SECURITIES AND EXCHANGE COMMISSION
FormFORM 10-K (Mark One)xþANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 20032006oroOro CommissionExact Name of Registrant State ofIRS EmployerFile Numberas specified in its charter IncorporationIRS Employer1-12609 PG&E CORPORATION California 94-3234914 1-2348 PACIFIC GAS AND ELECTRIC COMPANY California 94-0742640 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) CorporationCorporation: Common Stock, no par value Preferred Stock Purchase RightsNew York Stock Exchange and Pacific ExchangeCompany
Company: First Preferred Stock,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 Exchange7.90% Deferrable Interest Subordinated DebenturesAmerican Stock Exchange and Pacific ExchangePG&E Corporation Pacific Gas and Electric Company PG&E Corporation Pacific Gas and Electric Company Yes þ No oPG&E Corporation Pacific Gas and Electric Company 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 oPacific Gas and Electric Company þPG&E Corporation Pacific Gas and Electric Company
DOCUMENTS INCORPORATED BY REFERENCE(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 Yes Accelerated filer þ¨No Non-accelerated filer o¨Pacific Gas and Electric Company PG&E Corporation Pacific Gas and Electric Company No þx2003,2006, the last business day of the second fiscal quarter:PG&E Corporation Common Stock $ 8,16413,640 millionPacific Gas and Electric Company Common Stock Wholly owned by PG&E Corporation 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:418,976,121Pacific Gas and Electric Company:Wholly owned by PG&E Corporationinvolved.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 2007 Part IV (Item 15)III (Items 10, 11, 12, 13 and 14)Annual Meetings of Shareholders iiiiv Item 1. Business 1 General 1 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 11 12 12 12 12 12 12 13 13 14 14 14 15 15 15 15 15 16 16 16 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 Environment2222State Energy Regulation24Other Regulation25Ratemaking Mechanisms25Overview25DWR Electricity and DWR Revenue Requirements27DWR Allocated Contracts28Procurement Resumption and Procurement Plans28Electricity Transmission29Natural Gas31Environmental Matters32General32Air Quality33Water Quality34Endangered Species35Hazardous Waste Compliance and Remediation 3529 3731 3831 3931 Properties40i32 Page32
324032 Pacific Gas and Electric Company Chapter 11 Filing4133 43Pacific Gas and Electric Company vs. Michael Peevey, et al. 43In. re: Natural Gas Royalties Qui Tam Litigation44Diablo Canyon Power Plant44Complaints 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 52Item 9A.Controls and Procedures52PART IIIItem 10.Directors and Executive Officers of the Registrant52 Directors525442 Section 16 Beneficial Ownership Reporting Compliance5442 Audit Committee Members and Financial Expert54Website Availability of Corporate Governance and Other Documents54Item 11.Executive Compensation55Compensation of Directors55Summary Compensation Table56Option/SAR Grants in 200359Aggregated Option/SAR Exercises in 2003 and Year-End Option/SAR Values60Long Term Incentive Program-Awards in 200360Retirement Benefits61Termination of Employment and Change in Control Provisions6143 624343 Security Ownership of Management6244 Principal Shareholders6450 Equity Compensation Plan Information65Item 13.Certain Relationships and Related Transactions65Item 14.Principal Accountant Fees and Services6551 Fees Paid to Independent Public Accountants65Pre-Approval of Services Provided by the Independent Public Accountant66PART IVItem 15.Exhibits, 67Signatures76Independent Auditors’ Report77Financial Statement Schedules7852 iiUNITS OF MEASUREMENT1 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 iiian 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
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
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-
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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.
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.
2009. Forward-Looking Statements include, but are not limited to: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.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 a2$2.21 billion after-tax regulatory asset and allows for the recognition of an approximately $800 million after-tax regulatory asset related to generation assets. The Settlement Agreement and related decisions by the CPUC provide that the Utility’s revenue requirement will be collected regardless of sales levels and that the Utility’s rates will be adjusted in a timely manner to accommodate changes in costs that the Utility incurs. On January 20, 2004, several parties filed applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the Settlement Agreement. Although the CPUC is not required to act on these applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review. In addition, the two CPUC Commissioners who did not vote to approve the Settlement Agreement and a municipality have appealed the bankruptcy court’s confirmation order in the U.S. District Court for the Northern District of California, or the District Court. On January 5, 2004, the bankruptcy court denied a request to stay the implementation of the Plan of Reorganization until the appeals are resolved. The District Court will set a schedule for briefing and argument of the appeals at a later date. No additional parties may request rehearings or make appeals of the CPUC’s approval of the Settlement Agreement or the bankruptcy court’s confirmation order. Implementation of the Plan of Reorganization is subject to various conditions, including the consummation of the public offering of long-term debt, the receipt of investment grade credit ratings and final CPUC approval of the Settlement Agreement. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not subject to any pending appeal or further right of appeal, or approval on behalf of the CPUC that, although subject to a pending appeal or further right of appeal, has been agreed by the Utility and PG&E Corporation to constitute final approval. Thus, the terms of the Plan of Reorganization permit the Utility and PG&E Corporation to cause the Plan of Reorganization to become effective (and permit the Utility to issue the long term debt) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. Until certain conditions or events regarding the effectiveness of the Plan of Reorganization discussed above are resolved further, PG&E Corporation and the Utility cannot conclude that the applicable accounting probability standard needed to record the regulatory assets contemplated by the Settlement Agreement has been met. PG&E Corporation and the Utility believe that the Utility and the long-term debt to be issued will receive investment grade credit ratings. The Utility has targeted April 2004 to complete the sale of the long-term debt, which the Utility expects to be the last condition of the Plan of Reorganization to be satisfied. The Plan of Reorganization provides that the effective date will occur 11 business days after all the conditions have been satisfied or, with respect to all conditions except those relating to investment grade credit ratings, waived by PG&E Corporation and the Utility. There can be no assurance that the Settlement Agreement will not be overturned on rehearing or appeal or that the Plan of Reorganization will become effective.The Settlement Agreement and Plan of Reorganization are discussed further in the MD&A and in Note 2 of the Notes to the Consolidated Financial Statements in the Annual Report.Refinancing Supported by a Dedicated Rate Component Under the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized pre-tax balance of the $2.21 billion after-tax regulatory asset and related federal, state and franchise taxes, up to a total of $3.0 billion, as expeditiously as practicable after the effective date of the Plan of Reorganization using a securitized financing supported by a dedicated rate component, provided the following conditions are met:• Authorizing California legislation satisfactory to the CPUC, The Utility Reform Network, or TURN, and the Utility is passed and signed into law allowing securitization of the regulatory asset and associated federal and state income and franchise taxes and providing for the collection in the Utility’s rates of any portion of the associated tax amounts not securitized;• The CPUC determines that, on a net present value basis, the refinancing would save customers money over the term of the securitized debt compared to the regulatory asset;• The refinancing will not adversely affect the Utility’s issuer or debt credit ratings; and3• 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. and Risk Factorsportions 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· • 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; |
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| · | the potential impacts of climate change on the Utility’s electricity and natural gas operations; |
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| · | operating performance | |
| · | the ability of the Utility to |
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Legislative and Regulatory Environment and Pending Litigation
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Competition
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Electric Utility 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)
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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.
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||||
| 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 | ||||||||||||
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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:
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 of | Net Operating | |||||||||||
| Generation Type | County Location | Units | Capacity (MW) | |||||||||
| Nuclear: Diablo Canyon | San Luis Obispo | 2 | 2,174 | |||||||||
| Hydroelectric: Conventional | 16 counties in northern and central California | 107 | 2,684 | |||||||||
| Helms pumped storage | Fresno | 3 | 1,212 | |||||||||
| Hydro electric subtotal | 110 | 3,896 | ||||||||||
| Fossil fuel: | ||||||||||||
| Humboldt Bay(1) | Humboldt | 2 | 105 | |||||||||
| Hunters Point(2) | San Francisco | 2 | 215 | |||||||||
| Mobile turbines | Humboldt | 2 | 30 | |||||||||
| Fossil fuel subtotal | 6 | 350 | ||||||||||
| Total | 118 | 6,420 | ||||||||||
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.
| 2004 | 2005 | 2006 | 2007 | 2008 | |||||||||||||||||
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
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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.
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:
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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.
| · | |
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. |
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 “
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.
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.
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new information, future events or otherwise.
California law requires that, beginning in 2003, each California investor-owned electricmust 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.12 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.13 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%14Natural Gas Operating StatisticsThe 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: 2003 2002 2001 2000 1999 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 2003 2002 2001 2000 1999 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.15Natural 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. 2003 2002 2001 2000 1999 Avg. Avg. Avg. Avg. Avg. MMcf Price MMcf Price MMcf Price MMcf Price MMcf Price 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 FacilitiesThe 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.,16or 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 Expiration Quantity for the Year Ended Pipeline Date MDth per day December 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.17The 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.18 The Utility faces competition in the electricity distribution business as a result of the construction of duplicate distribution facilities to serve specific existing or new customers, condemnation of the Utility’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 to19deliver 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 EnvironmentFederal 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.State Energy Regulation
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| the capital requirements of the Utility, as determined to be necessary and prudent to meet the |
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among other changes:
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| · | 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 |
| · | require certain key officers to provide annual certifications of compliance with the affiliate rules; |
| · | 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 |
| · | 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 | |
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 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.
In response to the California energy crisis,Market Manipulation.
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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.
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 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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| · | 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.) |
Over the last several years, the Utility’s operations have been significantly affected by statutes passed by the California legislature, including:
One of
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
(For more information see “Environmental Matters - Water Quality” below.)
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.
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.
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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.
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.
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.
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.
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.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 DWR pays for its costs of purchasing electricity from a revenue requirement collected from The 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 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. 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. expire on October 31, 2008. Ten percent of any net insurance recoveries associated with hazardous waste remediation sites allowances. would seek to recover these costs through rates charged to customers. for many of these sites, the amount of potential liability for all of these sites cannot be quantified. 2006 Annual Report. 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 revenue requirements for estimated nuclear decommissioning costs 2006 Annual Report. 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 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 matters. 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. energy crisis. litigation.PG&E Corporation believes that the warrants were issued. There are no more warrants outstanding. 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. 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. reference. Directors of PG&E Corporation ” and “Compensation of Directors,” and “Potential Payments Upon Resignation, Retirement, Termination, Equity Compensation Plan Information 2007 Annual Meetings of Shareholders, which information is hereby incorporated by reference.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.· 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· · · 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.· · · 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.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 power27charge. 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 ContractsDWR 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 procure28energy 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 TransmissionThe 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 UnderFERC’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.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.Utility’sUtility's transmission revenue from base transmission rates.· 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). 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 CostsThe 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. establish its ownthe Consolidated Financial Statements in the 2006 Annual Report.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 2004.30Natural GasThe Gas Accordunder 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.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 ProceedingThe Utility’sovercollection,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 UnderUtility’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).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 to31— typically(typically in Canada and the southwestern United States —States) to the points at which the Utility's natural gas transportation system begins.Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities) 40% DWR 24% Qualifying Facilities/Renewables 20% Irrigation Districts 6% Other Power Purchases 10% Nuclear: Diablo Canyon San Luis Obispo 2 2,240 Hydroelectric: Conventional 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) Refueling April - January October Duration (days) 28 - 74 28 Startup May - April November Refueling - February October - April Duration (days) - 76 28 - 28 Startup - April November - May Agricultural and Other Customers 5 % Industrial Customers 18 % Residential Customers 37 % Commercial Customers 40 % 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) (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. (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. Residential Customers 27 % Transport-only Customers (noncore) 61 % Commercial Customers 12 % 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 (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 2006 2005 2004 2003 2002 Avg. Price Avg. Price Avg. Price Avg. Price 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 begins.at Daggett, California.Capacity Purchases on El Paso and Transwestern Pipelines In July 2002,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. 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 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.(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. owner’sowner's responsibility, and the availability of recoveries or contributions from third parties.GeneralUtility’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.32clean 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.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.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.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 QualityUtility’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.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.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.33 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.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.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 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.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, atthisthe 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.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 generation34would 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.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,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 interimimpactaffect 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 SpeciesUtility’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 RemediationUtility’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.35Utility’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 remediatingcleanupclean-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 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.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.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.36$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.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.Nuclear Fuel Disposal 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.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.37 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. facility is dismantled. Utility are unable to predict the outcome of this appeal or the amount of any additional awards the Utility may receive.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 DecommissioningThe 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.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 for38Humboldt 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 taxesThe 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. 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.39 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.report’sreport's conclusions contrast with otherServices’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 actionswill 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.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.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.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.2005.2012.Item 3.Legal Proceedings.40Utility’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.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 the44Canyon’sCanyon's NPDES permit. However, atCentral 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.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.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, 2004.45General’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.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 1146estate 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.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.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.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.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.Item 4.Submission of Matters to a Vote of Security Holdersexecutive“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: NameAgePositionR. 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. Harvey 48 Senior Vice President and Chief FinancialRisk and Audit OfficerC. P. JohnsRussell M. Jackson 4349 Senior Vice President, and ControllerHuman ResourcesD. D. Richard, Jr. Christopher P. Johns 5346 Senior Vice President, Public Affairs; Senior Vice President, Public Affairs, Pacific GasChief Financial Officer and Electric CompanyTreasurerG. R. SmithThomas B. King 5545 Senior Vice President; President and Chief Executive Officer, Pacific Gas and Electric CompanyG. B. StanleyHyun Park 57Senior Vice President, Human ResourcesB. R. Worthington5445 Senior Vice President and General Counsel Rand L. Rosenberg 53 Senior Vice President, Corporate Strategy and Development 48 NamePositionPeriod Held OfficeR. 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 presentP. A. DarbeePresident and Chief Executive Officer January 1, 2005 to December 31, 2005 Senior Vice President and Chief Financial Officer JulySeptember 20, 1999 to December 31, 2004Leslie H. Everett Senior Vice President, Communications and Public Affairs January 9, 2006 to present Senior Vice President and Assistant to the Chief Executive Officer January 1, 2005 to January 8, 2006 Senior Vice President and Assistant to the Chairman August 2, 2004 to December 31, 2004 Vice President and Assistant to the Chairman June 1, 2001 to August 1, 2004 Kent M. Harvey Senior Vice President and Chief Risk and Audit Officer October 1, 2005 to present Senior Vice President, Chief Financial Officer and Treasurer, Pacific Gas and Electric Company November 1, 2000 to September 20, 199930, 2005Russell M. Jackson Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric Company August 2, 2004 to July 8, 2001present Vice President, Human Resources, PG&E Corporation June 1, 2004 to August 1, 2004 Vice President, Human Resources, Pacific Gas and Electric Company June 1, 1999 to August 1, 2004 Christopher P. Johns Senior Vice President, Chief Financial Officer Advance Fibre Communications, Inc.and Treasurer June 30, 1997October 4, 2005 to September 19, 1999presentC. P. JohnsSenior Vice President, Chief Financial Officer and Treasurer, Pacific Gas and Electric Company October 1, 2005 to present Senior Vice President, Chief Financial Officer and Controller January 1, 2005 to October 3, 2005 Senior Vice President and Controller September 19, 2001 to presentVice President and ControllerJuly 1, 1997 to September 18, 2001Vice President and Controller, Pacific Gas and Electric CompanyJune 1, 1996 to December 31, 19992004D. D. Richard, Jr. Senior Vice President, Public AffairsOctober 18, 2000 to presentVice President, Governmental RelationsJuly 1, 1997 to October 17, 2000Senior Vice President, Public Affairs, Pacific Gas and Electric CompanyMay 1, 1998 to presentSenior Vice President, Governmental and Regulatory Relations, Pacific Gas and Electric CompanyJuly 1, 1997 to April 30, 1998G. B. StanleySenior Vice President, Human ResourcesJanuary 1, 1998 to presentSenior Vice President, National Energy & Gas Transmission, Inc.July 1, 2000 to July 7, 2003Vice President, Human ResourcesJune 1, 1997 to December 31, 1997B. R. WorthingtonSenior Vice President and General CounselJune 1, 1997 to presentVice President, National Energy & Gas Transmission, Inc.January 20, 1999 to July 1, 200049“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:NameAgePositionG. R. Smith55President and Chief Executive OfficerK. M. Harvey45Senior Vice President — Chief Financial Officer, and TreasurerT. B. King42Senior Vice President and Chief of Utility OperationsR. J. Peters53Senior Vice President and General CounselD. D. Richard, Jr. 53Senior Vice President, Public AffairsG. M. Rueger53Senior Vice President, Generation and Chief Nuclear OfficerAll 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 OfficeG. R. SmithPresident and Chief Executive OfficerJune 1, 1997 to presentThomas B. King Senior Vice President, PG&E Corporation January 1, 1999 to presentK. 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, 19992005T. B. KingExecutive Vice President and Chief of Utility Operations, Pacific Gas and Electric Company August 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*2002R. J. PetersHyun Park Senior Vice President and General Counsel January 1, 1999November 13, 2006 to present50Vice 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 OfficeD. D. Richard, Jr. Rand L. Rosenberg Senior Vice President, Corporate Strategy and Development November 1, 2005 to present Executive Vice President and Chief Financial Officer, Infospace, Inc. September 2000 to January 20, 2001 Peter A. Darbee 54 Chairman of the Board Thomas B. King 45 Chief Executive Officer William. T. Morrow 47 President and Chief Operating Officer Thomas E. Bottorff 53 Senior Vice President, Regulatory Relations Jeffrey D. Butler 51 Senior Vice President, Energy Delivery Leslie H. Everett 56 Senior Vice President, Communications and Public Affairs, (Please refer to description of business experience for executive officers of PG&E Corporation above.)Russell M. Jackson 49 Senior Vice President, Human Resources Christopher P. Johns 46 Senior Vice President, Chief Financial Officer and Treasurer John S. Keenan 58 Senior Vice President, Generation and Chief Nuclear Officer Hyun Park 45 Senior Vice President and General Counsel, PG&E Corporation Stewart M. Ramsay 48 Vice President, Asset Management and Electric Transmission Fong Wan 45 Vice President, Energy Procurement Peter A. Darbee Chairman of the Board, Pacific Gas and Electric Company January 1, 2006 to present Chairman of the Board, Chief Executive Officer and President, PG&E Corporation January 1, 2006 to present President and Chief Executive Officer, PG&E Corporation January 1, 2005 to December 31, 2005 Senior Vice President and Chief Financial Officer, PG&E Corporation July 9, 2001 to December 31, 2004 Thomas B. King Chief Executive Officer August 15, 2006 to present President and Chief Executive Officer January 1, 2006 to August 14, 2006 Senior Vice President, PG&E Corporation January 1, 2006 to present Executive Vice President and Chief Operating Officer July 1, 2005 to December 31, 2005 Executive Vice President and Chief of Utility Operations August 2, 2004 to June 30, 2005 Senior Vice President and Chief of Utility Operations November 1, 2003 to August 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 William T. Morrow President and Chief Operating Officer August 15, 2006 to present Chief Executive Officer, Europe, Vodafone Group PLC (a global mobile telecommunications company) May 1, 19982006 to July 31, 2006President, Vodafone KK, Japan April 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. Bottorff Senior Vice President, Regulatory Relations October 14, 2005 to present G.Senior Vice President, Customer Service and Revenue March 1, 2004 to October 13, 2005 Vice President, Customer Service June 1, 1999 to February 29, 2004 Jeffrey D. Butler Senior Vice President, Energy Delivery January 9, 2006 to present Senior Vice President, Transmission and Distribution March 1, 2004 to January 8, 2006 Vice President, Operations, Maintenance and Construction June 12, 2000 to February 29, 2004 Leslie H. Everett Senior Vice President, Communications and Public Affairs, PG&E Corporation January 9, 2006 to present Senior Vice President and Assistant to the Chief Executive Officer, PG&E Corporation January 1, 2005 to January 8, 2006 Senior Vice President and Assistant to the Chairman, PG&E Corporation August 2, 2004 to December 31, 2004 Vice President and Assistant to the Chairman, PG&E Corporation June 1, 2001 to August 1, 2004 Russell M. RuegerJacksonSenior Vice President, Human Resources, Pacific Gas and Electric Company and PG&E Corporation August 2, 2004 to present Vice President, Human Resources, PG&E Corporation June 1, 2004 to August 1, 2004 Vice President, Human Resources June 1, 1999 to August 1, 2004 Christopher P. Johns Senior Vice President, Chief Financial Officer and Treasurer October 1, 2005 to present Senior Vice President, Chief Financial Officer and Treasurer, PG&E Corporation October 4, 2005 to present Senior Vice President, Chief Financial Officer and Controller, PG&E Corporation January 1, 2005 to October 3, 2005 Senior Vice President and Controller, PG&E Corporation September 19, 2001 to December 31, 2004 John S. Keenan Senior Vice President, Generation and Chief Nuclear Officer April 2, 2000December 19, 2005 to presentVice President, Fossil Generation, Progress Energy November 10, 2003 to December 18, 2005 Vice President, Brunswick Nuclear Plant, Progress Energy May 1, 1998 to November 9, 2003 Hyun Park Senior 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. Ramsay Vice President, Asset Management and Electric Transmission January 9, 2006 to present Vice President, Electric Transmission July 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 Wan Vice President, Energy Procurement January 9, 2006 to present Vice President, Power Contracts and Electric Resource Development May 1, 2004 to January 8, 2006 Vice President, Risk Initiatives, PG&E Corporation Support Services, Inc. November 1, 19912000 to April 1, 200030, 2004Item 5.Market for the Registrant’s Common Equity and Related Shareholder Matters. Information responding to partPacific 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,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.2003, the period covered by this report.quarter ended December 31, 2006.Item 6.Selected Financial Data. 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 - $ - - $ 500,000,000 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.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 Analysis5120032006 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.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.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 “ConsolidatedCommon 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.Item 9A.Controls and ProceduresCorporation’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.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 IIIItem 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 directorsincluding 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 director52of 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. 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 &53Company (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.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.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 NationalUtility 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.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. 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. 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.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) SmartMeter4. 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. 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.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 corporate54companies’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.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.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.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.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.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 a55director’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 $20,000 limit).Summary Compensation TableThis table summarizes the principal components of compensation paid to the Chief Executive Officers and the other most highly compensated executive officers of PG&E Corporation and Pacific Gas and Electric Company, is included underUtility during the past year. Annual Compensation Long-Term Compensation Awards Payouts Other Annual Restricted Securities All Other Compen- Stock Underlying LTIP Compen- Salary Bonus sation Award(s) Options/SARs Payouts sation Name and Principal Position Year ($) ($)(1) ($)(2) ($)(3) (# of Shares) ($)(4) ($)(5) Robert D. Glynn, Jr. 2003 $ 1,050,000 $ 0 $ 3,154,268 $ 2,169,950 486,000 $ 9,879,911 $ 666,050 Chairman of the Board, Chief 2002 1,050,000 787,500 4,833,389 0 150,000 632,461 79,777 Executive Officer, and 2001 900,000 1,181,700 4,817 3,000,000 470,800 74,588 413,196 President of PG&E Corporation; Chairman of the Board of Pacific Gas and Electric Company Peter A. Darbee 2003 $ 490,000 $ 0 $ 2,368 $ 678,269 101,300 $ 4,023,098 $ 329,140 Senior Vice President and 2002 490,000 220,500 4,862 0 0 115,244 62,355 Chief Financial Officer 2001 455,000 328,578 4,817 1,125,000 183,800 26,105 613,596 of PG&E Corporation Bruce R. Worthington 2003 $ 425,000 $ 0 $ 836,295 $ 530,708 79,300 $ 2,310,713 $ 306,575 Senior Vice President and 2002 425,000 175,313 1,220,913 0 0 205,801 43,893 General Counsel of PG&E 2001 400,000 288,860 4,817 625,000 145,000 24,617 171,353 Corporation G. Brent Stanley 2003 $ 305,000 $ 0 $ 2,368 $ 353,927 52,900 $ 2,141,176 $ 204,782 Senior Vice President — 2002 305,000 114,375 4,862 0 0 84,311 18,010 Human Resources of PG&E 2001 285,000 187,103 4,817 625,000 102,800 15,385 110,691 Corporation P. Chrisman Iribe 2003 $ 450,000 $ 0 $ 0 $ 471,903 70,400 $ 3,017,831 $ 151,934 Senior Vice President of 2002 450,000 93,163 0 0 0 94,863 75,620 PG&E Corporation; Executive 2001 425,000 306,914 0 1,125,000 186,400 25,355 57,846 Vice President of National Energy & Gas Transmission, Inc. Gordon R. Smith 2003 $ 735,000 $ 0 $ 2,402,048 $ 943,441 140,900 $ 5,842,500 $ 453,723 Senior Vice President of 2002 735,000 519,278 4,310,520 0 0 182,009 37,173 PG&E Corporation; President 2001 630,000 664,808 937 1,750,000 272,000 40,282 241,302 and Chief Executive Officer of Pacific Gas and Electric Company Thomas B. King 2003 $ 500,000 $ 0 $ 23,780 $ 530,708 79,300 $ 2,938,351 $ 659,488 Senior Vice President and 2002 450,000 93,163 0 0 0 94,863 89,263 Chief of Utility Operations 2001 425,000 306,914 0 1,125,000 186,400 41,020 1,090,207 of Pacific Gas and Electric Company (November 1, 2003) Senior Vice President of PG&E Corporation (January 1, 1999 - October 31, 2003) 56 Annual Compensation Long-Term Compensation Awards Payouts Other Annual Restricted Securities All Other Compen- Stock Underlying LTIP Compen- Salary Bonus sation Award(s) Options/SARs Payouts sation Name and Principal Position Year ($) ($)(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 2001,57respectively, 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 $216,667).58Option/SAR Grants in 2003This table summarizes the distributionheadings“Compensation Discussion and the terms and conditions of stock options granted to the executive officers named in the SummaryAnalysis,”“Compensation Committee Report,” “Summary Compensation Table, during the past year. Grant Individual Grants Date Value Number of % of Total Securities Options/SARs Underlying Granted to Exercise or Grant Date Options/SARs Employees in Base Price Expiration Present Name Granted (#)(1)(2) 2003(2) ($/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 $5.68 per share.59Aggregated Option/SAR Exercises in 2003 and Year-End Option/SAR ValuesThis table summarizes exercises” “Grants of stock options and tandem stock appreciation rights (granted in prior years) by the executive officers named in the Summary Compensation Table during the past year, as well as the number and value of all unexercised options held by such named executive officers at the end of 2003. Value of Number of Securities Unexercised Underlying Unexercised In-the-Money Options/SARs at Options/SARs at Shares Acquired End of 2003 (#) End of 2003 ($)(1) on Exercise Value 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 2003This 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.AwardsPerformance orOther PeriodNumber of Shares,Until MaturationNameUnits, or Other Rightsor PayoutGregory M. Rueger2,601(1)3 yearsKent M. Harvey3,915(1)3 yearsRoger J. Peters631(1)3 yearsJames 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.60Benefits 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. 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.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”61will 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 ManagementThe 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. Percent Common Beneficial Stock of Stock Name Ownership(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 62 Percent Common Beneficial Stock of Stock Name Ownership(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.63(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 ShareholdersThe 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 Beneficial Percent Class of Stock Name and Address of Beneficial Owner Ownership of 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 investment64power with respect to 12,386,522 of these shares, and shared investment power with respect to 31,486 of these shares.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 to Weighted Average Future Issuance Under be Issued Upon Exercise Exercise Price of Equity Compensation Plans of Outstanding Options, Outstanding Options, (Excluding Securities Plan Category Warrants and Rights Warrants and Rights Reflected 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. 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 ) 14. Principal Accountant Fees and ServicesFees 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, tax65strategy 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.661.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 2001,2.1 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) 2.2 3.1 Restated 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) 3.2 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 December 20, 2006 3.4 Restated 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 4.1 Indenture, 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)4.2 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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1) 4.4 Consolidated Balance Sheets at December 31, 2003,for each(File No. 1-12609), Exhibit 4.2) 10.1 Credit 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)10.2 Consolidated 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) 10.4 4.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 Number Exhibit 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 Number Exhibit 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 Number Exhibit 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) 69May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2) Exhibit10.5NumberExhibit 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)10.6 Settlement 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)10.7 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 (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) 10.8 Operating 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) 10.9 Transmission 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) 10.10 Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (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) *10.11 PG&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)*10.13 Letter 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) * 10.1610.14 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.3)*10.15 Retention 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*10.17 Letter 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)* 10.19.110.18 Letter regarding retention award to Robert D. Glynn, Jr.Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006*10.19 PG&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)70ExhibitNumberExhibit 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)*10.2310.20 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.35)2007* 10.2410.21 Description 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) * 10.2510.22 Supplemental 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)* 10.26.210.24 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2)* 10.26.3Agreement 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)71ExhibitNumberExhibit 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)*10.27.510.25 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609);, Exhibit 10.2.5)* 10.2810.26 Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)* 10.2910.27 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)*10.28 *10.30RetirementNon-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)*10.29 Resolution 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*10.31 Resolution of the PG&E Corporation Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007 *10.32 Resolution of the Pacific Gas and Electric Company Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007 *10.33 PG&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) *10.34 PG&E Corporation Long-Term Incentive Program as amended May 16, 2001, including(including the PG&E Corporation Stock Option Plan and Performance Unit Plan, and Non-Employee Director Stock Incentive PlanPlan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)*10.35 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) * 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)*10.37 Form 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) *10.38 Form 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) *10.39 Form 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) *10.40 Form 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) *10.41 Form 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) *10.42 Form 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) *10.43 Form 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) *10.44 Form 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 Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609) Exhibit 10.2)* 10.3310.46 PG&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 Number Exhibit 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 Number Exhibit 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) *10.49 October 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)*10.50 PG&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) *10.51 Item 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)*10.52 Resolution 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) *10.53 Regulation 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 12.1 October 15, 2003Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company 13 Item 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.”21 Subsidiaries of the Registrant 23 Other EventsDistrict Court ruling regarding California BusinessConsent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)24.1 Resolutions of the Boards of Directors of PG&E Corporation and Professions CodePacific Gas and Electric Company authorizing the execution of the Form 10-K24.2 Powers of Attorney 31.1 Certifications 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 200231.2 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 Item 9.Regulation FD Disclosure (furnished to the SEC)Exhibit 1 — Revised Financial Projections Relating to the Settlement Plan3.October 24, 2003Item 5.Other EventsA. Credit Rating ChangeB. Department of Water Resources’ (DWR) 2001-2002 Revenue Requirement True-Up Proceeding4.November 12, 2003Item 12.Results of Operations and Financial Condition (furnished to the SEC)Release of Third Quarter Earnings Results5.November 20, 2003Item 5.Other EventsA. Proposed Decisions Regarding Proposed Settlement AgreementB. Conclusion of Confirmation Trial Testimony in Utility’s Chapter 11 ProceedingC. Ninth Circuit Preemption Decision6.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, 20037.December 9, 2003Item 5.Other EventsA. Additional Proposed Decisions Regarding Proposed Settlement AgreementB. Credit Rating Agency Announcement748.December 12, 2003Item 5.Other EventsProposed Decision Issued in the California Department of Water Resources” (DWR) 2001-2002 Revenue Requirement True-Up Proceeding and the DWR 2004 Revenue Requirement Proceeding9.December 15, 2003Item 5.Other EventsBankruptcy Court Decision Approving Proposed Chapter 11 Settlement Agreement and Plan of Reorganization10.December 16, 2003Item 5.Other EventsComments Regarding Proposed Settlement Agreement Filed by the Utility and TURN11.December 22, 2003Item 5.Other EventsA. California Public Utilities Commission Approves Proposed Settlement Agreement as Recommended to be Modified by Pacific Gas and Electric Company and The Utility Reform NetworkB. CPUC Approves Gas Accord IIItem 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 appendices12.December 23, 2003Item 5.Other EventsBankruptcy Court Confirms Utility’s Plan of Reorganization13.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, 200314.January 22, 2004Item 5.Other EventsApplications Filed for Rehearing of CPUC Decision Approving Chapter 11 Settlement AgreementItem 7.Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99 — Notice to Directors and Executive Officers, dated January 22, 2004Item 11.Temporary Suspension of Trading Under Registrant’s Employee Benefits Plan15.February 3, 2004Item 5.Other EventsImplementation of Chapter 11 Settlement Rate Reduction16.February 19, 2004Item 5.Other EventsItem 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 LLCItem 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).7520032006 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 By: (Hyun Park, Attorney-in-Fact) By: (Hyun Park, Attorney-in-Fact) Date: February 22, 2007 Date: February 22, 2007 (Registrant)ByByGARY P. ENCINASGARY P. ENCINAS(Gary P. Encinas, Attorney-in-Fact)(Gary P. Encinas, Attorney-in-Fact) SignatureTitleDate*PETER A. Principal Executive Officers*ROBERT D. GLYNN, JR.DARBEE Chairman 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, 2004B. Principal Financial Officers*PETER A. DARBEESenior 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, 2004C. Principal Accounting Officers*CHRISTOPHER P. JOHNSSenior Vice President and Controller (PG&E Corporation)February 19, 2004 *DINYAR B. MISTRYVice President-Controller (Pacific Gas and Electric Company)February 19, 2004D. 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. KINGChief Executive Officer (Pacific Gas and
Electric Company only)*BARRY LAWSON WILLIAMSCompany)February 22, 2007 Directors of PGB.*CHRISTOPHER P. JOHNS Senior Vice President, Chief Financial Officer and Treasurer (PG&E Corporation and Pacific Gas and Electric Company except as noted)February 22, 2007 February 19, 2004*By GARY P. ENCINAS *G. ROBERT POWELL Vice President and Controller (PG&E Corporation and Pacific Gas and Electric Company) February 22, 2007 Gary P. Encinas, Attorney-in-Fact)Director of Pacific Gas and Electric Company only)February 22, 2007 *By 76 the Shareholders and the Boards of Directors and Shareholders of 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.18, 200421, 200777 Balance at December 31, 2003 2002 (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 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 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 OPERATIONSINCOMEFor the Years Ended December 31, 2003, 2002 and 2001(in millions, except per share amounts) 2003 2002 2001 (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 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 $ 4,504 346 372 398 $ 2.78 $ 2.40 $ 10.80 $ 2.76 $ 2.37 $ 10.57 For(in millions) Cash Flows from Operating Activities: Net income $ 991 $ 917 $ 4,504 — (13 ) (684 ) Net income from continuing operations 991 904 3,820 Adjustments to reconcile net income to net cash provided by operating activities: (964 ) (918 ) (3,959 ) 2 (23 ) 27 — — (30 ) 130 86 160 Net cash provided by operating activities 159 49 18 Cash Flows From Investing Activities: (1 ) (1 ) — — — (28 ) Stock repurchase by subsidiary — 1,910 — 460 445 — — — 361 Other — (38 ) — Net cash provided by investing activities 459 2,316 333 131 243 162 (114 ) (2,188 ) (350 ) (456 ) (334 ) — — (2 ) (652 ) (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 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, 2004.2003, 20022006 reflect the allocation of earnings between PG&E Corporation common stock and 2001the participating security. 2003 2002 2001 (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 792003, 20022006, 2005 and 20012004 Additions Balance at Charged to Charged Balance at Beginning Costs and to Other End of Description of Period Expenses Accounts Deductions Period (in millions) Valuation and qualifying accounts deducted from assets: 2003: $ 59 $ 42 $ — $ 33 (3) $ 68 2002: $ 48 $ 34 $ (2 ) $ 23 (3) $ 59 2001: $ 52 $ 24 $ — $ 28 (3) $ 48 $ 6,939 $ — $ — $ 6,939 $ — �� (in millions) 2006: $ 77 $ 2 $ - $ 29 $ 50 2005: $ 93 $ 21 $ - $ 37 $ 77 2004: $ 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 A DEBTOR IN POSSESSION2003, 20022006, 2005 and 20012004 Additions Balance at Charged to Charged Balance at Beginning Costs and to Other End of Description of Period Expenses Accounts Deductions Period (in millions) Valuation and qualifying accounts deducted from assets: 2003: $ 59 $ 42 $ — $ 33 (2) $ 68 2002: $ 48 $ 34 $ (2 ) $ 23 (2) $ 59 2001: $ 52 $ 24 $ — $ 28 (2) $ 48 $ 6,939 $ — $ — $ 6,939 $ — (in millions) 2006: $ 77 $ 2 $ - $ 29 $ 50 2005: $ 93 $ 21 $ - $ 37 $ 77 2004: $ 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. (3) 2.1Provision was deduction from “Regulatory Assets.”81EXHIBIT INDEX Exhibit Number Exhibit 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 Number Exhibit 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) Exhibit2.2Number3.1Exhibit 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)3.2 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 10)3.2)3.3 *10Bylaws of PG&E Corporation amended as of December 20, 20063.4 .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 4.1 DescriptionIndenture, 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)4.2 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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1) 4.4 10.1 Credit 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) 10.2 First 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) 10.3 Credit 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) 10.4 First 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) 10.5 Master 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) 10.6 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) 10.7 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 (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) 10.8 Operating 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) 10.9 Transmission 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) 10.10 Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (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) *10.11 PG&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)*10.12 PG&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)*10.14 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609);, Exhibit 10.3)*10.15 Retention 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*10.17 Letter 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)* 10.19.110.18 Letter regarding retention award to Robert D. Glynn, Jr.Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006*10.19 PG&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)ExhibitNumberExhibit 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)*10.2310.20 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.35)2007* 10.2410.21 Description 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) * 10.2510.22 Supplemental 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)* 10.26.210.24 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2)* 10.26.3Agreement 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)ExhibitNumberExhibit 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)*10.27.510.25 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609);, Exhibit 10.2.5)* 10.2810.26 Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)* 10.2910.27 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)*10.28 *10.30RetirementNon-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)*10.29 Resolution 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*10.31 Resolution of the PG&E Corporation Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007 *10.32 Resolution of the Pacific Gas and Electric Company Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007 *10.33 PG&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) *10.34 PG&E Corporation Long-Term Incentive Program as amended May 16, 2001, including(including the PG&E Corporation Stock Option Plan and Performance Unit Plan, and Non-Employee Director Stock Incentive PlanPlan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation’sCorporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)*10.35 *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)* 10.3710.36 Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37) *10.37 Form 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)*10.39 Form 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) *10.40 Form 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) *10.41 Form 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)*10.43 Form 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) *10.44 Form 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 *10.46 PG&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 Number Exhibit 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 *10.48 PG&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) *10.49 PG&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) *10.50 PG&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) *10.51 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) *10.52 Resolution 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) *10.53 Resolution 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) 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 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.” 21 Subsidiaries of the Registrant 23 Consent of Independent Registered Public Accounting Firm (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 * 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.