees, including approximately 20,30020,200 employees of the Utility. Of the Utility’sUtility's employees, approximately 13,50013,400 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO, or the IBEW; the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC, or the ESC; and the Service Employees International Union, of Security Officers/ SEIU, Local 24/7, or the SEIU. The ESC and IBEW collective bargaining agreements expire on December 31, 2007.2008. The SEIU collective bargaining agreement expires on February 28, 2008.

2009.


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

2


     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

3


• 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 ofinformation incorporated by reference from the joint Annual Report incorporated by reference,to Shareholders for the year ended December 31, 2006, or the 2006 Annual Report, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations and projections about future events, and assumptions which management believes are reasonableregarding these events and onmanagement's knowledge of facts as of the information currently available to management.date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated Utility rate base, estimated environmental remediation liabilities, the anticipated outcome of various regulatory and legal proceedings, future cash flows, and the level of future equity or debt issuances, and are also identified by words such as “estimates,“assume,“expects,“expect,“anticipates,“intend,“plans,“plan,“believes,“project,“could,“believe,” “estimate,” “predict,” “anticipate,” “aim, “ “may,” “might,” “should,” “would,” “may”“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, someresults. 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 the Plan of Reorganization is Implemented

include, but are not limited to:

1

·  
• 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.timely recover costs through rates;

Operating Environment

·  the outcome of regulatory proceedings, including ratemaking proceedings pending at the CPUC and the FERC;
·  
• Unanticipated changes in operating expenses or capital expenditures;
• The levelthe adequacy and volatilityprice of wholesale electricity and natural gas prices and supplies, and the Utility’s ability of the Utility to manage and respond to the levelsvolatility of the electricity and volatility successfully;natural gas markets; 
·  
• Weather,the effect of weather, storms, earthquakes, fires, floods, disease, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards that could affect demand, result in power outages, reduce generating output, or cause damage to the Utility’s assets orfacilities and operations, or those ofits customers and third parties on which the Utility relies;
·  the potential impacts of climate change on the Utility’s electricity and natural gas operations;
·  • Unanticipatedchanges in customer demand for electricity and natural gas resulting from 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 whichtechnology including the Utility’s residual net open position (i.e., the amountdevelopment 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 retirementalternative energy sources, or other closure of the Utility’s electricity generation facilities, thereasons;

·  operating performance of the Utility’s electricity generation facilities, and other factors;
• The operation of the Utility’s Diablo Canyon nuclear power plant, which exposesgenerating facilities, or Diablo Canyon, the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;
·  the ability of the Utility to potentially significant environmentalrecognize benefits from its initiatives to improve its business processes and capital expenditure outlays, and, to customer service;
·  the extentability of the Utility is unable to increasetimely complete its spent fuel storage capacity by 2007 or find an alternative depository, planned capital investment projects;
·  the risk that the Utility may be required to close its Diablo Canyon power plant and purchase electricity from more expensive sources;
• Actionsimpact of credit rating agencies;
• Significant changes in the Utility’s relationship with its employees, the availability of qualified personnelfederal or state laws, or their interpretation, on energy policy and the potential adverse effects if labor disputes were to occur;regulation of utilities and
• Acts of terrorism. their holding companies;

Legislative and Regulatory Environment and Pending Litigation

·  
• Thethe impact of current and future ratemaking actions of the CPUC,changing wholesale electric or gas market rules, including the outcome of the Utility’s 2003 General Rate Case,California Independent System Operator’s, or the GRC;
• Prevailing governmental policies and legislative or regulatory actions generally, including those ofCAISO’s, new rules to restructure 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;wholesale electricity market;
·  
• 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;
• Howhow 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 ofimposed on PG&E Corporation when it became 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

     The Utility’s electricity distribution network extends throughout all or a part of 46 of California’s 58 counties, comprising most of northern and central California. The Utility’s network consists of 120,428 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 89 transmission substations and 45 transmission switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. There are 609 distribution substations and 117 low voltage distribution substations. There are 264 combined transmission and distribution substations. Combined transmission and distribution substations have both transmission and distribution transformers.

     The Utility’s distribution network interconnects to the Utility’s electricity transmission system at 1,012 points. This interconnection between the Utility’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’s customers. The distribution substations serve as the central hubs of the Utility’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.

2003 Electricity Deliveries

     The following table shows the percentage of the Utility’s total 2003 electricity deliveries represented by each of its major customer classes:

(80,156 GWhs)

Agricultural and Other Customers6%
Industrial Customers18%
Residential Customers36%
Commercial Customers40%

6


Electricity Distribution Operating Statistics

The following table shows certain of the Utility’s operating statistics from 1999 to 2003 for electricity sold or delivered, including the classification of sales and revenues by type of service.

                       
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.

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Electricity Resources

The following table shows the percentage of the Utility’s total sources of electricity for 2003 represented by each major electricity resource:

Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities)36%
DWR29%
Qualifying Facilities/ Renewables23%
Irrigation Districts5%
Other Power Purchases7%

     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’s electricity resources are not sufficient to meet the demand of the Utility’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.

Generation Facilities

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

             
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’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, the Utility’s Diablo Canyon power plant achieved a capacity factor of approximately 88.5%.

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The following table outlines the Diablo Canyon power plant’s refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 19 to 21 months. The average length of a refueling outage over the last five years has been approximately 35 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the steam generator replacements in 2008 and 2009 discussed below. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of up to 80 days to accommodate non-routine tasks, such as expanded steam generator inspection and repair, low pressure turbine rotor replacement and the first of two proposed 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.

     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 additional annual premiums of up to $36.7 million.

     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 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 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 reactors 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 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 over 100 MW, the Utility may be assessed up to

9


$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, that 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 Humboldt Bay Unit 3 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’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 83 permits and licenses and 163 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses, all of the Utility’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 three years, the Utility has received six renewed hydroelectric project licenses from the FERC. Licenses associated with approximately 928 MW expire within the next five years. Licenses associated with approximately 2959 MW expire between 2009 and 2043.

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’ 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’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 allocated contracts, to the Utility’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. During 2004, a total average capacity of approximately 2,700 MW of the electricity under the DWR allocated contracts is subject to “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 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.

     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

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• 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’s discretion to review the prudence of the Utility’s administration and dispatch of the assumed DWR power purchase contracts consistent with applicable law.

Third Party Agreementsholding company;
 
·  
Qualifying Facility Agreementsthe extent to which PG&E Corporation or the Utility incurs costs in connection with pending litigation that are not recoverable through rates, from third parties, or through insurance recoveries;

     The Utility is required by CPUC decisions to purchase energy

·  the ability of PG&E Corporation and/or the Utility to access capital markets and other sources of credit;
·  the impact of environmental laws and regulations and the costs of compliance and remediation; and
·  the effect of municipalization, direct access, community choice aggregation, or other forms of bypass.
For more information about the more significant risks that could affect the outcome of these forward-looking statements and capacity from independent power producers that are qualifying facilitiesPG&E Corporation's and the Utility's future financial condition and results of operations, see the discussion under the Public Utility Regulatory Policies Act of 1978, or PURPA. Under 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 options and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility’s actual electrical output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the 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, the Utility had agreements with 300 qualifying facilities for approximately 4,400 megawatts, or MW,heading “Risk Factors” that are in operation. Agreements for approximately 4,000 MW expire between 2004 and 2028. Qualifying facility power purchase agreements for approximately 400 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 agreements with 50 qualifying facilities that are not currently providing or expected to provide electricity. The total of approximately 4,400 MW consists of approximately 2,600 MW from cogeneration projects, 800 MW from wind projects and 1,000 MW from other projects, including biomass, waste-to-energy, geothermal, solar and hydroelectric. On January 22, 2004, the CPUC adopted a decision that requires California investor-owned electric utilities to allow owners of qualifying facilities with power purchase agreements expiring beforeappears near the end of 2005 to extend these contracts for five years. Qualifying facility power purchase agreements accounted for approximately 20%the section entitled “Management's Discussion and Analysis of Financial Condition and Results of Operations,” or the Utility’s 2003 electricity sources, approximately 25% ofMD&A, in the Utility’s 2002 electricity sources, and approximately 21% of the Utility’s 2001 electricity resources. No single qualifying facility accounted for more than 5% of the Utility’s 2003, 2002 or 2001 electricity sources.

In a proceeding pending at the CPUC, the Utility has requested refunds in excess of $500 million for overpayments from June 2000 through March 2001 made to qualifying facilities. Under the Settlement Agreement, the net after-tax amount of any qualifying facilities refunds, which the Utility actually realizes in cash, claim offsets or other credits, would reduce the $2.21 billion after-tax regulatory asset.2006 Annual Report that is incorporated by reference into this Annual Report on Form 10-K. PG&E Corporation and the Utility are unabledo not undertake an obligation to estimate the outcome of this proceeding.

Irrigation Districts and Water Agencies

     The Utility has contracts with various irrigation districts and water agenciesupdate forward-looking statements, whether in response to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts’ and water 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 2004 to 2031. The Utility’s irrigation district and water agency contracts accounted for approximately 5% of 2003 electricity sources, approximately 4% of 2002 electricity sources and approximately 3% of 2001 electricity sources.

11

new information, future events or otherwise.


2

Other Third Party Power Agreements
PG&E Corporation's Regulatory Environment
Electricity Purchases to Satisfy the Residual Net Open Position


On January 1, 2003, the Utility resumed buying electricity to meet its residual net open position. During that year, more than 14,000 GWh of energy was bought and sold in the wholesale market to manage the 2003 residual net open position. Most of the Utility’s contracts entered into in 2003 had terms of less than one year. During 2004 the Utility plans to enter into contracts of longer duration to satisfy its near-term residual net open position.Federal Energy Regulation

Renewable Energy Contracts

California law requires that, beginning in 2003, each California investor-owned electric

As a public utility 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 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 the annual procurement target will initially require it to purchase about 750 GWh, of electricity from renewable resources each year. The Utility met its 2003 commitment and the CPUC has approved several contracts intended to meet its 2004 renewable energy requirement.
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’s and WAPA’s electricity transmission systems, the use of the Utility’s electricity transmission and distribution system by WAPA, and the integration of the Utility’s and WAPA’s customer demands and electricity resources. The contracts give the Utility access to WAPA’s excess hydroelectric power and obligate the Utility to provide WAPA with electricity when its own resources are not sufficient to meet its requirements. The contracts are scheduled to terminate on December 31, 2004, but terminationholding company, PG&E Corporation is subject to FERC approval, which the Utility expects to receive.

     The costs to fulfill the Utility’s obligations to WAPA under the contracts cannot be accurately estimated at this time since both the purchase price and the amount of electricity WAPA will need from the Utility in 2004 are uncertain. However, the Utility expects that the cost of meeting its contractual obligations 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.

For more information regarding the Utility’s power purchase contracts, see Note 12requirements of the Notes to the Consolidated Financial StatementsEnergy Policy Act of the Annual Report.

Electricity Transmission

     At December 31, 2003, the Utility owned 18,612 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 42,798 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 120,428 circuit miles of distribution lines and substations with a capacity of 24,218 MVA. In 2003, the Utility delivered 80,156 GWh to its customers, including 8,979 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.

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     The Utility has been working closely with the ISO to continue expanding the capacity on the Utility’s electric transmission system. The Utility is engaged in the following significant expansion projects:

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.

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’s 58 counties and includes most of northern and central California. In 2003, the Utility served approximately 3.9 million natural gas distribution customers. The total volume of natural gas throughput during 2003 was approximately 804 Bcf.

     At December 31, 2003, the Utility’s natural gas system consisted of 39,510 miles of distribution pipelines, 6,350 miles of transportation pipelines and three storage facilities. The Utility’s distribution network connects to the Utility’s transportation and storage system at approximately 2,200 major interconnection points. The Utility’s Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation, a subsidiary of NEGT, at the California-Oregon border. This line has a receipt capacity at the border of 2.0 Bcf per day. The Utility’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’s transportation and storage system in close proximity to approximately 90% of the Utility’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’s northern California transportation system.

     Since 1991, the CPUC has divided the Utility’s natural gas customers into two categories — core and noncore customers. This classification is based largely on a customer’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, core customers represented over 99% of the Utility’s total customers and 35% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility’s total customers and 65% of its total natural gas deliveries.

     The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility’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% of core market demand, receive natural gas bundled services from the Utility.

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     In accordance with a 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’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’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’s 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 competitive 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’s 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’s costs to serve each customer class. The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility’s results of operations over the long term are not affected by their consumption levels. The Utility’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’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 2002 California Gas Report updated the Utility’s annual natural gas requirements forecast for the years 2002 through 2023, forecasting average annual growth in the Utility’s natural gas deliveries of approximately 1.8%. 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.

2003 Natural Gas Deliveries

     The following table shows the percentage of the Utility’s total 2003 natural gas deliveries represented by each of the Utility’s major customer classes:

(804 Bcf)

��
Residential Customers25%
Transport only Customers (noncore)65%
Commercial Customers10%

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Natural Gas Operating Statistics

The following table shows the Utility’s operating statistics from 1999 through 2003 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:

                       
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 


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

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Natural Gas Supplies

     The Utility purchases natural gas to serve the Utility’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’s portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. During 2003, the Utility purchased approximately 292,000 MMcf of natural gas (net of the sale of excess supply) from 48 suppliers. Substantially all this natural gas was purchased under contracts with a term of less than one year. The Utility’s largest individual supplier represented approximately 9.6% of the total natural gas volume the Utility purchased during 2003.

The following table shows the total volume and the average price of natural gas in dollars per Mcf of the Utility’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 2003, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

                                         
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 


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

Gas Gathering Facilities

The Utility’s gas gathering system collects and processes natural gas from third-party wells in California. During 2003, approximately 4% of the Utility’s natural gas supplies came from various California producers and 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 475 miles of gas gathering pipelines, as well as dehydration, separation, regulation, odorization and metering equipment located at 62 stations. The gas gathering system is geographically dispersed and is located in 14 California counties. Approximately 120 MMcf per day of natural gas flows through the Utility’s gas gathering system.

Interstate and Canadian Natural Gas Transportation Services Agreements

     In 2003, approximately 67% of the Utility’s natural gas supplies came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core 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’ 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’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, approximately 29% of the Utility’s natural gas supplies came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Co.,

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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’s natural gas transportation system in the area of California near Topock, Arizona.

The following table shows certain information about the Utility’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, extend each of these natural gas transportation agreements for additional minimum terms ranging, depending on the particular agreement, from one to ten years. On the FERC-regulated pipelines, the Utility has a right of first refusal 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.

             
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 — 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.

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The Electricity Industry

     The FERC’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’ transmission grids. The FERC’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’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’s approval. The FERC has approved the first phase of the ISO’s new rules and implementation of the first phase is expected to be completed in the second 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 2004 to address these issues. Both the timing and substance of the FERC’s regional transmission organization policy and the FERC’s and the ISO’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 Utility2005, or the ISO, generally to use standard interconnection procedures and a standard agreement for generator interconnections. These rules would requireEPAct, which became effective on February 8, 2006. Among its key provisions, the Utility and the ISO to revise the existing 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, the 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, filed proposed tariffs changes on January 20, 2004. 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(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’ customers and be those 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’s and the Utility’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 ratepayers any costs of implementing the program not reasonably attributable to a community choice aggregator.

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     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’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. 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’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’s service territory. The City and County of San Francisco (along with other California communities) have been considering municipalization of the Utility’s electricity distribution system within their jurisdictions. In addition, the Sacramento Municipal Utility District currently is considering annexing portions of the Utility’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’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’s facilities. In May 2003, the South San Joaquin Irrigation District revealed its plans to invest over $40 million to duplicate the Utility’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’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’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’s distribution services. The Gas Accord changed the terms of service and rate structure for natural gas transportation, allowing the Utility’s core customers to purchase natural gas from competing suppliers. The Utility’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.

     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’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’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’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

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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’s Regulatory Environment

Federal Energy Regulation

     PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), ofEPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005, or PUHCA. Currently, PG&E Corporation has no expectation of becoming a registered holding company under PUHCA. The California Attorney General has filed a petition with the SEC requesting the SEC to review and revoke PG&E Corporation’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 from2005. Under 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’s petition.

During 2003, proposed federal energy legislation was considered by the U.S. Senate. If adopted, the legislation would, among other things, repeal 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. Under the proposed legislation that would replace PUHCA, public utilities and2005, public utility holding companies would remainfall principally under the regulatory oversight of the FERC, but notan independent agency within the SEC.U.S. Department of Energy, or the DOE.


During 2006, the FERC issued rules implementing PUHCA 2005 that impose on holding companies and their subsidiaries various requirements concerning access to books and records, accounting, record retention and the filing of reports. On June 15, 2006, PG&E Corporation filed a notification of waiver with the FERC, which was deemed granted by operation of law on August 14, 2006. The effect of this waiver is to exempt PG&E Corporation and its subsidiaries from all requirements of PUHCA 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes. The books and records provisions to which PG&E Corporation and its subsidiaries remain subject under PUHCA 2005 are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.

In addition to enacting PUHCA 2005, the EPAct also significantly modified the FERC's authority and standard of review for mergers and consolidations involving public utilities and their holding companies under Section 203 of the Federal Power Act of 1935.


State Energy Regulation

PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such byCalifornia. The CPUC has authorized the CPUC. However, the CPUC approval authorizing the Utility to form aformation of public utility holding company was grantedcompanies 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 guaranteeingcannot guarantee any obligations of PG&E Corporation without prior written consent from the CPUC;
·  the Utility’sUtility's dividend policy must continue to be established by the Utility’sUtility'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’sUtility's obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation’sCorporation's Board of Directors or (known as the first priority“first priority” condition); and

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


(As discussed below under “Item 3 - Legal Proceedings,” the California Attorney General and the City and County of San Francisco have alleged that PG&E Corporation and its directors, as well as the directors of the Utility, violated the CPUC’s holding company conditions during the California 2000-2001 energy crisis. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules and orders.)

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 permitaddress the use of the regulated utilities’ names and logos by their non-regulated affiliates, of regulated utilities to compete in the affiliated utility’s service territory, and also to use the name and logo of their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUC. The rules also address the separation of regulated utilities and their non-regulated affiliates, and information exchange among the affiliates, and energy procurement-related transactions among regulated utilities and their non-regulated affiliates. The rules also 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,December 2006, the CPUC adoptedrevised its rules that prohibit regulated utility electric procurement from entering into power procurement related transactions with an affiliate, subject to, the following exceptions:

among other changes:


·  
• anonymous transactions through approved interstate brokers and exchanges, providedemphasize that the solicitation/bidding process is structured so thatholding company may not aid or abet a utility's violation of the rules or act as a conduit to provide confidential information to an affiliate;

·  
require prior CPUC approval before the utility can contract with an affiliate for resource procurement (e.g., electricity or gas), except in blind transactions where the identity of the sellerother party is not known until the transaction is consummated;

·  require certain key officers to provide annual certifications of compliance with the affiliate rules;

3

·  prohibit certain key officers from serving in the same position at both the utility and the holding company, or, in the alternative, prohibit the sharing of lobbying, regulatory relations and certain legal services (except for legal services necessary to the buyer until agreementprovision of permitted shared services);

·  require the utility to obtain a “nonconsolidation opinion” indicating that it would not be consolidated into a bankruptcy of its holding company;

·  
adopt as part of the affiliate rules the utilities’ current requirements to maintain a balanced capital structure (proportions of equity, long term debt, and preferred stock) consistent with that most recently determined to be reasonable by the CPUC; and
·  make the CPUC's Energy Division responsible for hiring the independent auditors to conduct the biennial audits to verify that the utility is reached, and vice-versa;
• transactions for natural gas services betweenin compliance with 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.affiliate rules.


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 investigate the 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’ actions to “ringfence” their unregulated subsidiaries. The CPUC will also determine whether additional rules, conditions or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the holding company structure. The CPUC will investigate whether it should modify, change or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions or recommend statutory changes to the California legislature. As a result of the investigation, the CPUC may impose remedies, prospective rules, or conditions, as appropriate.

     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 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 holding companies had opposed this broader interpretation 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 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. In the other 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.

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     In a related decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the interim decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to 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 Appeals for the First Appellate District in San Francisco agreed to hear the petitions for review of the CPUC’s decisions. Oral argument before the appellate court is set for March 5, 2004.

     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’s 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. These complaints are not affected by the Settlement Agreement. For more information, see “Item 3 — Legal 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. In addition to enacting PUHCA 2005 to replace the Public Utility Holding Company Act of 1935 as discussed above, the EPAct significantly amended various federal energy laws applicable to electric and natural gas markets, including the Federal Power Act of 1935, the Natural Gas Act of 1938 and the Public Utility Regulatory Policies Act of 1978, or PURPA.

This section and the “Ratemaking Mechanisms” section below summarize some of the more significant energy laws, regulations and regulatory mechanisms affecting the Utility. These sectionssummaries 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 section of the MD&A.&A entitled “Regulatory Matters” in the 2006 Annual Report.


Federal Energy Regulation

The FERC

     The FERC is an independent agency within the U.S. Department of Energy, or DOE, that regulates the transmission and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale of electricity in interstate commerce. The FERC also regulates electricityinterconnections of transmission interconnections,systems with other electric systems and generation facilities; tariffs and conditions of service of regional transmission organizations, including the ISOCAISO; and the terms and rates of wholesale electricity sales. The ISOEPAct granted the FERC significant new responsibilities to oversee the reliability of the nation’s electricity transmission grid, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission corridors that are determined to be of national interest. The EPAct also expanded the FERC’s authority to impose penalties for violation of certain federal statutes, including the Federal Power Act of 1935 and the Natural Gas Act of 1938, and for violations of FERC-approved regulations. The FERC can impose penalties of up to $1,000,000 per day per violation. The FERC has jurisdiction over the Utility's electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility's hydroelectric generation facilities, and the interstate sale and transportation of natural gas.


Electric Reliability Standards; Development of Transmission Grid. As part of its directive to oversee the development of mandatory electric reliability standards to protect the national bulk power system, the FERC certified the North American Electric Reliability Corp., or the NERC, as the nation’s Electric Reliability Organization under the EPAct. The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC review. All proposed reliability standards must be submitted by the NERC to the FERC for its approval. The NERC has requested the FERC to approve a delegation agreement to permit the NERC to delegate its enforcement authority for a geographic area known as the Western Interconnection to the Western Electricity Coordinating Council. Failure of the Utility to comply with FERC-approved electric reliability standards may subject the Utility to penalties.In addition, the CAISO is responsible for providing open access electricity 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.

The FERC also has issued a rule on electric transmission pricing reforms designed to promote needed investment in energy infrastructure and to reduce transmission congestion. In addition, the FERC has jurisdiction over the Utility’sissued a rule to require transmission organizations with organized electricity markets to make available to load-serving entities long-term firm transmission revenue requirements and rates, the licensingrights so these entities can enter into long-term transmission service arrangements without being exposed to unhedged congestion cost risk.

4

Prevention of substantially all of the Utility’s hydroelectric generation facilities and the interstate sale and transportation of natural gas.

     In response to the California energy crisis,Market Manipulation. The EPAct also gave the FERC issued a seriesbroader authority to police and penalize the exercise of ordersmarket power or behavior intended to manipulate the prices paid in FERC-jurisdictional transactions. In January 2006, the FERC adopted rules to prohibit market manipulation, modeling its new rules on SEC Rule 10b-5, which prohibits fraud and manipulation in the spring and summerpurchase or sale 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 bidssecurities. Under the FERC's new regulations, it is unlawful 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

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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, the FERC is expected to consider ISO market monitoring and oversightany entity, directly or indirectly, in connection with the FERC’s reviewpurchase or sale of natural gas, electric energy, or transportation/transmission services subject to the jurisdiction of the ISO’s standard market design proposals. Market monitoring and mitigation also may be affected byFERC: (1) to use or employ any energy legislation Congress may pass.

     Various entities,device, scheme or artifice to defraud, (2) to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (3) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any person.


Several parties, including the Utility and the State of California, are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity purchasers from January 2000 to June 2001. In December 2002, a FERC administrative law judge issued an initial decision finding that powerelectricity suppliers, overcharged the utilities, the State of Californiaincluding municipal and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001 (the only time periodgovernmental entities, 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.

     During 2003, the FERC confirmed most of the administrative law judge’s findings, 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 pricesovercharges incurred in the refund methodology. In addition, the FERC directed the ISOCAISO and the California Power Exchange, or PX, which operates solely to reconcile remaining refund amounts owed, to make compliance filings establishing refund amounts by March 2004. The ISO has indicated that it plans to make its compliance filing by August 2004. The actual refunds will not be determined untilwholesale electricity markets between May 2000 and June 2001 through various proceedings pending at the FERC and other judicial proceedings. Many issues a final decision followingraised in these proceedings, including the ISOextent of the FERC’s refund authority, and PX compliance filings. The FERCthe amount of potential refunds after taking into account certain costs incurred by the electricity suppliers, have not been resolved. It is uncertain when itthese proceedings will issue a final decision in this proceeding. In addition, future refunds could increase or decrease as a result of an alternative calculation proposed by the ISO, which incorporates revised data provided by the Utility and other entities.

     Under the Settlement Agreement, the Utility and PG&E Corporation agreed to continue to cooperate with the CPUC and the State of California in seeking refunds from generators and other energy suppliers. The net after-tax amount of any refunds, claim offsets or other credits from generators or other energy suppliers relating to the Utility’s ISO, PX, qualifying facilities or energy service provider costs that are actually realized in cash or by offset of creditor claims in its Chapter 11 proceeding would reduce the balance of the $2.21 billion after-tax regulatory asset created by the Settlement Agreement.

be concluded.


The Utility has recorded approximately $1.8 billion of claims filed byentered into settlements with various electricity generatorssuppliers resolving certain disputed claims and the Utility's refund claims against these power suppliers. The Utility continues to pursue additional refunds through settlement discussions with other electricity suppliers. Future amounts received under these settlements, and any future settlements with electricity suppliers, will be credited to customers after deductions for contingencies and amounts related to certain wholesale power purchases. For further discussion, see the section of Note 17: Commitments and Contingencies - California Energy Crisis Proceedings, of the Notes to the Consolidated Financial Statements in its Chapter 11 proceedingthe 2006 Annual Report.

QF Regulation. Under PURPA, electric utilities were required to purchase energy and capacity from independent power producers that are qualifying cogeneration facilities, or QFs. To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with QFs and approved the applicable terms, conditions, prices and eligibility requirements. The EPAct significantly amended the purchase requirements of PURPA. As amended, Section 210(m) of PURPA authorizes the FERC to waive the obligation of an electric utility under Section 210 of PURPA to purchase the electricity offered to it by a QF (under a new contract or obligation) if the FERC finds that the QF has nondiscriminatory access to one of three defined categories of competitive wholesale electricity markets. The statute permits such waivers 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.particular QF or on a “service territory-wide basis.” The Utility currently estimates thatplans to wait until after the claims filed would have been reduced to approximately $1.2 billion based on the refund methodology recommendednew day-ahead market structure provided for in the administrative law judge’s initial decision, resulting inCAISO’s Market Redesign and Technology Update, or MRTU, initiative to restructure the California electricity market becomes effective to assess whether it will file a net liability of approximately $1.0 billion after the approximately $200 million pre-petition offset. The recalculation of market prices according to the revised methodology adopted byrequest with the FERC into terminate its October 2003 decision could further reduceobligations under PURPA to enter into new QF purchase obligations.


The Nuclear Regulatory Commission, or the amount of the suppliers’ claims by several hundred million dollars. However, this 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 NRC

     The NRC, oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility’stwo nuclear generating units at Diablo Canyon power plant and the Utility’s retired nuclear generating unit at Humboldt Bay, or 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. SafetyNRC safety and security requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at the Utility’s Diablo Canyon, power plant and additional significant capital expenditures could be required in the future.

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The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2 expires in August 2025. Under the terms of these licenses, there must be sufficient storage capacity for the radioactive spent fuel produced by this plant. For a discussion of the Utility’s spent fuel storage project, see “Environmental Matters - Nuclear Fuel Disposal,” below.



The Utility's operations have been significantly affected by various statutes passed by the California legislature, including:

·  
State Energy RegulationAssembly Bill 1890. Assembly Bill 1890, enacted in 1996, 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 investor-owned utilities’ customers were given the choice to become “direct access” customers by buying energy from an alternate service provider other than the regulated utilities. Among other provisions, Assembly Bill 1890 provided for the establishment of the CAISO, as a nonprofit public benefit corporation, to operate and control the state-wide electricity transmission grid and ensure efficient use and reliable operation of the transmission grid.

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·  
The CPUCAssembly Bill 1X. Assembly Bill 1X, enacted during the California 2000-2001 energy crisis, authorized the California Department of Water Resources, or the DWR, beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities' retail customers. Assembly Bill 1X required the California investor-owned electric utilities to deliver electricity purchased by the DWR under long-term contracts and to act as the DWR's billing and collection agent.

·  
Assembly Bill 57. Assembly Bill 57, enacted in September 2002 and amended by Senate Bill 1976, required the California investor-owned utilities to resume purchasing power on January 1, 2003, required the CPUC to allocate electricity to be provided under the DWR contracts among the customers of the California investor-owned electric utilities, requires the utilities to file short- and long-term electricity resource procurement plans with the CPUC for approval, and authorizes the utilities to recover their reasonable wholesale procurement costs incurred under a CPUC-approved procurement plan through the establishment of new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under the approved procurement plans.


·  
Senate Bill 1078. Senate Bill 1078, enacted in September 2002 (as amended by SB 107 enacted in September 2006 and effective on January 1, 2007) established the Renewables Portfolio Standard Program, which requires each California retail seller of electricity, except municipal utilities, to increase its purchases of eligible renewable energy (such as biomass, small hydro, 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 eligible renewable resources equals at least 20% of its total retail sales by 2010.
·  
Assembly Bill 380. Assembly Bill 380, enacted in September 2005, requires the CPUC in consultation with the CAISO, to establish resource adequacy requirements for all load-serving entities, including the California investor-owned electric utilities but excluding local publicly owned electric utilities. Assembly Bill 380 requires each load-serving entity to maintain physical generating capacity adequate to meet its load requirements, including, but not limited to, peak demand and planning and operating reserves, deliverable to locations and at times as may be necessary to provide reliable electric service.

·  
Assembly Bill 32. Assembly Bill 32, enacted in September 2006 to address climate change, requires the California Air Resources Board, or the CARB, to adopt regulations to limit statewide greenhouse gas emissions, to 1990 levels by 2020. (See “Environmental Matters” below for more information.)

·  
Senate Bill 1368. Senate Bill 1368, also enacted in September 2006, prohibits any load-serving entity, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload generation (i.e., electricity generation from a power plant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60%) unless it complies with a greenhouse gas emission performance standard. (See “Environmental Matters” below for more information.)


The CPUC has jurisdiction to set the rates, terms and conditions of service for the Utility’sUtility's electricity distribution, electricity generation, 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 that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC conducts varioushas general jurisdiction over most of the Utility’s operations, and regularly reviews of utility performance, using measures such as the frequency and duration of outages. The CPUC also 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

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

• 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

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PG&E Corporation and the Utility’s obligationsUtility entered into a settlement agreement with the CPUC on December 19, 2003 to resolve the Utility's proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California, or the Bankruptcy Court, since April 2001, referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter 11 Settlement Agreement is seekingestablished certain regulatory assets and addressed various ratemaking matters in order to refinancerestore the remaining unamortized pre-tax balanceUtility’s financial health and enable it to emerge from Chapter 11 and fully resume its traditional role of providing safe and reliable electric and gas service at just and reasonable rates, subject to CPUC regulation. The terms of the regulatory assetChapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11 which became effective on April 12, 2004. Although the Utility's operations are no longer subject to the oversight of the Bankruptcy Court, the Bankruptcy Court retains jurisdiction to hear and related federal, state and franchise taxes using a securitized financing supported by a dedicated rate component that would require enactmentdetermine disputes arising in connection with the interpretation, implementation or enforcement of authorizing California legislation. On January 22, 2004, the CPUC approved proposed legislation, Senate Bill 772, that would authorize a dedicated rate componentChapter 11 Settlement Agreement, in addition to securitizeother matters. (For more information, see Note 15 of the regulatory asset andNotes to the related taxes. Consolidated Financial Statements included in the 2006 Annual Report.)


The California Energy Resources Conservation and Development Commission

The California Energy Resources Conservation and Development Commission, commonly called the California Energy

Commission, or the 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, advancing energy science and technology through research, development funds, as well asand demonstration, and providing 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 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.

(For more information see “Environmental Matters - Water Quality” below.)


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.counties. 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 feefees 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.



Overview
Transition from Frozen Rates to Cost of Service Ratemaking

     FrozenHistorically, 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 undertook a continuing obligation to serve their customers, in return for which beganthe 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—the supply of electricity and natural gas. The driving forces behind these competitive pressures have been customers who believe that 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.


Federal. At the federal level, many provisions of the EPAct support the development of competition in the wholesale electric market. The EPAct has directed the FERC to develop rules to encourage fair and efficient competitive markets by employing best practices in market rules and reducing barriers to trade between markets and among regions. The EPAct also gives the FERC authority to prevent accumulation and exercise of market power by assuring that proposed mergers and acquisitions of public utility companies and their holding companies are in the public interest and by addressing market power in jurisdictional wholesale markets through its new powers to establish and enforce rules prohibiting market manipulation.

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Even before the passage of the EPAct, the FERC's policies 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' transmission grids. Order 888 requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to have on file open access non-discriminatory transmission tariffs, or OATT, that contain minimum terms and conditions of non-discriminatory service. The FERC'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. On February 16, 2007, the FERC issued Order 890 that is designed to (1) strengthen the form of OATT adopted in Order 888 to ensure that it achieves its original purpose of remedying undue discrimination; (2) provide greater specificity in the form of OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement; and (3) increase transparency in the rules applicable to planning and use of the transmission system.

The FERC also has issued rules on the interconnection of generators larger than 20 MW with a transmission system to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections. These rules are intended 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 generation and transmission. Under the rules and associated tariffs, a new generator is required to pay for the transmission system upgrades needed in order to interconnect the generator. The generator will be reimbursed over a five-year period after the power plant achieves commercial operation. The cost of the network upgrades then is recovered by the regulated transmission provider in its overall transmission rates.

State. At the state level, Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry commencing in 1998. Assembly Bill 1890 established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity through transactions conducted on the PX. As a result of the California 2000-2001 energy crisis, the PX filed a petition for bankruptcy protection and now operates solely to reconcile remaining refund amounts owed and make compliance filings as required by the FERC in the California refund proceeding still pending at the FERC. Established pursuant to AB 1890 to take control of the California investor-owned electric transmission facilities in California, the CAISO currently administers a real-time or “spot” wholesale market for the sale of electric energy. The market is used to allocate space on the transmission lines, maintain operating reserves and match supply with demand in real time. In September 2006, the FERC approved the CAISO’s proposal to establish its MRTU initiative to restructure the California electricity market and to enhance power grid reliability. The FERC directed the CAISO to make certain changes to the MRTU proposal, including a requirement to comply with the FERC’s new rule that regional transmission organizations provide long-term transmission rights to users of the transmission grid. The MRTU tariffs, currently estimated to become effective on January 31, 2008, will apply to all load-serving entities, including the investor-owned utilities, serving California consumers.

Assembly Bill 1890 also permitted retail end-use customers to choose their energy service provider by becoming a direct access customer. To ensure that the DWR recovers its costs to procure electricity, Assembly Bill 1X required the CPUC to suspend the right of retail end-user customers to become direct access customers until the DWR no longer procures electricity on behalf of the customers of the California investor-owned electric utilities. The CPUC suspended direct access 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. The CPUC has been asked to open a proceeding to determine whether to re-establish direct access by January 1, 1998, were designed2008. Although the Utility supports the ability of customers to allowchoose their energy provider, the Utility believes there are a number of important policy and implementation questions that must be addressed before re-establishing direct access in order to ensure that all customers are treated equitably, with no undue cost responsibility burdens or risks being placed either on any one customer group or on the utilities.

The Utility’s customers may also obtain power from a “community choice aggregator” instead of obtaining power from the Utility. California Assembly Bill 117, enacted in 2002, permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators. Under Assembly Bill 117, the Utility would continue to provide distribution, metering and billing services to the community choice aggregators' customers and would be those 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. The CPUC has adopted rules to implement community choice aggregation, including the imposition of a surcharge on retail end-users of the community choice aggregator to prevent a shifting of costs to customers of a utility who receive bundled services. Assembly Bill 117 also authorized the Utility to recover its authorized utilityfrom each community choice aggregator any costs of implementing the program that are reasonably attributable to the community choice aggregator, and to recover from customers any costs of implementing the extent frozen rates generated revenuesprogram not reasonably attributable to a community choice aggregator.

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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 whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of these costs,California and are exempt from FERC rules and regulations applicable to recoverinterstate pipelines. Instead, the Utility’s transition costs. Althoughpipeline operations are subject to the surcharges implemented in 2001 effectively increasedjurisdiction of the actual rate,CPUC.

                 The Utility’s gas transmission and storage system has operated under the frozen rateCPUC-approved “Gas Accord” market structure increases insince 1998. This market structure largely mimics 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. As a result of revised electricity rates discussed below and a January 2004 CPUC decision determining that the rate freeze ended on January 18, 2001, the Utility expects that onceregulatory framework required by FERC for interstate gas pipelines. The original Gas Accord, approved by the CPUC its rates will reflect its costsin 1998, is a CPUC-approved settlement agreement reached among the Utility and many interested parties, under which the natural gas transportation and storage services that the Utility provides were separated for ratemaking purposes from the Utility's distribution services. The Gas Accord changed the terms of service wherebyand rate structure for natural gas transportation, allowing the Utility's core customers (i.e., residential and small commercial customers) greater flexibility to purchase natural gas from competing suppliers. The Utility's noncore customers (i.e., industrial, larger commercial and electric generation 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 a bundled service.

Under the Gas Accord structure noncore customers have access to capacity rights for firm service, as well as interruptible (or “as-available”) services. All services are offered on a nondiscriminatory basis to any creditworthy customer. The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utility’s “citygate,” which refers to the interconnection between the big “backbone” gas transmission system and the smaller, downstream local transmission systems.

In December 2004, the CPUC approved the Gas Accord III which retained the Gas Accord market structure and resolved the rates, are calculated basedterms and conditions of service for the Utility’s natural gas and transportation system through 2007. The Utility is obligated to file a new rate case proposing gas transmission and storage rates and terms and conditions of service, for the period commencing January 1, 2008.  The Utility currently is scheduled to submit that filing on March 15, 2007.  In the event the CPUC does not issue a final decision approving new rates effective January 1, 2008, the Gas Accord III provides that the rates and terms and conditions of service in effect as of December 31, 2007, will remain in effect, with an automatic 2 percent escalation in the rates as of January 1, 2008.

The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the aggregatebasis of various authorized rate components. Changestransportation 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'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 any individual revenue requirement will change customers’ electricity rates.

     On January 26, 2004,addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility's case, includes the cost of transportation of the natural gas from Canada to the California border and the amount that the Utility filed revised electricity ratescharges 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's market share of transportation services into southern California decreases. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.


PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Northwest Pipeline Corporation, have agreed to jointly pursue the development of a new 232-mile interstate gas transmission pipeline that would increase natural gas supplies for the entire West Coast region of the United States. The proposed Pacific Connector Gas Pipeline, together with the CPUC based onJordan Cove liquefied natural gas, or LNG, terminal in Coos Bay, Oregon, being developed by Fort Chicago Partners, L.P., would open growing West Coast natural gas markets to diverse worldwide natural gas supply sources, providing additional alternatives to traditional Canadian, Southwest and Rocky Mountain supplies and increasing supply options and reliability. The proposed Pacific Connector Gas Pipeline would connect the Utility’s 2004 forecast revenue requirementsproposed Jordan Cove LNG terminal to Northwest Pipeline Corporation’s pipeline system in Oregon, and requested implementationto the Utility's backbone gas transmission system near Malin, Oregon. Other potential interconnects include Tuscarora Gas Transmission Company’s pipeline system which serves northern Nevada. The proposed Pacific Connector Gas Pipeline would be capable of delivering 1 bcf per day to the West Coast natural gas market, to customers in the Pacific Northwest through Northwest Pipeline Corporation's pipeline system, to the Utility's system for delivery to customers in California, and to customers in northern Nevada through Tuscarora Gas Transmission Company’s pipeline system. On May 1, 2006, the FERC approved a request to begin the environmental assessment process for the Pacific Connector Gas Pipeline under the National Environmental Policy Act. The public will have an opportunity to participate in this process.  The full application to request the FERC’s authorization to construct the Pacific Connector Gas Pipeline is scheduled to be submitted to the FERC in April 2007. The development and construction of the rate changes. These rates reflect allocationPacific Connector Gas Pipeline depends upon the construction of the Utility’s revenue requirementsproposed LNG terminal at Jordan Cove by Fort Chicago Partners, L.P. PG&E Corporation cannot predict whether Fort Chicago Partners, L.P. will be successful in accordance with a January 20, 2004 rate design settlement agreement entered into with a numbercompleting the development and construction of consumer groupsits proposed LNG terminal.  In addition, the development and government agencies, including TURNconstruction of the proposed LNG terminal and the CPUC’s Office of Ratepayer Advocates, or ORA. The rate design settlement agreement has been submittedproposed Pacific Connector Gas Pipeline are subject to the

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CPUC for approval. The revised ratesobtaining required permits, regulatory approvals, and forecast revenue requirementscommitments under long-term transportation contracts. Assuming the required permits, authorizations, and long-term transportation commitments are based on,timely received 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 onthat other conditions are timely satisfied, it is anticipated that 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 decisionLNG terminal and the $860 million filed by the Utility relates to a proposed decreasePacific Connector Gas Pipeline would begin commercial operation in the DWR’s revenue requirement included in the2011.


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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’s electricity and natural gas utility services are based on its costs of service. Before rates can be set, the CPUC and the FERC must determine the amount of “revenue requirements” that the Utility can collect from its customers. The CPUC determines the Utility’s revenue requirements must first be determined.associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations.


Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital 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 primarily determined based on the Utility’s forecast of future costs, including the costs of purchasing electricity and natural gas for the Utility's customers. 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

The Utility’s regulatory balancing accounts are designedused as a mechanism for the Utility to allow a utility an opportunityrecover amounts incurred for certain costs, primarily commodity costs. Sales balancing accounts accumulate differences between revenues and the Utility's authorized revenue requirements. Cost balancing accounts accumulate differences between incurred costs and authorized revenue requirements. The Utility also obtained CPUC approval for balancing account treatment of variances between forecasted and actual commodity costs and volumes. To the extent that the Utility is unable to recover its reasonable costs of providing utility services, including a return of, and a fairthrough rates because the Utility’s actual costs are determined to be unreasonable or are higher than forecast, the Utility may be unable to earn its authorized rate of return on, its investment in utility facilities, or rate base. Revenuereturn.

The amount of authorized revenue requirements are then allocated among customer classes (mainly residential, commercial, industrial and agricultural) and specific rates designedare established to produce the required revenue. The Utility's rates reflect the sum of individual revenue are established.requirement components authorized by the CPUC and the FERC. Changes in any individual revenue requirement affect customers' rates and could affect the Utility's revenues. The timing of the CPUC and other regulatory decisions affect when the Utility is able to record the authorized revenues. In annual true-up proceedings, the Utility’sUtility requests the CPUC to authorize an adjustment to electric and gas rates effective to (1) reflect over- and under-collections in the Utility's major electric and gas balancing accounts, and (2) implement various other electricity and gas revenue requirement changes authorized by the CPUC or the FERC. Generally, rate cases, intervenors have the opportunity to commentchanges become effective on the Utility’s application. The issues raised by these commentsfirst day of the following year. Balances in all CPUC-authorized accounts are then resolvedsubject to review, verification audit and adjustment, if necessary, by the appropriate regulatory agency. IfCPUC.



The General Rate Case, or GRC, is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility and the intervenors can settle these issues, these settlements are submitted to the regulatory agency for approval.
General Rate Cases

     The Utility’s primary revenue requirement proceeding is the general rate case, or GRC, filed with the CPUC. In the GRC, the CPUC authorizes the Utilityauthorized to collect from customers an amount known as base revenues to recover basethe Utility’s basic business and operational costs related to the Utility’sits electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC typicallyevery three years. The CPUC sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in GRC proceedingsperiod based on a forecast of costs for the first, or test, year. After authorizingTypical interveners in the revenue requirements,Utility's GRC include the CPUC’s Division of Ratepayer Advocates, or the DRA, and The Utility Reform Network, or TURN. On August 21, 2006, the Utility, together with the DRA and other parties, filed a motion with the CPUC allocatesseeking approval of a settlement agreement reached among the parties to resolve all of the issues raised by these parties and all revenue requirements among customer classes (mainly residential, commercial, industrial and agricultural) and establishes specific rate levels. Typical intervenorsrequirement-related issues raised by other parties in the Utility’s 2007 GRC includeproceeding. The settlement agreement proposes to set the ORA and TURN.

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Utility’s revenue requirements for a four-year period, 2007-2010, rather than for a typical three-year period. Under this proposal, the Utility’s next GRC would be effective January 1, 2011. On February 13, 2007, the administrative law judge overseeing the GRC issued a proposed decision that recommends modifications to the settlement agreement. On the same day, an alternate proposed decision was issued by the assigned CPUC Commissioner in the GRC that recommends that the settlement agreement be approved. For more information, see “Regulatory Matters - 2007 General Rate Case” in the MD&A in the 2006 Annual Report.


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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 in order 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. The proposed settlement agreement in the Utility’s 2007 GRC includes a provision for attrition adjustments to be made in 2008, 2009 and 2010.


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 thatrelative weightings of 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 debteach component that the Utility will have the opportunity to collect in its authorized rates. For 2005, this proceeding alsoThe Chapter 11 Settlement Agreement requires the CPUC to authorize a minimum return on equity for the Utility of 11.22% until the Utility receives a credit rating of “A3” from Moody’s Investor Services or “A-” from Standard & Poor’s Rating Services. The Utility’s CPUC-authorized capital structure for 2006 and 2007 consists of 46% long-term debt, 2% preferred stock and 52% equity. The Utility’s CPUC-authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base for 2006 and 2007 is 6.02% for long-term debt, 5.87% for preferred stock and 11.35% for equity, resulting in an overall rate of return on rate base of 8.79%. The CPUC will next re-evaluate the level of the Utility’s authorized return on equity and capital structure for the calendar year 2008. The Utility is required to file its 2008 cost of capital application by May 8, 2007.

Although the FERC has authority to set the authorizedUtility’s rate of return for its electricity transmission operations, the rate of return is often unspecified if the Utility's transmission rates are determined through a negotiated rate settlement. The Utility’s rates of return for its backbone and local gas transportationtransmission and storage assets.operations through 2007 have been previously set in the Gas Accord, described below, at 11.22% for the return on equity and 8.77% for the overall rate of return.


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 increasesincrease with usage.


The Utility administers, and/or funds, several state-mandated and CPUC-authorized public purpose and other programs. California law requires the CPUC to authorize certain levels of funding for electric and gas public purpose programs related to energy efficiency, low-income energy efficiency, research and development, and renewable energy resources. In addition, California law requires the CPUC to authorize funding for the California Solar Initiative discussed below, and other self-generation programs. In addition, the CPUC has authorized additional funding for energy efficiency and demand response programs. For 2006 expenditures, the CPUC has authorized the Utility to collect revenue requirements of approximately $583 million from electricity customers to fund these electricity public purpose and other programs and to collect revenue requirements of approximately $99 million from gas customers to fund these natural gas public purpose programs. The CPUC is responsible for authorizing the programs, funding levels and cost recovery mechanisms for the Utility's operation of both energy efficiency and low-income energy efficiency programs. The CEC administers both the electric public interest research and development program and the renewable energy program on a statewide basis. In 2006, the Utility transferred $109 million to the CEC for these programs. These programs include:

 
·  
DWR ElectricityEnergy Efficiency Programs. The CPUC has authorized 2006 through 2008 energy efficiency portfolio plans and DWR Revenue Requirementsprogram funding levels, not including funding for evaluation, measurement and verification, or EM&V activities for the Utility and the other investor-owned California utilities. The CPUC approved funding of approximately $867 million for the Utility's energy efficiency programs over the 2006 through 2008 period, 20% of which is to be awarded to third parties through a competitive bid process. The CPUC also has authorized funding for EM&V activities of approximately $75 million for the Utility over the 2006 through 2008 period. The increased energy efficiency funding level is part of a larger effort by the State of California to reduce consumption of fossil fuels. The increased funding level will enable both residential and business customers to take more advantage of the diverse mix of energy efficiency programs.

     As

·  
Demand Response Programs. Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. In March 2006, the CPUC authorized 2006 through 2008 demand response programs and funding levels for the Utility and other investor-owned California utilities. The CPUC approved funding of approximately $109 million for the Utility’s demand response programs over the 2006 through 2008 period, which include some demand response programs that will be provided by third parties. In November 2006, the CPUC approved augmented demand response programs for the Utility and other investor-owned California utilities in order to promote system reliability during the summer peak demand periods of 2007 and 2008. These augmented programs were approved within the existing authorized budget. Programs requiring additional funding beyond the already authorized level will require further regulatory authorization. On February 15, 2007, the CPUC approved the Utility’s proposal to start a limited deployment of an airconditioning load control program that is expected to yield 5 MW of load relief for summer 2007. In early spring 2007, the Utility anticipates requesting that the CPUC approve an expanded air conditioning load control program that is expected to yield approximately 300 MW of additional load relief by the end of 2010. These increased demand response programs are part of an effort by the state of California to promote demand reduction through price-responsive programs and reliability-triggered programs.

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·  
Self-Generation Incentive and California Solar Initiative. The Utility administers the self-generation incentive program authorized by the CPUC to provide incentives to electricity customers who install clean or renewable distributed generation resources that meets all or a portion of their onsite energy usage. The CPUC also authorized the California investor-owned utilities to collect an additional $2.1 billion over the 2007 through 2016 period from their customers to fund customer incentives for the installation of retail solar energy projects to serve onsite load. The goal of this program, called the California Solar Initiative, or the CSI, is to bring 1,940 MW of solar power on-line by 2017 through the California investor-owned utilities. Of the total amount authorized, the Utility has been allocated $946 million to fund customer incentives, research, development and demonstration activities (with an emphasis on the demonstration of solar and solar-related technologies), and administration expenses. California Senate Bill 1, enacted in August 2006, modified the CSI program to include participation of the California municipal utilities. The overall goal of the CSI is to install 3,000 MW (through both investor-owned electric utilities and electric municipal utilities) through 2017.

·  
Low-Income Energy Efficiency Programs and California Alternate Rates for Energy. The CPUC has approved funding of $78 million in each of 2007 and 2008 to support energy efficiency programs for low-income and fixed-income customers. The Utility also provides a discount rate called the California Alternate Rates for Energy, or CARE, for low-income customers. This rate subsidy is paid for by the Utility's other customers. For 2006, the amount of this subsidy was approximately $458 million (including avoided surcharges).

In December 2006, the CPUC approved the Utility’s proposal to allow customers to choose to neutralize greenhouse gas emissions associated with their energy use. Beginning in 2007, customers who choose to enroll in the program will pay a consequencesmall premium on their monthly utility bill, based on their energy usage, to fund environmental projects aimed at removing carbon dioxide and other greenhouse gases from the air. The Utility estimates that this program will generate approximately $20 million during its first three years to fund these greenhouse gas reduction projects, which will initially be focused on forest restoration and conservation projects in California. The Utility would select projects to fund through a competitive bidding process using stringent criteria and protocols developed by an independent non-profit organization, the California Climate Action Registry. Project types are expected to expand beyond forestry, such as potentially to dairy biogas methane reduction projects, as more certification protocols become available. The greenhouse gas reduction projects will be overseen by an external advisory group consisting of a wide range of community groups, businesses and non-profit conservation agencies. The program will be reviewed by independent auditors and the Utility will regularly report program results to the CPUC, as well as to all participating customers.



Each California investor-owned electric utility is responsible to procure electricity to meet customer demand, plus applicable reserve margins, not satisfied from that utility's own generation facilities and existing electricity contracts (including DWR allocated contracts). Each utility must submit a long-term procurement plan covering a ten-year period to the CPUC for approval. California legislation, Assembly Bill 57, allows the California investor-owned utilities to recover their wholesale electricity procurement costs incurred in compliance with their CPUC-approved procurement plans. After CPUC approval of the procurement plans, the utilities may, if appropriate, conduct a competitive request for offers, or RFO, 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) to meet the utility’s projected need for electricity resources. Agreements entered into after the conclusion of the competitive bidding process are submitted to the CPUC for approval, along with a request for the CPUC to authorize revenue requirements to recover the costs associated with that contract. If necessary, the utilities conduct separate competitive solicitations to meet their resource adequacy and renewable energy resource requirements. The utilities submit the contracts after the conclusion of these solicitations to the CPUC for approval and authorization of the associated revenue requirements.

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The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility under DWR contracts) through the Energy Resource Recovery Account, or the ERRA, a balancing account authorized by the CPUC in accordance with Assembly Bill 57. The ERRA tracks the difference between the authorized revenue requirement and actual costs incurred under the Utility's authorized procurement plans and contracts. To determine the authorized revenue requirement recorded in the ERRA, each year the CPUC reviews the Utility’s forecasted costs under power purchase agreements and fuel costs. Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility's prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer. The CPUC also performs periodic compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power procurement costs.

The authorized revenue requirements for capital costs and non-fuel operating and maintenance costs for Utility-owned generation are addressed in the Utility’s GRC. The revenue requirement to recover the initial capital costs for CPUC-approved utility owned generation projects will be recovered through a balancing account, the Utility Generation Balancing Account, or the UGBA, which will track the difference between the CPUC-approved forecast of initial capital costs, adjusted from time to time as permitted by the CPUC, and actual costs. The initial revenue requirement for the utility-owned projects generally would begin to accrue in the UGBA as of the new facility’s commercial operation date or the date a completed facility is transferred to the Utility, and would be included in rates on January 1 of the following year.


During 2006, the CPUC approved several power purchase agreements with third parties in accordance with the Utility’s CPUC-approved long-term procurement plan and to meet renewable energy and resource adequacy requirements. The CPUC also authorized the Utility to recover fixed and variable costs associated with these contracts through the ERRA.

For new non-renewable generation purchased from third parties under power purchase agreements, the utilities may elect to recover any above-market costs through either (1) the imposition of a non-bypassable charge imposed on bundled and departing customers only or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the utilities’ service territory, including direct access customers and community choice aggregation customers. (For information about the status of direct access and community choice aggregation, see the section above entitled “Competition  - Competition in the Electricity Industry.”) The non-bypassable charge can be imposed from the date of signing a power purchase agreement and last for 10 years from the date the new generation unit comes on line or for the term of the contract, whichever is less. Utilities are allowed to justify a cost recovery period longer than 10 years on a case-by-case basis.

If a utility elects to use the net capacity cost allocation method, the net capacity costs would be allocated for the term of the contract or 10 years, whichever is less, starting on the date the new generation unit comes on line. Under this allocation mechanism, the energy rights to the contract are auctioned off to maximize the energy revenues and minimize the net capacity costs that would be subject to allocation. If no bids are accepted for the energy rights, the utility would retain the rights to the energy and would value it at spot market prices for the purposes of determining the net capacity costs to be allocated until the next periodic auction.


During 2006, the CPUC approved three agreements related to Utility-owned generation projects. The CPUC also authorized the amount of revenue requirements that the Utility is authorized to recover related to each project to recover capital costs and non-fuel operations and maintenance costs.

·  
Gateway Generating Station. In June 2006, the CPUC authorized the Utility to acquire the equipment, permits and contracts relating to a partially completed 530-MW power plant in Antioch, California, referred to as the Gateway Generating Station, or Gateway. The Utility completed the acquisition in November 2006. The CPUC authorized the Utility to recover approximately $295 million in capital costs to complete the construction of the facility as well as costs for its operation. On February 15, 2007, the CPUC approved the Utility’s request to recover an additional approximately $75 million necessary to convert the plant from fresh water cooling to dry cooling in order to reduce the environmental impact of the facility and as a result of changes to Gateway’s environmental permits. The Utility also has requested the CEC to amend the facility’s current permit to authorize the plant to be converted from fresh water cooling to dry cooling. The Utility expects that the CEC will issue a decision in the second quarter of 2007. Subject to obtaining the permit amendment from the CEC, meeting construction schedules, operational performance requirements and other conditions, the Utility estimates that it will complete construction of the Gateway facility and commence operations in 2009

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Colusa Power Plant. In November 2006, the CPUC approved an agreement for the development and construction of a 657-MW power plant to be located in Colusa County, California. The CPUC adopted an initial capital cost for the Colusa project that is equal to the sum of the fixed contract costs plus the Utility’s estimated owner’s costs and a contingency amount to account for the risk and uncertainty in the estimation of owner’s costs. (Owner’s costs include the Utility’s expenses for

·  
Colusa Power Plant. In November 2006, the CPUC approved an agreement for the development and construction of a 657-MW power plant to be located in Colusa County, California. The CPUC adopted an initial capital cost for the Colusa project that is equal to the sum of the fixed contract costs plus the Utility’s estimated owner’s costs and a contingency amount to account for the risk and uncertainty in the estimation of owner’s costs. (Owner’s costs include the Utility’s expenses for legal, engineering and consulting services as well as the costs for internal personnel and overhead related to the project.) The CPUC also authorized the Utility to adjust the initial capital cost for the Colusa project to reflect any actual incentive payments made to, or liquidated damages received from, the contractors through notification to the CPUC but without a reasonableness review. Subject to obtaining required permits, meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Colusa project will commence operations in 2010 at an estimated cost of approximately $673 million.
·  
Humboldt Bay. In November 2006, the CPUC also approved an agreement for the construction of a 163-MW power plant to re-power the Utility’s existing Humboldt Bay power plant, which is at the end of its useful life. The CPUC adopted an initial capital cost of the Humboldt Bay project equal to the sum of the fixed contract costs plus the Utility’s estimated owner’s costs, but limited the contingency amount for owner’s costs to 5 percent of the fixed contract cost and estimated owner’s costs. Subject to obtaining required permits and meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Humboldt Bay project will commence operations in 2009 at an estimated cost of approximately $239 million. 

On December 11, 2006, the Utility submitted its 2006 long-term procurement plan covering procurement over 2007-2016 to the CPUC for approval. For more information about the 2006 plan, see the section of MD&A in the 2006 Annual Report entitled “Regulatory Matters - Electricity Generation Resources.”


During the California 2000-2001 energy crisis, on January 17, 2001, the Governor of California signed an order declaring an emergency and authorizing the DWR entered into long-term contracts to purchase electricity to maintain the continuity of supply to retail customers. This was followed by AB 1X, which authorized the DWR to purchasefrom third parties. The electricity and sell that electricity directlyprovided under these contracts has been allocated to the California investor-owned 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’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’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’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’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’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 electricitythese customers ofthrough a rate component called the three California investor-owned electric utilities through what is known asDWR “power charge.” The rates that these customers pay also include a power

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charge. The Utility’s customers also must pay what is known as a bond charge“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 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.

     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. 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

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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’s authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. The CPUC must review the revenues and costs associated with an investor-owned 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’s prior year electricity procurement revenues,, excluding amounts collected for the DWR. These mandatory adjustments will continue until January 1, 2006.

Electricity Transmission

The Utility’sUtility's electricity transmission revenuesrevenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main 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’s participationUtility entered into before the CAISO began its operations in the ISO. Customers that receive transmission services under these pre-existing contracts,March 1998. These wholesale customers are referred to as existing transmission contract customers and are charged individualized rates based on the terms of their contracts. TransmissionOther customers pay transmission rates that are established by the FERC in the Utility's transmission owner tariff rate cases. These FERC-approved rates are included by the CPUC in the Utility’sUtility's retail electricityelectric rates, and collected from retail electricity customers receiving bundled service underconsistent with the federal filed rate doctrine.doctrine, and are collected from retail electric customers receiving bundled service.



Transmission Owner Rate Cases

     Under

The primary FERC rate-making proceeding to determine the FERC’s regulatory regime,amount of revenue requirements the Utility is ableauthorized to file a new baserecover for its electric transmission costs and to earn its return on equity is the transmission owner rate case. A transmission owner rate case under the Utility’s transmission owner tariff whenever the Utility deems it necessary to increase itsis generally held every year and sets rates within certain guidelines set forth by the FERC.for a one-year period. 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.

components. The primary component consists of base transmission rates intended to recover the Utility's operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity. The Utility derives the majority of the Utility’sUtility's transmission revenue from base transmission rates.

The other component consists of rates intended to reflect credits and charges from the CAISO. The CAISO credits the Utility for transmission revenues received by the CAISO. The CAISO also charges the Utility for reliability service costs and imposes a transmission access charge for the Utility’s use of CAISO-controlled transmission facilities in serving its customers. These credits and charges are described below.


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On August 1, 2006, the Utility filed its transmission owner rate case application with the FERC requesting authorization of an annual transmission revenue requirement effective October 1, 2006. On September 29,


2006, the FERC issued an order accepting the Utility’s rate application, suspending the requested rate changes for five months to become effective March 1, 2007, subject to refund. On February 15, 2007, the Utility submitted an offer of settlement reached by the parties and requested that the settlement judge recommend that the FERC approve the settlement.  For more information, see “Regulatory Matters - FERC Transmission Rate Case” in the MD&A in the 2006 Annual Report.



CAISO transmission revenues include:

·  
Transmission Control Agreementthe proceeds received from the CAISO for wholesale wheeling service (i.e., the transfer of electricity that is being sold in the wholesale market) that the CAISO provides to third parties using the Utility’s transmission facilities, and


·  revenues that the CAISO collects from transmission users to relieve congestion on the Utility’s transmission line (either in the form of financial hedges such as firm transmission rights relating to future deliveries of electricity or in the form of a usage charge to manage congestion relating to real time delivery of electricity).

The amount of CAISO transmission revenues is adjusted by the shortfall or surplus resulting from any cost differences between the amount the Utility is entitled to receive from certain wholesale customers under specific contracts and the amount the Utility is entitled to receive or be charged for scheduling services under the CAISO’s rules and protocols.


The CAISO 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 CAISO's demand when the generation from those RMR units is needed for local transmission system reliability. RMR agreements are established or extended by the CAISO on an annual basis.  As a party to aparticipating transmission owner under the Transmission Control Agreement or TCA, with the ISO and other participating transmission owners. As a transmission owner, the Utility is required to give two years notice and receive regulatory approval if it wishes to withdraw from the TCA. Under this agreement, the transmission owners, which also include Southern California Edison, or SCE, San Diego Gas & Electric Company and several municipal utilities, assign operational control of their electricity transmission systems to the ISO. In addition, as a party to the TCA,CAISO, the Utility is responsible for a share ofreimbursing the costs of reliability must-run, or RMR, agreements between 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 PlantsCAISO for which the Utility receives revenue from the ISO. Under the RMR agreements, RMR Plants must remain availablepayments it makes to generate electricity when needed for local transmission system reliability upon the ISO’s demand.

     At December 31, 2003, the ISO had RMR agreements for which the Utility could be obligated to pay the ISO an estimated $446 million in net costs during the period January 1, 2004 to December 31, 2005. These costs are recoverable under applicable ratemaking mechanisms.

It is possible that the Utility may receive a refund of RMR costs that the Utility previously paidpower plant owners within or adjacent 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 claims 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.

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’s transmission system. The costs of reliability must run agreements attributed to supporting the Utility’s historic transmission control area are charged to the Utility as a participating transmission owner. These costs were approximately $330 million in 2003. Under the Utility’s transmission owner tariff, the Utility charges its customers rates designed to recover these reliabilityUtility's service charges, without mark-up or service fees.territory. The Utility tracks these costs and revenues related to reliability services in the reliability services balancing account. Periodically, the Utility’s electricity transmission owner rates are adjusted to refund over-collections to the Utility’s customers as a result of the effect of these reliability service costs or to collect any under-collections from customers.

Transmission Access Charge

     In March 2000, During 2006, the ISO filed an applicationCPUC adopted rules to implement state law requirements for California investor-owned utilities to meet resource adequacy requirements, including rules to address local transmission system reliability issues.  As the utilities fulfill their responsibility to meet these requirements, the number of RMR agreements with the FERC seekingCAISO and the associated costs will decline.  


For further discussion of other RMR-related issues, see the section of Note 17: Commitments and Contingencies -  Reliability Must Run Agreements, of the Notes to establish its ownthe Consolidated Financial Statements in the 2006 Annual Report.


The CAISO imposes a transmission access charge as directed by AB 1890.on users of the CAISO-controlled electric transmission grid. The ISO’sCAISO's transmission access charge methodology approved by the FERC in December 2004, provides for a transition over a 10-year period 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.above of all transmission owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology also requires the Utility and othermay result in a cost shift from transmission owners during a ten-year transition period, to pay a charge intended to reimburse otherwhose costs for existing transmission owners (who are generally new ISO participants) whose costsfacilities at 200 kV and above are higher than that embedded in the uniform rate. Undertransmission access charge rate, to transmission owners with lower embedded costs for existing high voltage transmission, such as the ISO’s application, the Utility’sUtility. The Utility's obligation for this cost differential would behas been capped at $32 million per year during the ten-year10-year transition period. A hearing in this matter was conducted at 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.

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15

Natural Gas
The Gas Accord



Under 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. OnIn December 18, 2003,2004, the CPUC approved a multi-party settlement agreement, the Utility’s applicationGas Accord III, 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 2005 through 2007. Under this framework, the costs associated with the Utility’s local transportation and gas storage assets that are used for service to core customers are recovered through balancing account mechanisms that adjust for the difference between actual usage and forecast usage. In addition, approximately 65% of the costs associated with the Utility’s backbone gas transmission system that is used to serve core customers are recovered through fixed charges. The Utility continues to be at riskremaining 35% of not recovering its naturalthese costs are recoverable through volumetric charges. Revenues from these charges vary depending on the level of throughput volume. The costs that are recoverable through balancing accounts or fixed reservation charges account for approximately 45% of the Utility’s total revenue requirement for gas transportationtransmission and storage. The remainder of the Utility’s gas transmission and storage costs are recovered from core customers through volumetric charges and from noncore customers under firm or interruptible transmission or storage contracts. The Utility’s recovery of this portion of its costs depend on the level of throughput volume, gas prices, and the extent to which noncore customers contract for firm services.

The Utility is obligated to file a new rate case proposing gas transmission and storage rates and terms and conditions of service, for the period commencing January 1, 2008. The Utility currently is scheduled to submit that filing on March 15, 2007. In the event the CPUC does not have regulatory balancing account protection for over-collections or under-collectionsissue a final decision approving new rates effective January 1, 2008, Gas Accord III provides that the rates and terms and conditions of natural gas transportation or storage revenues.service in effect as of December 31, 2007, will remain in effect, with an automatic 2 percent escalation in the rates as of January 1, 2008.


Biennial Cost Allocation Proceeding

The Utility’s

Certain of the Utility'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,over-collection, 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

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 Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core procurement customers, through its retail gas rates. The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under an incentive mechanism known as the Core Procurement Incentive Mechanism, or CPIM. Under the CPIM, the Utility’s natural gasUtility's purchase costs (including Canadian and interstate capacity and volumetric transportation charges)for a twelve-month period 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 fallThe CPIM establishes a “tolerance band” around the benchmark index price, and all costs within athe tolerance band which is currently between 99%are fully recovered from core customers. If total natural gas costs fall below the tolerance band, the Utility’s customers and 102%shareholders will share 75% and 25% of the benchmark, are considered reasonablesavings below the tolerance band, respectively. Conversely, if total natural gas costs rise above the tolerance band, the Utility’s core customers and fully recoverable, in customers’ rates. One-half ofshareholders share equally the costs above 102%the tolerance band. The shareholder award is capped at the lower of the benchmark are recoverable1.5% of total natural gas commodity costs or $25 million. While this incentive mechanism remains in customers’ rates, and the Utility’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 annuallyplace, changes 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, 2004, the CPUC opened a rulemaking proceeding to establish policies and rules to ensure reliable, long-term suppliesprice of natural gas, consistent with the market-based benchmark, are not expected to California. materially impact net income. (For more information see the “Risk Management Activities” section of MD&A in the 2006 Annual Report).



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 rules whereby utilities could receive CPUC pre-approval of contracts for interstate pipeline capacity to support their natural gas procurement activities.
Interstate and Canadian Natural Gas Transportation and Storage

     The Utility’sUtility's interstate and Canadian natural gas transportation agreements with third partythird-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 are approved 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

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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's natural gas transportation system begins.

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The following table shows the percentage of the Utility's total sources of electricity for 2006 represented by each major electricity resource:
Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities)40%
DWR24%
Qualifying Facilities/Renewables20%
Irrigation Districts6%
Other Power Purchases10%

The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. Least-cost dispatch requires the Utility, in certain cases, 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 sales proceeds exceed the variable costs to operate a generation facility or buy electricity under an optional contract. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR based on the percentage of volume supplied by each entity to the Utility's total load. The Utility's net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.


At December 31, 2006, 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 2,240
Hydroelectric:      
Conventional 
16 counties in northern
and central California
 107 2,684
Helms pumped storage Fresno 3 1,212
Hydroelectric subtotal   110 3,896
Fossil fuel:      
Humboldt Bay(1) Humboldt 2 105
Mobile turbines Humboldt 2 30
Fossil fuel subtotal   4 135
Total   116 6,271
(1)
The Humboldt Bay facilities consist of a retired nuclear generation unit and two operatingfossil fuel-fired plants. As described above, the CPUC has approved the Utility’s application to re-power the two fossil fuel-fired plants.
In May 2006, the Utility retired its fossil fuel-fired plant at Hunters Point in San Francisco after the completion of a new 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line. The Utility is in the process of decommissioning the Hunters Point power plant. The completed transmission line provides additional transmission system reliability in San Francisco and northern San Mateo County that allowed the Hunters Point fossil-fueled power plant in San Francisco to be retired.
Diablo Canyon Power Plant. The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, with a total-plant net generation capacity of approximately 2,240 MW of electricity. Unit 1 began commercial operation in May 1985, and the operating license for this unit expires in November 2024. Unit 2 began commercial operation in March 1986, and the operating license for this unit expires in August 2025. For the 10-year period ended December 31, 2006, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 89.8%.

The Utility has entered into various purchase agreements for nuclear fuel with terms ranging from two to five years that are intended to ensure long-term fuel supply. For more information about these agreements, see Note 17: Commitments and Contingencies - Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2006 Annual Report.

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The following table outlines the Diablo Canyon power plant's refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 16 to 21 months. The average length of a refueling outage over the last five years has been approximately 48 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the replacement of the steam generators in Unit 2 in 2008 and in Unit 1 in 2009. The capital expenditures necessary to complete these projects are discussed further in the “Capital Expenditures” section of MD&A in the 2006 Annual Report. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of approximately 80 days 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.

  
2007
 
2008
 
2009
 
2010
2011
Unit 1
         
   Refueling April - January October 
   Duration (days) 28 - 74 28 
   Startup May - April November 
Unit 2
         
   Refueling - February October -April
   Duration (days) - 76 28 -28
   Startup - April November -May

In addition, as discussed below under “Environmental Matters - Nuclear Fuel Disposal,” the Utility is constructing an on-site dry cask storage facility to store the spent nuclear fuel that is expected to be completed by 2008. To provide another storage alternative in the event that construction of the dry cask storage facility is delayed, in December 2006, the Utility completed the installation of temporary storage racks in each unit's existing spent fuel storage pool that increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. If the Utility is unable to complete the dry cask storage facility, or if construction is delayed beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2010 with respect to Unit 1 and 2011 with respect to Unit 2 until such time as additional spent fuel can be safely stored.

Hydroelectric Generation Facilities. The Utility'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 87 permits or licenses and 160 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses totaling approximately 7.7 MW, all of the Utility'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 five years, the FERC has renewed six hydroelectric project licenses associated with a total of 699 MW. The Utility is in the process of seeking FERC renewal of licenses associated with approximately 1,314 MW of hydroelectric power. Although the original licenses associated with 917 MW of the 1,314 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately 2,569 MW, including the 699 MW recently relicensed, will expire between 2013 and 2043.


During 2006, electricity from the DWR contracts allocated to the Utility provided approximately 24% of the electricity delivered to the Utility's customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of the DWR's electricity procurement contracts allocated to the Utility’s customers. The DWR remains legally and financially responsible for its electricity procurement contracts. As described above under “Ratemaking Mechanisms,” the Utility acts as a billing and collection agent to collect the DWR's revenue requirements from the Utility's customers. For more information regarding the DWR contracts, see Note 17: Commitments and Contingencies - Third Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2006 Annual Report.

Qualifying Facility Power Purchase Agreements. As of December 31, 2006, the Utility had agreements with 268 QFs for approximately 4,150 MW that are in operation. Agreements for approximately 3,800 MW expire at various dates between 2007 and 2028. QF power purchase agreements for approximately 350 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with approximately 68 inoperative

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QFs. The total of approximately 4,150 MW consists of approximately 2,550 MW from cogeneration projects, 600 MW from wind projects and 1,000 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar and hydroelectric.

QF power purchase agreements accounted for approximately 20% of the Utility’s 2006 electricity sources, 22% of the Utility’s 2005 electricity sources and approximately 23% of the Utility's 2004 electricity sources. No single QF accounted for more than 5% of the Utility's 2006, 2005 or 2004 electricity sources.

Renewable Energy Contracts. California law requires that each California retail seller of electricity, except for municipal utilities, increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2010. During 2006, the Utility entered into several new renewable power purchase contracts that will help the Utility meet its goals. Currently, power from eligible renewable energy resources comprises approximately 12% of the Utility’s retail sales. The Utility expects to comply with its 2004, 2005, 2006 and 2007 annual targets. Although the Utility expects it will achieve the 20% target using the “flexible compliance” rules by 2010, actual deliveries of renewable power may not comprise 20% of its bundled retail sales by 2010 due to such factors as the time required for the construction of new generation facilities and/or needed transmission capacity. Failure to satisfy the targets may result in a penalty of five cents per kWh, with an annual penalty cap of $25 million. The exact amount of any penalty and conditions under which it would be applied is subject to the CPUC’s review of the circumstances for under-delivery.

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' and water agencies' debt service requirements, whether or not any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2007 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 6% of the Utility’s 2006 electricity sources, and approximately 5% of the Utility’s 2005 and 2004 electricity sources.

Other Power Purchase Agreements. After competitive solicitations, bilateral negotiations, and request for offers or proposals, were conducted, the Utility entered into several agreements with third party power providers during 2006 to meet the Utility’s intermediate and long-term generation resource needs. Under these contracts, the Utility will purchase power from facilities that may start as early as January 1, 2007 to as late as 2011. These combined agreements cover an aggregate of 7,129 MW of contractual capacity that expire between December 31, 2010 and January 31, 2036. Payments are not required under these agreements until the underlying generation facilities are operational.

For more information regarding the Utility's power purchase contracts, see Note 17: Commitments and Contingencies - Third Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2006 Annual Report.


In accordance with the Utility’s CPUC-approved procurement plan covering 2004-2014, the Utility has entered into contracts covering 2,780 MW of new long-term electricity generation resources in northern California. Three of the agreements provide for the construction of generation facilities to be owned and operated by the Utility: the 530-MW Gateway power plant located in Antioch, California; the 657-MW Colusa power plant located in Colusa, California; and the 163-MW power plant to re-power the Utility’s existing Humboldt Bay power plant, which is at the end of its useful life. Subject to obtaining required permits and meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Gateway and Humboldt Bay plants will commence operations in 2009 and the Colusa plant will commence operations in 2010. The Utility also executed five power purchase agreements that would provide approximately 1,430 MW of capacity with terms from 10 to 20 years. If permitting and construction schedules are met, the new generation facilities supporting these power purchase agreements are anticipated to begin delivering power to the grid during 2009 through 2010.
On December 11, 2006, the Utility submitted its 2006 long-term electricity procurement plan covering procurement over 2007-2016 to the CPUC for approval. The plan forecasts a need for up to an additional 2,300 MW of new dispatchable and operationally flexible capacity to come on line starting in 2011 to ensure continued reliable service. For more information about the 2006 plan, see the section of MD&A in the 2006 Annual Report entitled “Regulatory Matters - Electricity Generation Resources.”

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At December 31, 2006, the Utility owned 18,640 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 53,094 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 140,049 circuit miles of distribution lines and substations with a capacity of 26,079 MVA. In 2006, the Utility delivered 84,310 GWh to its customers, including 7,604 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 1998, in connection with electric industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the CAISO. The Utility has entered into a Transmission Control Agreement with the CAISO and other participating transmission owners (including Southern California Edison Company, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO. The Utility is required to give the CAISO two years’ notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.

The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for assuring that the reliability of the transmission system is maintained. The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid. The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998.

In April 2006, the Utility completed a new 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line. The completed transmission line provides additional transmission system reliability in San Francisco and northern San Mateo County. As result of the completion of the transmission line, the Utility was able to retire the Hunters Point power plant in San Francisco. The Utility expects to undertake various transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, and to replace aging or obsolete equipment to maintain system reliability and reduce reliance on RMR generation. These potential projects include the construction of the Midway-Gregg 500-kV transmission line designed to increase access to southern California and Southwest generation resources and to reduce RMR generation contracts in the Fresno, California, area.  In addition, the Utility is currently working with several stakeholders in the western United States to assess the feasibility of new large-scale electric transmission expansion projects to address regional electricity needs over the long term.  In addition, the CPUC has adopted a procedure to enable the utilities to recover the cost of electric transmission facilities necessary to interconnect renewable energy resources if those costs cannot be recovered in FERC-approved rates.


The Utility's electricity distribution network extends throughout all or a part of 47 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of 140,049 circuit miles of distribution lines (of which approximately 19% are underground and approximately 81% are overhead). There are 94 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. There are 602 distribution substations and 110 low-voltage distribution substations. There are 55 combined transmission and distribution substations. Combined transmission and distribution substations have both transmission and distribution transformers.

The Utility's distribution network interconnects to the Utility's electricity transmission system at 1,106 points. This interconnection between the Utility'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's customers. The distribution substations serve as the central hubs of the Utility'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 other facilities to entities, such as municipal and other utilities, that then resell the electricity.

During 2006, the Utility began the installation of an advanced metering system for virtually all of the Utility's residential and small commercial electric and gas customers.  These meters will enable the Utility to measure usage of electricity on a time-of-use basis and to charge demand-responsive rates to encourage customers to reduce energy consumption during peak demand periods and

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to reduce peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility expects to complete the installation of the network infrastructure and advanced meters throughout its service territory by the end of 2011. In 2006, the CPUC also approved the Utility’s proposal to offer customers a new voluntary billing option called critical peak pricing, or CPP, under which customers will be able to take advantage of electricity prices that vary by day and hour, potentially reducing their bills by shifting their energy use away from critical peak periods. By shifting energy demand away from critical peak periods, the Utility anticipates that it would need to purchase less power for critical peak periods. (For more information about the advanced metering initiative, see the section entitled “Capital Expenditures” in the MD&A portion of the 2006 Annual Report.)


The following table shows the percentage of the Utility's total 2006 electricity deliveries represented by each of its major customer classes.

Total 2006 Electricity Delivered: 84,310 GWh

Agricultural and Other Customers5%
Industrial Customers18%
Residential Customers37%
Commercial Customers40%


The following table shows certain of the Utility's operating statistics from 2002 to 2006 for electricity sold or delivered, including the classification of sales and revenues by type of service.
  
2006
 
2005
 
2004
 
2003
 
2002
 
Customers (average for the year):            
Residential  4,417,638  4,353,458  4,366,897  4,286,085  4,171,365 
Commercial  515,297  509,786  509,501  493,638  483,946 
Industrial  1,212  1,271  1,339  1,372  1,249 
Agricultural  79,006  78,876  80,276  81,378  78,738 
Public street and highway lighting  28,799  28,021  27,176  26,650  24,119 
Other electric utilities  4  4  3  4  5 
Total (1)  5,041,956  4,971,416  4,985,192  4,889,127  4,759,422 
Deliveries (in GWh):(2)            
Residential  31,014  29,752  29,453  29,024  27,435 
Commercial  33,492  32,375  32,268  31,889  31,328 
Industrial  15,166  14,932  14,796  14,653  14,729 
Agricultural  3,839  3,742  4,300  3,909  4,000 
Public street and highway lighting  785  792  2,091  605  674 
Other electric utilities  14  33  28  76  64 
Subtotal  84,310  81,626  82,936  80,156  78,230 
California Department of Water Resources (DWR)  
(19,585
)
 (20,476) (19,938) (23,554) (21,031)
Total non-DWR electricity  64,725  61,150  62,998  56,602  57,199 
Revenues (in millions):            
Residential  4,491 $3,856 $3,718 $3,671 $3,646 
Commercial  4,414  4,114  4,179  4,440  4,588 
Industrial  1,293  1,232  1,204  1,410  1,449 
Agricultural  483  446  491  522  520 
Public street and highway lighting  72  66  71  69  73 
Other electric utilities  59  4  22  24  10 
Subtotal  10,812  9,718  9,685  10,136  10,286 
DWR  (2,119) (1,699) (1,933) (2,243) (2,056)
Direct access credits        (277) (285)
Miscellaneous(3)  261  235  (248) (52) 193 
Regulatory balancing accounts  (202) (327) 363  18  40 
Total electricity operating revenues $8,752 $7,927 $7,867 $7,582 $8,178 
Other Data:            
Average annual residential usage (kWh)  7,020  6,834  6,744  6,772  6,577 
Average billed revenues (cents per kWh):            
Residential  14.48  12.96  12.62  12.65  13.29 
Commercial  13.18  12.71  12.95  13.92  14.65 
Industrial  8.53  8.25  8.14  9.62  9.84 
Agricultural  12.58  11.92  11.41  13.35  13.00 
Net plant investment per customer $3,148 $2,966 $2,790 $2,689 $2,105 

(1)Starting in 2005, the Utility’s methodology used to count customers changed from the number of billings to the number of active service agreements.
(2)These amounts include electricity provided to direct access customers who procure their own supplies of electricity.
(3)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.


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's 58 counties and includes most of northern and central California. In 2006, the Utility served approximately 4.2 million natural gas distribution customers. The total volume of natural gas throughput during 2006 was approximately 836 Bcf.

At December 31, 2006, the Utility's natural gas system consisted of 40,704 miles of distribution pipelines, 6,138 miles of backbone and local transmission pipelines, and three storage facilities. The Utility's distribution network connects to the Utility's transmission and storage system at approximately 2,200 major interconnection points. The Utility’s backbone transmission system, composed of Lines 300, 400 and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution system. The Utility'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. The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.0 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, the Rocky Mountains 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 connected to the Utility's transmission and storage system. These storage fields have a combined annual cycle capacity of approximately 42 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.

The CPUC divides the Utility's natural gas customers into two categories: core and noncore customers. This classification is based largely on a customer'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, larger commercial and electric generation natural gas customers. In 2006, core customers represented more than 99% of the Utility's total customers and 39% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility's total customers and 61% of its total natural gas deliveries.

The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility'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 96% of core market demand, receive natural gas bundled services from the Utility.

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The Utility does not provide procurement service to noncore customers. Electricity generators, cogenerators, enhanced oil recovery and refiners, and other large noncore customers may not transfer to core service, and smaller noncore customers must sign up for a minimum five-year term if they elect to transfer to core service. These restrictions were put in place because large increases in the Utility'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 its pipeline system to provide core service reliability on a short-term basis to serve this new load.

The Utility offers backbone gas transmission, delivery (local transmission and 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 other third-party storage providers. 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's backbone gas transmission system is available for all natural gas marketers and shippers, as well as noncore customers.

The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility's results of operations over the long term are not affected by weather variations, conservation or changes in their consumption levels. The Utility's results of operations can, however, be affected by noncore consumption levels because there are fewer regulatory balancing accounts related to noncore customers. Approximately 97% of the Utility's natural gas distribution base revenues are recovered from core customers and 3% are recovered from noncore customers.

The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon. It is prepared in even-numbered years followed by a supplemental report in odd-numbered years. The 2006 California Gas Report forecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 1.3% for the years 2006 through 2025. 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, price, and the number and location of electricity generation facilities.


The following table shows the percentage of the Utility's total 2006 natural gas deliveries represented by each of the Utility's major customer classes:

Total 2006 Natural Gas Deliveries: 836 Bcf

Residential Customers27%
Transport-only Customers (noncore)61%
Commercial Customers12%


The following table shows the Utility's operating statistics from 2002 through 2006 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:

  
2006
 
2005
 
2004
 
2003
 
2002
 
Customers (average for the year):            
Residential  3,989,331  3,929,117  3,812,914  3,744,011  3,738,524 
Commercial  220,024  216,749  215,547  208,857  206,953 
Industrial  988  962  2,178  1,988  1,819 
Other gas utilities  6  6  6  6  5 
Total  4,210,349  4,146,834  4,030,645  3,954,862  3,947,301 
Gas supply (MMcf):            
Purchased from suppliers in:            
Canada  202,274  204,884  205,180  196,278  210,716 
California  (13,401) (18,951) (9,108) (7,421) 19,533 
Other states  103,658  103,237  103,801  102,941  67,878 
Total purchased  292,531  289,170  299,873  291,798  298,127 
Net (to storage) from storage  4,359  (3,659) (532) 1,359  (218)
Total  296,890  285,511  299,341  293,157  297,909 
Utility use, losses, etc. (1)
  (27,610) (14,312) (19,287) (14,307) (16,393)
Net gas for sales  269,280  271,199  280,054  278,850  281,516 
Bundled gas sales (MMcf):            
Residential  196,092  194,108  201,601  198,580  202,141 
Commercial  73,178  77,056  78,080  79,891  78,812 
Industrial  10  35  373  379  563 
Other gas utilities  ___         
Total  269,280  271,199  280,054  278,850  281,516 
Transportation only (MMcf):  559,270  572,869  597,706  525,353  508,090 
Revenues (in millions):            
Bundled gas sales:            
Residential $2,452 $2,336 $1,944 $1,836 $1,379 
Commercial  859  885  712  697  499 
Industrial  -      1  3 
Other gas utilities  -      1  1 
Miscellaneous  121  (22) (29) (31) 127 
Regulatory balancing accounts  40  340  316  68  11 
Bundled gas revenues  3,472  3,539  2,943  2,572  2,020 
Transportation service only revenue  315  237  270  284  316 
Operating revenues $3,787 $3,776 $3,213 $2,856 $2,336 
Selected Statistics:            
Average annual residential usage (Mcf)  49  49  53  53  54 
Average billed bundled gas sales revenues per Mcf:            
Residential $12.50 $12.04 $9.64 $9.25 $6.82 
Commercial  11.73  11.48  9.12  8.73  6.33 
Industrial  1.03  0.61  (0.56) 2.48  4.35 
Average billed transportation only revenue per Mcf  0.56  0.42  0.45  0.54  0.62 
Net plant investment per customer $1,304 $1,262 $1,266 $1,261 $1,006 
             
(1)Includes fuel for the Utility's fossil fuel-fired generation plants.

The Utility purchases natural gas to serve the Utility'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's portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. During 2006, the Utility purchased approximately 293,000 Mcf of natural gas (net of the sale of excess supply) from 68 suppliers. Consistent with existing CPUC policy directives, substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility's largest individual supplier represented approximately 10.7% of the total natural gas volume the Utility purchased during 2006.

The following table shows the total volume and the average price of natural gas in dollars per Mcf of the Utility'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 2006, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

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  2006 2005 2004 2003 2002 
  
 
MMcf
 Avg. Price 
 
MMcf
 Avg. Price 
 
MMcf
 Avg. Price 
 
MMcf
 Avg. Price 
 
MMcf
 Avg. Price 
Canada  202,274  6.27  204,884 $7.12  205,180 $5.37  196,278 $4.73  210,716 $2.42 
California (1)  (13,401) 7.04  (18,951)$7.70  (9,108)$4.89  (7,421)$3.39  19,533 $2.88 
Other states (substantially all U.S. southwest)  103,658  6.51  103,237 $7.10  103,801 $5.44  102,941 $4.63  67,878 $3.04 
Total/weighted average  292,531  6.32  289,170 $7.07  299,873 $5.41  291,798 $4.73  298,127 $2.59 

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


The Utility's gas gathering system collects natural gas from third-party wells in California. During 2006, approximately 6% of the gas transported on the Utility's system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 395.6 miles of gas gathering pipelines. The Utility receives gas well production at approximately 250 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 13 California counties. Approximately 138 MMcf per day of natural gas produced in northern California was delivered into the Utility's gas gathering system during 2006.


In 2006, approximately 62% of the gas transported 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' 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' 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'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 2006, approximately 32% of the gas transported on the Utility's system came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Co., 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's natural gas transportation system in the area of California near Topock, Arizona. The Utility also has a short-term firm transportation agreement with Kern River Gas Transmission Company to transport this natural gas from supply points in this region to an interconnection point with the Utility’s natural gas transportation system begins.at Daggett, California.

Capacity Purchases on El Paso and Transwestern Pipelines

     In July 2002,

The following table shows certain information about the CPUC ordered California investor-owned electric utilities to contract for additional amounts of El Paso pipeline capacity to gainUtility's firm access to the southwest natural gas producing basins.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 CPUC believed that iftotal demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the utilities had firm access rights, they would have been able to mitigatecase of TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System, and by the gas price spikes that occurred duringFERC in all other cases. The Utility may, upon prior notice and with the energy crisis when shippers raised the price of gas at the California border. The CPUC pre-approved the costsCPUC’s approval, extend each of these contracts as just and reasonable. Sincenatural gas transportation agreements. On the July 2002 decision,FERC-regulated pipelines, the Utility has signed contracts foreither 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, 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 paidwould be required to Transwestern for natural gas pipeline capacity through 1997. The Utility pays approximately $22 million in annual reservation charges undermatch the Transwestern contract. The Gas Accord provided for partial recoverycompeting bid with respect to both price and term.


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Pipeline
 
Expiration
Date
  
Quantity
MDth per day
 
Demand Charges
for the Year Ended
December 31, 2006
(In millions)
        
TransCanada NOVA Gas Transmission, Ltd. 12/31/2008(a) 619 25.2
TransCanada PipeLines Ltd., B.C. System 10/31/2008  611 14.3
Gas Transmission Northwest Corporation 10/31/2008  610 56.1
Transwestern Pipeline Co. 03/31/2010  150 19.9
El Paso Natural Gas Company (b) Various  252 17.2
Kern River Gas Transmission Company 2/28/2007  29 0.4
(a)A small portion (23 MDth/d) 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 useddue 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.

expire on October 31, 2008.

(b)As of December 31, 2006, the Utility has four active contracts with El Paso with expiration dates ranging from February 28, 2007 to June 30, 2010.


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:


·  
• Thethe discharge of pollutants into air, water and soil;
·  
• Thethe 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
·  
• Landland use, including endangered species and habitat protection.

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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 upclean-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.(e.g., for cleaning up the Utility’sUtility's facilities and sites where the Utility has sent hazardous substances) from customers. ThatThis mechanism allows the Utility to include 90% of the hazardous waste remediation costs in the Utility’sUtility's rates without a reasonableness review. Hazardous waste remediation costs in the future are likely to be significant. However, based on the Utility’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 areis assigned to the Utility’sUtility's customers. The balance of any insurance recoveries (90%) areis retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. There alsoAny insurance recoveries above full cost reimbursement levels would then be allocated 60% to customers and 40% to the Utility. Finally, 10% of any recoveries from the Utility's claims against third parties associated with hazardous waste remediation sites is a special sharingretained by the Utility; 90% of any such recoveries is assigned to the Utility's customers.


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Hazardous waste remediation costs are rising and likely to be significant into the foreseeable future. Based on the Utility's past experience, it believes that it can recover most of the future costs incurred pursuing recovery underthat it may incur to remediate hazardous waste through rates and 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.recoveries. 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 electricity generation plants, and natural gas pipeline operations, fleet and fuel storage tanks 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.

     Various multi-pollutant The Utility’s existing and forecast emissions of greenhouse gases are relatively low compared to average emissions by other electric utilities and generators in the country.

In addition, various laws and regulations addressing climate change are being considered or implemented at the federal and state levels. At the federal level, several legislative initiatives have been introduced recently in the U.S. Senate and HouseCongress aimed at addressing climate change through imposition of Representatives. These initiatives includenation-wide regulatory limits on the emissions of nitrogen oxide, sulfur dioxide, mercurygreenhouse gases. No such legislation has yet been enacted by Congress, but extensive hearings and carbon dioxide,discussion is expected in the coming year.
At the state level, in 2006 California enacted Assembly Bill 32, the California Global Warming Solutions Act of 2006, to address climate change. The law establishes a regulatory program and some would allowschedule to gradually reduce greenhouse gas emissions in California to 1990 levels by 2020. By January 1, 2008, this law requires the use of trading mechanismsCARB to achievedetermine what the state-wide greenhouse gas emission level was in 1990, approve a statewide greenhouse gas emissions limit, and adopt regulations to require significant greenhouse gas emitters, including utilities and other load-serving entities, to submit annual greenhouse gas emissions reports that have been verified or maintaincertified by the CARB. Assembly Bill 32 also authorizes the CARB to monitor and enforce compliance with the proposed rules. Hearings on legislationgreenhouse gas reduction program and to amend the federal Clean Air Act have been held in the U.S. Senate but not in the Houseconsider implementing market-based mechanisms, including trading of Representatives.

     As a result of the Utility’s divestiture of most of its fossil fuel-fired and geothermal generation facilities, the Utility’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 oxidegreenhouse gas 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’s costs for its nitrogen oxide retrofit projects related to natural gas compressor stations on the Utility’s Line 300, which delivers gas from the southwest. Several air districts are considering nitrogen oxide rules that would apply to the Utility’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.

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allowances.


In addition to Assembly Bill 32, California Senate Bill 1368, enacted in September 2006, prohibits any load-serving entity in California, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload electricity generation unless the generation complies with a greenhouse gas emission performance standard. As required by Senate Bill 1368, on January 25, 2007, the CPUC adopted an interim greenhouse gas emissions performance standard of 1,100 pounds of carbon dioxide per MWh that applies to new commitments for baseload electricity procured under contracts with a term of five years or longer or generated by the Utility. After an enforceable state-wide greenhouse gas emissions limit is established and in operation in accordance with Assembly Bill 32, the CPUC will re-evaluate its interim greenhouse gas emissions performance standard and determine whether to continue, modify or rescind it.

The new California legislation, as well as current federal and other state regulatory initiatives particularly at the federal level, could increase the Utility’s compliance costs and capital expenditures primarily with respect to the Utility’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, thesepollutants, could cause the Utility's compliance costs and capital expenditures to increase. 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 towill 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’s generation facilities are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Utility’s steam-electric generation facilities comply in all material respectsrates consistent with the discharge constituents standardsrecovery of other reasonable costs of complying with environmental laws and regulations.

The CARB also oversees the thermal standards.Periodic Smoke Inspection Program to test and repair heavy-duty diesel vehicles in order to ensure efficient operations and reduce particulate matter emissions. The program applies to approximately 2,000 vehicles owned by the Utility. In addition, underJuly 2006, the federal Clean Water Act,CARB requested the Utility's program compliance records. The Utility discovered that its records were incomplete and that some records could not be located. The Utility immediately notified the CARB and began the evaluation and implementation of process improvements to ensure accurate recordkeeping. The CARB is requiredauthorized to demonstrateassess penalties of up to $500 per missing or incomplete record. The Utility continues to work with the CARB and expects to resolve the matter in the first quarter of 2007. The Utility believes that the location, design, construction and capacityultimate outcome of generation facility cooling water intake structures reflect the best technology available for minimizingthis matter would not result in a material adverse environmental impacts ateffect on its existing water-cooled thermal plants. financial condition or results of operations.


The Utility has submitted detailed studies of each steam-electric generation facility’s intake structure to various governmental agencies and each power plant’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” cooling water system that is regulated under a Clean Water Act National Pollutant Discharge Elimination System, or NPDES, permit issued by the Central Coast Regional Water Quality Control Board, or the 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


25


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 tounder 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 meetsreflects the best technology available, requirements.as defined in the federal Clean Water Act. As part of the Central Coasttentative settlement, agreement, the Utility has 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 thisthe 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 settlement agreement, 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 U.S. Environmental Protection Agency, or 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” cooling. The Utility’s Diablo Canyon Hunters Point and Humboldt Bay power plants areplant is among an estimated 539 generation

34


facilities nationwide that would beare affected by this rulemaking. The proposedUtility permanently closed its Hunters Point power plant in May 2006 and the Humboldt Bay power plant will be re-powered without the use of once-through cooling. The EPA 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 benefits achieved or the compliance costs considered by the EPA, and also allow the use of environmental mitigation or restoration to meet compliance requirements in certain cases. Various parties challenged the EPA’s regulations and the cases were consolidated in the U.S. Court of Appeal for the Second Circuit, or Second Circuit.

In June 2006, the California State Water Resources Control Board published a draft policy for California’s implementation of Section 316(b). If adopted, the draft policy would be substantially more stringent than the 2004 EPA regulations as the state policy would eliminate the EPA’s site-specific compliance options based on cost-benefit assessments and essentially requires the installation of cooling towers at once-through cooled power facilities. The draft policy provides that nuclear facilities may use environmental restoration as a compliance option only if the installation of technology would conflict with a nuclear safety requirement. It is uncertain when the state’s final policy will be adopted. If the final policy is adopted without change from the draft policy, the Utility could be required to incur significant capital costs to achieve compliance.

On January 25, 2007, the Second Circuit issued its decision on the appeals of the EPA Section 316(b) regulations. The Second Circuit remanded significant provisions of the regulations are adopted as proposed.to EPA for reconsideration and held that a cost benefit test cannot be used to establish performance standards or to grant variances from the standards. The final regulations are scheduledSecond Circuit also ruled that environmental restoration cannot be used to achieve compliance. The parties may seek either en banc review by the Second Circuit or review by the U.S. Supreme Court. Regardless of whether the decision is subject to further judicial review, the EPA will likely require significant time to review and revise the regulations. It is uncertain how the Second Circuit decision will affect development of the state’s proposed implementation policy. The regulatory uncertainty is likely to continue and the Utility’s cost of compliance, while likely to be issued in February 2004.significant, will remain uncertain as well.

In mid-January 2004,


Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium was detected inas a sample taken from a groundwater monitoring well nearresult of the Utility’s past operating practices. The Utility has a comprehensive program to monitor a network of groundwater wells at both the Hinkley and Topock natural gas compressor stations. At Hinkley, the Utility is cooperating with the Regional Water Quality Control Board to evaluate and remediate the chromium groundwater plume. In 2006, the Utility took interim measures to control movement of the Hinkley plume, as well as evaluated options to remediate the plume. At the Topock gas compressor station, located near Topock, Arizona. ThisNeedles, California, adjacent to the Colorado River, hexavalent chromium has been 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 implement interim

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measures as well as develop a long-term plan to ensure that the hexavalent chromium does not impactaffect the Colorado River. In 2006, the Utility took interim measures to control the chromium plume by extracting impacted groundwater and spent approximately $17 million on these measures. The Utility plans to continue these activities in 2007 and to work toward the development of a final plan to address the plume in 2007. The Utility currently estimates that it will spend at least $20 million in 2007 for remediation activities at Topock and $22 million in 2007 for remediation activities at Hinkley. Although implementation ofwork at the planTopock site poses several technical and regulatory obstacles, the Utility’s remediation costs for Topock are subject to the ratemaking mechanism described above. The Utility does not expect the outcome in this matterremediation of the Topock and Hinkley gas compressor sites to have a material adverse effect on its results of operations or financial condition. The Utility does not expect that it will incur any material expenditures related to any remediation at its Kettleman natural gas compressor station.


Endangered Species

Several lawsuits have been filed against the Utility alleging that exposure to chromium at or near the Utility's natural gas compressor stations caused personal injuries, wrongful deaths or other injuries. During 2006, the Utility entered into a settlement agreement to resolve most of these claims. Pursuant to the settlement agreement, in April 2006, the Utility released $295 million from escrow for payment to approximately 1,100 plaintiffs. There are three complaints filed by approximately 125 plaintiffs who did not participate in the settlement that are still pending in the Superior Court for the County of Los Angeles. With respect to the unresolved claims, the Utility will continue to pursue appropriate defenses, including the statute of limitations, the exclusivity of workers’ compensation laws, lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. PG&E Corporation and the Utility do not expect that the outcome with respect to the remaining unresolved claims will have a material adverse effect on their financial condition or results of operations.


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 conservation 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.

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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

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several such sites with the oversight of various governmental agencies.


In addition, the federal Toxic Substances Control Act regulates the use, disposal and cleanupclean-up of polychlorinated biphenyls, or PCBs, which are used in certain electrical equipment. During the 1980s, theThe Utility initiated two major programs to removehas removed from service all of the distribution capacitors and network transformers containing high concentrations of PCBs. These programs removedPCBs, 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’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$3 million in 20032006 and expects to spend approximately $6 million in 20042007 on these projects. The Utility expects that expenses will increase as remedial actions related to these sites are approved by regulatory agencies. In addition,There are approximately 6867 other manufactured gas plantsplant sites in the Utility’sUtility's service territory that are now owned by others. The Utility has not incurred any significant costs associated with these non-owned sites, but itothers which remain a source of potential claims. It is possiblelikely that the Utility maywill incur additional cleanupremediation costs related to some of these sites in the future if hazardous substances for whichsites. Although the Utility has been able to quantify potential liability are found.

for many of these sites, the amount of potential liability for all of these sites cannot be quantified.

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 cleanupclean-up costs or natural resource damages. The Utility is currently aware of eight such sites where investigation or cleanupclean-up activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility has been directed to perform site studiesis in the process of completing a three-year closure of the disposal facility which was abandoned by its operator. The Utility was the major responsible party and any necessary remedial measures by regulatory agencies.led this effort on behalf of the responsible parties. In 2006, the Utility completed settlements with the other responsible parties for their share of future costs and assumed ownership of the closed facility. 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. The Utility estimates the upper end of this cost range using reasonably possible outcomes that are least favorable to the Utility. 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.

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The Utility had an undiscounted environmental remediation liability of approximately $314$511 million at December 31, 2003,2006 and $331approximately $469 million at December 31, 2002. During 2003,2005. The increase in the undiscounted environmental remediation reflects an increase of $74 million for remediation at the Utility’s gas compressor stations located near Hinkley, California and Topock, Arizona. The portion of the increased liability of $39 million for remediation at the Hinkley facility is attributable to changes in the California Regional Water Quality Control Board’s imposed remediation levels. Costs incurred at this facility are not recoverable from customers and, as a result, the after-tax impact on income was reduced bya reduction of approximately $17$23 million mainly due to reassessmentfor 2006. Ninety percent of the estimated costremediation costs associated with the Utility’s gas compressor station located near Topock, Arizona will be recoverable in rates in accordance with the hazardous waste ratemaking mechanism which permits the Utility to recover ninety percent of hazardous waste remediation andcosts from customers without a reasonableness review.

For more information about environmental remediation payments. The approximately $314 million accrued at December 31, 2003, includes approximately $104 million relatedliabilities, see Note 17 of the Notes to the pre-closing remediation liability associated with divested generation facilities, and approximately $210 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 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 million environmental remediation liability, approximately $147 million has been included in prior rate-setting proceedings, and the Utility expects that approximately $116 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’s ultimate obligations may be subject to refund to ratepayers.

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

2006 Annual Report.


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Nuclear Fuel Disposal

Under the Nuclear Waste Policy Act of 1982, the Department of Energy, or Nuclear Waste Act, the DOE, is responsible for the transportation and ultimate long-termpermanent storage and 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 contracthas contracted with the DOE providingto provide for the disposal of the spent nuclear fuel and high-level radioactive wastethese materials from the Utility’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’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.Diablo Canyon. Under the Utility’s contract, with the DOE, if the DOE completes a storage facility by 2010, the earliest that Diablo Canyon’sCanyon's spent fuel would be accepted for storage or disposal wouldis thought to be 2018.

     On January 22, Under current operating procedures, the Utility believes that the existing spent fuel pools (which include newly constructed temporary storage racks) have sufficient capacity to enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1 and 2011 for Unit 2. After receiving a permit from the NRC in March 2004, the Utility filed separate complaintsbegan building an on-site dry cask storage facility to store spent fuel through at least 2024. The Utility estimates it could complete the dry cask storage project in 2008. The NRC’s March 2004 decision, however, was appealed by various parties, and the U.S. Court of Federal Claims againstAppeals for the Ninth Circuit, or Ninth Circuit, issued a decision in 2006 that requires the NRC to consider the environmental consequences of a potential terrorist attack at Diablo Canyon as part of the NRC’s supplemental assessment of the dry cask storage permit. The Utility may incur significant additional expenditures if the NRC decides that the Utility must change the design and construction of the dry cask storage facility. If the Utility is unable to complete the dry cask storage facility, or if construction is delayed beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2010 with respect to Unit 1 and 2011 with respect to Unit 2 and until such time as additional spent fuel can be safely stored.


As a result of the DOE’s failure to develop a permanent storage facility, the Utility has been required to incur substantial costs for planning and developing on-site storage options for spent nuclear fuel as described above at Diablo Canyon as well as at the retired nuclear facility at Humboldt Bay, or Humboldt Bay Unit 3.  The Utility is seeking to recover these costs from the DOE allegingon the basis 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.  Any amounts recovered from the DOE will be credited to customers.  In October 2006, the U.S. Court of Federal Claims issued a decision awarding approximately $42.8 million of the $92 million incurred by the Utility through 2004. The complaintsUtility will seek recovery of the Utility’s costs incurred after 2004 in future lawsuits against the DOE.  In January 2007, the Utility filed a notice of appeal of the U.S. Court of Federal Claims’ decision in the U.S. Court of Appeals for the planning and development of on-site storage at both facilities as a resultFederal Circuit seeking to increase the amount of the DOE’s failure to meet its obligations. The Utility’s complaints are similar to complaints filed by at least 20 other utilities with nuclear facilities.

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     Under current operating procedures,award and challenging the court’s finding the Utility believeswould have had to incur some of the costs for the onsite storage facilities even if the DOE had complied with the contract.   If the court’s decision is not overturned or modified on appeal, it is likely that the Diablo Canyon power plant’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 facilityUtility will be available by 2007. Therefore,unable to recover all of its future costs for onsite storage facilities from the Utility has appliedDOE.  However, reasonably incurred costs related to the NRC for a license to build an on-site dry caskonsite storage facility to store spent fuel atfacilities are, in the Diablo Canyon power plant, pending disposal or storage at a DOE facility. The NRC has provided initial approvals for the facility and is expected to complete its authorization process in early 2004. The Utility also has initiated the process for obtaining a required California Costal Commission permit for the facility. If the dry cask storage facility is not approved or is delayed, the Utility also is pursuing NRC approval of another storage option to install a temporary rack in each unit 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 also would pursue NRC approval for a high density reracking of both units, which, if approved, would allow the Utility to operate both units until shortly before the licenses expire in 2021 for Unit 1 and 2025 for Unit 2. If the Utility is unsuccessful in permitting and constructing the on-site dry cask storage facility, and it is otherwise unable to increase its on-site storage capacity it is possible that the operationscase of Diablo Canyon, may have to be curtailed or halted until such time as spent fuel can be safely stored.

     In July 1988, the NRC gave the Utility final approval to store radioactive waste from the Utility’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 steprecoverable through rates and, in the decommissioningcase 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 poolrecoverable through its decommissioning trust fund. 

PG&E Corporation and the facility is dismantled. Utility are unable to predict the outcome of this appeal or the amount of any additional awards the Utility may receive.

The used fuel assemblies currently are stored in metal racks submerged in a poolUtility's nuclear power facilities consist of water called a wet storage pool. The specially designed storage pool is constructed of steel-reinforced concretetwo units at Diablo Canyon and lined with stainless steel.

The Utility filed an application in December 2003 with the NRC seeking authorization to build an on-site dry cask storageretired 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’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 20212024 and to be completed in 2040.2044. 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 to be completed in 2015.

The Utility's revenue requirements for estimated nuclear decommissioning costs for the Diablo Canyon power plant and Humboldt Bay Unit 3 are approximately $1.83 billion in 2003 dollars (or approximately $5.25 billion in future dollars). These estimatesrecovered from customers through a non-bypassable charge that will continue until those costs are based on a 2002 decommissioning cost study, prepared in accordance with CPUC requirements, and used in the Utility’s Nuclear Decommissioning Costs Triennial Proceeding discussed below.fully recovered. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’sUtility's nuclear power plants. Actual decommissioning costs are expected tomay vary from this estimate becausethese estimates as a result of changes in assumedassumptions such as decommissioning dates, of decommissioning, regulatory requirements, technology, and costs of labor, materials and equipment.

     The CPUC has established For more information about nuclear decommissioning, including the Nuclear Decommissioning Costs Triennial Proceeding to determine the Utility’s estimated decommissioning costs, andsee Note 13 of the Notes to establish the associated annual revenue requirement and escalation factors for consecutive three-year periods. In October 2003, the CPUC issued a decisionConsolidated Financial Statements 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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2006 Annual Report.

Humboldt Bay Unit 3 at approximately $18.5 million

     The Utility’s revenue requirements for nuclear decommissioning costs are recovered from ratepayers 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 ratepayers through the decommissioning charge. The qualified trusts are subject to a lower tax rate on income and capital gains, thereby increasing the 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, the Utility collected approximately $22.6 million in rates and contributed approximately $21.3 million, on an after-tax basis, to the nuclear decommissioning trusts. For 2004, the Utility is authorized to collect approximately $18.5 million in rates for decommissioning Humboldt Bay Unit 3. Of this amount, the Utility expects to contribute approximately $13.3 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 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 taxes

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


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’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


29


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 isof 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


On January 26, 2006, the CPUC will takeissued a decision which affirms the CPUC’s “low-cost/no-cost, prudent avoidance” policy to respondreduce EMF exposure for new utility transmission and substation projects. The CPUC ordered the continued use of a 4% of project cost benchmark for EMF reduction measures. The CPUC also reaffirmed that it has exclusive jurisdiction with respect to this report. Possible outcomes include, but are not limited to, continuation of current policies and imposition of more stringent measures to mitigateutility 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.

matters.


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 allegedIn a case involving allegations of 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, thea California 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.

     The Utility’s corporate headquarters consistplaintiffs’ appeal of approximately 1.8 million square feetthis decision.



A discussion of office space locatedthe significant risks associated with investments in several buildingsthe securities of PG&E Corporation and the Utility is set forth under the heading “Risk Factors” in San Francisco, California. In additionthe MD&A in the 2006 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this corporate office space, thereport.


Not applicable.


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“Electric Utility Operations” and “—“Natural Gas Utility Operations.”Operations” above. In total, the Utility occupies 9.39.8 million square feet of real property, including approximately 975,0008.5 million square feet that the Utility owns. Of the 9.8 million square feet of leasedoccupied real property, approximately 1.7 million square feet represent the Utility's corporate headquarters located in several buildings in San Francisco, California. The Utility leases approximately 120,000 square feet of the approximate 1.7 million square feet of 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 170,000167,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements and/or donate to public agencies or non-profit conservation organizations under the settlement agreement with the CPUC.Chapter 11 Settlement Agreement. Approximately 44,00075,000 acres of this land may be either donated orin fee and encumbered with conservation easements. The remaining land contains the Utility’sUtility's or a joint licensee’slicensee's hydroelectric generation facilities and maywill only be encumbered with conservation easements.

As contemplated in the Chapter 11 Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council, or the Council, to oversee the development and implementation of a Land Conservation Plan, or LCP, that will articulate the long-term management objectives for the 140,000 acres. The Council is governed by an 18-member Board of Directors that represent a range of diverse interests, including the CPUC, California environmental agencies, organizations representing underserved and minority constituencies, agricultural and business interests, and public officials. The Utility has appointed 1 out of 18 members of the Board of Directors of the Council. While the Council originally contemplated adopting and presenting the LCP to the Utility by April 2007, it currently anticipates approving the LCP in the summer of 2007. The Utility will then seek authorization from the CPUC, the FERC and other approving entities to proceed with the transactions necessary to implement the LCP. If the Council is unable to reach consensus on all or part of the LCP, 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, before April 2013.


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.

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 in the U.S. Bankruptcy Court for the Northern District of California. The factors that caused the Utility to take this action are discussed in MD&A and in Note 2 of 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, the Utility has retained control of its assets and is authorized to operate its business as a debtor-in-possession while it is subject to the jurisdiction of the bankruptcy court.

     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’s Chapter 11 case for approximately $1.45 million relating to its ownership interest in shares of the Utility’s preferred stock. 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’s pollution control bonds. Both entities are subsidiaries of J.P. Morgan Chase & Co.

     In September 2001, PG&E Corporation and the Utility submitted a plan of reorganization that proposed to disaggregate the Utility’s current businesses. The CPUC, later joined by the Official Committee of Unsecured Creditors, or OCC, submitted a competing proposed plan of reorganization that did not provide for disaggregation of the Utility’s businesses. As discussed above, on December 19, 2003, 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 the 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’ rights under the Settlement Agreement, the Plan of Reorganization 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’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’ rights under, the Settlement Agreement, the Plan of Reorganization 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’ rights under the Settlement Agreement, the Plan of Reorganization or the confirmation order.

     The Settlement Agreement generally terminates nine years after the effective date of the Plan of 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

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     As required by the Settlement Agreement, the Utility has requested 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 date of the confirmed Plan of Reorganization or as soon thereafter as practicable, the Utility and PG&E Corporation will withdraw or abandon all applications for these regulatory approvals.

     There are several legal proceedings still pending in connection 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 in the appeal filed by the CPUC and other parties of an order issued by 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. 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

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Chapter 11 Filing of NEGT

     On July 8, 2003, NEGT 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.

     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’s customers are recoverable in retail rates under the federal filed rate doctrine.

     The Utility’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’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’s property. The Utility argues that the CPUC’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’s 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’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’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’s other arguments for dismissal of the Utility’s complaint.

     In August 2001, the Utility re-filed the Utility’s complaint in the District Court based on the Utility’s belief that the CPUC decisions referenced in the court’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’s motion to dismiss on all grounds, as well as the parties’ motions for summary judgment. While the court agreed with the Utility’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’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’s request, the District Court certified the appeal as “wholly without merit and, therefore, frivolous,” and rejected the CPUC’s request to stay the proceedings. On November 21,

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     Under the Settlement Agreement, the Utility will dismiss the filed rate case with prejudice on or as soon as practicable after the later of the effective date of the Plan of Reorganization 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 report 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 in 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 on the Utility’s financial condition or results of operations.

Diablo Canyon Power Plant


The Utility’sUtility's Diablo Canyon power plant employs a “once-through” cooling water system whichthat is regulated under a Clean Water Act National Pollutant Discharge Elimination System, or NPDES, permit issued by the Central Coast Regional Water Quality Control Board, or the 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 and the Central Coast Board reached a tentative settlement of this matter with the Central Coast Board pursuant tounder which the Central Coast Board agreed to find that the Utility’sUtility's discharge of cooling water from the Utility’s Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available, as defined in the Federalfederal Clean Water Act. As part of the Central Coasttentative 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 NPDES 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,customers.


PG&E Corporation and the Utility is currently seeking withdrawal of those portions of the claim relating to financial assurance and hazardous waste matters.

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



On January 10, 2002, the California Attorney General filed a complaint in the Superior Court for the County of San Francisco, or the 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 moneyfunds from the Utility to PG&E Corporation during the period from 1997 through 2000 (primarily in the form of dividends and stock repurchases), 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 also alleged that the December 2000 and January and February 2001 ringfencing transactions, by whichdefendants violated these conditions when PG&E Corporation subsidiaries complied with credit rating agency criteriaallegedly failed to establish independent credit ratings, violatedprovide adequate financial support to 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 beforeUtility during the California Court of Appeal for the First Appellate District in San Francisco, California. Oral argument is scheduled for March 5, 2004.

energy crisis.


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’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’s allegations concerning PG&E Corporation’s participation in the Utility’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’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’s participation in the Utility’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.competition in violation of Section 17200. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation “took at least $5.2 billion from the Utility,” and for unjust enrichment. The City and County of San Francisco, or CCSF, seeks injunctive relief, the appointment of a receiver, payment to customers,restitution, disgorgement, the imposition of a constructive trust, civil penalties and costs of suit.

     After removing the City’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’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’s June 2002 decision and ordered the California Attorney General’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’s claims at approximately $5 billion, are the property of the Utility’s Chapter 11

46


estate and therefore are properly within the bankruptcy court’s jurisdiction. Under the Plan of Reorganization, the Utility would release these claims. The District Court also affirmed, in part, the bankruptcy court’s June 2002 decision and found that the California Attorney General’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. The California Attorney General and the City and County of San Francisco have appealed this ruling to the Ninth Circuit. The defendants have filed motions to dismiss the appeals. No proceedings have been scheduled in bankruptcy court regarding the restitution claims. Under Section 17200, the California Attorney General is entitled to seek civil penalties of $2,500 against each defendant for each violation of Section 17200 and costs of suit.

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The complaints, which have been consolidated in the Superior Court, were filed after the CPUC issued two decisions in its investigative proceeding commenced in April 2001 into whether the California investor-owned electric utilities, including the Utility, 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 would, among other matters, investigate the 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' actions to “ringfence” their unregulated subsidiaries. In May 2005, the CPUC closed this investigation without making any findings.

PG&E Corporation believes that the intercompany transactions challenged by the California Attorney General and CCSF were in full compliance with applicable law and CPUC conditions. The challenged transactions forming the bulk of the restitution claims were regular quarterly dividends and stock repurchases. As part of its annual cost of capital proceedings, the Utility advised the CPUC in advance of its forecast stock repurchases and dividends. The CPUC did not challenge or question those payments.

In January 2006, the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, issued a decision on the parties’ appeals of various rulings by the Bankruptcy Court and the U.S. District Court for the Northern District of California, or the District Court, concerning jurisdictional issues. The Ninth Circuit found that the Superior Court had jurisdiction over the California Attorney General’s and CCSF’s restitution claims. (In October 2006, the U.S. Supreme Court declined to grant PG&E Corporation’s request to review the Ninth Circuit’s decision.) The Ninth Circuit did not address the California Attorney General’s and CCSF’s underlying allegations that PG&E Corporation and the other defendants violated Section 17200. The Ninth Circuit also did not decide the issue of who would be entitled to receive the proceeds, if any, of a restitution award, and PG&E Corporation continues to believe that any such proceeds would be the property of the Utility. Pursuant to the Chapter 11 Settlement Agreement, the CPUC released all claims against PG&E Corporation or the Utility arising out of or in any way related to the energy crisis, including the CPUC’s investigation into past PG&E Corporation actions during the energy crisis. Accordingly, PG&E Corporation believes that any claims for such proceeds by the CPUC would be precluded.

While the Ninth Circuit appeal was pending, the Superior Court held a trial in December 2004 to consider the appropriate standard to determine what constitutes a separate violation of Section 17200 in order to determine the magnitude of potential penalties under Section 17200 (up to $2,500 per separate “violation”). The Superior Court did not address the question of whether any violations occurred. In March 2005, the Superior Court issued a decision rejecting the “per victim” and “per [customer] bill” approaches advocated by the plaintiffs, standards that potentially could have resulted in millions of separate “violations.” The Superior Court found that the appropriate standard was each transfer of money from the Utility to PG&E Corporation that plaintiffs allege violated Section 17200. In July 27, 2005, the California Court of Appeal summarily denied a petition filed by the California Attorney General and CCSF seeking to overturn this decision. The California Attorney General’s complaint asserted thatGeneral and CCSF have resumed discovery in the total civil penalties would be not less than $500 million.Superior Court action. The bankruptcy court’s confirmation order providesnext case management conference is scheduled for April 17, 2007.

PG&E Corporation believes that the California Attorney General’s and the CityCCSF’s allegations have no merit and County of San Francisco’s claims are not released in connection with implementation of the Plan of Reorganization.

     The defendants filed a motionwill continue to seek clarification from the District Court regarding whether the District Court’s October 2003 order reaches the restitution claimsvigorously respond to and defend against the director defendants, as distinct from PG&E Corporation. At a hearing in November 2003, the District Court confirmed that its October 2003 order holds that the defendants’ restitution claims against the directors are also the property of the Utility’s estate.

litigation.PG&E Corporation believes that the applicable calculation methodology for civilultimate outcome of this matter would not result in a material adverse effect on PG&E Corporation’s financial condition or results of operations.



The CARB oversees the Periodic Smoke Inspection Program to test and repair heavy-duty diesel vehicles in order to ensure efficient operations and reduce particulate matter emissions. The program applies to approximately 2,000 vehicles owned by the Utility. In July 2006, the CARB requested the Utility's program compliance records. The Utility discovered that its records were incomplete and that some records could not be located. The Utility immediately notified the CARB and began the evaluation and implementation of process improvements to ensure accurate recordkeeping. The CARB is authorized to assess penalties if any violations were found,of up to $500 per missing or incomplete record. The Utility continues to work with the CARB and expects to resolve the matter in the first quarter of 2007. The Utility believes that the ultimate outcome of this matter would not result in a material adverse effect on its financial condition or results of operations.


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Compressor Station Chromium LitigationItem 4.

The following 14 civil suits are pending in several California courts against the Utility relatingSubmission of Matters 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.

     Alla Vote 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’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 amount.”

     In general, plaintiffs and claimants allege that exposure to chromium at or near the Utility’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’ motion for relief from stay so that the state court lawsuits pending before the Utility’s Chapter 11 filing can proceed.

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     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’ 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’ 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 13 summary judgment motions or motions in limine (motions to exclude potentially prejudicial information) challenging the claims of the trial test plaintiffs. Two of these motions are scheduled for hearing in the first quarter of 2004, with the others to 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.Security Holders

The Utility has recorded a reserve in the Utility’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’s financial condition or future results of operations.


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

Not applicable.



The names, ages and positions of PG&E Corporation executive“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, 2003February 1, 2007, are as follows:

Name
 
Age
Position
     
NameAgePosition



R. D. Glynn, Jr. Peter A. Darbee 6154 Chairman of the Board, Chief Executive Officer and President
P. A. DarbeeLeslie H. Everett 5056 Senior Vice President, Communications and Public Affairs
Kent M. Harvey48 Senior Vice President and Chief FinancialRisk and Audit Officer
C. P. JohnsRussell M. Jackson 4349 Senior Vice President, and ControllerHuman Resources
D. D. Richard, Jr. Christopher P. Johns 5346 Senior Vice President, Public Affairs; Senior Vice President, Public Affairs, Pacific GasChief Financial Officer and Electric CompanyTreasurer
G. R. SmithThomas B. King 5545 Senior Vice President; President and Chief Executive Officer, Pacific Gas and Electric Company
G. B. StanleyHyun Park 57Senior Vice President, Human Resources
B. R. Worthington5445 Senior Vice President and General Counsel
Rand L. Rosenberg53Senior Vice President, Corporate Strategy and Development


All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through February 1, 2007, 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.

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Name
Position
Period Held Office
     
NamePositionPeriod Held Office



R. D. Glynn, Jr. Peter A. Darbee Chairman of the Board, Chief Executive Officer and President January 1, 19982006 to present
  Chairman of the Board, Pacific Gas and Electric Company January 1, 19982006 to present
P. A. DarbeePresident and Chief Executive OfficerJanuary 1, 2005 to December 31, 2005
 Senior Vice President and Chief Financial Officer JulySeptember 20, 1999 to December 31, 2004
Leslie H. EverettSenior Vice President, Communications and Public AffairsJanuary 9, 2006 to present
Senior Vice President and Assistant to the Chief Executive OfficerJanuary 1, 2005 to January 8, 2006
Senior Vice President and Assistant to the ChairmanAugust 2, 2004 to December 31, 2004
Vice President and Assistant to the ChairmanJune 1, 2001 to August 1, 2004
Kent M. HarveySenior Vice President and Chief Risk and Audit OfficerOctober 1, 2005 to present
  Senior Vice President, Chief Financial Officer and Treasurer, Pacific Gas and Electric Company November 1, 2000 to September 20, 199930, 2005
Russell M. JacksonSenior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric CompanyAugust 2, 2004 to July 8, 2001present
  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
Christopher P. JohnsSenior Vice President, Chief Financial Officer Advance Fibre Communications, Inc.and Treasurer June 30, 1997October 4, 2005 to September 19, 1999present
C. P. JohnsSenior Vice President, Chief Financial Officer and Treasurer, Pacific Gas and Electric CompanyOctober 1, 2005 to present
Senior Vice President, Chief Financial Officer and ControllerJanuary 1, 2005 to October 3, 2005
 Senior Vice President and Controller September 19, 2001 to present
Vice President and ControllerJuly 1, 1997 to September 18, 2001
Vice President and Controller, Pacific Gas and Electric CompanyJune 1, 1996 to December 31, 19992004
D. D. Richard, Jr. Senior Vice President, Public AffairsOctober 18, 2000 to present
Vice President, Governmental RelationsJuly 1, 1997 to October 17, 2000
Senior Vice President, Public Affairs, Pacific Gas and Electric CompanyMay 1, 1998 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

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“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. King42Senior Vice President and Chief of Utility Operations
R. J. Peters53Senior Vice President 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
Thomas B. King Senior Vice President, PG&E Corporation January 1, 1999 to present
K. M. HarveySenior Vice President — Chief Financial Officer, and TreasurerNovember 1, 20002006 to present
  Senior Vice President, Chief FinancialExecutive Officer, Controller,Pacific Gas and TreasurerElectric Company January 1, 2000August 15, 2006 to October 31, 2000present
  SeniorPresident and Chief Executive Officer, Pacific Gas and Electric CompanyJanuary 1, 2006 to August 14, 2006
Executive Vice President and Chief FinancialOperating Officer, Pacific Gas and TreasurerElectric Company July 1, 19972005 to December 31, 19992005
T. B. KingExecutive Vice President and Chief of Utility Operations, Pacific Gas and Electric CompanyAugust 2, 2004 to June 30, 2005
 Senior Vice President and Chief of Utility Operations, Pacific Gas and Electric 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
Hyun Park Senior Vice President and General Counsel January 1, 1999November 13, 2006 to present

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Vice President, General Counsel and Secretary, Allegheny Energy, Inc. (an investor-owned utility company headquartered in Pennsylvania)April 5, 2005 to October 17, 2006
Senior Vice President, General Counsel and Secretary, Sithe Energies, Inc.March 2000 to February 2005
     
NamePositionPeriod Held Office



D. D. Richard, Jr. Rand L. Rosenberg Senior Vice President, Corporate Strategy and DevelopmentNovember 1, 2005 to present
Executive Vice President and Chief Financial Officer, Infospace, Inc.September 2000 to January 20, 2001

33

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 February 1, 2007, are as follows:

Name
Age
Position
Peter A. Darbee54Chairman of the Board
Thomas B. King45Chief Executive Officer
William. T. Morrow47President and Chief Operating Officer
Thomas E. Bottorff53Senior Vice President, Regulatory Relations
Jeffrey D. Butler51Senior Vice President, Energy Delivery
Leslie H. Everett56Senior Vice President, Communications and Public Affairs, (Please refer to description of business experience for executive officers of PG&E Corporation above.)
Russell M. Jackson49Senior Vice President, Human Resources
Christopher P. Johns46Senior Vice President, Chief Financial Officer and Treasurer
John S. Keenan58Senior Vice President, Generation and Chief Nuclear Officer
Hyun Park45Senior Vice President and General Counsel, PG&E Corporation
Stewart M. Ramsay48Vice President, Asset Management and Electric Transmission
Fong Wan45Vice President, Energy Procurement


All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 1, 2007, 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
Peter A. DarbeeChairman of the Board, Pacific Gas and Electric CompanyJanuary 1, 2006 to present
Chairman of the Board, Chief Executive Officer and President, PG&E CorporationJanuary 1, 2006 to present
President and Chief Executive Officer, PG&E CorporationJanuary 1, 2005 to December 31, 2005
Senior Vice President and Chief Financial Officer, PG&E CorporationJuly 9, 2001 to December 31, 2004
Thomas B. KingChief Executive OfficerAugust 15, 2006 to present
President and Chief Executive OfficerJanuary 1, 2006 to August 14, 2006
Senior Vice President, PG&E CorporationJanuary 1, 2006 to present
Executive Vice President and Chief Operating OfficerJuly 1, 2005 to December 31, 2005
Executive Vice President and Chief of Utility OperationsAugust 2, 2004 to June 30, 2005
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, PG&E Gas Transmission CorporationAugust 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 CorporationNovember 23, 1998 to September 10, 2002
William T. MorrowPresident and Chief Operating OfficerAugust 15, 2006 to present
Chief Executive Officer, Europe, Vodafone Group PLC (a global mobile telecommunications company) May 1, 19982006 to July 31, 2006
President, Vodafone KK, JapanApril 1, 2005 to April 30, 2006
Chief Executive Officer, Vodafone UK, Ltd.February 1, 2004 to March 31, 2005
President, Japan Telecom Holdings Co., Inc.December 21, 2001 to January 31, 2004
Thomas E. BottorffSenior Vice President, Regulatory RelationsOctober 14, 2005 to present
G.Senior Vice President, Customer Service and RevenueMarch 1, 2004 to October 13, 2005
Vice President, Customer ServiceJune 1, 1999 to February 29, 2004
Jeffrey D. ButlerSenior Vice President, Energy DeliveryJanuary 9, 2006 to present
Senior Vice President, Transmission and DistributionMarch 1, 2004 to January 8, 2006
Vice President, Operations, Maintenance and ConstructionJune 12, 2000 to February 29, 2004
Leslie H. EverettSenior Vice President, Communications and Public Affairs, PG&E CorporationJanuary 9, 2006 to present
Senior Vice President and Assistant to the Chief Executive Officer, PG&E CorporationJanuary 1, 2005 to January 8, 2006
Senior Vice President and Assistant to the Chairman, PG&E CorporationAugust 2, 2004 to December 31, 2004
Vice President and Assistant to the Chairman, PG&E CorporationJune 1, 2001 to August 1, 2004
Russell M. RuegerJacksonSenior Vice President, Human Resources, Pacific Gas and Electric Company and PG&E CorporationAugust 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
Christopher P. JohnsSenior Vice President, Chief Financial Officer and TreasurerOctober 1, 2005 to present
Senior Vice President, Chief Financial Officer and Treasurer, PG&E CorporationOctober 4, 2005 to present
Senior Vice President, Chief Financial Officer and Controller, PG&E CorporationJanuary 1, 2005 to October 3, 2005
Senior Vice President and Controller, PG&E CorporationSeptember 19, 2001 to December 31, 2004
John S. Keenan Senior Vice President, Generation and Chief Nuclear Officer April 2, 2000December 19, 2005 to present
Vice President, Fossil Generation, Progress EnergyNovember 10, 2003 to December 18, 2005
Vice President, Brunswick Nuclear Plant, Progress EnergyMay 1, 1998 to November 9, 2003

 Hyun ParkSenior Vice President and General Counsel, PG&E Corporation November 13, 2006 to present
Vice President, General Counsel and Secretary, Allegheny Energy, Inc. (an investor-owned utility company headquartered in Pennsylvnia) April 5, 2005 to October 17, 2006
  Senior Vice President, General Counsel and General Manager, NuclearSecretary, Sithe Energies, Inc. March 2000 to February 2005
Stewart M. RamsayVice President, Asset Management and Electric TransmissionJanuary 9, 2006 to present
Vice President, Electric TransmissionJuly 1, 2005 to January 8, 2006
Vice President, Distribution Asset Management, American Electric Power Generation Business UnitFebruary 1, 2004 to June 30, 2005
Senior Vice President, Power and Gas, UMS Group, Inc.October 1, 2001 to January 31, 2004
Fong WanVice President, Energy ProcurementJanuary 9, 2006 to present
Vice President, Power Contracts and Electric Resource DevelopmentMay 1, 2004 to January 8, 2006
Vice President, Risk Initiatives, PG&E Corporation Support Services, Inc. November 1, 19912000 to April 1, 200030, 2004


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

     Information responding to part


As of February 1, 2007, there were 92,901 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York Stock Exchange and Pacific Gasthe Swiss stock exchanges. The high and Electric Company, islow sales prices of PG&E Corporation common stock for each quarter of the two most recent fiscal years are set forth under the heading “Quarterly Consolidated Financial Data (Unaudited)” in the 20032006 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. As of February 17, 2004, there were 110,740 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York, Pacific, and Swiss stock exchanges. The discussion of dividends with respect to PG&E Corporation’sCorporation's common stock is hereby incorporated by reference from “Management’s“Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Financial Resources — Dividend Policy”- Dividends” of the 20032006 Annual Report.

     On July 2, 2003,


34


As previously disclosed, in connection with its entry into certain credit agreements, in June 2002 and October 2002, PG&E Corporation completedissued warrants to purchase 5,066,931 shares of PG&E Corporation common stock at an exercise price of $0.01 per share. During the offeryear ended December 31, 2006, warrant holders exercised, on a net exercise basis, warrants to purchase 51,904 shares, and salereceived 51,890 shares of $600 million of 6 7/8% Senior Secured Notes due 2008 pursuant to anPG&E Corporation common stock in reliance on the exemption from or in a transaction not subject to, the registration requirements of the Securities Act of 1933 or Act. The net proceedsprovided by Section 4(2) 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 agreementAct. As 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’s 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. actingDecember 31, 2006, warrant holders had exercised, on a discretionarynet exercise 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 3warrants to the “Notes to Consolidated Financial Statements”purchase 5,066,931 shares, and had received 5,065,099 shares of PG&E Corporation contained incommon stock since the 2003 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.

warrants were issued. There are no more warrants outstanding.


Pacific Gas and Electric Company did not make any sales of unregistered equity securities during 2003, the period covered by this report.quarter ended December 31, 2006.
 
Item 6.Selected Financial Data.

Issuer Purchases of Equity Securities

               PG&E Corporation common stock:
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)
 
Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs (2)
 
              
October 1 through October 31, 2006  - $-  - $500,000,000 
November 1 through November 30, 2006  - $-  - $500,000,000 
December 1 through December 31, 2006  - $-  - $500,000,000 
Total
  - $-  - $500,000,000 
 
(1) On October 19, 2005, the PG&E Corporation Board of Directors authorized the repurchase of up to $1.6 billion of shares of PG&E Corporation's common stock from time to time, but no later than December 31, 2006. No purchases were made under this authorization during the quarter ended December 31, 2006.
(2) The authority to repurchase shares under this authorization expired on December 31, 2006.

During the fourth quarter of 2006, Pacific Gas and Electric Company did not redeem or repurchase any shares of its various series of preferred stock outstanding.


A summary of selected financial information, for each of PG&E Corporation and Pacific Gas and Electric Company for each of the last five fiscal years, is set forth under the heading “Selected Financial Data” in the 20032006 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.

A discussion of PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's consolidated financial condition and 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” in the 20032006 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.


Information responding to Item 7A appears in the 20032006 Annual Report under the heading “Management’s“Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Management Activities,” and under Notes 12 and 812 of the “Notes to the Consolidated Financial Statements” of the 20032006 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.

Information responding to Item 8 appears in the 20032006 Annual Report under the following headings for PG&E Corporation: “Consolidated Statements of Operations,Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated

35


Statements of Common Shareholders’Shareholders' Equity;” under the following headings for Pacific Gas and Electric Company: “Consolidated Statements of Operations,Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders’Shareholders' Equity;” and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” “Independent Auditors’ Report,” and “Responsibility for the Consolidated Financial Statements,“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 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

Not applicable.


Item 9A.Controls and Procedures

Based on an evaluation of PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sthe Utility's disclosure controls and procedures as of December 31, 2003,2006, 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 that the companies file or submit under the Securities and Exchange Act of 1934, or the 1934 Act, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange CommissionSEC rules and forms.

In addition, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.


There were no changes in internal controlscontrol over financial reporting that occurred during the quarter ended December 31, 2003,2006 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’sCorporation's or Pacific Gas and Electric Company’s controlsthe Utility's internal control 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 occupations forhave prepared an annual report on internal control over financial reporting. Management's report, together with the past five years, certain other directorships, age, and length of service as a director

52


of PG&E Corporation and the Utility. The directors of PG&E Corporation and the directorsreport of the Utility are the same, except that Gordon R. Smith is a director of the Utility only.

David R. Andrews. Mr. Andrews is Senior Vice President Government Affairs, General Counsel, and Secretary of PepsiCo, Inc. (food and beverage businesses), and has held that position since February 2002. Prior to joining PepsiCo, Inc., Mr. Andrews was a partnerindependent registered public accounting firm, appears in the law firm2006 Annual Report under the heading “Management's Report on Internal Control Over Financial Reporting” and “Report of McCutchen, Doyle, Brown & Enersen, LLP from May 2000Independent Registered Public Accounting Firm,” which information is hereby incorporated by reference and filed as part of Exhibit 13 to January 2002 and from 1981 to July 1997. From August 1997 to April 2000, he servedthis report.  



Officer Appointments

On February 21, 2007, the Utility’s Board of Directors elected William T. Morrow, 47, as the legal advisor to the U.S. Department of State and former Secretary Madeleine Albright. Mr. Andrews, 62, has been a director of PG&E Corporation and the Utility since 2000. He also serves as a director of UnionBanCal Corporation.

Leslie S. Biller. Mr. Biller is retired Vice Chairman and Chief Operating Officer of Wells Fargo & Company (financial services and retail banking). He held that position from November 1998 until his retirement in October 2002. Mr. Biller was President and Chief Operating Officer of Norwest Corporation (bank holding company) from 1997 until it merged with Wells Fargo & Company in 1998. Mr. Biller, 55, has been an advisory director of PG&E Corporation and the Utility since January 2003, and was elected a director of PG&E Corporation and the Utility on February 18, 2004. He also serves 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 of 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 officerthe Utility, effective July 1, 2007. Mr. Morrow will continue to report to Thomas B. King, currently Chief 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 directorthe Utility, who will become President 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 director of the Utility since 1992 and a director of PG&E Corporation since 1996. He also serves as a director of The Home Depot, Inc.

Robert D. Glynn, Jr. Mr. Glynn iseffective July 1, 2007. Peter A. Darbee, currently Chairman of the Board, Chief Executive Officer, and President of PG&E Corporation, and Chairman of the Board of the Utility. He has been an officer of PG&E Corporation since December 1996 and an officer 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.

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 retiredwill become 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 officerPG&E Corporation effective July 1, 2007. Mr. Darbee will continue to serve as Chairman of Wells Fargo Bank from 1978 until his retirement in December 1994. the Board of the Utility.

Mr. Reichardt, 72,Morrow has been a directorPresident and Chief Operating Officer of the Utility since 1985August 15, 2006. Before joining the Utility, Mr. Morrow held various executive positions in the telecommunications industry. Most recently Mr. Morrow served as Chief Executive Officer, Europe, of Vodafone Group PLC, a position he held from May 2006 to July 2006. From April 2005 to April 2006, Mr. Morrow served as President of Vodafone K.K. in Japan and a directorfrom February 2004 to March 2005, he was Chief Executive Officer of PG&E Corporation since 1996. He also serves as a directorVodafone, U.K., Ltd. From December 2001 through January 2004, Mr. Morrow was President of ConAgra Foods,Japan Telecom Holdings Co., Inc. and Ford Motor Company.

Gordon R. Smith.Japan Telecom Co., Inc. Previously in 2001, Mr. Smith isMorrow was Vice President and Country Manager, Japan for Vodafone Group PLC.


Mr. King has served as Chief Executive Officer of the Utility since August 15, 2006. Prior to that date, Mr. King served as President and Chief Executive Officer of the Utility, a position he held from January 1, 2006 to August 14, 2006. He served as Executive Vice President and has been an officerChief Operating 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 investmentfrom July 1, 2005 to December 31, 2005, and consulting), and has held that position since 1987. He also served as interimExecutive Vice President and Chief Executive Officerof Utility Operations from August 2, 2004 to June 30, 2005. From November 1, 2003 to August 1, 2004, he was Senior Vice President and Chief of Utility Operations of the American Management Association (management development organization) fromUtility. Prior to November 2000 to June 2001.1, 2003, Mr. Williams, 59, hasKing had been a directorSenior Vice President of PG&E Corporation from January 1, 1999. Since 2000, Mr. King also held various executive positions at PG&E National


36


Energy Group, Inc., a former subsidiary of PG&E Corporation involved in power generation, natural gas transmission, and wholesale energy marketing and trading. Mr. King focused his activities primarily in the Utility since 1990natural gas transmission business. From November 15, 2002 to July 8, 2003, Mr. King served as the President and as a director of PG&E National Energy Group, Inc.

Mr. King and Mr. Morrow are entitled to receive equity awards under the PG&E Corporation since 1996. He2006 Long-Term Incentive Plan and the PG&E Corporation Executive Stock Ownership Program. They are also serveseligible to receive annual cash incentive awards under an annual Short-Term Incentive Plan adopted by the PG&E Corporation Board of Directors. The Utility provides retirement benefits to all of its employees, including its officers, under a tax-qualified defined benefit pension plan. Officers of PG&E Corporation and the Utility are also entitled to receive pension benefits under the PG&E Corporation Supplemental Executive Retirement Plan, a non-tax qualified defined benefit pension plan. Officers of PG&E Corporation and the Utility may also participate in the PG&E Corporation Retirement Savings Plan, a 401(k) plan available to all eligible employees, and the PG&E Corporation Supplemental Retirement Savings Plan. PG&E Corporation also has adopted an Officer Severance Policy that covers officers of PG&E Corporation and the Utility. These plans, as well as perquisites provided to officers, are described in PG&E Corporation’s and the Utility’s 2006 joint proxy statement filed with the Securities and Exchange Commission.  

Neither Mr. Morrow nor Mr. King has any relationship or related transaction with PG&E Corporation or the Utility that would require disclosure pursuant to Item 404(a) of Securities and Exchange Commission Regulation S-K.

2007 Short-Term Incentive Plan 
As previously disclosed, the Nominating, Compensation and Governance Committee of the PG&E Corporation Board of Directors, or the Committee, has approved the structure of the PG&E Corporation 2007 Short-Term Incentive Plan, or STIP, under which officers of PG&E Corporation and the Utility are provided an opportunity to receive annual incentive cash payments. Corporate financial performance, as measured by corporate earnings from operations, will account for 50 percent of the incentive, 20 percent of the incentive will be based on customer satisfaction indices, 20 percent of the incentive will be based on the Utility’s success in implementing its strategy to achieve operational excellence and improved customer service, 5 percent will be based on the results of an employee opinion survey measuring employee engagement, and the remaining 5 percent will be based on achieving safety standards. At its meeting on February 21, 2007, 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 corporate financial performance portion of the 2007 STIP as was used for the 2006 STIP. The corporate financial performance measure is based on PG&E Corporation's budgeted earnings from operations that were previously approved by the Board, consistent with the basis 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 also approved the 2007 performance targets for each of the four other measures set forth in the table below. The 2006 performance results for each measure are included for comparative purposes.
2007 STIP Performance Targets (1)


Measure
 
Relative Weight
 
2006 Results
 
2007 Target
 
Customer Satisfaction (Residential & Business) (2) 20% 100 676 
Business Transformation Index (3)  20% N/A  1.0 
Employee Survey (Premier) Index (4)  5% 64.0% 66.0%
Occupational Safety and Health Administration (OSHA) Recordable Injury Rate (5)  5% 12.9% reduction  15% reduction 

1.As explained above, 50% of the STIP award will be based on achievement of corporate earnings from operations targets.
2.This measure reflects a directorweighted composite of CH2M Hill Companies, Ltd.,the overall customer satisfaction indices of the Utility’s residential and business customers as reported by the J.D. Power Residential Survey and the J.D. Power Business Survey. For 2006, the residential customers’ and business customers’ scores were weighted equally. In an effort to enhance the focus on improving residential customer satisfaction, which has been lower than business customer satisfaction, for the 2007 target the weighting of the residential customers’ score will be increased to 60% and the weighting of the business customers’ score will be lowered to 40%. In addition, for 2007, J.D. Power and Associates has changed the scale used to report results from the J.D. Power Survey from a scale that attempted to center the industry average score at approximately 100 to a 1,000-point scale. By way of comparison, results for 2006 would have been 678 under the new 1000-point scale based on equally weighted scores and results for 2006 would have been 673 based on the revised weightings. The Northwestern Mutual Life Insurance Company, R.H. Donnelley Corporation, 2007 target may be adjusted to reflect changes in the J.D. Power industry average scores, which are expected by mid-year 2007.

37


3.The Simpson Manufacturing Company Inc.,Business Transformation Index is comprised of five measurement points that define success in achieving key Business Transformation operational, financial, and SLM Corporation.post-implementation objectives. The five measurement points are (1) overall Business Transformation cost performance in comparison to budgeted amounts, (2) overall business transformation benefit performance in comparison to planned/budgeted amounts, (3) new business customer connection performance for cycle time and number of customer commitments met, (4) SmartMeter

TM project performance for number of meters installed and activated, and (5) the extent to which core business transformation initiatives are implemented compared to planned schedule and scope of initiatives.

4.The Premier Survey is the primary tool used to measure employee engagement at PG&E Corporation and the Utility. The employee index is designed around 15 key drivers of employee engagement. The average overall employee survey index score provides a comprehensive metric that is derived by adding the percent of favorable responses from all 40 core survey items (all of which fall into one of 15 broader topical areas), and then dividing the total sum by 40.
5.An “OSHA Recordable” is an occupational (job-related) injury or illness that requires medical treatment beyond first aid, or results in work restrictions, death or loss of consciousness. The “OSHA Recordable Rate” is the number of OSHA Recordables for every 200,000 hours worked, or for approximately 100 employees. This metric measures the percentage reduction in the Utility’s OSHA Recordable rate from the prior year.

The Committee has full discretion as to the determination of final officer STIP awards for 2007 performance.


Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included above in a separate item captioned “Executive Officers of the Registrants” contained on pages 48 through 50 inat the end of 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 2007 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 Code of Ethics, Corporate Governance and Other Documents


The following documents are available both on PG&E Corporation’sCorporation's website www.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, Vice President, Corporate Governance and 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.

Compensationwebsite and any waivers to the code will be disclosed in a Current Report on Form 8-K filed within 4 business days of Directors

     Each director who is not an officer or employeethe waiver.


Procedures for Shareholder Recommendations of Nominees to the Boards of Directors

During 2006 there were no material changes to the procedures described in PG&E CorporationCorporation’s and the Utility’s joint proxy statement relating to the 2006 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or the Utility receives a quarterly retainerUtility’s Boards 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. UnderDirectors.

Audit Committees and Audit Committee Financial Expert

Information regarding 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 tied to the market value of PG&E Corporation common stock. Alternatively, participating directors may elect that their deferred compensation be invested in the Utility Bond Fund.

     No director who serves 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 meeting 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 practiceAudit Committees of PG&E Corporation and the Utility that meetingsand the “audit committee financial expert” as defined by the SEC is included under the heading “Information Regarding the Boards of the respective Boards and corresponding committees are held concurrently and, therefore, that a single meeting fee is paid to each director for each set of meetings.

Directors of PG&E Corporation or the Utility are reimbursed for reasonable expenses incurred for participating inand Pacific Gas and Electric Company - 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 heldCommittees- Audit Committees” in the Deferred Compensation Plan for Non-Employee Directors. The payment of frozen accrued retirement benefits, or distributions from the Deferred Compensation Plan attributableJoint Proxy Statement relating to the conversion2007 Annual Meetings 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,Shareholders, which information 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 entitledhereby incorporated by reference.



Information responding 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 stockItem 11, 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


38


the Utility during 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)                                

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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).

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Option/SAR Grants in 2003

This table summarizes the distributionheadings“Compensation Discussion and the terms and conditions of stock options granted to the executive officers named in the SummaryAnalysis,”“Compensation Committee Report,” “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.

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

This table summarizes exercises” “Grants 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 —Plan-based Awards in 2003

This table summarizes the long-term incentive grants made to the executive officers named in the Summary2006,” “Outstanding Equity Awards at Fiscal Year End,” “Option Exercises and Stock Vested During 2006,” “Pension Benefits,” “Nonqualified Deferred 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.

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” and “Compensation of Directors,” and “Potential Payments Upon Resignation, 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,Death, or Disability” in the Joint Proxy Statement relating to the 2007 Annual Meetings of Shareholders, which covers most officersinformation is hereby incorporated by reference.


Information responding to Item 12, for each of PG&E Corporation and its subsidiaries, includingPacific Gas and Electric Company, is included under the executive officers namedheading “Security Ownership of Management” and under the heading “Principal Shareholders” 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 realization2007 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”

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will be deemed to have occurred if any of the following occurs: (1) any “person” (as such termShareholders, which information 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 electionhereby incorporated 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.reference.

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, 2003,2006 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation’sCorporation's existing equity compensation plans.
             
(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.

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  6,477,959(1)$24.16  11,421,085(2)
Equity compensation plans not approved by shareholders   $   
Total equity compensation plans  6,477,959(1)$24.16  11,421,085(2)
(1) Includes 79,639 phantom stock units and restricted stock units. The weighted average exercise price reported in column (b) does not take these awards into account.

(2) Represents the total number of shares available for issuance under PG&E Corporation's Long-Term Incentive Program, or LTIP, and the PG&E Corporation 2006 Long-Term Incentive Plan, or 2006 LTIP, as of December 31, 2006. 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. The LTIP expired on December 31, 2005. The 2006 LTIP, which became effective on January 1, 2006 authorizes up to 12 million shares to be issued pursuant to awards granted under the 2006 LTIP. Outstanding stock-based awards granted under the 2006 LTIP include stock options, restricted stock, restricted stock units and phantom stock payable in an equal number of shares upon termination of employment or service as a director. For a description of the LTIP and the 2006 LTIP, see Note 14 of the Notes to the Consolidated Financial Statements in the 2006 Annual Report.


Information responding to 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 accountants13, for purposeseach 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 billed for all audit-related services rendered by Deloitte & Touche LLP to PG&E Corporation and its subsidiaries consisted 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

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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 Actheadings “Related Person Transactions,” “Review, Approval, and Ratification of 2002. In determining whether to pre-approve any services fromRelated Person Transactions” and “Information Regarding the independent public accountants, the Audit Committees assess, among other things, the impactBoards of that service on the auditor’s independence.

     Following the initial annual pre-approval, the Audit Committees must pre-approve any proposed engagementDirectors 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 and their consolidated affiliates were approved pursuant- Director Independence” in the Joint Proxy Statement relating to the applicable pre-approval procedures.

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2007 Annual Meetings of Shareholders, which information is hereby incorporated by reference.



Information responding to Item 14, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading “Information Regarding the Independent Registered Public Accounting Firm of PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2007 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

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(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 2003 Annual Report, which have been incorporated by reference in this report:

Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002, and 2001,

1.The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are contained in the 2006 Annual Report and are incorporated by reference in this report:

Consolidated Statements of Income for the Years Ended December 31, 2006, 2005, and 2004, for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December 31, 2006, and 2005 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2006, 2005, and 2004, for each of PG&E Corporation and Pacific Gas and Electric Company.

Notes to the Consolidated Financial Statements.

Quarterly Consolidated Financial Data (Unaudited).

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

2.The following financial statement schedules and report of independent registered public accounting firm are filed as part of this report:

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

I - Condensed Financial Information of Parent as of December 31, 2006 and 2005 and for the Years Ended December 31, 2006, 2005, and 2004.

II - Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2006, 2005, and 2004.

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.

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3.Exhibits required by Item 601 of Regulation S-K:

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)
2.2
Order of the U.S. Bankruptcy Court for 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)
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 3.2)
3.3Bylaws of PG&E Corporation amended as of December 20, 2006
3.4Restated 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)
3.5
Bylaws of Pacific Gas and Electric Company amended as of December 20, 2006
4.1Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company.Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2Indenture 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).
4.3Supplemental 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)
4.4Consolidated Balance Sheets at December 31, 2003,
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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 for each(File No. 1-12609), Exhibit 4.2)
10.1Credit Agreement dated as of April 8, 2005, among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JP Morgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC, BNP Paribas and Deutsche Bank Securities Inc., as documentation agents and lenders, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and Union Bank of California, N.A., as senior managing agents, and KBC Bank, NV, Morgan Stanley Bank and William Street Commitment Corporation, as lenders (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company.Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.3)
10.2Consolidated StatementsFirst Amendment, dated as of Common Shareholders’ Equity forNovember 30, 2005, to 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 forCredit Agreement among Pacific Gas and Electric Company.
NotesCompany, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC and BNP Paribas as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and the following other lenders: Deutsche Bank AG New York Branch, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, UBS Loan Finance LLC, Union Bank of California, N.A., KBC Bank, N.V., Morgan Stanley Bank and William Street Commitment Corporation. (incorporated by reference 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 CompanyCompany's Form 10-K for the Years Endedyear ended December 31, 2003, 2002,2005 (File No. 1-12609 and 2001.

File No. 1-2348), Exhibit 10.2)
10.3     Schedules not included are omitted becauseCredit 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 absencefollowing 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 conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto.

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)
10.44.Exhibits requiredFirst Amendment, dated as of April 8, 2005, to bethe Credit Agreement dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent and a lender, 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, KBC Bank N.V., and The Bank of New York (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q 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

67


     
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)

68


     
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


May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
Exhibit10.5
NumberExhibit Description


*10.13Letter regarding Compensation ArrangementMaster Confirmation dated November 16, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Lyn E. MaddoxGoldman, Sachs & Co. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.5)
10.6Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated April 25, 1997as 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)
10.7Firm 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)
10.8Operating 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)
10.9Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
10.10Operating 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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)
*10.11PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 20002004) (File No. 1-12609), Exhibit 10.7)10.10)
*10.12*10.14Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)
*10.15DescriptionSupplemental Retirement Savings Plan effective as of Relocation Arrangement Between PG&E Corporation and Lyn E. MaddoxJanuary 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 20002004) (File No. 1-12609), Exhibit 10.9)10.11)
*10.13Letter regarding Compensation Arrangement between PG&E Corporation and Peter Darbee effective July 1, 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)
*10.1610.14Letter 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)
*10.15Retention Agreement between PG&E Corporation and Thomas B. King dated August 31, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.2)
*1010.16.17
Letter regarding Compensation Arrangement between Pacific Gas and Electric Company and William T. Morrow dated June 20, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.1)
*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)
*10.18PG&E Corporation Senior Executive Officer Retention Program approved December 20, 2000Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 20002005) (File No. 1-12609), Exhibit 10.10)10.18)
*10.19.110.18Letter regarding retention award to Robert D. Glynn, Jr.Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006
*10.19PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 22, 20011, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 20002004) (File No. 1-12609), Exhibit 10.10.1)10.17)
*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 Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
*10.2310.20Description 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)2007
*10.2410.21Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.23)
*10.2510.22Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of September 19, 2001December 31, 2004, and frozen as of January 1, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 20012004) (File No. 1-2248)1-2348), Exhibit 10.16)10.20)
*10.23*10.26.1Agreement and Release regarding annuitizationSupplemental Executive Retirement Plan of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002as amended effective as of January 1, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 20022005) (File No. 1-12609)1-2348), Exhibit 10.37.1)10.27)
*10.26.210.24Agreement 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)
*10.26.3Agreement 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’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 10.37.3)
*10.26.4Agreement 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’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 10.37.4)

71


Exhibit
NumberExhibit Description


*10.26.5Agreement 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’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 10.37.5)
*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)
*10.27.1Agreement 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’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609); Exhibit 10.2.1)
*10.27.2Agreement 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’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 10.2.2)
*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)
*10.27.4Agreement 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’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 10.2.4)
*10.27.510.25Agreement 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)
*10.2810.26Pacific 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)
*10.2910.27Postretirement 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)
*10.28*10.30
PG&E Corporation RetirementNon-Employee Director Stock Incentive Plan for Non-Employee Directors,(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 terminated January 1, 1998 (incorporatedPacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 19972004 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.13)10.27)
*10.29Resolution 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)
*1010.30.31
Resolution 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)
*10.31Resolution of the PG&E Corporation Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007
*10.32Resolution of the Pacific Gas and Electric Company Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007
*10.33PG&E Corporation 2006 Long-Term Incentive Plan, as amended on February 15, 2006 (with respect to change in control provisions) and December 20, 2006 (with respect to Section 7 governing nondiscretionary awards to non-employee directors)
*10.34PG&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)
*10.35Form 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)
*1010.36.32Form 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)
*10.37Form 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)
*10.38Form of Restricted Stock Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.1)
*10.39Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006)
*10.40Form 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)
*10.41Form of Performance Share Award Agreement for 2004 grants 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)
*10.42Form of Performance Share 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 99.2)
*10.43Form of Performance Share Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.2)
*10.44Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006)
*10.45
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)
*10.3310.46PG&E Corporation Officer Severance Policy,Executive Stock Ownership Program Guidelines as amended as of December 19, 2001February 15, 2006 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 20022005 (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.

10.46)
*10.47PursuantPG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2005 (incorporated by reference 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:

PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.37)
1.*10.48PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48)
*10.49October 3, 2003PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
*10.50PG&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 10.1)
*10.51Item 9.PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)
*10.52Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
*10.53Regulation FD Disclosure (furnished toResolution of the SEC)
Exhibit 1 —Board of Directors of Pacific Gas and Electric Company Income Statementregarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the monthyear ended AugustDecember 31, 2003 and Balance Sheet dated August 31, 20032004 (File No. 1-2348), Exhibit 10.41)
2.11Computation of Earnings Per Common Share
12.1October 15, 2003Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
13Item 5.The following portions of the 2006 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 Income,” “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 Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders' Equity,” “Notes to the 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,” and “Report of Independent Registered Public Accounting Firm.”
21Subsidiaries of the Registrant
23Other Events
District Court ruling regarding California BusinessConsent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1Resolutions of the Boards of Directors of PG&E Corporation and Professions CodePacific 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 17200 lawsuits302 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
   Item 9.Regulation FD Disclosure (furnished to the SEC)
Exhibit 1 — Revised Financial Projections Relating to the Settlement Plan
3.October 24, 2003Item 5.Other Events
A. Credit Rating Change
B. Department of Water Resources’ (DWR) 2001-2002 Revenue Requirement True-Up Proceeding
4.November 12, 2003Item 12.Results of Operations and Financial Condition (furnished to the SEC)
Release 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, 2003 and Balance Sheet dated October 31, 2003
7.December 9, 2003Item 5.Other Events
A. Additional Proposed Decisions Regarding Proposed Settlement Agreement
B. Credit Rating Agency Announcement

74

 *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.

41

8.December 12, 2003Item 5.Other Events
Proposed Decision Issued in the California Department 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 Plan 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 Recommended to be Modified by Pacific Gas and Electric Company and The Utility Reform Network
B. CPUC Approves Gas Accord II
Item 7.Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99 — 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
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 — Pacific Gas and Electric Company Income Statement for the month ended November 30, 2003 and Balance Sheet dated November 30, 2003
14.January 22, 2004Item 5.Other Events
Applications Filed for Rehearing of CPUC Decision Approving Chapter 11 Settlement Agreement
Item 7.Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99 — Notice to 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 (Pacific Gas and Electric Company) and Commission File Number 1-12609 (PG&E Corporation).

75





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, 20032006 to be signed on their behalf by the undersigned, thereunto duly authorized, in the City and County of San Francisco, on the 19th day of February, 2004.authorized.

 PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY
 
(Registrant)
HYUN PARK
(Registrant)
HYUN PARK
By:(Hyun Park, Attorney-in-Fact)By:(Hyun Park, Attorney-in-Fact)
Date:February 22, 2007Date:February 22, 2007
   (Registrant)
ByBy
GARY P. ENCINASGARY P. ENCINAS
(Gary P. Encinas, 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 Officers
  
    
SignatureTitleDate



*PETER A. Principal Executive Officers
*ROBERT D. GLYNN, JR.
DARBEEChairman of the Board, Chief Executive Officer and President (PG&E Corporation)February 19, 200422, 2007
     *GORDON R. SMITHPresident and Chief Executive Officer (Pacific Gas and Electric Company)February 19, 2004
B.  Principal Financial Officers
*PETER A. DARBEE
Senior Vice President and Chief Financial Officer (PG&E Corporation)February 19, 2004
     *KENT M. HARVEYSenior Vice President, Chief Financial Officer, and Treasurer (Pacific Gas and Electric Company)February 19, 2004
C.  Principal Accounting Officers
*CHRISTOPHER P. JOHNS
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    
 *LESLIE S. BILLER
*DAVID A. COULTER
*C. LEE COX
*WILLIAM S. DAVILA
*ROBERT D. GLYNN, JR.
*DAVID M. LAWRENCE, M.D.
*MARY S. METZ
*CARL E. REICHARDT
*GORDON R. SMITH
     (Director of PacificTHOMAS B. KING
Chief Executive Officer (Pacific Gas and
Electric Company only)
*BARRY LAWSON WILLIAMSCompany)
February 22, 2007
 




Directors of PGB.
Principal Financial Officer
*CHRISTOPHER P. JOHNSSenior Vice President, Chief Financial Officer and Treasurer (PG&E Corporation and Pacific Gas and Electric Company except as noted)February 22, 2007
C.
Principal Accounting Officer
 



February 19, 2004

*By GARY P. ENCINAS 

 
*G. ROBERT POWELLVice President and Controller (PG&E Corporation and Pacific Gas and Electric Company)February 22, 2007
D.
Directors
*DAVID R. ANDREWS
*LESLIE S. BILLER
*DAVID A. COULTER
*C. LEE COX
*PETER A. DARBEE
*MARYELLEN C. HERRINGER
*THOMAS B. KING
(Gary P. Encinas, Attorney-in-Fact)Director of Pacific Gas and Electric Company only)
*RICHARD A. MESERVE
*MARY S. METZ
*BARBARA L. RAMBO
*BARRY LAWSON WILLIAMS
Directors of PG&E Corporation and
Pacific Gas and Electric Company,
except as noted
February 22, 2007
*By
HYUN PARK
 

76

                                               (Hyun Park, Attorney-in-Fact)
42


To the Shareholders and the Boards of Directors and Shareholders 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, 20032006 and 2002,2005, and for each of the three years in the period ended December 31, 20032006, management’s assessment of the effectiveness of the Company’s and the Utility’s internal control over financial reporting as of December 31, 2006, and the effectiveness of the Company’s and the Utility’s internal control over financial reporting as of December 31, 2006, and have issued our reportreports thereon dated February 18, 2004 (which report expresses an unqualified opinion and includes explanatory paragraphs relating to accounting changes, a revision to the 2002 and 2001 financial statements of PG&E Corporation and going concern uncertainties). Such21, 2007; such consolidated financial statements of each of the Companiesand reports are included in the combined 2003your 2006 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, 200421, 2007

77


43



SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED BALANCE SHEETS
           
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 
   
   
 

78

(in millions)

  
Balance at December 31,
 
  
2006
 
2005
 
ASSETS
       
Cash and cash equivalents $386 $250 
Advances to affiliates  42  38 
Other current assets  3  3 
Total current assets  431  291 
Equipment  15  15 
Accumulated depreciation  (14) (14)
Net equipment  1  1 
Investments in subsidiaries  7,959  7,401 
Other investments  81  71 
Deferred income taxes  132  127 
Other  10  15 
Total Assets $8,614 $7,906 
LIABILITIES AND SHAREHOLDERS' EQUITY
       
Current Liabilities       
Accounts payable—related parties $41 $27 
Accounts payable—other  18  17 
Long-term debt, classified as current  280  - 
Income taxes payable  122  28 
Other  210  193 
Total current liabilities  671  265 
Noncurrent Liabilities:       
Long-term debt  -  280 
Other  133  143 
Total noncurrent liabilities  133  423 
Preferred stock     
Common Shareholders' Equity       
Common stock  5,877  5,827 
Common stock held by subsidiary  (718) (718)
Unearned compensation  -  (22)
Reinvested earnings  2,670  2,139 
Accumulated other comprehensive loss  (19) (8)
Total common shareholders' equity  7,810  7,218 
Total Liabilities and Shareholders' Equity $8,614 $7,906 


44

PG&E CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)

CONDENSED STATEMENTS OF OPERATIONSINCOME
For the Years Ended December 31, 2003, 2002 and 2001(in millions, except per share amounts)
             
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 
   
   
   
 


  
Year Ended December 31,
 
  
2006
 
2005
 
2004
 
Administrative service revenue $110 $97 $85 
Equity in earnings of subsidiaries  964  918  3,959 
Operating expenses  (115) (97) (110)
Interest income  15  9  15 
Interest expense  (30) (35) (132)
Other expense  (1) (17) (91)
Income before income taxes  943  875  3,726 
Income tax benefit  48  29  94 
Income from continuing operations  991  904  3,820 
Gain on disposal of NEGT    13  684 
Net income before intercompany eliminations $991 $917 $4,504 
 
Weighted average common shares outstanding
  346  372  398 
Earnings per common share, basic(1)
 $2.78 $2.40 $10.80 
Earnings per common share, diluted(1)
 $2.76 $2.37 $10.57 

CONDENSED STATEMENTS OF CASH FLOWS
For(in millions)
  
Year Ended December 31,
 
  
2006
 
2005
 
2004
 
Cash Flows from Operating Activities:          
Net income $991 $917 $4,504 
Gain on disposal of NEGT (net of income tax benefit of $13 million in 2005 and income tax
expense of $374 million in 2004) 
    (13) (684)
Net income from continuing operations  991  904  3,820 
Adjustments to reconcile net income to net cash provided by operating activities:          
Equity in earnings of subsidiaries
  (964) (918) (3,959)
Deferred taxes
  2  (23) 27 
NEGT settlement payment
      (30)
Other
  130  86  160 
Net cash provided by operating activities  159  49  18 
Cash Flows From Investing Activities:          
Capital expenditures
  (1) (1)  
Investment in subsidiaries
      (28)
Stock repurchase by subsidiary    1,910   
Dividends received from subsidiaries
  460  445   
Restricted cash
      361 
Other    (38)  
Net cash provided by investing activities  459  2,316  333 
Cash Flows From Financing Activities(2):
          
Common stock issued
  131  243  162 
Common stock repurchased
  (114) (2,188) (350)
Common stock dividends paid 
  (456) (334)  
Long-term debt redeemed
    (2) (652)
Other
  (43) (17) (1)
Net cash used by financing activities  (482) (2,298) (841)
Net change in cash and cash equivalents  136  67  (490)
Cash and cash equivalents at January 1  250  183  673 
Cash and cash equivalents at December 31  386  250  183 

45


(1)PG&E Corporation adopted the Years Endedconsensus 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 diluted earnings per share calculations for each of the years in the three year period ended December 31, 2003, 20022006 reflect the allocation of earnings between PG&E Corporation common stock and 2001the participating security.

(2)On January 16, April 15, July 15, and October 15, 2006, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share, totaling approximately $489 million. Of the total dividend payments made by PG&E Corporation in 2006, approximately $33 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.
              
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


On April 15, July 15 and October 17, 2005, PG&E Corporation paid a quarterly common stock dividend of $0.30 per share, totaling approximately $356 million. Of the total dividend payments made by PG&E Corporation in 2005, approximately $22 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. PG&E Corporation did not pay any dividends during 2004.


46



PG&E CORPORATION


SCHEDULE II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2003, 20022006, 2005 and 20012004
                       
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  $ 
   
   
   
��  
   
 



    
Additions
    
         
    
Charged
      
  
Balance
 
to
     
Balance
  
at
 
Costs
 
Charged
   
at
  
Beginning
 
and
 
to Other
   
End of
Description
 
of Period
 
Expenses
 
Accounts
 
Deductions (3)
 
Period
           
(in millions)          
Valuation and qualifying accounts deducted from assets:
                    
 2006:                    
  
Allowance for uncollectible accounts (1) (2)
 $77  $2  $-  $29  $50 
                      
                      
 2005:                    
  
Allowance for uncollectible accounts (1) (2)
 $93  $21  $-  $37  $77 
                      
                      
 2004:                    
  
Allowance for uncollectible accounts (1) (2)
 $68  $85  $-  $60  $93 
                      


(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




47




PACIFIC GAS AND ELECTRIC COMPANY A DEBTOR IN POSSESSION


SCHEDULE II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2003, 20022006, 2005 and 20012004
                       
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  $ 
   
   
   
   
   
 



    
Additions
    
         
    
Charged
      
  
Balance
 
to
     
Balance
  
at
 
Costs
 
Charged
   
at
  
Beginning
 
and
 
to Other
   
End of
Description
 
of Period
 
Expenses
 
Accounts
 
Deductions (2)
 
Period
           
(in millions)          
Valuation and qualifying accounts deducted from assets:
                    
 2006:                    
  
Allowance for uncollectible accounts (1)
 $77  $2  $-  $29  $50 
                      
                      
 2005:                    
  
Allowance for uncollectible accounts (1)
 $93  $21  $-  $37  $77 
                      
                      
 2004:                    
  
Allowance for uncollectible accounts (1)
 $68  $85  $-  $60  $93 
                      


(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.


48


EXHIBIT INDEX

Exhibit
Number
Exhibit Description
(3) 2.1Provision was deduction from “Regulatory Assets.”

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)


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 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)
Exhibit2.2
Order of the U.S. Bankruptcy Court for 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)
Number3.1Exhibit Description


*10.14Letter Regarding Relocation Arrangement BetweenRestated Articles of Incorporation of PG&E Corporation and Thomas B. King dated March 16, 2000effective 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)3.2)
3.3*10Bylaws of PG&E Corporation amended as of December 20, 2006
3.4.15Restated 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)
3.5
Bylaws of Pacific Gas and Electric Company amended as of December 20, 2006
4.1DescriptionIndenture, dated as of Relocation Arrangement BetweenApril 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Lyn E. MaddoxPacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2Indenture 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).
4.3Supplemental 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)
4.4
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 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 April 8, 2005, among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JP Morgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC, BNP Paribas and Deutsche Bank Securities Inc., as documentation agents and lenders, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and Union Bank of California, N.A., as senior managing agents, and KBC Bank, NV, Morgan Stanley Bank and William Street Commitment Corporation, as lenders (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.3)
10.2First Amendment, dated as of November 30, 2005, to the Credit Agreement among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC and BNP Paribas as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and the following other lenders: Deutsche Bank AG New York Branch, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, UBS Loan Finance LLC, Union Bank of California, N.A., KBC Bank, N.V., Morgan Stanley Bank and William Street Commitment Corporation. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.3Credit 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)
10.4First Amendment, dated as of April 8, 2005, to the Credit Agreement dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent and a lender, 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, KBC Bank N.V., and The Bank of New York (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.5Master Confirmation dated November 16, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.5)
10.6Settlement 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)
10.7Firm 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)
10.8Operating 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)
10.9Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
10.10Operating 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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)
*10.11PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 20002004) (File No. 1-12609), Exhibit 10.9)10.10)
*10.12PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.11)
*1010.13.16Letter regarding Compensation Arrangement between PG&E Corporation and Peter Darbee effective July 1, 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 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)
*10.15Retention Agreement between PG&E Corporation and Thomas B. King dated August 31, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.2)
*1010.16.17
Letter regarding Compensation Arrangement between Pacific Gas and Electric Company and William T. Morrow dated June 20, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.1)
*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)
*10.18PG&E Corporation Senior Executive Officer Retention Program approved December 20, 2000Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 20002005) (File No. 1-12609), Exhibit 10.10)]10.18)
*10.19.110.18Letter regarding retention award to Robert D. Glynn, Jr.Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006
*10.19PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 22, 20011, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 20002004) (File No. 1-12609), Exhibit 10.10.1)10.17)
*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 Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
*10.2310.20Description 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)2007
*10.2410.21Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.23)
*10.2510.22Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of September 19, 2001December 31, 2004, and frozen as of January 1, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 20012004) (File No. 1-2248)1-2348), Exhibit 10.16)10.20)
*10.23*10.26.1Agreement and Release regarding annuitizationSupplemental Executive Retirement Plan of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002as amended effective as of January 1, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 20022005) (File No. 1-12609)1-2348), Exhibit 10.37.1)10.27)
*10.26.210.24Agreement 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)
*10.26.3Agreement 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’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 10.37.3)
*10.26.4Agreement 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’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 10.37.4)
*10.26.5Agreement 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’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 10.37.5)
*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)
*10.27.1Agreement 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’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609); Exhibit 10.2.1)
*10.27.2Agreement 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’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 10.2.2)


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)
*10.27.4Agreement 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’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 10.2.4)
*10.27.510.25Agreement 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)
*10.2810.26Pacific 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)
*10.2910.27Postretirement 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)
*10.28*10.30
PG&E Corporation RetirementNon-Employee Director Stock Incentive Plan for Non-Employee Directors,(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 terminated January 1, 1998 (incorporatedPacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 19972004 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.13)10.27)
*10.29Resolution 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)
*1010.30.31
Resolution 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)
*10.31Resolution of the PG&E Corporation Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007
*10.32Resolution of the Pacific Gas and Electric Company Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007
*10.33PG&E Corporation 2006 Long-Term Incentive Plan, as amended on February 15, 2006 (with respect to change in control provisions) and December 20, 2006 (with respect to Section 7 governing nondiscretionary awards to non-employee directors)
*10.34PG&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)
*10.35*10.32PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609); Exhibit 10.2)
*10.33PG&E Corporation Officer Severance Policy, amended as of December 19, 2001 (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’s Form 10-Q for the quarter ended March 31, 1998 (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 (File No. 1-12609), Exhibit 10.2)
*10.36PG&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)
*10.3710.36Form 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)
*10.37Form 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)
*1010.38.38Form of Restricted Stock Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.1)
*10.39Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006)
*10.40Form 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)
*10.41Form of Performance Share Award Agreement grantedfor 2004 grants 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)
*10.42*10.39Form of Performance Share Agreement for 2005 grants under the PG&E National Energy Group, Inc. Management Retention/ Performance AwardCorporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation’sCorporation and Pacific Gas and Electric Company's Form 10-K/A Amendment8-K filed January 6, 2005 (File No. 212609 and File No. 1-2348), Exhibit 99.2)
*10.43Form of Performance Share Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.2)
*10.44Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006)
*10.45
PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (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 10.2)
*10.46PG&E Corporation Executive Stock Ownership Program Guidelines as amended February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 20022005 (File No. 1-12609);, Exhibit 10.47)10.46)
*10.47*10.39.1Letter regarding retention award to Thomas B. King dated September 9, 2002PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K/ A Amendment No. 210-K for the year ended December 31, 20022004 (File No. 1-12609);, Exhibit 10.47.1)10.37)


     
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


*10.48PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48)
*10.49PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
*10.50PG&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 10.1)
*10.51PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)
*10.52Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
*10.53Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
11Computation of Earnings Per Common Share
12.1Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
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 2006 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 Income,” “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 Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders' Equity,” “Notes to the 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,” and “Report of Independent Registered Public Accounting Firm.”
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
**32.1Certifications 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.

 *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.