Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K: Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, The Utility served approximately are discussed below in Item 1A. Risk Factors. These factors include, but are not limited to: classes. 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 2007. 2008. its QF purchase obligations under this case-by-case approach. 2006 or later. goals. maintained. 2005. system during 2005. Transwestern Pipeline Co., or Transwestern, and El Paso Natural Gas Company, or El Paso, to transport this natural gas from supply points in this region to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona. 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 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. rates. 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 customers any costs of implementing the program not reasonably attributable to a community choice aggregator. The Utility’s natural gas pipelines are located within the State of California and are exempt from FERC rules and regulations applicable to interstate pipelines. core customers buy natural gas, as well as transportation and distribution services, from the Utility as a bundled service. The Gas Accord market structure has been extended by the CPUC through 2007. affiliate transaction rules. the Utility does not currently anticipate. For discussion of specific regulatory proceedings affecting the Utility, see the section of MD &A entitled “Regulatory Matters” in the 2005 Annual Report. price cap. judicial proceedings. The Utility has entered into The NRC The California Energy Resources Conservation and Development Commission Utility may be unable to earn its authorized rate of return. operations through 2007 has been previously set in the Gas Accord at 11.22% for the return on equity and 8.77% for the overall rate of return. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricity customers of the three California investor-owned electric utilities through what is known as a power charge. The Utility's customers also must pay what is known as a bond charge to pay a share of the DWR's revenue requirements to recover costs associated with the DWR'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'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's revenues. MD&A entitled “Regulatory Matters—Electricity Generation Resources—Long-Term Generation Resource Commitments.” assigned operational control of their electricity transmission systems to the ISO. The Utility is required to give the ISO two The For further discussion of other RMR-related issues, see the section of Note 17: Commitments and Contingencies— Reliability Must Run Agreements, of the Notes to the Consolidated Financial Statements in the 2005 Annual Report. storage rates. On December 16, 2004, the CPUC approved a multi-party settlement agreement to retain the Gas Accord market structure, and resolve the rates, and terms and conditions of service for the Utility's natural gas transportation and storage system for the three-year period of revenue and core storage costs. Interstate and Canadian Natural Gas Transportation and Storage Utilities Board and the National Energy Board. The Utility's agreements with interstate and Canadian natural The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility's personnel and the public. These laws and requirements relate to a broad range of activities, including: Ten percent of any net insurance recoveries associated with hazardous waste remediation sites are assigned to the Utility's customers. The balance of any insurance recoveries, (90%) are retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. technology available for minimizing adverse environmental impacts at its existing water-cooled thermal plants. The Utility has submitted detailed studies of each steam-electric generation facility's intake structure to various governmental agencies and each power plant's existing intake structure was found to meet the best technology available requirements. For a further discussion of this matter, see “Item 3. Legal Proceedings,” below. monitoring wells located approximately 65 feet from the Colorado River. The Utility is cooperating with the California Department of Toxic Substances Control, or DTSC, other state agencies, appropriate federal agencies and other interested parties, to implement interim measures as well as develop a long-term plan to ensure that the hexavalent chromium does not The Utility does not expect that it will incur any material expenditures related to any remediation at its Kettleman natural gas compressor station. records the costs at the lower end of this range. It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the Utility'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. The Utility's undiscounted future costs could increase to as much as this appeal. be completed by 2008. January 2006. allow early decommissioning of Humboldt Bay Unit 3. The Utility anticipates that begin in 2009. 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. 2004. The into the fair value calculation. authorized to collect approximately $18.4 million in rates for decommissioning Humboldt Bay Unit 3. October 2006. authorities members before April 2013. On this date, the effective date, the Utility emerged from Chapter 11. On the effective date, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon their resolution, reinstated certain obligations, and paid other obligations. on February 13, 2006. It is uncertain when a decision will be issued. PG&E Corporation and the Utility believe the former commissioners' appeal of the confirmation order is without merit and will be rejected. complaint. violated various conditions established by the CPUC in decisions approving the holding company formation. The California Attorney General alleged that the defendants violated these conditions when PG&E Corporation allegedly failed to provide adequate financial support to the Utility during the California energy crisis. In August 2002, the California Attorney General filed its amended complaint in the Superior Court. The Superior Court has coordinated the California Attorney General’s case with the case filed by CCSF. In July 27, 2005, the California Court of Appeal summarily denied a petition filed by the California Attorney General and CCSF seeking to overturn this decision. precluded. These claims were not discharged when the Utility’s plan of reorganization became effective. settlement agreement: The Utility has recorded a $314 million reserve in exemption from the registration requirements of the Securities Act of 1933 provided by Section 4(2) of the Act. quarter ended December 31, 2005. The Committee used the same methodology to establish the performance scale for the Corporation and Pacific Gas and Electric Company. 2003. 2003. Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, Form 10-K ýx20042005
Or
o1-12609 PG&E CORPORATION California 94-3234914 1-2348 PACIFIC GAS AND ELECTRIC COMPANY California 94-0742640 Pacific Gas and Electric Company77 Beale StreetP.O. Box 770000
PG&E Corporation
(Zip Code)94177(Zip Code)
(415) 973-7000267-7000PG&E CorporationOne Market, Spear TowerSuite 2400
Pacific Gas and Electric Company
(Zip Code)94105(Zip Code)
(415) 267-7000973-7000CorporationCorporation:
Common Stock, no par valueNew York Stock Exchange and Pacific Exchange CompanyCompany:
First Preferred Stock,American Stock Exchange and Pacific Exchange 7.04%, 5% Series A, 5%, 4.80%, 4.50%, 4.36%Mandatorily Redeemable: 6.57%, 6.30% PG&E Corporation Pacific Gas and Electric Company PG&E Corporation Pacific Gas and Electric Company PG&E Corporation Pacific Gas and Electric Company ý No oPG&E Corporation Pacific Gas and Electric Company PG&E Corporationo Pacific Gas and Electric Companyý(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 YesAccelerated filer ý¨ NooNon-accelerated filer ¨Pacific Gas and Electric Company YesAccelerated filer o¨ NoýNon-accelerated filer xPG&E Corporation Pacific Gas and Electric Company 2004,2005, the last business day of the second fiscal quarter:PG&E Corporation Common Stock $ 11,18313,975 millionPacific Gas and Electric Company Common Stock Wholly owned by PG&E Corporation 11, 2005:10, 2006: PG&E Corporation: 396,487,454345,319,971 (excluding shares held by a wholly owned subsidiary)Pacific Gas and Electric Company: Wholly owned by PG&E Corporation involved.involved:Designated portions of the combined 2005 Annual Report to Shareholders for the year ended December 31, 2004Part I (Item 1)1, Item 1.A.), Part II (Items 5, 6, 7, 7A, 8 and 9A), Part IV (Item 15)Designated portions of the Joint Proxy Statement relating to the 20052006 Part III (Items 10, 11, 12, 13 and 14) Annual Meetings of Shareholders Page iii 1 Corporate Structure and Business1 1 NEGT21 Corporate and Other Information21 Employees21 Forward-Looking Statements and Risk Factors3 Appeals of the Utility's Plan of Reorganization and Settlement Agreement3 Operating Environment3 Legislative and Regulatory Environment and Pending Litigation4 Competition4Electric Utility Operations5 5 7 Owned Generation Facilities78 9 Third Party Power Purchase Agreements109 Other Power Purchase Agreements911 Electricity Transmission1112 Natural Gas Utility Operations1312 15Natural Gas Supplies16Gas Gathering Facilities16Interstate and Canadian Natural Gas Transportation Services Agreements 12 13 13 14 15 15 16 Competition1617 18 The Natural Gas Industry1918 PG&E Corporation's Regulatory Environment1818 20 20 21The Utility's Regulatory Environment22Federal Energy Regulation23State Energy Regulation25Other Regulation26Ratemaking Mechanisms27Overview27DWR Electricity and DWR Revenue Requirements 2820 21 22 24 25 25 25 26 27 27 29 Electricity Transmission3031 31 Natural Gas32Environmental Matters34General34Air Quality35Water Quality35Endangered Species37 iHazardous Waste Compliance and Remediationi37 Nuclear Fuel Disposal393232 32 33 41Electric and Magnetic Fields42Item 2.Properties43Item 3.Legal Proceedings43Pacific Gas and Electric Company Chapter 11 Filing 4333 4533 4633 4633 483637 4938 Executive Officers of the Registrants4952395439544054405440544040 40 5440 Item 9B40 Other Information5541 Nomination for Election as Directors55Amendment of Bylaws55Approval of Performance Scale under 2005 Short Term Incentive Plan56PART III5643Website Availability of Corporate Governance and Other Documents5643Item 11.Executive Compensation5743 5744 Equity Compensation Plan Information57Item 13.Certain Relationships and Related Transactions57Item 14.Principal Accountant Fees and Services58PART IV5845 Signatures6550 6651 67521 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 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, procurement 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. During 2004, PG&E Corporation also owned National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., which engaged in electricity generation and natural gas transportation in the United States, or U.S.The Utility4.95 million electricity distribution customers and approximately 4.14.2 million natural gas distribution customers at December 31, 2004.2005. The Utility had approximately $34.3$33.8 billion of assets at December 31, 2004,2005, and generated revenues of approximately $11.1$11.7 billion in 2004.2005. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC. On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California. In March 2004, in anticipation of its exit from Chapter 11, the Utility issued $6.7 billion of first mortgage bonds, or First Mortgage Bonds, and, together with its consolidated subsidiaries, entered into $2.9 billion of credit facilities. On April 12, 2004, the Utility's plan of reorganization under Chapter 11 became effective. On this date, the effective date, the Utility emerged from Chapter 11. On the effective date, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon their resolution, reinstated certain obligations, and paid other obligations. The Utility's plan of reorganization incorporated the terms of the settlement agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's Chapter 11 proceeding, or Settlement Agreement. The parties agreed that the bankruptcy court has jurisdiction over the parties for all purposes relating to enforcement of the Settlement Agreement over its nine-year term, the plan of reorganization, and the bankruptcy court's December 22, 2003 order confirming the plan of reorganization, or confirmation order. Although the Utility's operations are no longer subject to the oversight of the bankruptcy court, the bankruptcy court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the plan of reorganization, and (3) the confirmation order. In addition, the bankruptcy court retains jurisdiction to resolve remaining disputed claims. As discussed further below under Item 3. Legal Proceedings, appeals of the confirmation order and petitions seeking review of the CPUC's approval of the Settlement Agreement remain pending. Under applicable federal precedent, once the plan of reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed. If, notwithstanding this federal precedent, the bankruptcy court's confirmation order or the Settlement Agreement issubsequently overturned or modified, PG&E Corporation and the Utility's financial condition and results of operations could be materially adversely affected. The Utility's plan of reorganization and the Settlement Agreement are discussed in Management's Discussion and Analysis of Financial Condition and Results of Operations, or the MD&A, and in Note 2 of the Notes to the Consolidated Financial Statements in PG&E Corporation's and the Utility's Combined 2004 Annual Report to Shareholders, or the Annual Report, which is incorporated by reference into this report. NEGT was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. On July 8, 2003, NEGT and certain of its subsidiaries filed voluntary petitions for relief under the provisions of Chapter 11 in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. For the reasons described in Note 5, PG&E Corporation considers NEGT to be an abandoned asset under Statement of Financial Accounting Standards, or SFAS, "Accounting for Impairment or Disposal of Long-Lived Assets," or SFAS No. 144, and, as a result, the operations of NEGT prior to July 8, 2003 and for all prior periods, are reflected as discontinued operations in the Consolidated Financial Statements. In addition, as discussed in Note 4, effective July 8, 2003, PG&E Corporation no longer consolidated the earnings and losses of NEGT or its subsidiaries and began accounting for its ownership interest in NEGT using the cost method, under which PG&E Corporation's investment in NEGT is reflected as a single amount on the Condensed Consolidated Balance Sheet of PG&E Corporation. On October 29, 2004, NEGT's plan of reorganization became effective and NEGT emerged from Chapter 11, at which time PG&E Corporation's equity interest in NEGT was cancelled. For a discussion of the effect of the cancellation of PG&E Corporation's equity ownership in NEGT on PG&E Corporation's earnings from discontinued operations for the quarter and year ended December 31, 2004, see MD&A.www.pge-corp.comwww.pgecorp.com, and the Utility'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.2004,2005, PG&E Corporation and its subsidiaries had approximately 20,20019,800 employees, including approximately 20,00019,500 employees of the Utility. Of the Utility's employees, approximately 13,70012,800 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO, or IBEW; the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC, or ESC; and the Service Employees International Union, Local 24/7, or SEIU. The ESC and IBEW collective bargaining agreements expire on December 31, 2007.2008. The SEIU collective bargaining agreement expires on February 28, 2008.2009.portions of the Annual Reportinformation incorporated by reference, contains forward-looking statements that are necessarily subject to various risks and uncertainties, the realization or resolution of which are outside of management's control. These statements are based on current expectations and projections about future events, and assumptions regarding these events and management's knowledge of facts at the time the statements were made.date of this report. These forward-looking statements are identified by words such as "assume," "expect," "intend," "plan," "project," "believe," "estimate," "predict," "anticipate," "aim, " "may," "might," "will," "should," "would," "could," "goal," "potential" and similar expressions. AlthoughPG&E Corporation’s and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, timely recover its authorized costs, and earn its authorized rate of return. 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:· How the Utility manages its responsibility to procure electric capacity and energy for its customers; · The adequacy and price of natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the natural gas market for its customers; · Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards that affect demand for electricity or natural gas, result in power outages, reduce generating output, disrupt natural gas supply, cause damage to the Utility's assets or generating facilities, cause damage to the operations or assets of third parties on which the Utility relies, or subject the Utility to third party claims for damage or injury; · Unanticipated population growth or decline, general economic and financial market conditions, changes in technology including the development of alternative energy sources, all of which may affect customer demand for natural gas or electricity; · Whether the Utility is required to cease operations temporarily or permanently at its Diablo Canyon nuclear power plant because the Utility is unable to increase its on-site spent nuclear fuel storage capacity, find another depositary for spent fuel, or timely complete the replacement of the steam generators, or because of mechanical breakdown, lack of nuclear fuel, environmental constraints, or for some other reason and the risk that the Utility may be required to purchase electricity from more expensive sources; and · Whether the Utility is able to recognize the anticipated cost benefits and savings expected to result from its efforts to improve customer service through implementation of specific initiatives to streamline business processes and deploy new technology. Appeals of the Utility's Plan of ReorganizationLegislative Actions and Settlement AgreementRegulatory Proceedings· The outcome of the regulatory proceedings pending at the CPUC and the FERC and the impact of future ratemaking actions by the CPUC and the FERC; · The impact of the recently enacted Energy Policy Act of 2005 which, among other provisions, repeals the Public Utility Holding Company Act of 1935 making electric utility industry consolidation more likely; expands the FERC’s authority to review proposed mergers; changes the FERC regulatory scheme applicable to qualifying co-generation facilities, or QFs; authorizes the formation of an Electric Reliability Organization to be overseen by the FERC to establish electric reliability standards; and modifies certain other aspects of energy regulation and federal tax policies applicable to the Utility; · The extent to which the CPUC or the FERC delays or denies recovery of the Utility's costs, including electricity or gas purchase costs, from customers due to a regulatory determination that such costs were not reasonable or prudent, or for other reasons, resulting in write-offs of regulatory assets; · How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the CPUC's past decisions permitting the establishment of holding companies for the California investor-owned electric utilities and the outcome of the CPUC's new rulemaking proceeding concerning the relationship between the California investor-owned energy utilities and their holding companies and non-regulated affiliates, which may include (1) establishing reporting requirements for the allocation of capital between utilities and their non-regulated affiliates by the parent holding companies, and (2) changing the CPUC's affiliate transaction rules; · Whether the Utility is determined to be in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, including tariffs related to the Utility’s billing and collection practices, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses, such as has been recommended with respect to the CPUC’s investigation into the Utility’s billing and collection practices; and · Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities, including the Utility’s natural gas compressor stations, to comply with existing and future environmental laws, regulations and policies. •· The outcome of pending litigation; and · The timing and resolution of the pending appeal of the bankruptcy court order confirming the Utility's plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code. resolution of the petitions for review that were filed in the California Court of Appeal for the first Appellate District, or the California Court of Appeal, seeking review of the CPUC's approval of the Settlement Agreement; andBypass· Continuing efforts by local public utilities to take over the Utility's distribution assets through exercise of their condemnation power or by duplication of the Utility's distribution assets or service, and other forms of municipalization that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and · The extent to which the Utility's distribution customers are permitted to switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers, and the extent to which cities, counties and others in the Utility's service territory begin directly serving the electricity needs of the Utility's customers, potentially resulting in stranded generating asset costs and non-recoverable procurement costs. •The timing and resolution of the pending appeals of the confirmation order.•Unanticipated changes in operating expenses or capital expenditures, which may affect the Utility's ability to earn its authorized rate of return;•The level and volatility of wholesale electricity and natural gas prices and supplies, the Utility's ability to manage and respond to the levels and volatility successfullyextentUtility do not undertake an obligation to which the Utility is ableupdate forward-looking statements, whether in response to timely recover increased costs related to such volatility;•Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns and othernew information, future events or hazards that affect demand, result in power outages, reduce generating output, or cause damage to the Utility's assets or operations or those of third parties on which the Utility relies;•Unanticipated population growth or decline, changes in market demand and demographic patterns, and general economic and financial market conditions, including unanticipated changes in interest or inflation rates, and the extent to which the Utility is able to timely recover its costs in the face of such events;•The operation of the Utility's Diablo Canyon nuclear power plant, or Diablo Canyon, which exposes the Utility to potentially significant environmental costs and capital expenditure outlays and, to the extent the Utility is unable to increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close Diablo Canyon and purchase electricity from more expensive sources;•Actions of credit rating agencies;•Significant changes in the Utility's relationship with its employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur; and•Acts of terrorism.Legislative and Regulatory Environment and Pending Litigation•The impact of current and future ratemaking actions of the CPUC, including the risk of material differences between forecasted costs used to determine rates and actual costs incurred;•Whether the assumptions and forecasts underlying the Utility's CPUC-approved long-term electricity procurement plan prove to be accurate, the terms and conditions of the generation or procurement commitments the Utility enters into in connection with its plan, and the extent to which the Utility is able to recover the costs it incurs in connection with these commitments, and the extent to which a failure to perform by any of the counterparties to the Utility's electricity purchase contracts or the DWR contracts allocated to the Utility's customers affects the Utility's ability to meet its obligations or to recover its costs;•Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, the U.S. Congress, the CPUC, the FERC, and the Nuclear Regulatory Commission, or the NRC, with regard to the Utility's allowed rates of return, industry and rate structure, recovery of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities;•The extent to which the CPUC or the FERC delays or denies recovery of the Utility's costs, including electricity purchase costs, from customers due to a regulatory determination that such costs were not reasonable or prudent or for other reasons resulting in write-offs of regulatory balancing accounts;•How the CPUC administers the capital structure, stand-alone dividend and first priority conditions of the CPUC's decisions permitting the establishment of holding companies for the California investor-owned electric utilities;•The terms under which the CPUC authorizes the Utility to issue debt and equity in the future, and in particular the extent to which the conditions adopted by the CPUC, such as those contained in the CPUC's general financing authorization decision issued on October 28, 2004 (under which the Utility is authorized to issue debt and preferred stock in the future within certain amounts and for specific purposes) limit the Utility's ability to issue debt in the future;•Whether the Utility is in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses;•Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws, regulations and policies; and•The outcome of pending litigation.•Increased competition as a result of the takeover by condemnation of the Utility's distribution assets, duplication of the Utility's distribution assets or service by local public utilities, and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and•The extent to which the Utility's distribution customers switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers, the extent to which cities, counties and others in the Utility's service territory begin directly serving the Utility's customers, and the extent to which the Utility's customers become self-generators, results in stranded generating asset costs and non-recoverable procurement costs. For a further discussion of the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation's and the Utility's future results of operations and financial condition, see the section of the Annual Report titled "Risk Factors."4647 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of 123,054128,128 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 89 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. There are 610611 distribution substations and 118 low voltagelow-voltage distribution substations. There are 290 combined transmission and distribution substations. Combined transmission and distribution substations have both transmission and distribution transformers.1,118671 points. This interconnection between the Utility's distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility's customers. The distribution substations serve as the central hubs of the Utility's electricity distribution network and consist of transformers, voltage regulation equipment, protective devices and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as municipal and other utilities, that then resell the electricity.20042005 electricity deliveries represented by each of its major customer classes:20042005 Electricity Delivered: 82,907 GWhs81,626 GWhAgricultural and Other Customers 8%6%Industrial Customers 18%18%Residential Customers 35%36%Commercial Customers 39%40%20002001 to 20042005 for electricity sold or delivered, including the classification of sales and revenues by type of service. 2004 2003 2002 2001 2000 Customers (average for the year): Residential 4,366,897 4,286,085 4,171,365 4,165,073 4,071,794 Commercial 509,501 493,638 483,946 484,430 471,080 Industrial 1,339 1,372 1,249 1,368 1,300 Agricultural 80,276 81,378 78,738 81,375 78,439 Public street and highway lighting 27,176 26,650 24,119 23,913 23,339 Other electric utilities 3 4 5 5 8 Total 4,985,192 4,889,127 4,759,422 4,756,164 4,645,960 Deliveries (in GWh):(1) Residential 29,453 29,024 27,435 26,840 28,753 Commercial 32,268 31,889 31,328 30,780 31,761 Industrial 14,796 14,653 14,729 16,001 16,899 Agricultural 4,300 3,909 4,000 4,093 3,818 Public street and highway lighting 2,091 605 674 418 426 Other electric utilities 28 76 64 241 266 Subtotal 82,936 80,156 78,230 78,373 81,923 DWR (19,938 ) (23,554 ) (21,031 ) (28,640 ) — Total non-DWR electricity 62,998 56,602 57,199 49,733 81,923 Revenues (in millions): Residential $ 3,718 $ 3,671 $ 3,646 $ 3,396 $ 3,062 Commercial 4,179 4,440 4,588 4,105 3,110 Industrial 1,204 1,410 1,449 1,554 1,053 Agricultural 491 522 520 525 420 Public street and highway lighting 71 69 73 60 43 Other electric utilities 22 24 10 39 26 Subtotal 9,685 10,136 10,286 9,679 7,714 DWR (1,933 ) (2,243 ) (2,056 ) (2,173 ) — Direct access credits — (277 ) (285 ) (461 ) (1,055 ) Miscellaneous(2) (248 ) (52 ) 193 244 202 Regulatory balancing accounts 363 18 40 37 (7 ) Total electricity operating revenues $ 7,867 $ 7,582 $ 8,178 $ 7,326 $ 6,854 Other Data: Average annual residential usage (kWh) 6,744 6,772 6,577 6,444 7,062 Average billed revenues (cents per KWh): Residential 12.62 12.65 13.29 12.65 10.65 Commercial 12.95 13.92 14.65 13.34 9.79 Industrial 8.14 9.62 9.84 9.71 6.23 Agricultural 11.41 13.35 13.00 12.83 11.00 Net plant investment per customer $ 2,790 $ 2,689 $ 2,105 $ 2,018 $ 1,969 Customers (average for the year): Residential 4,353,458 4,366,897 4,286,085 4,171,365 4,165,073 Commercial 509,786 509,501 493,638 483,946 484,430 Industrial 1,271 1,339 1,372 1,249 1,368 Agricultural 78,876 80,276 81,378 78,738 81,375 Public street and highway lighting 28,021 27,176 26,650 24,119 23,913 Other electric utilities 4 3 4 5 5 Total (1) 4,971,362 4,985,192 4,889,127 4,759,422 4,756,164 Deliveries (in GWh):(2) Residential 29,752 29,453 29,024 27,435 26,840 Commercial 32,375 32,268 31,889 31,328 30,780 Industrial 14,932 14,796 14,653 14,729 16,001 Agricultural 3,742 4,300 3,909 4,000 4,093 Public street and highway lighting 792 2,091 605 674 418 Other electric utilities 33 28 76 64 241 Subtotal 81,626 82,936 80,156 78,230 78,373 California Department of Water Resources (DWR) (20,476) (19,938) (23,554) (21,031) (28,640) Total non-DWR electricity 61,150 62,998 56,602 57,199 49,733 Revenues (in millions): Residential $3,856 $3,718 $3,671 $3,646 $3,396 Commercial 4,114 4,179 4,440 4,588 4,105 Industrial 1,232 1,204 1,410 1,449 1,554 Agricultural 446 491 522 520 525 Public street and highway lighting 66 71 69 73 60 Other electric utilities 4 22 24 10 39 Subtotal 9,718 9,685 10,136 10,286 9,679 DWR (1,699) (1,933) (2,243) (2,056) (2,173) Direct access credits — — (277) (285) (461) Miscellaneous(3) 235 (248) (52) 193 244 Regulatory balancing accounts (327) 363 18 40 37 Total electricity operating revenues $7,927 $7,867 $7,582 $8,178 $7,326 Other Data: Average annual residential usage (kWh) 6,834 6,744 6,772 6,577 6,444 Average billed revenues (cents per kWh): Residential 12.96 12.62 12.65 13.29 12.65 Commercial 12.71 12.95 13.92 14.65 13.34 Industrial 8.25 8.14 9.62 9.84 9.71 Agricultural 11.92 11.41 13.35 13.00 12.83 Net plant investment per customer $2,966 $2,790 $2,689 $2,105 $2,018 (2)20042005 represented by each major electricity resource:Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities) 33%40%DWR 25%27%Qualifying Facilities/Renewables 23%22%Irrigation Districts 5%5%Other Power Purchases 14%6%2004,2005, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:Generation Type County Location Number of
Units Net Operating
Capacity (MW)Nuclear: Diablo Canyon San Luis Obispo 2 2,174 Hydroelectric: Conventional 16 counties in northern
and central California 107 2,684 Helms pumped storage Fresno 3 1,212 Hydro electric subtotal 110 3,896 Fossil fuel: Humboldt Bay(1) Humboldt 2 105 Hunters Point(2) San Francisco 2 215 Mobile turbines Humboldt 2 30 Fossil fuel subtotal 6 350 Total 118 6,420 Nuclear: Diablo Canyon San Luis Obispo 2 2,174 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 Hunters Point(2) San Francisco 2 215 Mobile turbines Humboldt 2 30 Fossil fuel subtotal 6 350 Total 118 6,420 or Humboldt Bay Unit 3, and two operating fossil fuel-fired plants.or ISO, to support system reliability. The agreement expresses the Utility's intention to retire the plant when it is no longer needed. The Utility expects to retire the plant in 2006 after the completion of a new 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line, that will provide additional transmission system reliability in San Francisco and northern San Mateo County. Construction of this project is expected to be completed in April 2006.ten-year10-year period ended December 31, 2004,2005, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 88.4%89.1%.4647 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the replacement of the steam generators in Unit 2 in 2008 and in Unit 1 in 2009. The capital expenditures necessary to complete these projects are discussed further in the section of PG&E Corporation’s and the Utility’s combined 2005 Annual Report to Shareholders, or 2005 Annual Report, entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” or MD&A. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of up to 45 days to accommodate non-routine tasks, such as expanded steam generator inspection and repair and low-pressure turbine rotor replacement. Outages of up to 80 days are scheduled for steam generator replacements. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors. 2005 2006 2007 2008 2009 Unit 1 Refueling October — April — January Duration (days) 45 — 35 — 80 Startup December June March Unit 2 Refueling April February October Duration (days) — 45 — 80 25 Startup — June — April October Refueling - April - January October Duration (days) - 35 - 80 35 Startup - June - April November Refueling April - February October - Duration (days) 45 - 80 35 - Startup June - April November - incident.incident for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $42.5$43.6 million per one-year policy term.Under the Terrorism Risk Insurance Act of 2002,There is no policy coverage limitation for an act caused by foreign terrorism because NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act causedreimbursement by foreign terrorism.the federal government under the Terrorism Risk Insurance Extension Act of 2005. The Terrorism Risk Insurance Extension Act of 20022005 expires on December 31, 2005.$100.6 $100.6 million per reactor, with payments in each year limited to a maximum of $10$15 million per incident until the Utility has fully paid its share of the liability. Since the Diablo Canyon power plant has two nuclear reactors each with a rated capacity of over 100 MW, the Utility may be assessed up to $201.2 million per incident, with payments in each year limited to a maximum of $20$30 million per incident. AlthoughThe Energy Policy Act of 2005 extended the Price-Anderson Act expired onthrough December 31, 2003, coverage continues to2025. Both the maximum assessment per reactor and the maximum yearly assessment will be provided to all licensees, including the Diablo Canyon power plant, which had coverage before Decemberadjusted for inflation beginning August 31, 2003. Congress may address renewal of the Price Anderson Act in future energy legislation.the retired nuclear generating unit at the Humboldt Bay power plantUnit 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.8687 permits or licenses and 163160 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 four years, the Utility has received six renewed hydroelectric project licenses from the FERC totaling 699 MW. Licenses associated with approximately 879917 MW now in relicensing have expired; these projects are being operated on automatically renewed annual licenses pending issuance of renewed licenses. Within the next fourthree years 2006 through 2008, licenses associated with another 5012 MW will expire. Licenses associated with approximately 2,9592,960 MW will expire between 2009 and 2043. In January 2001, because ofdeteriorating credit conditions of2000-2001 energy crisis the California investor-owned electric utilities lost their creditworthiness and were unable to purchase electricity in the wholesale market for their customers. As a result, in January 2001, 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, which was 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 to the Utility's customers. In January 2003, the Utility became responsible for scheduling and dispatching the electricity subject to the 19 DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. The contracts terminate at various times through 2012 and consist of must-take and capacity charge contracts. During 2004, a total average capacity of approximately 2,700 MW of the electricity under the DWR allocated contracts is subject to "must take" provisions that require the DWR to take and pay for the electricity regardless of whether the electricity is needed. A total average capacity for 2004 of approximately 1,200 MW of the electricity under the DWR allocated contracts is subject to provisions that require the DWR to pay a capacity charge, but do not require the purchase of electricity unless that electricity is dispatched and delivered. Electricity from the DWR allocated contracts represented approximately 22% of the Utility's total sources of electricity in 2004.intendsintended 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 approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code, or 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 Service, or Moody's, will be no less than A2 and the Utility's long-term issuer credit rating by Standard & Poor's, or S&P, will be no less than A;· After assumption, the Utility's issuer rating by Moody's Investors Service, or Moody's, will be no less than A2 and the Utility's long-term issuer credit rating by Standard & Poor's, or S&P, will be no less than A; •· The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and · The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review. •The 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.qualifying facility'sQF's actual electrical output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility'sQF's total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the qualifying facilityQF fails to meet or exceeds performance requirements specified in the applicable power purchase agreement.2004,2005, the Utility had agreements with 300 qualifying facilities280 QFs for approximately 4,300 megawatts, or4,200 MW that are in operation. Agreements for approximately 3,9503,900 MW expire at various dates between 20052006 and 2028. Qualifying facilityQF power purchase agreements for approximately 350300 MW have no specific expiration dates and will terminate only when the owner of the qualifying facilityQF exercises its termination option. The Utility also has power purchase agreements with approximately 5060 inoperative qualifying facilities.QFs. The total of approximately 4,3004,200 MW consists of approximately 2,600 MW from cogeneration projects, 700600 MW from wind projects and 1,000 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar and hydroelectric.qualifying facilitiesQFs with certain power purchase agreements expiring before the end of 2005 to extend these contracts for five years with modified pricing terms. As of December 31, 2004, thirteen qualifying facilities2005, 21 QFs had entered into such five-year contract extensions. Qualifying facilityextensions, 13 QFs entered in extensions in 2004 and 8 QFs entered into extensions in 2005. QF power purchase agreements accounted for approximately 21%22% of the Utility’s 2005 electricity sources, approximately 23% of the Utility's 2004 electricity sources and approximately 20% of the Utility's 2003 electricity sources, and approximately 25% of the Utility's 2002electricity sources. No single qualifying facilityQF accounted for more than 5% of the Utility's 2005, 2004 2003, or 20022003 electricity sources.qualifying facilitiesQFs and the number of qualifying facilitiesQFs holding power purchase agreements with the Utility. The CPUC will address whether certain payments for short-term power deliveries required by the power purchase agreements comply with the pricing requirements of the PURPA. The CPUC is also considering whether to require the California investor ownedinvestor-owned electric utilities to enter into new power purchase agreements with existing qualifying facilitiesQFs with expiring power purchase agreements and with newly-constructed qualifying facilities. PG&E CorporationQFs. For a further discussion of QF matters, see the section of Note 17: Commitments and Contingencies— Power Purchase Agreements—Qualifying Facility Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2005 Annual Report. are unableintends to estimate the outcomeapply for a service territory-wide waiver of these proceedings.ifof whether or not any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2005 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 4%5% of 2004the Utility’s 2005 electricity sources, approximately 5% of 2003the Utility's 2004 electricity sources and approximately 4%5% of 2002the Utility's 2003 electricity sources.Residual Net Open Position2004,2005, the Utility continued buying electricity to meet its residual net open position.position, which is the portion of the demand of a utility's customers, plus applicable reserve margins, not satisfied from that utility's own generation facilities and existing electricity contracts. During 2004,2005, more than 10,000 Gigawatt hours, or9,000 GWh of energy was bought andor sold in the wholesale market to manage the Utility's 2004 residualUtility’s 2005 net short/open position. Most of the Utility's contractsContracts entered into in 20042005 had both terms of less than one year.year, and multi-year terms. In 2004,2005, the Utility both submitted and requested bids in competitive solicitations to meet intermediate and long-term needs and anticipates procuring electricity under contracts with multi-year terms beginning in 2005. that, beginning in 2003, each California retail seller of electricity, except for municipal utilities, mustto increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, the annual procurement target, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. The Utility was excused from meeting its annual procurement target under the current law in 2003 and 2004 due to its Chapter 11 proceeding. With its exit from Chapter 11, as of January 1, 2005, the Utility is no longer exempt from complying with its annual procurement target. To meet the 20% goal by the end of 2017, the Utility estimates that it will need to purchase 700-800 GWh of electricity from renewable resources each year. During 2003 and 2004, the Utility entered into several new renewable power purchase contracts that will help the Utility meet its goals. The Utility also is conducting negotiations with several renewable energy providers pursuant to a request for offers made by the Utility in July 2004 that should result in the Utility entering into a number of new renewable contracts in 2005. In January 2005, the California Senate introduced a bill proposing to require the goal to be met by the end of 2010 instead of 2017. The CPUC also has suggested that the 20% goal be met by 2010.2010 and a 33% goal be met by 2020. The Utility estimates that the accelerated goal would require the Utility to increase the amount of its annual renewable energy purchases to approximately 800-900 GWh. Based onDuring 2005, the medium load scenario in the Utility's long-term electricity procurement plan, the Utility believes that it can meet the accelerated goal.Western Area Power Administration In 1967, the Utility and the Western Area Power Administration, or WAPA, entered into several long-termnew renewable power purchase 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 gavethat will help the Utility access to WAPA's excess hydroelectric power and obligated the Utility to provide WAPA with electricity when its own resources were not sufficient to meet its requirements. In recent years the pricing formula under the contract often resulted in the Utility selling power to WAPA at prices that were below market. On December 3, 2004, the FERC approved termination of the contracts as of January 1, 2005, and approved the new service contracts that WAPA and the Utility executed in October 2004. Under the new contracts, which became effective on January 1, 2005, the Utility no longer provides any electric power or transmission services to WAPA but continues to provide wholesale distribution service.1217: Commitments and Contingencies— Power Purchase Agreements, of the Notes to the Consolidated Financial Statements ofin the 2005 Annual Report.2004,2005, the Utility owned 18,61018,616 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 46,03649,158 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 123,054128,128 circuit miles of distribution lines and substations with a capacity of 24,87725,254 MVA. In 2004,2005, the Utility delivered 82,93681,626 GWh to its customers, including 9,2108,867 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.maintainingassuring that the reliability of the transmission system. The Utility has been working closely with the ISO to continue expanding the capacity on the Utility's electric transmission system. In December 2004, construction was completed on a new 500 kV line to expand one segment of the transmission system known as Path 15, which is located in the southern portion of the Utility's service area, and serves as part of the primary transmission path between northern California and southern California. The improvements are intended to mitigate transmission constraints in this area. The Utility has interconnected the new 500 kV line at its existing substations at the line terminals and reconfigured its 230 kV and 115 kV facilities in the area to support a higher transfer capability through this section of the grid. This new 500 kV line became operational in December 2004.230 kV230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230 kV230-kV Line. The improvement is intended to provide additional transmission system reliability in San Francisco and northern San Mateo County. Construction of this project is expected to be completed in earlyApril 2006.2004,2005, the Utility served approximately 4.14.2 million natural gas distribution customers. The total volume of natural gas throughput during 20042005 was approximately 888856 Bcf.2004,2005, the Utility's natural gas system consisted of 40,12340,704 miles of distribution pipelines, 6,1366,128 miles of transportationbackbone and local transmission pipelines and three storage facilities. The Utility's distribution network connects to the Utility's transportationtransmission and storage system at approximately 2,200 major interconnection points. The Utility's Line 400/Utility’s backbone transmission system, composed of Lines 300, 400 and 401, interconnectsis used to transport gas from the Utility’s interconnection with interstatenatural gas transportation pipeline of Transcanada's Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.0 Bcf per day.Utility’s local transmission and distribution system. The Utility's Line 300, which interconnects with the U.S. southwest and California-Oregon pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity at the California-Arizona border of approximately 1.1 Bcf per day. The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of TransCanada's Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.0 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains and the southwestern United States. The Utility also is supplied by natural gas fields in California.located alongconnected to the Utility's transportationtransmission and storage system in close proximity to approximately 90% of the Utility's end-user demand.system. These storage fields have a combined annual cycle capacity of approximately 42 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system. Since 1991, thehas divideddivides 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 and electric generation natural gas customers. In 2004,2005, core customers represented more than 99% of the Utility's total customers and 32%40% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility's total customers and 68%60% of its total natural gas deliveries.97%96% of core market demand, receive natural gas bundled services from the Utility. In accordance with a 1998 ratemaking settlement agreement called the Gas Accord, thestopped providingdoes not provide 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,customers. Electricity generators, cogenerators, enhanced oil recovery and refinery,refiners, and other large noncore customers from electing tomay not transfer to core service, and requiring smaller noncore customers tomust sign up for a minimum five-year term if they elect to transfer to core service. The Utility made this requestThese restrictions were put in place 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 its pipeline system to provide core service reliability on a short-term basis to serve this new load.transportation, distributionbackbone gas transmission, delivery (local transmission and distribution), and storage services as separate and distinct services to its noncore customers. These customers may elect to receive storage services from the Utility or other third partythird-party storage providers. Noncore customers interconnected at a transportation level only pay for transportation service, while those interconnected at a distribution level pay for both transportation and distribution service. Noncore customers formerly were able to subscribe for natural gas bundled service as if they were core customers but are no longer allowed to do so. Access to the Utility's backbone gas transportationtransmission 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. no similarfewer regulatory balancing accounts related to noncore customers. Approximately 96%97% of the Utility's natural gas distribution base revenues are recovered from core customers and 4%3% are recovered from noncore customers.which presentsis prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon,horizon. It is prepared annuallyin even-numbered years followed by the California electric and natural gas utilities.a supplemental report in odd-numbered years. The 2004 California Gas Report updated the Utility's annual natural gas requirements forecast for the years 2004 through 2025, forecastingforecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 1.2%.1.3% for the years 2004 through 2025. The natural gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, price, and the number and location of electricity generation facilities.20042005 natural gas deliveries represented by each of the Utility's major customer classes:20042005 Natural Gas Deliveries: 888856 BcfResidential Customers 23%28%Transport onlyTransport-only Customers (noncore)68%60%Commercial Customers 9%12%20002001 through 20042005 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service: 2004 2003 2002 2001 2000 Customers (average for the year): Residential 3,812,914 3,744,011 3,738,524 3,705,141 3,642,266 Commercial 215,547 208,857 206,953 205,681 203,355 Industrial 2,178 1,988 1,819 1,764 1,719 Other gas utilities 6 6 5 6 6 Total 4,030,645 3,954,862 3,947,301 3,912,592 3,847,346 Gas supply (MMcf): Purchased from suppliers in: Canada 205,180 196,278 210,716 209,630 216,684 California (9,108 ) (7,421 ) 19,533 20,352 32,167 Other states 103,801 102,941 67,878 76,589 75,834 Total purchased 299,873 291,798 298,127 306,571 324,685 Net (to storage) from storage (532 ) 1,359 (218 ) (27,027 ) 19,420 Total 299,341 293,157 297,909 279,544 344,105 Utility use, losses, etc.(1) (19,287 ) (14,307 ) (16,393 ) (8,988 ) (62,960 ) Net gas for sales 280,054 278,850 281,516 270,556 281,145 Bundled gas sales (MMcf): Residential 201,601 198,580 202,141 197,184 210,515 Commercial 78,080 79,891 78,812 72,528 66,443 Industrial 373 379 563 831 4,146 Other gas utilities — — — 13 41 Total 280,054 278,850 281,516 270,556 281,145 Transportation only (MMcf): 597,706 525,353 508,090 646,079 606,152 Revenues (in millions): Bundled gas sales: Residential $ 1,944 $ 1,836 $ 1,379 $ 2,308 $ 1,681 Commercial 712 697 499 783 513 Industrial — 1 3 16 35 Other gas utilities — 1 1 — — Miscellaneous (29 ) (31 ) 127 (93 ) 84 Regulatory balancing accounts 316 68 11 (253 ) 132 Bundled gas revenues 2,943 2,572 2,020 2,761 2,445 Transportation service only revenue 270 284 316 375 338 Operating revenues $ 3,213 $ 2,856 $ 2,336 $ 3,136 $ 2,783 Selected Statistics: Average annual residential usage (Mcf) 53 53 54 53 59 Average billed bundled gas sales revenues per Mcf: Residential $ 9.64 $ 9.25 $ 6.82 $ 11.70 $ 7.98 Commercial 9.12 8.73 6.33 10.80 7.72 Industrial (0.56 ) 2.48 4.35 19.15 8.53 Average billed transportation only revenue per Mcf 0.45 0.54 0.62 0.58 0.56 Net plant investment per customer $ 1,266 $ 1,261 $ 1,006 $ 970 $ 1,003 Customers (average for the year): Residential 3,929,117 3,812,914 3,744,011 3,738,524 3,705,141 Commercial 216,749 215,547 208,857 206,953 205,681 Industrial 962 2,178 1,988 1,819 1,764 Other gas utilities 6 6 6 5 6 Total 4,146,834 4,030,645 3,954,862 3,947,301 3,912,592 Gas supply (MMcf): Purchased from suppliers in: Canada 204,884 205,180 196,278 210,716 209,630 California (18,951) (9,108) (7,421) 19,533 20,352 Other states 103,237 103,801 102,941 67,878 76,589 Total purchased 289,170 299,873 291,798 298,127 306,571 Net (to storage) from storage (3,659) (532) 1,359 (218) (27,027) Total 285,511 299,341 293,157 297,909 279,544 Utility use, losses, etc.(1) (14,312) (19,287) (14,307) (16,393) (8,988) Net gas for sales 271,199 280,054 278,850 281,516 270,556 Bundled gas sales (MMcf): Residential 194,108 201,601 198,580 202,141 197,184 Commercial 77,056 78,080 79,891 78,812 72,528 Industrial 35 373 379 563 831 Other gas utilities — — — — 13 Total 271,199 280,054 278,850 281,516 270,556 Transportation only (MMcf): 572,869 597,706 525,353 508,090 646,079 Revenues (in millions): Bundled gas sales: Residential $2,336 $1,944 $1,836 $1,379 $2,308 Commercial 885 712 697 499 783 Industrial — — 1 3 16 Other gas utilities — — 1 1 — Miscellaneous (22) (29) (31) 127 (93) Regulatory balancing accounts 340 316 68 11 (253) Bundled gas revenues 3,539 2,943 2,572 2,020 2,761 Transportation service only revenue 238 270 284 316 375 Operating revenues $3,777 $3,213 $2,856 $2,336 $3,136 Selected Statistics: Average annual residential usage (Mcf) 49 53 53 54 53 Average billed bundled gas sales revenues per Mcf: Residential $12.04 $9.64 $9.25 $6.82 $11.70 Commercial 11.48 9.12 8.73 6.33 10.80 Industrial 0.61 (0.56) 2.48 4.35 19.15 Average billed transportation only revenue per Mcf 0.42 0.45 0.54 0.62 0.58 Net plant investment per customer $1,262 $1,266 $1,261 $1,006 $970 2004,2005, the Utility purchased approximately 300,000289,000 MMcf of natural gas (net of the sale of excess supply) from 5157 suppliers. SubstantiallyConsistent with existing CPUC policy directives, substantially all this natural gas was purchased under contracts with a term of less than one year.year or less. The Utility's largest individual supplier represented approximately 10.3%10.4% of the total natural gas volume the Utility purchased during 2004.2004 and 2003,2005, the sale of excess supplies to parties located in California exceeded purchases from parties located in California. 2004 2003 2002 2001 2000 MMcf Avg.
Price MMcf Avg.
Price MMcf Avg.
Price MMcf Avg.
Price MMcf Avg.
PriceCanada 205,180 $ 5.37 196,278 $ 4.73 210,716 $ 2.42 209,630 $ 4.43 216,684 $ 4.05 California(1) (9,108 ) $ 4.89 (7,421 ) $ 3.39 19,533 $ 2.88 20,352 $ 11.55 32,167 $ 8.20 Other states (substantially all U.S southwest) 103,801 $ 5.44 102,941 $ 4.63 67,878 $ 3.04 76,589 $ 10.41 75,834 $ 5.99 Total/weighted average 299,873 $ 5.41 291,798 $ 4.73 298,127 $ 2.59 306,571 $ 6.40 324,685 $ 4.92 Canada 204,884 $ 7.12 205,180 $ 5.37 196,278 $ 4.73 210,716 $ 2.42 209,630 $ 4.43 California(1) (18,951 ) $ 7.70 (9,108 ) $ 4.89 (7,421 ) $ 3.39 19,533 $ 2.88 20,352 $ 11.55 Other states (substantially all U.S southwest) 103,237 $ 7.10 103,801 $ 5.44 102,941 $ 4.63 67,878 $ 3.04 76,589 $ 10.41 Total/weighted average 289,170 $ 7.07 299,873 $ 5.41 291,798 $ 4.73 298,127 $ 2.59 306,571 $ 6.40 and processes natural gas from third-party wells in California. During 2004,2005, approximately 4% of the gas transported on the Utility's system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream and to odorizethe Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include 440approximately 420 miles of gas gathering pipelines, aspipelines. The Utility receives gas well as dehydration, separation, regulation, odorization andproduction at approximately 300 metering equipment located at 63 stations.facilities. The Utility’s gas gathering system is geographically dispersed and is located in 1413 California counties. Approximately 103119 MMcf per day of natural gas flows throughproduced in northern California was delivered into the Utility's gas gathering system.2004,2005, approximately 68%65% of the gas transported on the Utility's system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers' service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- Canadian border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System. These companies' pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest Corporation which provides natural gas transportation services to interconnection points with the Utility's natural gas transportation system in the area of California near Malin, Oregon. The Utility has a firm transportation agreement with Gas Transmission Northwest Corporation for these services.2004,2005, approximately 28%31% of the gas transported on the Utility's system came from the western United States, excluding California. The Utility has firm transportation agreements withCPUCCPUC’s approval, extend each of these natural gas transportation agreements. On the FERC-regulated pipelines, the Utility has either a right of first refusal or evergreen rights allowing it to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.Pipeline Expiration
Date Quantity
MDth per day Demand Charges
for the Year Ended
December 31, 2004 (In millions) El Paso Natural Gas Company 12/31/2004 64 4.1 TransCanada NOVA Gas Transmission, Ltd. 12/31/2006 593 26.8 TransCanada PipeLines Ltd., B.C. System 10/31/2006 584 10.3 Gas Transmission Northwest Corporation 10/31/2006 610 55.1 Transwestern Pipeline Co. 03/31/2007 150 17.7 El Paso Natural Gas Company 03/31/2007 40 3.8 El Paso Natural Gas Company 04/30/2005 100 8.2 El Paso Natural Gas Company 03/31/2006 64 — TransCanada NOVA Gas Transmission, Ltd. 12/31/2007 616 28.0 TransCanada PipeLines Ltd., B.C. System 10/31/2007 607 13.0 Gas Transmission Northwest Corporation 10/31/2007 610 54.8 Transwestern Pipeline Co. 03/31/2007 150 20.5 El Paso Natural Gas Company (b) Various 202 19.2 (a) A small portion (23 MDth/d) of the Utility’s capacity is due to expire on October 31, 2007. (b) As of December 31, 2005, the Utility has three active contracts with El Paso with expiration dates ranging from June 30, 2007 to June 30, 2010. Competitionundertakeundertook 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.FERC's standard market design proposal issued in July 2002 encourages unbundled transmission. The ISO also issued its own comprehensive energy market design proposal to effect changes to the structure and operation of the California electricity market, subject to the FERC's approval.market. The FERC has approved the first phase of the ISO'sISO’s new rulesmarket design has been approved by the FERC and implementation ofwas implemented by the first phase was substantially completedISO in the fourth quarter of 2004. A later phase to establish integrated forward markets and locational marginal pricing and revise congestion management would be implemented inOn February 14, 2006, the future, assuming FERC approval. The ISO is expected to filefiled its proposed tariff language with the FERC later in 2005 to address these issues, with implementationimplement the balance of aits market design proposal. Assuming FERC approval, the balance of the ISO’s new market design incould be implemented as early as November 2007. 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. will require regulated transmission providers, such as the Utility or the ISO, generally to use standard interconnection procedures and a standard agreement for generator interconnections. These rules would requirerequired the Utility and the ISO to revise the current form of agreements and procedures used when constructing facilities to interconnect new generators. Numerous parties have requested rehearing and a stay of the generator interconnection rules. The FERC has ordered that the rules will not become effective until afterIn July 2005, the FERC accepts newaccepted tariff changes filed by the Utility and the ISO to implement the new rules. The Utility, along with other transmission owners and the ISO, initially, filed proposed tariffs changes on January 20, 2004. In July 2004,doing so, the FERC summarily rejected those filings, based on a findingconfirmed that the ISO did not satisfyis authorized to implement California-specific modifications to the FERC's standardspro forma agreement and procedures for new interconnections under what is known as an "Independent Entity" within"independent entity variation." The new rules, tariffs and related interconnection procedures establish time-frames for completing studies on behalf of new generator applicants, and codify the meaningFERC's preexisting policy regarding financing of transmission system upgrades needed in order to interconnect a new generator. Under this policy, the generator must finance such upgrade facilities in the first instance, but then is reimbursed the funds, with interest, over a five-year period after the power plant achieves commercial operation. The cost of the FERC's rules. The FERC directed the ISO and the transmission owners to make a new filing with stronger justification for any California-specific deviations from the FERC's generally applicable rules. In January 2005,network upgrades then is recovered by the Utility along with otherin its overall transmission owners and the ISO, re-filed with the FERC the proposed tariff changes and procedures, as required by the FERC. It is uncertain when the FERC will act on the proposed tariff changes. In October 2003, the CPUC instituted a rulemaking implementingwhich permits California cities and counties to purchase and sell electricity for their local residents and businesses 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 The Utility faces competition In December 2005, the CPUC adopted rules that allow for the implementation of community choice aggregation.In addition, Kern River Pipeline Company completed a major expansion of its pipeline system in May 2003 that increased its capacity to deliver natural gas into the southern California market by approximately 900 MMcf per day. As a result this expansion, the volume of natural gas that the Utility delivers to the southern California market may decrease, although to date the Utility has not experienced any significant decrease in its volumes shipped. The Utility also competes for storage services with other third-party storage providers, primarily in northern California. PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of thePUHCA. Currently, PG&E Corporation has no expectationPUHCA, imposed structural and regulatory approval requirements on certain public utility holding companies that have limited their utility operations to a single integrated system. These requirements primarily related to sales and acquisitions of becoming a registeredutility property and securities, issuance of securities by the top-level holding company, under PUHCA. In 2001,and various affiliate arrangements involving extensions of credit and the California Attorney General filedprovision of goods, services or construction. PUHCA prevented these holding companies from owning other businesses that are not reasonably incidental or functionally related to the utility business. PUHCA also discouraged ownership of U.S. electric and gas utilities by domestic industrial and financial institutions and by foreign institutions generally. As a petitionholding company with the SEC requesting the SECutility operations confined to review and revoke PG&E Corporation's exemption from PUHCA and to begin fully regulating the activities ofone state, PG&E Corporation and its affiliates. PG&E Corporation respondedsubsidiaries were exempt from most of PUHCA’s requirements.detailits place the Public Utility Holding Company Act of 2005, or PUHCA 2005. Under PUHCA 2005, public utility holding companies fall principally under the regulatory oversight of the FERC, rather than the SEC (which previously administered PUHCA). On December 8, 2005, the FERC issued its final rule implementing PUHCA 2005 and, among other actions, adopted a requirement that, unless otherwise eligible for exemption, every utility holding company provide the FERC with access to its books and records that are relevant to the California Attorney General petition demonstratingFERC’s ratemaking responsibilities. The authorities granted to the FERC under PUHCA 2005 are supplementary to and somewhat duplicative of authorities it holds under other applicable law. On February 7, 2006, the FERC decided that PG&E Corporation qualifiedit will rehear its December 8, 2005 order. In addition to providing for an exemption fromFERC access to utility holding company books and records and other matters, PUHCA 2005 also provides for access by state utility commissions to utility holding company books and that there was no basis for action byrecords in certain circumstances..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 2003FERC's authority and 2004, proposed federal energy legislation was considered by the U.S. Congress. If it had been adopted, the legislation would, among other things, have repealed PUHCA. PUHCA currently imposes significant regulatory barriersstandard of review with respect to mergers and acquisitions involving public utilities and public utility holding companies.consolidations. The repeal of PUHCA couldis expected to trigger a period of consolidation among public utilities, as well as The proposed effective date for the repeal of PUHCA, as well as the proposed effective date for proposed legislation that would replace PUHCA, was 12 months after the passage of the legislation. Under the proposed legislation that would replace PUHCA, public utilities and public utility holding companies wouldremain under the regulatory oversight of the FERC, but not the SEC. Similar legislation is likely to be considered in 2005.However, the CPUC approval authorizing the Utility to form aformation of holding company wascompanies has been granted subject to various conditions set forth in CPUC decisions issued in 1996 and 1999 related to finance, human resources, records and bookkeeping, and the transfer of customer information. In 2004, the California Court of Appeal issued an opinion finding that the CPUC has limited jurisdiction over the holding companies to enforce these conditions. The financial conditions provide that:•the· The Utility is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC; · The Utility's dividend policy must continue to be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company; · The capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation's Board of Directors (known as the “first priority” condition); and · The Utility must maintain on average its CPUC-authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition if an adverse financial event reduces the Utility's equity ratio by 1% or more. without prior written consent fromand its directors, as well as the CPUC;•the Utility's dividend policy must continue to be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company;•the capital requirementsdirectors of the Utility, as determined to be necessaryviolated the CPUC’s holding company conditions during the California energy crisis. PG&E Corporation and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudentbelieve that they have complied with applicable statutes, CPUC decisions, rules and efficient manner, must be given first priority by PG&E Corporation's Board of Directors, (known as the first priority condition); andorders.•the Utility must maintain on average its CPUC-authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition if an adverse financial event reduces the Utility's equity ratio by 1% or more.permit non-regulated affiliatesaddress the use of the regulated utilities to compete in the affiliated utility's service territory, and also to use theutilities’ name and logo ofby their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUC. The rules also addressnon-regulated affiliates, the separation of regulated utilities and their non-regulated affiliates, and information exchange among the affiliates, and power-procurement related transactions among regulated utilities and their non-regulated affiliates. The rules also prohibit each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility's non-regulated affiliates. In January 2004, the CPUC adopted rules that prohibit regulated utility electric procurement from entering into power procurement related transactions with an affiliate, subject to the following exceptions:•anonymous transactions through approved interstate brokers and exchanges, provided that the solicitation/bidding process is structured so that the identity of the seller is not known to the buyer until agreement is reached, and vice-versa;•transactions for natural gas services between the regulated utility and affiliates or operating divisions that are found necessary and beneficial for ratepayer interests, subject to the receipt and review of a management audit; and•transactions that occur pursuant to contracts with affiliates that were already existing on January 22, 2004. In December 2004, the CPUC lifted its ban on affiliate transactions for long-term electricity procurement through all source competitive solicitations but retained the ban on short-term electricity procurement transactions. On April 3, 2001,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/Order Instituting Rulemaking, or governing affiliate transactions, as well as applicable statutes. The order states thatOIR, to allow the CPUC will, among other matters, investigateto re-examine the utilities' transfer of money torelationship between California energy utilities and their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties; the failure of the holding companies to financially assist the utilities when needed; the transfer by the holding companies of assets to unregulated subsidiaries; and the holding companies' actions to "ringfence" their unregulated subsidiaries. Under the Settlement Agreement the CPUC has agreed to dismiss with prejudice PG&E Corporation and the Utility from the CPUC's investigation as to past practices. On January 9, 2002, the CPUC issued two decisions in its pending investigation. In one decision, the CPUC, for the first time, adopted a broad interpretation of the first priority condition and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies "infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve." Nevertheless, the CPUC dismissed PG&E Corporation (but no other utility holding company) from the investigation. In the second decision, the CPUC asserted that it maintains jurisdiction to enforce the conditions against PG&E Corporation and similarparent holding companies and to modify, clarify or add toaffiliates. The CPUC noted that in light of the conditions. In November 2003, PG&E Corporation andrepeal of PUHCA, as discussed above, the parent holding companies of the California energy utilities may try to expand the unregulated activities of their affiliates, may try to merge with or acquire other majorcompanies or may be acquired by other companies, and that it was necessary for the CPUC to review its existing regulations and to consider whether additional, new rules or regulations are needed. The CPUC stated that it may propose rules to ensure that the California investor-owned electricenergy utilities filed petitionsretain sufficient capital and the ability to access capital in order to meet their customers' needs, and to address the potential conflicts between the utilities' ratepayers' interests and the parent holding companies' and affiliates' interests in order to ensure that these conflicts do not undermine the utilities' ability to meet their public service obligations at the lowest possible cost. The CPUC stated that it may propose additional rules or regulations regarding, but not necessarily limited to, (1) reporting requirements for reviewthe allocation of capital between utilities and their non-regulated affiliates by the parent holding companies, and (2) changes to the CPUC's decisions with the California Court of Appeal. On May 21, 2004, the California Court of Appeal issued an opinion finding that the CPUC has limited jurisdiction over the holding companies to enforce the conditions imposed by the CPUC when the CPUC authorized the formation of the holding companies, but that the CPUC's decision interpreting the first priority condition was not ripe for review. PG&E Corporation appealed the decision of the California Court of Appeal finding that the CPUC had limited jurisdiction to the California Supreme Court. On September 1, 2004, the California Supreme Court denied the petition. On February 11, 2005, a CPUC administrative law judge issued a ruling noting that the pending CPUC investigation had been dormant for some time and requesting comments on whether the investigation should remain open. The ruling also stated that if no comments were received, a draft decision would be prepared for CPUC consideration closing the proceeding. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules and orders. On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against the directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200. Among other allegations, the California Attorney General alleges that PG&E Corporation violated the various conditions established by the CPUC in decisions approving the holding company formation. A similar complaint filed by the City and County of San Francisco also is pending. These complaints are not affected by the Settlement Agreement. For more information, see "Item 3—Legal Proceedings" below.&A. of electricity in interstate commerce. The FERC also regulates electricity transmission, interconnections, tariffs and conditions of service of the ISO, and the terms and rates of wholesale electricity sales. The ISO is responsible for providing open access transmission service on a non-discriminatory basis, meeting applicable reliability criteria, planning transmission system additions and assuring the maintenance of adequate reserves of generation capacity. In addition, the FERC has jurisdiction over the Utility'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 2005, The FERC has proposed to repeal these behavioral conditions in favor of its more generalized prohibition on market manipulation that it adopted in January 2006 based on SEC Rule 10b-5, as discussed above. On January 13, 2006, the FERC is expectedapproved an increase in the energy price cap, from $250 to $400 per MWh, in response to the ISO’s request to reflect natural gas price increases. The FERC's January 13 order also initiated a proceeding to consider ISO market monitoring and oversight in connection withwhether to extend the FERC's review ofenergy price cap increase throughout the ISO's market design proposals. Market monitoring and mitigation also may be affected by anyWestern Electricity Coordinating Council area, as well as whether to increase the price cap for ancillary services to the same level as the energy legislation Congress may pass.up to $8.9 billionrefunds from energy suppliers in refundsthe California ISO and California Power Exchange, or PX, markets for electricity overcharges on behalf of California electricity purchasers fromfor the period May 2000 to June 2001 through a proceeding pending at the FERC. This FERC proceeding, the "Refund Proceeding," commenced on August 2, 2000 when a complaint was filed against all suppliers in the ISOregulatory and PX markets. On July 25, 2001, the FERC held that refunds would be available for certain overcharges, and established a process to determine the amount of the overcharges that will be refunded. The FERC asserted that it would not order market-wide refunds for periods before October 2, 2000, because under a federal statute it can only order refunds beginning 60 days after a complaint for overcharges was filed and the first complaint for overcharges was not filed with the FERC until August 2, 2000. In December 2002, a FERC ALJ issued an initial decision in the Refund Proceeding finding that power suppliers overcharged the utilities, the state of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001, but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills. In March 2003, the FERC confirmed most of the ALJ's findings in the Refund Proceeding, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the PX (which operates solely to reconcile remaining refund amounts owed) to make compliance filings establishing refund amounts by March 2004. The ISO calculation process has been continuing, and the ISO has indicated that it plans to make its compliance filing by the first half of 2005. The PX cannot make its compliance filing until after the ISO has made its filing. In October 2003, the FERC affirmed its March 2003 decision. Various parties have filed appeals with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, of the various FERC orders in theRefund Proceeding. Although the Ninth Circuit originally held those appeals in abeyance while the FERC process continued, on October 22, 2004, the Ninth Circuit ordered that the appeals should proceed. According to a schedule developed by the Ninth Circuit, the parties are required to submit all briefs by March 2005 to address the issues of which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds. These matters will be considered at oral argument before the Ninth Circuit on April 12 and 13, 2005, and a decision is expected in the following months. The final refunds will not be determined until the FERC issues a final decision in the Refund Proceeding, following the ISO and PX compliance filings and the resolution of the appeals of the FERC's orders. The FERC is uncertain when it will issue a final decision in the Refund Proceeding, after which further appellate review is expected. In addition, future refunds could increase or decrease as a result of retroactive adjustments proposed by the ISO, which incorporate revised data provided by the Utility and other entities. As noted above, the FERC asserted in the Refund Proceeding that it does not have the power to direct the power suppliers to make comprehensive market-wide refunds to customers for the period before October 2, 2000. However, in the FERC's separate proceedings to investigate whether tariff violations occurred in the period before October 2, 2000, the FERC has asserted that it has the power to order power suppliers to disgorge any profits if the FERC finds that the tariffs in force at that time were violated or subject to manipulation. In addition, in September 2004, acting in a separate case from the Refund Proceeding and the FERC's investigative proceedings, the Ninth Circuit found that the FERC has the authority to provide refunds for tariff violations involving inadequate transaction reporting for sales into the California spot markets throughout the period before October 2, 2000. The Ninth Circuit remanded the case to the FERC to determine the appropriate remedy. Pending a decision on the suppliers' request for a rehearing of this Ninth Circuit decision, the FERC has not yet acted on the September 2004 remand order. It is uncertain whether the Ninth Circuit's decision interpreting the FERC's power to order refunds will be upheld and how it will be applied by the FERC. The Utility recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to compromise. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. Under a bankruptcy court order, the aggregate allowable amount of ISO, PX and generator claims was limited to approximately $1.6 billion. The Utility currently estimates that the claims would have been reduced to approximately $1.0 billion based on the refund methodology recommended in the FERC ALJ's initial decision. The recalculation of market prices according to the revised methodology adopted by the FERC in its March 2003 decision could further reduce the amount of the suppliers' claims by several hundred million dollars. This reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology. The FERC has directed that sellers claiming a fuel cost allowance should submit their claims to an independent auditor before inclusion of any amounts in an ISO calculation of refunds and offsets for such fuel costs.various settlements with various power suppliers resolving certain disputed claims and the Utility's refund claims against these power suppliers. Although settlement discussions with a numberFor further discussion of other major sellersthese settlements, see the section of Note 17: Commitments and other market participants are continuing, the Utility cannot predict whether these settlement negotiations will be successful. The net after-tax amounts received by the Utility under settlements reduced the amountContingencies—California Energy Crisis Proceedings, of the Settlement Regulatory Asset. Customers also will receiveNotes to the benefit of any future energy supplier refunds received byConsolidated Financial Statements in the Utility. See discussion entitled "Contingencies" in MD&A. On November 25, 2003, the FERC issued Order No. 2004, its final rule on standards of conduct for interstate natural gas pipelines and public utilities (jointly referred to as transmission providers). The standards of conduct are designed to ensure that transmission providers do not provide affiliated market participants with preferential access to service or information. In Order No. 2004, the FERC consolidated the previously separate standards of conduct for interstate natural gas pipelines and electric transmission providers and expanded the range of affiliates covered by the standards. In accordance with Order No. 2004, on September 22, 2004, the Utility posted its plan for compliance with the standards of conduct on its internet website,www.pge.com.conducts varioushas general jurisdiction over most of the Utility’s operations, and regularly reviews of utility performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms.California Legislature Over the last several years, the Utility's operations have been significantly affected by statutes passed by the California legislature, including:•Assembly Bill 1890. AB 1890 mandated the restructuring of the California electricity industry, commencing in 1998 with the implementation of a market framework for electricity generation in which generators and other energy providers were permitted to charge market-based rates for wholesale electricity and the Utility's customers were given the choice of becoming direct access customers;•Assembly Bill 6X. AB 6X, enacted in January 2001 in response to the California energy crisis, prohibited disposition of utility-owned generation facilities before January 1, 2006;•Assembly Bill 1X. AB 1X authorized the DWR, beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities' retail customers.AB 1X required the California investor-owned electric utilities, including the Utility, to deliver that electricity and act as the DWR's billing and collection agent;•Senate Bill 1976. SB 1976, enacted in September 2002, required the CPUC to allocate electricity from contracts that the DWR entered into under AB 1X among the customers of the California investor-owned electric utilities, required the utilities to file short- and long-term procurement plans with the CPUC, contemplated that the utilities would resume buying electricity pursuant to these plans by January 1, 2003, and mandated new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under approved procurement plans;•Senate Bill 1078. SB 1078, enacted in September 2002, creates a renewable portfolio standard for investor-owned utilities that requires annual 1% increases of renewable electrical procurement purchases until renewable resources equal 20% of total retail sales in 2017; and•Senate Bill 772. SB 772, enacted in June 2004, (1) authorized the CPUC to approve the issuance of energy recovery bonds, or ERBs, to refinance the $2.21 billion regulatory asset established under the Settlement Agreement, or Settlement Regulatory Asset, (2) established a dedicated rate component to securitize the ERBs, and (3) authorized the CPUC to impose a charge for the dedicated rate component on the Utility's electricity distribution customers, subject to certain limited exceptions. On February 10, 2005, PG&E Energy Recovery Funding LLC, or PERF, a limited liability company which is wholly owned and consolidated by the Utility (but legally separate from the Utility), issued $1.9 billion of ERBs that are secured by this dedicated rate component. The proceeds of the issuance of ERBs were paid by PERF to the Utility and will be used by the Utility to refinance the remaining unamortized after-tax balance of the Settlement Regulatory Asset.MW,MW; overseeing funding programs that support public interest energy research; advanceadvancing energy science and technology through research, development and demonstration; and provideproviding market support to existing, new and emerging renewable technologies. In addition, the CEC is responsible for forecasting future energy needs that will be used by the CPUC in determining the adequacy of the utilities' electricity procurement plans. OverviewCost of Service Ratemaking In January 2004, the CPUC determined that the retail electric rate freeze implemented as part of electric industry restructuring in 1998 ended on January 18, 2001. In February 2004, the CPUC approved a rate design settlement to implement an annualThe Utility’s rates for electricity rate reduction of approximately $799 million to begin on January 1, 2004. As a result of the Settlement Agreement and these CPUC decisions, the Utility's ratesnatural gas utility services are now determined based on its costs of service. ElectricBefore rates reflectcan be set, the sumCPUC and the FERC must determine the amount of individual revenue requirement components, including base“revenue requirements” the Utility is authorized to collect from its customers to recover the Utility’s operating and capital costs. The CPUC determines the Utility’s revenue requirements set by general rate cases as described below,associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The Utility’s revenue requirements forassociated with its electricity transmission operations are established by the regulatory assets provided underFERC. RevenueSettlement Agreement, electricity procurementUtility’s forecast of future costs, and the DWR's requirement, among others. Changes in any individual revenue requirement will change customers' electricity rates and the Utility's revenues.Revenue Requirements Before the rates for the Utility'sincluding electricity and natural gas utility services can be set, revenue requirements must first be determined.procurement costs. The components of revenue requirements for electricity and natural gas utility service include depreciation, operating, administrative and general expenses, taxes and return on investment, as applicable, for each area of these services, including distribution, transmission, transportation, generation, procurement and public purpose programs. Revenue requirements are then allocated among customer classes and specific rates designed to produce the required revenue are established. In the Utility's rate cases, interveners have the opportunity to comment on the Utility's application. The issues raised by these comments are then resolved by the appropriate regulatory agency. If the Utility and the interveners can settle these issues, these settlements are submitted to the regulatory agency for approval. Changes in any individual revenue requirement will affect customers' electricity and gas rates and the Utility's revenues.Revenue requirements are then allocated among customer classes and specific rates designed to produceTo the required revenue are established. In the Utility's rate cases, intervenors have the opportunity to comment on the Utility's application. The issues raised by these comments are then resolved by the appropriate regulatory agency. Ifextent that the Utility andis unable to recover its costs through rates because the intervenors can settle these issues, these settlementsUtility’s actual costs are submitteddetermined to be unreasonable or are higher than forecast, the regulatory agency for approval.intervenorsinterveners in the Utility's GRC include the Office of Ratepayer Advocate, or ORA, and The Utility Reform Network, or TURN. The nextOn December 2, 2005, the Utility filed its 2007 GRC will coverapplication with the period of 2007-2009.CPUC. For more information, see “Regulatory Matters—2007 General Rate Case” in the MD&A in the 2005 Annual Report.ForOn December 15, 2005, this proceeding alsothe CPUC issued a cost of capital decision approving a capital structure for the Utility consisting of 46% long-term debt, 2% preferred stock and 52% equity. The CPUC set the authorizedrate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base for 2006 at 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%. Although the FERC has authority to set the Utility’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.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 purchasedDWR-purchased electricity or reselling it to the Utility's customers.SB 1976,California Senate Bill, or 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 wasthat have been 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.utilities.residual net open positions (i.e., that portion of the Utility's electricity customers' demand not satisfied by electricity that the Utility generates or has under contract, or by electricity provided under the DWR allocated contracts).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. SB 1976 requires the CPUC to review the revenues and costs associated with a 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. All load-serving entities, including the utilities, energy service providers and future community choice aggregators, must achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements by June 1, 2006. Also, beginning in 2006, the utilities and other load-serving entities are required to secure 90% of their electricity needs during the peak energy months of May through September through forward contracts at least one year in advance.ten-year10-year period 2005-2014.2005 through 2014. The decision recognizes that each utility will have capacity needs over the ten-year10-year period, especially in 2011 when most of the DWR contracts expire. The decision states that a major issue in the proceeding is the extent to which the utilities will be compensated for investments or purchases that they must make in order to meet their obligation to provide reliable service to their customers, noting that the implementation of community choice aggregation, departing municipal load, and the potential for allowing new direct access all create a great degree of uncertainty as to the amount of load the existing utilities will be responsible for serving in the future. The decision includes the following key points:•The decision finds that the Utility's strategy of adding 1,200 MW of capacity and new peaking generation in 2008 and an additional 1,000 MW of new peaking and dispatchable generation in 2010 through requests for offers, or RFOs, is reasonable and compatible with the Utility's resource needs under its medium load preferred case scenario, does not crowd out policy-preferred resources, and is a reasonable level of commitment given load uncertainty.•· The decision finds that the Utility's strategy of adding approximately 1,200 MW of capacity and new peaking generation in 2008 and approximately 1,000 MW of new peaking and dispatchable generation in 2010 through requests for offers, or RFOs, is reasonable and compatible with the Utility's resource needs under its medium load preferred case scenario, does not crowd out policy-preferred resources, and is a reasonable level of commitment given load uncertainty. · To meet the utilities' resource requirements, the utilities are required to solicit bids from providers of all potential sources of new generation (e.g. conventional or renewable resources to be provided under turnkey developments, buyouts, or power purchase agreements, or PPAs) through a single, open, transparent and competitive RFO process, although an utility can tailor a RFO to meet specific resource needs. In particular, bids for long-term generation resources (whether PPAs or utility-owned) would be evaluated side-by-side. In evaluating bids, the IOUs are required to: · To meet the utilities' resource requirements, the utilities are required to solicit bids from providers of all potential sources of new generation (e.g. conventional or renewable resources to be provided under turnkey developments, buyouts, or power purchase agreements, or PPAs) through a single, open, transparent and competitive RFO process, although an utility can tailor a RFO to meet specific resource needs. In particular, bids for long-term generation resources (whether PPAs or utility-owned) would be evaluated side-by-side. In evaluating bids, the IOUs are required to: Ø procure the maximum amount of renewable generation resources, and be prepared to defend any selection of fossil-fuel generation resources over renewable resources, Ø employ the Least-Cost Best-Fit methodology when evaluating bids for PPAs and utility-owned generation resources, taking into account the qualitative and quantitative attributes (such as performance risk, credit risk, price diversity, term and operational flexibility) associated with each bid, and Ø employ a "greenhouse gas adder" to evaluate fossil-fuel generation bids as a method to recognize the risk of future greenhouse gas emissions costs to develop a more accurate price comparison between fossil-fuel, renewable and demand-side bids (the greenhouse gas adder would be used for analytical purposes only and would not be paid to a generator). · The CPUC has agreed that it will consider the debt equivalence impact of procurement contracts on credit ratings in future cost of capital proceedings. The Utility is required to employ S&P’s method for assessing the debt equivalence of power purchase agreements when evaluating bids in an all-source solicitation, except that the debt equivalence factor should be 20% instead of 30%. · The utilities are prohibited from recovering initial capital costs in excess of their final bid price for utility-owned generation resources. If final project costs are less than the final bid price, the savings would be shared with customers and any cost overruns would be absorbed by the utilities. Costs of future plant additions and annual operating and maintenance costs and similar costs incurred by a utility would be eligible for cost-of service ratemaking treatment. · Affiliates of the utilities are permitted to participate in the bidding process for long-term generation resources, subject to certain guidelines and safeguards, including a requirement that the utility use an independent third-party evaluator in resource solicitations where there are bids that involve affiliates or utility-built or utility-turnkey development projects. The independent evaluator will not be able to make binding decisions on behalf of the utility. · The utilities are permitted to recover their net stranded costs of all new fossil-fuel generation resources from all customers, including departing customers, for a period of 10 years or the life of the PPA, whichever is less, provided that the CPUC will allow the utilities an opportunity to justify a longer recovery period on a case-by-case basis. Stranded costs arising from renewable generation procurement activities can be collected from all customers, including departing load, over the life of the contract. The utilities are required to take appropriate steps to minimize potential stranded costs by selling excess energy and capacity needs into the marketplace and crediting the revenues from these sales against the utilities' costs. · The CPUC extended the mandatory rate adjustment mechanism provided under SB 1976 (which otherwise expired on January 1, 2006) to the length of a resource commitment or 10 years, whichever is longer. Under this rate adjustment mechanism, the CPUC has agreed to 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 allocated contracts. · With respect to the utilities' contracting authority, the decision permits the utilities to enter into short-term, mid-term and long-term contracts with starting delivery dates through 2014, provided the utilities submit necessary compliance filings and provided that contracts with terms five years or longer are submitted to the CPUC for pre-approval. The decision adopts a rolling 10-year procurement period, noting that the LTPPs cover a 10-year period and will be updated and reviewed every 2 years. from providers of all potential sources of new generation (e.g. conventionalto develop or renewable resources to be provided under turnkey developments, buyouts, or power purchase agreements, or PPAs) through a single, open, transparent and competitive RFO process, although an utility can tailor a RFO to meet specific resource needs. In particular, bids foracquire long-term generation resources (whether PPAs or utility-owned) would be evaluated side-by-side. In evaluating bids, the IOUs are required to:•procure the maximum amount of renewable generation resources, and be prepared to defend any selection of fossil-fuel generation resources over renewable resources,•employ the Least-Cost Best-Fit methodology when evaluating bids for PPAs and utility-owned generation resources, taking into account the qualitative and quantitative attributes (such as performance risk, credit risk, price diversity, term, and operational flexibility) associated with each bid, and•employ a "greenhouse gas adder" to evaluate fossil-fuel generation bids as a method to recognize the cost of greenhouse gas emissions to develop a more accurate price comparison between fossil-fuel, renewable and demand-side bids (the greenhouse gas adder would be used for analytical purposes only and would not be paid to a generator).•The CPUC has agreed that it will consider the debt equivalence impact of procurement contracts on credit ratings in future cost of capital proceedings. The Utility is required to employ Standard & Poor's method for assessing the debt equivalence of power purchase agreements when evaluating bids in an all-source solicitation, except that the debt equivalence factor should be 20% instead of 30%.•The utilities are prohibited from recovering initial capital costs in excess of their final bid price for utility-owned generation resources. If final project costs are less than the final bid price, the savings would be shared with customers and any cost overruns would be absorbed by the utilities. Costs of future plant additions and annual operating and maintenance costs and similar costs incurred by an utility would be eligible for cost-of service ratemaking treatment.•Affiliates of the utilities are permitted to participate in the bidding process for long-term generation resources, subject to certain guidelines and safeguards, including a requirement that the utility use an independent third party evaluator in resource solicitations where there are bids that involve affiliates or utility-built or utility-turnkey development projects. The independent evaluator will not be able to make binding decisions on behalf of the utility.•The utilities are permitted to recover their net stranded costs of all new fossil-fuel generation resources from all customers, including departing customers, for a period of 10 years or the life of the PPA, whichever is less, provided that the CPUC will allow the utilities an opportunity to justify a longer recovery period on a case-by-case basis. Stranded costs arising from renewable generation procurement activities can be collected from all customers, including departing load, over the life of the contract. The utilities are required to take appropriate steps to minimize potential stranded costs by selling excess energy and capacity needs into the marketplace and crediting the revenues from these sales against the utilities' costs.•The mandatory rate adjustment mechanism under SB 1976, which otherwise would cease on January 1, 2006, has been extended to the length of a resource commitment or 10 years, whichever is longer.•With respect to the utilities' contracting authority, the decision permits the utilities to enter into short-term, mid-term and long-term contracts with starting delivery dates through 2014, provided the utilities submit necessary compliance filings and provided that contracts with terms five yearsor longer are submitted to the CPUC for pre-approval. The decision adopts a rolling 10-year procurement period, noting that the LTPPs cover a 10-year period and will be updated and reviewed every 2 years. The decision grants the Utility's petition for modification of its existing short-term procurement plan to permit all utilities to conduct procurement using negotiated bilateral agreements for transactions up to 3 calendar months, or one quarter, forward. The decision notes that ultimately the CPUC will eliminate short-term procurement plans and the utilities will act in accordance with a single CPUC-approved plan; but until then, the utilities' existing short-term plans remain in effect and any updates or modifications should be filed with an advice letter within 30 days afterUtility’s plan, see the issuancesection of the decision. The Utility filed an update to its short-term plan on January 18, 2005. The decision requires the utilities to submit a compliance filing updating their procurement plans to reflect the changes and modifications in the decision by March 25, 2005.•The decision directs the utilities to meet CPUC-mandated energy efficiency goals over the 10-year period, but defers consideration of the $245 million incremental revenue requirement requested by the Utility to fund energy efficiency programs for 2006 through 2008 to the CPUC's energy efficiency rulemaking proceeding.existing wholesale transmission customers that pre-date the Utility's participation inUtility entered into before 1998, when the ISO. Customers that receive transmission services under these pre-existing contracts,ISO commenced operations. These 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•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· 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.· Rates to recover the pass-through of ISO charges for reliability service costs and an ISO charge associated with cost differences in utility-specific transmission charges and an ISO grid-wide charge, both of which are discussed below. yearsyears’ notice and receive regulatory approval from the FERC if it wishes to withdraw from the TCA. At December 31, 2004, the Utility estimated that it could be obligated to pay the ISO approximately $570 million in costs incurred under these RMR agreements during the period January 1, 2005 to December 31, 2006. Of this amount, the Utility estimates that it would receive approximately $42 million under its RMR agreements during the same period. These costs and revenues are subject to applicable ratemaking mechanisms. For a discussion of a proposed settlement agreement entered into in January 2005 with Mirant Corporation and various of its subsidiaries to resolve the Utility's claims that it was overcharged under Mirant's RMR agreements and other RMR-related issues that could affect the Utility, see the section titled "Reliability Must Run Agreements" in MD&A.Reliability Services CostsISO 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 reliabilityUtility’s share of the Utility's transmission system. TheISO’s reliability service 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 werein 2005 was approximately $425 million in 2004.$217 million. Under the Utility'sUtility’s transmission owner tariff, the Utility charges its customers rates designed to recoverrecovers these reliability service charges,costs, without mark-up or service fees. The Utility also received approximately $59 million in 2005 under the RMR agreements that the Utility entered into with the ISO for the Utility’s units that have been designated as RMR units. The Utility tracks these costs and revenues related to reliability services in the reliability services balancing account. Periodically, the Utility'sUtility’s electricity transmission rates are adjusted to refund over-collections to the Utility'sUtility’s customers or to collect any under-collections from customers. In March 2000, thefiled an application with the FERC seeking to establish its ownimposes a transmission access charge as directed by AB 1890.on users of the ISO-controlled electricity transmission grid. The ISO's transmission access charge methodology approved by the FERC in December 2004 provides for 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. 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 other transmission owners (who are generally new ISO participants) whose costs for existing transmission are higher than that embedded in the uniform rate. Underrate, to transmission owners with lower embedded costs for existing transmission, such as the ISO's application, theUtility. The Utility's obligation for this cost differential would behas been capped at $32 million per year during the ten-year10-year transition period. In December 2004, the FERC issued an Order in this proceeding accepting the ISO's transmission access charge methodology. In 1998, the Utility implemented under which the Utility'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 gas2005-2007.2005 through 2007. The Utility continues to be at risk of not recovering its natural gas transportation and storage costs and does not have regulatory balancing account protection for over-collections or under-collections of most of its natural gas transportation or storage revenues, except for core local transmission revenue. Theovercollection,over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues. the core procurement incentive mechanism, or the CPIM, the Utility's natural gas 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 fall within a tolerance band, which is currently between 99% and 102% of the benchmark, are considered reasonable and are fully recoverable in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive three-fourths of the savings when the costs are below 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. Any awards associated with the CPIM are reflected annually in the purchased natural gas balancing account after the close of the annual period ending October 31 that is used to measure the CPIM. These awards are not included in earnings until approved by the CPUC.Gas Public Purpose Program Surcharges Authorized amounts for gas public purpose programs have been recovered through gas rate surcharges since January 1, 2001, pursuant to AB 1002, and are set on an annual basis. Effective March 1, 2005, the Utility intends to change its treatment of these gas surcharges to remove them from revenues and treat the surcharges as taxes, in accordance with a recent CPUC decision.General•The discharge of pollutants into air, water and soil;· The discharge of pollutants into air, water and soil; •· The identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting of, remediation of and emergency response in connection with hazardous and radioactive substances; and · Land use, including endangered species and habitat protection. •Land use, including endangered species and habitat protection.clean upclean-up of sites that contain hazardous substances are subject to a special ratemaking mechanism. In 1994, the CPUC established a ratemaking mechanism under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims (e.g., for cleaning up the Utility'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'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.There also is a special sharingAny 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 are retained by the Utility; 90% of any such recoveries are assigned to the Utility's customers. incurred pursuing recovery underthat it may incur to remediate hazardous waste through rates and insurance contracts. Inconnection 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.2004,2005, various multi-pollutant initiatives were introduced in the U.S. Senate and House of Representatives. These initiatives includeproposed limits on the emissions of nitrogen oxide, sulfur dioxide, mercury and carbon dioxide, and some would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules. Hearings on legislation to amend the federal Clean Air Act have been held in the U.S. Senate butAlthough these initiatives were not in the House of Representatives. Similarenacted into law, similar legislation is expected to be introduced in 2005. 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.2006. Two of the local air districts in which the Utility owns and operates fossil fuel-fired generation facilities have adopted final rules under the California Clean Air Act and the federal Clean Air Act that required reductions in nitrogen oxide emissions from the facilities of approximately 90% by 2004. The Utility is in compliance with these rules. The Utility is permitted to recover in customer rates 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 other 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.tanks, to comply with laws relating to emissions of carbon dioxide and other greenhouse gases, particulates and other toxic pollutants.tanks. If enacted, these laws could require the Utility to replace equipment, install additional pollution controls, purchase various emission allowances, or curtail operations. Although associated costs and capital expenditures could be material, the Utility expects that it would be able to recover these costs and capital expenditures in rates. In October 2000, the Utility and the Central Coast Board reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility's discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology meets the best technology available requirements. As part of the Central Coast settlement agreement, the Utility has agreed to take measures to preserve certain acreage north of the plant and will fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the Central Coast settlement agreement. On June 17, 2003, the Central Coast settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General's Office. A condition to the effectiveness of this settlement agreement is that the Central Coast Board renew Diablo Canyon's NPDES permit. At its July 10, 2003 meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the Central Coast settlement agreement accepted in March 2003, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists'a draft report prepared by a team of scientists recommending several such mitigation measures.measures to mitigate the effect of the cooling water system. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers.nearat both the Utility'sHinkley 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 2005, 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 Needles, California. In mid-January 2004 and again in mid-February 2005,California adjacent to the Colorado River, hexavalent chromium washas been detected in samples taken from groundwaterimpactaffect the Colorado River. In 2004,2005, the Utility took interim measures to control the chromium plume viaby extracting impacted groundwater and spent approximately $23.6 million.$38.8 million on these measures. The Utility plans to continue these activities in 2006 and to work toward the development of a final plan to address the plume in 2005.2006. The Utility currently estimates that it will spend at least $25$22 million in 2005 with respect to this matter. The Utility is currently2006 for remediation activities at Topock and $7.4 million in the process of obtaining additional samples from these and other wells and testing these additional samples.2006 for remediation activities at Hinkley. Although work at thisthe Topock 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 outcomeremediation of this matterthe Topock and Hinkley gas compressor sites to have a material adverse effect on its results of operations or financial condition.cleanupclean-up of polychlorinated biphenyls, or PCBs, which are used in certain electrical equipment. During the 1980s, theThe Utility initiated two major programs to removehas removed from service all of the distribution capacitors and network transformers containing high concentrations of PCBs. These programs removedPCBs, the vast majority of PCBs existing in the Utility's electricity distribution system.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 2827 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 $5.8$2 million in 20042005 and expects to spend approximately $7.2$5 million in 20052006 on these projects. The Utility expects that expenses will increase as remedial actions related to these sites are approved by regulatory agencies. In addition, approximately 68 other manufactured gas plants in the Utility's service territory are now owned by others. The Utility has not incurred any significant costs associated with these non-ownedspent approximately $4.1 million settling third-party remediation claims by the current owners of former manufactured gas plant sites butin 2005 and it is possible that the Utility may incur additional cleanupclean-up costs related to these sites in the future if hazardous substances for which the Utility has liability are found.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 studies and any necessary remedial measures by regulatory agencies. At the Casmalia disposal facility near Santa Maria, California, the Utility and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and mitigation measures.2004, and approximately $314 million at December 31, 2003.2004. During the year ended December 31, 2004,2005, the liability increased by approximately $13$142 million. This net increase reflects a $131 million mainly dueincrease attributable to reassessment ofa revised remediation estimate for the estimated cost ofTopock gas compressor station and a $24 million increase attributable to a revised remediation andestimate for the Hinkley gas compressor station. These increases, in addition to other increases in liability, were offset by remediation payments. The approximately $327$469 million accrued at December 31, 2004,2005, includes approximately $102$193 million for remediation at these gas compressor sites, approximately $100 million related to the pre-closing remediation liability associated with divested generation facilities, and approximately $225$176 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, third-party disposal sites, and manufactured gas plant sites that either are 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 $327$469 million environmental remediation liability, approximately $144$141 million has been included in prior rate settingrate-setting proceedings and the Utility expects that an additional approximately $141$259 million will be allowable for inclusion in future rates.$480$680 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than anticipated. The amount of approximately $480$680 million does not include an estimate for the cost of remediation at known sites owned or operated in the past by the Utility's predecessor corporations for which the Utility has not been able to determine whether a liability exists.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 contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities beginning not later than January 1998. 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. Under the Utility's contract with the DOE, if the DOE completes a storage facility by 2010, the earliest Diablo Canyon's spent fuel would be accepted for storage or disposal would be 2018.Diablo Canyon power plant's existingthe Utility's current facilities are able to store on-site all spent fuel pools have sufficient capacity to enable it to operateproduced through approximately 2007. TheIn March 2004, the NRC granted authorization toauthorized the Utility in March 2004 to build an on-site dry cask storage facility to store spent fuel through approximately 2021 for Unit 1 and to 2024 for Unit 2. Several intervenorsinterveners appealed the NRC's decision to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. Oral argumentsThe Ninth Circuit heard oral argument on thatthe appeal are expected in the first quarter ofOctober 2005, withand a decision anticipated in the second half of 2005.is pending. PG&E Corporation and the Utility cannot predict the outcome of these appeals.start in the second quarter of 2005 after grading permits are obtained from the County of San Luis Obispo.the Utility also has requested thatin November 2005 the NRC approve another storage optionauthorized the Utility to install a temporary storage rack in each unit's existing spent fuel storage pool that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 tountil 2011. The Utility anticipates that it would complete the installation of the temporary storage racks by December 2006. This temporary option woulddoes not require local or California Coastal permissionCommission permits to be obtained. If the on-siteUtility is unable to complete the dry cask storage facility, or if construction is not completeddelayed beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operationsoperation 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.AlthoughOn August 19, 2005, the NRC issued an inspection report concluding that the Utility was unable to account for the location of three 18-inch segments of used nuclear fuel. The NRC issued its report after the Utility filed its final report in May 2005 updating the NRC as to the Utility's efforts to locate the used fuel. The Utility's report concludes that it is very likely that these pieces were shipped to a low-level radioactive waste facility. In its August 19, 2005 report, the NRC determined that the Utility's inability to conclusively locate the used fuel segments havedid not been found after an initial searchpose any threat to the health and safety of the pool,public. In December 2005, the NRC issued a notice of violation to the Utility is continuingand imposed a penalty of $96,000 on the Utility for failure to control its effortsinventory and to search other, less accessible locationskeep adequate records of these materials. The Utility did not contest the finding of a violation and paid the penalty in the pool. It is possible that a complete search may not be concluded until the 390 used fuel assemblies, along with other components, are removed from the pool, as part of the plant decommissioning process currently set for 2009.filed an application withreceived a license from the NRC seeking authorization to build an on-site dry cask storage facility at Humboldt Bay Unit 3. The Utility plans to file an application withalso has received approval from the California Coastal Commission for a permit to build the facility. Transfer of spent fuel to athe dry cask facility wouldif it were licensed to employ an on-siteconstruction of the dry cask storage facility the Utility would receive a 20-year initial licensecan be completed in time for on-site dry cask storage with the opportunitydecommissioning of Humboldt Bay Unit 3 to receive a 20-year renewal term. The Utility's nuclear power facilities consist of two units at the Diablo Canyon power plant and the retired facility at Humboldt Bay Unit 3. For ratemaking purposes, the eventual decommissioning of Diablo Canyon Unit 1 is scheduled to begin in 2021 and to be completed in 2040. Decommissioning of Diablo Canyon Unit 2 is scheduled to begin in 2025 and to be completed in 2041, and decommissioning of Humboldt Bay Unit 3 is scheduled to begin in 2009 and to be completed in 2015. Thepower plantUnits 1 and 2 and Humboldt Bay Unit 3 is approximately $1.83$2.03 billion in 20042005 dollars (or approximately $5.25$5.12 billion in future dollars). These estimates are based on a 2002the 2005 decommissioning cost study and arestudies, prepared in accordance with CPUC requirements. The Utility's revenue requirements andfor nuclear decommissioning costs are used in the Utility's Nuclear Decommissioning Costs Triennial Proceeding discussed below.recovered from customers through a non-bypassable charge that will continue until those costs are fully recovered. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility'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. estimated nuclear decommissioning cost estimate described above is used for regulatory purposes. Under generally accepted accountingaccounted principles, or GAAP, requirements, the decommissioning cost estimate is calculated using a different method. In accordance with Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," the Utility adjusts its nuclear decommissioning obligation to reflect the fair value of decommissioning its nuclear power facilities. In addition, theThe Utility records the Utility's total nuclear decommissioning obligation as an asset retirement obligation on the Utility's Consolidated Balance Sheet. Decommissioning costs are recorded as a component of depreciation expense, with a corresponding credit to the asset retirement costs regulatory liability. The total nuclear decommissioning obligation accrued in accordance with GAAP was approximately $1.3 billion at December 31, 2005 and $1.2 billion at December 31, 2004 and $1.1 billion at December 31, 2003.CPUC has established the Nuclear Decommissioning Costs Triennial Proceeding to determineprimary difference between the Utility's estimated decommissioning costs and to establish the associated annual revenue requirement and escalation factors for consecutive three-year periods. The Utility's revenue requirements for nuclear decommissioning obligation as recorded in accordance with GAAP and the estimate prepared in accordance with the CPUC requirements is that GAAP incorporates various potential settlement dates for the obligation and includes an estimated amount for third-party labor costs are recovered from customers through a nonbypassable charge that will continue until those costs are fully recovered.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 thesuch decommissioning costs are actually incurred. In 2004,collectedwas authorized to collect approximately $18.4 million in rates and contributed approximately $18.4 million on an after-tax basis, to the qualified nuclear decommissioning trusts.trust for Humboldt Bay Unit 3. For 2005,2006, the Utility isOf this amount, theThe Utility expects to contribute approximately $18.4 million, on an after-tax basis,that entire amount to the qualified trusts for Humboldt Bay Unit 3. The Utility has requestedreceived approval from the IRS approveto contribute all of the newcollected amounts to be contributed to the qualified trust for Humboldt Bay Unit 3 for 2005. The Utility expects to file a ruling request with the IRS in the first quarter of 2006 for contributions made in 2006. The CPUC issued a decision in the 2002 NDCTP finding that the funds in the Diablo Canyon nuclear decommissioning trusts are sufficient to pay for the eventual decommissioning. Therefore, no contributions were made to the Diablo Canyon trusts in 2005 and no contributions are expected for 2006.If the IRS does not approve the request, the Utility must withdraw any contributions it made to the qualified trusts for 2003 and 2004 and contribute the withdrawn amounts, on an after-tax basis, to the non-qualified trust. The Utility would likely request thatexpects to begin evidentiary hearings with the CPUC approve an increase in revenue requirements to make up for the reduced amount contributed to the non-qualified trust due to the reduced rate of return attributable to taxes. The fundsMay 2006 and expects a decision 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 assets held in the trusts, net of authorized disbursements from the trusts and investment management and administrative fees, are reinvested. Amounts may not be released from the decommissioning trusts until authorized by the CPUC. At December 31, 2004, the Utility had accumulated decommissioning trust funds with an estimated fair value of approximately $1.6 billion, based on quoted market prices and net of deferred taxes on unrealized gains.913 of the Notes to the Consolidated Financial Statements in the 2005 Annual Report. It is not yet clear what actionsrespond to this report. In August 2004, the CPUC opened a rulemaking proceeding to determine if there are improvements that should be made to the CPUC's existing rules and regulations concerning EMFs. Possible outcomes include, but are not limited to, continuation of current policies and imposition of more stringent measures to mitigateutility EMF exposures. The Utility cannot estimate the costs of such mitigation measures with any certainty at thismatters.time. However, such costs could be significant, depending on the particular mitigation measures undertaken, especially if the Utility must ultimately relocate existing power lines. Utility's corporate headquarters consist of approximately 1.8 million square feet of office space located in several buildings in San Francisco, California. In addition to this corporate office space, the Utility owns or has obtained the right to occupy and/or use real property comprising the Utility'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 Utility Operations" and "Gas Utility Operations." In total, the Utility occupies 9.38.2 million square feet of real property, including approximately 975,0007.0 million square feet the Utility owns. Of the 8.2 million square feet of leasedoccupied real property, approximately 1.5 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 1.5 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.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. 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's or a joint licensee's hydroelectric generation facilities and maywill only be encumbered with conservation easements. As contemplated in the Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council, or the Council.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 guided 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 one out of 18 members of the boardBoard of directorsDirectors of the Council. Other board members include representatives of federal and state agencies, non-governmental organizations, and tribal interests. The Council will recommend a planis charged to preserveadopt and present the 140,000 acresLCP to the Utility by April��April 2007. If the Council reaches consensus on the plan, theThe Utility will then seek regulatory approval ofauthorization from the CPUC, the FERC and other approving entities to proceed with the transactions requirednecessary to implement the plan.LCP. If the Council is unable to reach consensus on all or part of the plan,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.California.California, or Bankruptcy Court. On April 12, 2004, the Utility's plan of reorganization under Chapter 11 became effective. David A. Coulter, a director of the Utility, is Vice Chairman of J.P. Morgan Chase & Co. and J.P. Morgan Chase Bank. J.P. Morgan Trust Co. of Delaware submitted a proof of claim in the Utility's Chapter 11 case for approximately $1.45 million relating to its ownership interest in shares of the Utility's preferred stock. The bankruptcy court disallowed this claim. J.P. Morgan Chase Bank submitted a proof of claim for approximately $173 million, related to its provision of a stand-by letter of credit which provides credit and liquidity support for certain of the Utility's pollution control bonds. This claim was paid upon the Effective Date of the Utility's plan of reorganization. Both entities are subsidiaries of J.P. Morgan Chase & Co. settlement agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's Chapter 11 proceeding, or Settlement Agreement. Under the Settlement Agreement, the CPUC has waived all existing and future rights of sovereign immunity, and all other similar immunities, as a defense in connection with any action or proceeding concerning the enforcement of, or other determination of the parties' rights under the Settlement Agreement, the plan of reorganization or the confirmation order. The CPUC also consented to the jurisdiction of any court or other tribunal or forum for those actions or proceedings, including the bankruptcy court.Bankruptcy Court. The CPUC's waiver is irrevocable and applies to the jurisdiction of any court, legal process, suit, judgment, attachment in aid of execution of a judgment, attachment before judgment, set-off or any other legal process with respect to the enforcement of, or other determination of the parties' rights under, the Settlement Agreement, the plan of reorganization or the confirmation order. The Settlement Agreement contemplates that neither the CPUC nor any other California entity acting on its behalf may assert immunity in an action or proceeding concerning the parties' rights under the Settlement Agreement, the plan of reorganization or the confirmation order.bankruptcy courtBankruptcy Court will have jurisdiction over the parties for all purposes relating to enforcement of the Settlement Agreement, the plan of reorganization and the confirmation order. The bankruptcy courtBankruptcy Court retains jurisdiction to resolve remaining disputed claims. The parties also agreed that the Settlement Agreement, the plan of reorganization or any order entered by the bankruptcy courtBankruptcy Court contemplated or required to implement the Settlement Agreement or the plan of reorganization will be irrevocable and binding on the parties and enforceable under federal law notwithstanding any future decisions or orders of the CPUC. On March 16, 2004, thedenied separate applications that had been filed by the City of Palo Alto, the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, requesting that the CPUC rehear and reconsider its December 18, 2003 decision approving the Settlement Agreement. CCSF, Aglet and the CPUC's Office of Ratepayer Advocates, or ORA, also filed a joint application for rehearing. On April 15, 2004, CCSF and Aglet each filed a petition with the California Court of Appeal seeking review of the CPUC's December 18, 2003 decision approvingcommissioners who did not vote to approve the Settlement Agreement and the CPUC's March 16, 2004 decision denying applications for rehearing of its December 18, 2003 decision. CCSF and Aglet allege that the Settlement Agreement violates California law, among other claims. CCSF requests that the appellate court hear and review the CPUC's decisions, approving the Settlement Agreement and Aglet requests that the CPUC's decisions be overturned. Three California state senators have filed a brief in supportan appeal of the CCSF and Aglet petitions. The California Court of Appeal has not yet acted on the petitions. PG&E Corporation and the Utility believe the petitions are without merit and should be denied. On July 15, 2004,Bankruptcy Court's confirmation order with the U.S. District Court for the Northern District of California, or the District Court. On July 15, 2004, the District Court dismissed the appeals of the bankruptcy court's confirmation order that had been filed by the two CPUCtheir appeal. The former commissioners who did not vote to approve the Settlement Agreement. These two commissioners alsohave appealed the District Court's order withto the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. AnThe Ninth Circuit heard oral arguments on the appeal of the confirmation order filed by the City of Palo Alto remains pending at the District Court. PG&E Corporation and the Utility believe the appeals of the confirmation order are without merit.dismissed.dismissed as moot. If notwithstanding this federal precedent, the bankruptcy court'sBankruptcy Court's confirmation order or the Settlement Agreement is subsequently overturned or modified on appeal, PG&E CorporationCorporation's and the Utility's financial condition and results of operations, and the Utility's ability to pay dividends or otherwise make distributions to PG&E Corporation, could be materially adversely affected. The Utility's complaint alleges that the wholesale electricity costs that the Utility has prudently incurred are paid pursuant to filed tariffs that the FERC has authorized and approved, and that, under the U.S. Constitution and numerous court decisions, such costs cannot be disallowed by state regulators. The Utility's complaint also alleges that, to the extent that the Utility is denied recovery of these wholesale electricity costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of the Utility's property. The Utility argues that the CPUC's decisions are preempted by federal law under the filed rate doctrine, which requires the CPUC to allow the Utility to recover in full its reasonable purchase costs incurred under lawful rates and tariffs approved by the FERC, a federal governmental agency. The complaint also asserts claims under the Commerce Clause and the Due Process Clause of the U.S. Constitution. On January 29, 2001, the Utility's lawsuit was transferred to the U.S. District Court for the Central District of California, where a similar lawsuit filed by Southern California Edison Company was pending. On May 2, 2001, the court dismissed the Utility's complaints without prejudice to re-filing at a later date, on the ground that the lawsuit was premature, since two CPUC decisions referenced in the complaint had not become final under California law. The court rejected all of the CPUC's other arguments for dismissal of the Utility's complaint. In August 2001, the Utility re-filed the Utility's complaint in the District Court based on the Utility's belief that the CPUC decisions referenced in the court's May 2001 order had become final under California law. On October 31, 2001, the CPUC moved to dismiss the action. While the motion was under submission, the parties filed cross-motions for summary judgment. On July 25, 2002, the court denied the CPUC's motion to dismiss on all grounds, as well as the parties' motions for summary judgment. While the court agreed with the Utility's position that the filed rate doctrine applies to the federally-tariffed wholesale costs at which the Utility had purchased electricity, it held that certain triable issues of fact precluded entry of summary judgment in the Utility's favor. On August 23, 2002, the CPUC filed an appeal to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. Pursuant to the Utility's request, the District Court certified the appeal as "wholly without merit and, therefore, frivolous," and rejected the CPUC's request to stay the proceedings. On November 21, 2002, the Ninth Circuit stayed the District Court's proceedings pending the CPUC's appeal. The appeal was fully briefed and the Ninth Circuit heard oral argument on March 10, 2003.TheSince the appeal brought by two former CPUC commissioners challenging thecomplaint, pending the outcome of the appeals of the CPUC's approval of the Settlement Agreement discussed above.whichthat is regulated under a NPDES permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility's Diablo Canyon power plant's discharge was not protective of beneficial uses. with the Central Coast Board pursuant to which the Central Coast Board agreed to find that the Utility'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 Coast settlement agreement, the Utility agreed to take measures to preserve certain acreage north of the plant and to 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's Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon's NPDES permit.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, The California Attorney General also alleged that the December 2000 and January and February 2001 ringfencing transactions, by which PG&E Corporation subsidiaries complied with credit rating agency criteria to establish independent credit ratings, violated the holding company conditions. 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 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 Superior Court, omitting the allegations concerning PG&E Corporation's participation in the Utility's Chapter 11 proceedings.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 $5.2payment to customers,restitution, disgorgement, the imposition of a constructive trust, civil penalties of $2,500 against each defendant for each violation of Section 17200 and costs of suit. After removingCity's actionCPUC issued two decisions in its investigative proceeding commenced in April 2001 into whether the California investor-owned electric utilities, including the Utility, complied with past CPUC decisions, rules and orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC would, among other matters, investigate the utilities' transfer of money to their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties the bankruptcy courtfailure of the holding companies to financially assist the utilities when needed, the transfer by the holding companies of assets to unregulated subsidiaries, and the holding companies' actions to "ringfence" their unregulated subsidiaries. In May 2005, the CPUC closed this investigation without making any findings. Under the Settlement Agreement, the CPUC agreed to dismiss with prejudice PG&E Corporation and the Utility from the CPUC's investigation as to past practices.a motionnotices of removal in the Bankruptcy Court to dismisstransfer the complaint.complaints to the Bankruptcy Court. Subsequently, the Cityplaintiffs filed a motionmotions to remand the actiontheir actions 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 bankruptcy court issuedproceedings. The Bankruptcy Court directed the California Attorney General to file an amended order on motioncomplaint omitting certain of his Section 17200 allegations and remanded the amended complaint to remand stating that the bankruptcy courtSuperior Court. The Bankruptcy Court retained jurisdiction over theCCSF’s 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,CCSF, but remanding theremanded CCSF’s Section 17200 cause of action to state court. BothIn both cases, the parties appealed the bankruptcy court'sBankruptcy Court’s remand order to the District Court.bankruptcy court'sBankruptcy Court’s June 2002 decision and ordered that the California Attorney General'splaintiffs’ restitution claims under Section 17200 be sent back to the bankruptcy court.Bankruptcy Court. The District Court found that these claims, estimated along with the City and County of San Francisco's claims atby plaintiffs to be approximately $5 billion, are the property of the Utility'sUtility’s Chapter 11 estate and are therefore are properly within the bankruptcy court'sBankruptcy Court’s jurisdiction. Under the Plan of Reorganization, the Utility has released these claims. The District Court also affirmed, in part, the bankruptcy court'sBankruptcy Court’s June 2002 decision and found that the California Attorney General'splaintiffs’ civil penalty and injunctive relief claims under Section 17200 could be resolved in Superior Court. The California Attorney General and CCSF appealed the City and County of San Francisco have appealed this rulingDistrict Court’s remand order to the Ninth Circuit, where the appeal is currently pending.Circuit.has coordinateddid not address the California Attorney General's case with the case filed by the City and Countyquestion of San Francisco. At a hearing on December 8, 2004, the Superior Court heard argument on the issue of how to determine the number ofwhether any violations of Section 17200 for purposes of calculating the amount of potential civil penalties at issue. Under Section 17200, the Superior Court can impose a civil penalty for each violation of up to $2,500. On January 21,occurred. In March 2005, the Superior Court issued a tentative decision rejecting the "per victim"“per victim” and "per“per [customer] bill"bill” approaches advocated by the plaintiffs, standards that potentially could have resulted in millions of separate "violations."“violations.” The Superior Court found that the appropriate standard was each transfer of money from the Utility to PG&E Corporation that plaintiffs allege violated Section 17200.Superior Court statedNinth Circuit ruled that it would consider any non-substantive revisionsthe plaintiffs’ restitution claims constituted actions to enforce their police or regulatory power, actions which are exempt from the provisions of the Bankruptcy Code permitting removal of state actions to Bankruptcy Court. The Ninth Circuit remanded the restitution claims back to the tentative decision proposedSuperior Court. PG&E Corporation has filed a request for rehearing en banc with the Ninth Circuit.parties at a case management conferenceCPUC against PG&E Corporation or the Utility arising out of or in any way related to the energy crisis are released, including the CPUC’s investigation into past PG&E Corporation actions during the energy crisis. Accordingly, PG&E Corporation believes that any claims for such proceeds by the CPUC would be held on February 25, 2005.applicable calculation methodology for civil penalties, if any violations were found,California Attorney General’s and CCSF’s allegations have no merit and will continue to vigorously respond to and defend against the litigation.PG&E Corporation believes that the ultimate outcome of this matter would not result in a material adverse effect on itsPG&E Corporation’s financial condition or results of operations.1412 civil suits are pending in several California courts against the Utility relating to alleged chromium contamination: (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995, in the Superior Court for the County of Los Angeles or Los Angeles County Superior Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996, in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November 27, 1996, in Los Angeles County Superior Court, (4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed July 25, 2000, in Los Angeles County Superior Court, (5) Baldonado v. Pacific Gas and Electric Company, filed October 25, 2000, in Los Angeles County Superior Court, (6) Gale v. Pacific Gas and Electric Company, filed January 30, 2001, in Los Angeles County Superior Court, (7) Fordyce v. Pacific Gas and Electric Company, filed March 16, 2001, in San Bernardino Superior Court, (8) Puckett v. Pacific Gas and Electric Company, filed March 30, 2001, in Los Angeles County Superior Court, (9) Alderson, et al. v. PG&E Corporation, Pacific Gas and Electric Company, Betz Chemical Company, et al., filed April 11, 2001, in Los Angeles County Superior Court, (10) Bowers, et al. v. Pacific Gas and Electric Company, et al., filed April 20, 2001, in Los Angeles County Superior Court, (11) Boyd, et al. v. Pacific Gas and Electric Company, et al., filed May 2, 2001, in Los Angeles County Superior Court, (12) Martinez, et al. v. Pacific Gas and Electric Company, filed June 29, 2001, in San Bernardino County Superior Court and (13) Miller v. Pacific Gas and Electric Company, filed November 21, 2001, in Los Angeles County Superior Court, and (14) Lytle v. Pacific Gas and Electric Company, filed March 22, 2002, in Yolo County Superior Court.except the Lytle case, which is pending in Yolo County. Currently thereor Superior Court. There are now approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals have filed proofs of claim in the Utility's Chapter 11 case, mostChromium Litigation who seek compensatory damages, more than 1,000 of whom are plaintiffsalso seeking punitive damages. Although the plaintiffs’ complaints in the chromium litigation. Approximately 1,035 claimants haveChromium Litigation do not state the amount of compensatory or punitive damages claimed, approximately 1,000 of the current plaintiffs filed proofsclaims in the Utility’s Chapter 11 proceeding requesting compensatory damages in an approximate aggregate amount of claim requesting approximately $580$500 million in damages and another approximately 225 claimants haveothers filed claims for an "unknown amount."at or nearcontamination in the vicinity of the Utility's gas compressor stations located at Kettleman and Hinkley, California, and the area of California near Topock, Arizona, caused personal injuries, wrongful death or other injuryinjuries, and seek related damages.bankruptcy court has granted certain claimants' motions for relief from stay so thatfollowing cases are covered by the state court lawsuits pending before the Utility's Chapter 11 filing can proceed.is respondinghas agreed to pay $295 million to the suitssettling plaintiffs. The Utility will deposit the settlement amount into escrow on April 21, 2006. The settling plaintiffs are required to execute general releases in whichfavor of the Utility, hasPG&E Corporation, its officers, directors, employees, and other affiliates, as to any and all claims asserted or which could have been servedasserted in the Chromium Litigation. After receipt of releases from at least 90% of the settling plaintiffs, executed requests for dismissals with prejudice of the settled cases, and is asserting affirmative defenses. Thedocumentation evidencing the Superior Court’s approval of the compromises or settlements with the settling plaintiffs who are minors, payments will be released from escrow to plaintiffs’ attorneys for the plaintiffs who have submitted executed releases. If 90% of the settling plaintiffs do not execute releases by September 15, 2006, including a release signed by each of the eighteen plaintiffs scheduled to participate in the first trial, the Utility may, at its option, terminate the settlement agreement. In order to obtain 100% of the settlement funds from escrow, plaintiffs’ attorneys must submit releases from or on behalf of 100% of the settling plaintiffs.workers'workers’ compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select plaintiffs from theAguayo, Acosta andAguilar cases for a test trial. Plaintiffs' counsel selected ten of these initial trial plaintiffs, defense counsel selected seven of the plaintiffs, and one plaintiff and two alternates were selected at random. The Utility has filed 14 summary judgment motions or motions in limine (motions to exclude potentially prejudicial information) challenging the claims of the trial test plaintiffs. The Los Angeles Superior Court began hearing argument on two of the motions in February 2004. At a hearing on February 14, 2005, the court indicated that it had signed orders denying these two motions, but the orders have not been delivered to the parties. The court set a trial date of January 9, 2006 for the first eighteen plaintiffs. The other motions will be heard throughout 2005.the Utility'sits financial statements in the amount of $160 million for these matters. The Utility believes that, in light of the reserves that have already been accrued with respect to this matter, the ultimateChromium Litigation. PG&E Corporation and the Utility do not expect that the outcome of this matterwith respect to the remaining unresolved claims will not have a material adverse impacteffect on the Utility'stheir financial condition or future results of operations. "Theexecutive"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, 2004February 1, 2006, are as follows:AgePositionR. D. Glynn, Jr. 62P. A. Darbee 53 Chairman of the Board, Chief Executive Officer and President P. A. DarbeeL. H. Everett 5155Senior Vice President, Communications and Public Affairs K.M. Harvey 47 Senior Vice President and Chief FinancialRisk and Audit OfficerL. H. Everett54Senior Vice President and Assistant to the ChairmanR. A.M. Jackson 4748 Senior Vice President, Human Resources C. P. Johns 4445 Senior Vice President, Chief Financial Officer and ControllerTreasurerT. B. King 43Executive Vice President and Chief of Utility Operations, Pacific Gas and Electric CompanyD. D. Richard, Jr.54Senior Vice President, Public AffairsG. R. Smith5644 Senior Vice President; President and Chief Executive Officer, Pacific Gas and Electric Company R. L. Rosenberg 52 Senior Vice President, Corporate Strategy and Development B. R. Worthington 5556 Senior Vice President and General Counsel through December 31, 2004, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation. Effective January 1, 2005, Peter A. Darbee became President and Chief Executive Officer of PG&E Corporation replacing Mr. Glynn, who continues to serve as P. A. Darbee Chairman of the Board, of Directors of each of PG&E Corporation and Pacific Gas and Electric Company. Mr. Darbee also became a director of PG&E Corporation and Pacific Gas and Electric Company on January 1, 2005. Also, effective January 1, 2005, Christopher P. Johns became Senior Vice President and Chief Financial Officer replacing Mr. Darbee. Mr. Johns continues to be the Controller of PG&E Corporation. Effective January 1, 2005, Ms. Everett became Senior Vice President and Assistant to the Chief Executive Officer.NamePositionPeriod Held OfficeR. D. Glynn, Jr.Chief Executive Officer and President of PG&E Corporation January 1, 19982006 to December 31, 2004present Chairman of the Board, PG&E Corporation and Pacific Gas and Electric Company January 1, 19982006 to presentP. A. Darbee
President and Chief Executive OfficerJanuary 1, 2005 to December 31, 2005 Senior Vice President and Chief Financial Officer
July 9, 2001 to December 31, 2004 Senior Vice President, Chief Financial Officer, and Treasurer September 20, 1999 to July 8, 2001 L. H. Everett
Senior Vice President, Communications and Public AffairsJanuary 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 Vice President, Corporate Secretary, and Assistant to the Chairman May 1, 2001 to May 31, 2001 Vice President and Corporate Secretary July 1, 1997 to April 30, 2001 Vice President and Corporate Secretary, Pacific Gas and Electric Company November 1, 1996 to April 30,May 31, 2001K. 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 30, 2005 Senior Vice President - Chief Financial Officer, Controller, and Treasurer, Pacific Gas and Electric Company January 1, 2000 to October 31, 2000 R. A.M. Jackson
Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric Company
August 2, 2004 to present Vice President, Human Resources, PG&E Corporation June 1, 2004 to August 1, 2004 Vice President, Human Resources, Pacific Gas and Electric Company June 1, 1999 to August 1, 2004 C. P. Johns
Senior Vice President, Chief Financial Officer and TreasurerOctober 4, 2005 to present Senior 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 December 31, 2004 Vice President and Controller July 1, 1997 to September 18, 2001 T. B. King Senior Vice President, PG&E Corporation January 1, 2006 to present President and Controller,Chief Executive Officer, Pacific Gas and Electric Company JuneJanuary 1, 19962006 to presentExecutive Vice President and Chief Operating Officer, Pacific Gas and Electric Company July 1, 2005 to December 31, 19992005T. B. King
Executive Vice President and Chief of Utility Operations, Pacific Gas and Electric Company
August 2, 2004 to presentJune 30, 2005 Senior Vice President and Chief of Utility Operations, Pacific Gas and Electric Company 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 D. D. Richard, Jr
R. L. Rosenberg Senior Vice President, Public AffairsCorporate Strategy and Development
October 18, 2000November 1, 2005 to present Executive Vice President Governmental Relationsand Chief Financial Officer, Infospace, Inc. July 1, 1997September 2000 to October 17, 2000January 20, 2001 Chief Financial Officer and Senior Vice President, Public Affairs, Pacific GasFinance and Electric CompanyCorporate Development, Infospace, Inc. May 1, 1998June 2000 to presentSeptember 2000 G.R. SmithB. R. Worthington
Senior Vice PresidentJanuary 1, 1999 to presentPresident and Chief Executive Officer, Pacific Gas and Electric CompanyGeneral Counsel June 1, 1997 to present B. R. WorthingtonSenior Vice President and General CounselJune 1, 1997 to presentDecember 31, 2004February 1, 2006, are as follows:AgePositionR.D. Glynn, Jr. 62P.A. Darbee 53 Chairman of the Board of DirectorsG. R. SmithT. B. King 5644 President and Chief Executive Officer T. B. KingE. Bottorff 43Executive Vice President and Chief of Utility OperationsP.A. Darbee5152 Senior Vice President, and Chief Financial Officer of PG&E CorporationRegulatory RelationsJ. D. Butler 50 Senior Vice President, Energy Delivery L.H. Everett 5455 Senior Vice President, Communications and Assistant to the Chairman,Public Affairs, PG&E CorporationK. M. Harvey46Senior Vice President—Chief Financial Officer, and TreasurerR.M. Jackson 4748 Senior Vice President, Human Resources R. J. PetersC. P. Johns 5445 Senior Vice President, Chief Financial Officer and General CounselTreasurerD. D. Richard, Jr.J. S. Keenan 54Senior Vice President, Public AffairsG. M. Rueger5457 Senior Vice President, Generation and Chief Nuclear Officer S. M. Ramsay 47 Vice President, Asset Management and Electric Transmission F Wan 44 Vice President, Energy Procurement B. R. Worthington 5556 Senior Vice President and General Counsel, PG&E Corporation December 31, 2004,February 1, 2006, 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.R. D. Glynn, Jr. P. 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, 19982006 to presentPresident 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 Chairman of the Board, Pacific GasSenior Vice President, Chief Financial Officer, and Electric CompanyTreasurer, PG&E CorporationSeptember 20, 1999 to July 8, 2001 T. B. King President and Chief Executive Officer January 1, 2006 to present Senior Vice President, PG&E Corporation January 1, 19982006 to presentG. R. Smith
Executive Vice President and Chief ExecutiveOperating Officer Senior Vice President, PG&E Corporation
JuneJuly 1, 19972005 to presentJanuary 1, 1999 to presentDecember 31, 2005T. B. King
Executive Vice President and Chief of Utility Operations
August 2, 2004 to presentJune 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 PG&E Gas Transmission CorporationPresident and Chief Operating Officer, Gas Transmission, PG&E National Energy Group, Inc. August 9, 2002 to November 14, 2002 Transmission, PG&E National Energy Group, Inc.President and Chief Operating Officer, July 1, 2000 to August 8, 2002West 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 P. A. DarbeeT. E. Bottorff
Senior Vice President, and Chief Financial Officer, PG&E CorporationRegulatory Relations
July 9, 2001October 14, 2005 to December 31, 2004present Senior Vice President, Chief Financial Officer,Customer Service and Treasurer,RevenueMarch 1, 2004 to October 13, 2005 Vice President, Customer Service June 1, 1999 to February 29, 2004 J. 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 L. H. Everett Senior Vice President, Communications and Public Affairs, PG&E Corporation September 20, 1999January 9, 2006 to July 8, 2001presentL. H. Everett
Senior Vice President and Assistant to the Chief Executive Officer, PG&E CorporationJanuary 1, 2005 to January 8, 2006 Senior Vice President and Assistant to the Chairman, PG&E 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 Vice President, Corporate Secretary, and Assistant to the Chairman, PG&E Corporation May 1, 2001 to May 31, 2001 Vice President and Corporate Secretary, PG&E Corporation July 1, 1997 to April 30, 2001 Vice President and Corporate Secretary November 1, 1996 to April 30,May 31, 2001K. M. HarveySenior Vice President, Chief Financial Officer, and TreasurerNovember 1, 2000 to present Senior Vice President, Chief Financial Officer, Controller, and Treasurer January 1, 2000 to October 31, 2000
R. A.M. Jackson
Senior Vice President, Human Resources, Pacific Gas and Electric Company and PG&E Corporation
August 2, 2004 to present Vice President, Human Resources, PG&E Corporation June 1, 2004 to August 1, 2004 Vice President, Human Resources June 1, 1999 to August 1, 2004 R. J. Peters
C. P. Johns Senior Vice President, Chief Financial Officer and General CounselTreasurer
JanuaryOctober 1, 1999 to presentD. D. Richard, Jr.Senior Vice President, Public AffairsMay 1, 19982005 to present Senior Vice President, Public Affairs,Chief Financial Officer and Treasurer, PG&E Corporation October 18, 2000 to presentVice President, Governmental Relations, PG&E CorporationJuly 1, 1997 to October 17, 2000G. M. RuegerSenior Vice President, Generation and Chief Nuclear OfficerApril 2, 20004, 2005 to present Senior Vice President, Chief Financial Officer and General Manager,Controller, PG&E CorporationJanuary 1, 2005 to October 3, 2005 Senior Vice President and Controller, PG&E Corporation September 19, 2001 to December 31, 2004 Vice President and Controller, PG&E Corporation July 1, 1997 to September 18, 2001 J. S. Keenan Senior Vice President, Generation and Chief Nuclear Officer December 19, 2005 to present Vice 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 S. 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 February 1, 2004 to June 30, 2005 Senior Vice President, Power Generation Business Unitand Gas, UMS Group, Inc.October 1, 2001 to January 31, 2004 Managing Director, UK Operations, UMS Group, Inc. January 2, 2001 to September 30, 2001 F. 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, 2004B. R. Worthington
Senior Vice President and General Counsel, PG&E Corporation
June 1, 1997 to present the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities (a) Information responding to part of Item 5, for each of PG&E Corporation and Pacific Gas and Electric Company, is set forth under the heading "Quarterly Consolidated Financial Data (Unaudited)" in the 2004 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. As of February 15, 2005,1, 2006, there were 103, 70798,083 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed principally on the New York Stock Exchange. PG&E Corporation common stock also is listed on the Pacific Exchange and the Swiss stock exchanges. The high and low 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 2005 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. The discussion of dividends with respect to PG&E Corporation's common stock is hereby incorporated by reference from "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Financial Resources—Dividends" of the 20042005 Annual Report.During the quarter endedOn November 17, 2005 and December 31, 2004,29, 2005, warrant holders exercised, on a net exercise basis, warrants to purchase, 961,480in the aggregate, 73,559 shares, and received, 961,183 shares of PG&E Corporation common stock. As of December 31, 2004, warrant holders had exercised, on a net exercise basis, warrants to purchase 4,719,019 shares, and had received 4,717,290in the aggregate, 73,538 shares of PG&E Corporation common stock sincein reliance on the warrants were issued.2004, the period covered by this report.Period Total Number of
Shares Purchased Average Price
Paid Per Share Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs(1)(2)(3) Approximate Dollar
Value that may yet
be Purchased Under
the Plans or
ProgramsOctober 1 through October 31, 2004 — — — $ 350,000,000 November 1 through November 30, 2004 340,000 $ 33.5676 340,000 $ 350,000,000 December 1 through December 31, 2004 11,293,200 $ 32.4493 11,293,200 — Total 11,633,200 (4) $ 32.4820 11,633,200 $ — (1)On September 15, 2004, the October 1 through October 31, 2005 - $ - - $ - November 1 through November 30, 2005 31,650,300 $ 34.75 31,650,300 $ 500,000,000 December 1 through December 31, 2005 - $ - - $ - 31,650,300 $ 34.75 31,650,300 $ 500,000,000 On September 15, 2004, the PG&E Corporation Board of Directors authorized PG&E Corporation and its subsidiaries to repurchase shares of PG&E Corporation's common stock with an aggregate purchase price not to exceed PG&E Corporation's net cash proceeds from sales of PG&E Corporation's common stock upon exercise of options granted under PG&E Corporation's Stock Option Plan. The program was publicly announced in a Current Report on Form 8-K filed by PG&E Corporation on October 14, 2004. The program expired on December 31, 2005. On December 15, 2004, the PG&E Corporation Board of Directors authorized the repurchase of up to $975 million in PG&E Corporation common stock. The program was publicly announced in a Current Report on Form 8-K filed by PG&E Corporation on December 16, 2004. On February 16, 2005, the Board of Directors increased the repurchase authorization to $1.05 billion, which was announced in PG&E Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004. PG&E Corporation used all of this authorization to enter into an accelerated share repurchase arrangement on March 4, 2005 with Goldman, Sachs & Co., Inc., or GS&Co, to repurchase 29,489,400 shares at an initial price of $35.60 per share. Under the share forward component of the March 2005 arrangement, certain additional payments were required by both PG&E Corporation and GS&Co upon termination. Most significantly, PG&E Corporation was to receive from, or be required to pay to, GS&Co a price adjustment on the repurchased shares based on the difference between the amount it paid and the daily volume weighted average price, or VWAP, of PG&E Corporation common stock over the approximately six-month intended arrangement period. PG&E Corporation made additional payments to GS&Co of $78,000 on June 30, 2005 and $22 million on September 12, 2005. The amount of the price adjustment based on the VWAP of PG&E Corporation common stock over the term of the arrangement increased the average purchase price per share to $36.19. On October 19, 2005, the PG&E Corporation Board of Directors authorized the repurchase of up to $1.6 billion in shares of PG&E Corporation's common stock, from time to time, but no later than December 31, 2006. The program was publicly announced in a Current Report on Form 8-K filed by PG&E Corporation on October 21, 2005. As described in a Current Report on Form 8-K filed by PG&E Corporation on November 18, 2005, PG&E Corporation entered into an accelerated share repurchase arrangement with GS&Co on November 16, 2005 under which PG&E Corporation repurchased 31,650,300 shares of its outstanding common stock at an initial price of $34.75 per share and an aggregate price of approximately $1.1 billion. As with the March 2005arrangement, PG&E Corporation may receive from, or be required to pay, GS&Co various payments, including a price adjustment based on the daily VWAP of PG&E Corporation common stock over a period of approximately seven months. Directors authorized the Corporation2005, Pacific Gas and its subsidiaries to repurchase shares of PG&E Corporation's common stock with an aggregate purchase priceElectric Company did not to exceed PG&E Corporation's net cash proceeds from sales of PG&E Corporation's common stock upon exercise of options granted under PG&E Corporation's Stock Option Plan. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. Repurchases may be made from time until the program expires on December 31, 2005. Amounts remaining under this program are not determinable as PG&E Corporation cannot predict how many options will be exercised before December 31, 2005.(2)Also on September 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase up to $350 million in shares of PG&E Corporation's common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. As of December 13, 2004, when PG&E Corporation terminated its open market stock purchase program, PG&E Corporation had used approximately $32 million of the previously announced $350 million authorization to repurchase shares. As disclosed in a Form 8-K filed on December 16, 2004, PG&E Corporation entered into accelerated share repurchase arrangements with a broker on December 15, 2004, under which PG&E Corporation used the remaining approximately $318 million to repurchase shares of its common stock on an accelerated basis.(3)On December 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase up to $975 million in shares of PG&E Corporation's common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on December 16, 2004. As disclosed in a Form 8-K filed on December 23, 2004, PG&E Corporation entered into accelerated share repurchase arrangements with a broker on December 23, 2004, but provided notice of termination of these arrangements on January 31, 2005, effective on February 1, 2005. PG&E Corporation did notredeem or repurchase any shares of its commonvarious series of preferred stock under this program.(4)Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation, purchased 850,000 shares of PG&E Corporation common stock during the fourth quarter. These shares remain outstanding under California law although for accounting purposes they are treated as if they were treasury shares.20042005 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.on under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the 20042005 Annual Report, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.20042005 Annual Report under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities," and under Notes 1 and 812 of the "Notes to the Consolidated Financial Statements" of the 20042005 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.20042005 Annual Report under the following headings for PG&E Corporation: "Consolidated Statements of Operations,Income," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of 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' 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. Pacific Gas and Electric Company's, or the Utility's disclosure controls and procedures as of December 31, 2004,2005, PG&E Corporation's and the 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 the Utility in reports the companies file or submit under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. As of January 1, 2004, PG&E Corporation and the Utility adopted the Financial Accounting Standards Board's, or FASB, revision to FASB Interpretation No. 46, "Consolidation of Variable Interest Entities," or FIN 46R. In accordance with FIN 46R, the Utility consolidated the assets, liabilities and non-controlling interests of low-income housing partnerships that were determined to be variable interest entities, or VIEs, under FIN 46R. PG&E Corporation and the Utility do not have the legal right or authority to assess the internal controls of VIEs. Therefore, PG&E Corporation and the Utility's evaluation of disclosure controls and procedures performed as of December 31, 2004 did not include these entities in that evaluation. PG&E Corporation and the Utility have not designed, established, or maintained disclosure controls and procedures for consolidated VIEs.controlscontrol over financial reporting that occurred during the quarter ended December 31, 20042005 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's controlsinternal control over financial reporting.the 2004their joint 2005 Annual Report to Shareholders under the heading "Management's Report on Internal Control Over Financial Reporting" and "Report of Independent Registered Public Accounting Firm," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. On of PG&E Corporation, or the Board, adopted a Golden Parachute Restriction Policy that became effective on February 16, 2005,15, 2006, subject to existing contractual obligations. This policy requires that the holders of a majority of the shares represented and voting approve executive severance payments provided in connection with a change in control of PG&E Corporation to the extent that those payments exceed 2.99 times the sum of a covered officer’s base salary and target annual bonus. The Golden Parachute Restriction Policy applies generally to the value of cash, special benefits, or perquisites that would be due to the executive following both a change in control and the termination or constructive termination of an officer covered by the PG&E Corporation Officer Severance Policy. It does not apply to the value of benefits that would be triggered by a change in control without severance, or to the value of benefits that would be triggered by severance in the absence of a change in control. Under the Golden Parachute Restriction Policy, the Board has delegated to the Nominating, Compensation and Governance Committee of the Board, or the Committee, full authority to make determinations regarding the interpretation of Directorsthe provisions of the Golden Parachute Restriction Policy in its sole discretion.Committee, nominated the following individuals for election as directorsvoting securities of PG&E Corporation outstanding immediately prior thereto continuing to be voted on at the 2005 annual meeting of shareholders: David R. Andrews, Leslie S. Biller, David A. Coulter, C. Lee Cox, Peter A. Darbee, Robert D. Glynn, Jr., Mary S. Metz, Barbara L. Rambo, and Barry Lawson Williams. The Committee also nominated the same nine individuals for election as directorsrepresent (either by remaining outstanding or by being converted into voting securities of the Utility, in addition to Gordon R. Smith. Onesurviving entity or any parent of such surviving entity) at least 70 percent of the current members of the Boards of Directors, David M. Lawrence, MD, will retire from the Board of Directorscombined voting power of PG&E Corporation, andsuch surviving entity, or the Utility effective atparent of such surviving entity outstanding immediately after the adjournmentmerger or consolidation. Under the prior definition, a “change in control” would have occurred upon shareholder approval of such a transaction. Certain other events, including the turnover of two-thirds of the 2005 joint annual meetingincumbent board members without incumbent board member approval within two years, the acquisition of the shareholders ofa 20 percent voting stake in PG&E Corporation, and Utility, and has not been nominated for re-electionshareholder approval of certain asset sales or a plan of liquidation or dissolution, will continue to constitute a change in control.Boards.AmendmentOfficer Severance Policy became subject to the Golden Parachute Restriction Policy and the new definition of Bylaws On“change in control” effective as of February 16, 2005,15, 2006, subject to existing contractual obligations. The Officer Severance Policy provides that any changes which would reduce the Boardaggregate level of Directorsbenefits provided under the policy will become effective three years after the covered officers receive notice of those changes. The Golden Parachute Restriction Policy and the amendments to the Officer Severance Policy would reduce the aggregate level of benefits, and therefore will become effective three years after the covered officers receive notice of those changes. PG&E Corporation adopted resolutionsintends to amendprovide such notice shortly.bylawsLong-Term Incentive Program, which expired on December 31, 2005, with the new 2006 LTIP, which became effective on January 1, 2006. The Guidelines also were amended to decreasebe consistent with the authorized number of directors from ten to nine, effective at the adjournmentamended terms of the annual meeting of shareholders to be held on April 20, 2005. Under PG&E Corporation's bylaws, the authorized number of directors may not be less than 7 nor more than 13, but within that range the Board of Directors may set the exact number of directors by an amendment to the bylaws. The text of the bylaw amendment follows: 1. Number. As stated in paragraph I of Article Third of this Corporation's Articles of Incorporation, the Board of Directors of this Corporation shall consist of such number of directors, not less than seven (7) nor more than thirteen (13). The exact number of directors shall be nine (9) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders.On2006 LTIP as described above. These changes became effective February 16, 2005, the Board of Directors of the Utility also adopted resolutions to amend the Utility bylaws to decrease the authorized number of directors from eleven to ten, effective at the adjournment of the annual meeting of shareholders to be held on April 20, 2005. Under the Utility'sbylaws, the authorized number of directors may not be less than 9 nor more than 17, but within that range the Board of Directors may set the exact number of directors by an amendment to the bylaws. The text of the bylaw amendment follows: 1. Number. The Board of Directors of this Corporation shall consist of such number of directors, not less than nine (9) nor more than seventeen (17). The exact number of directors shall be ten (10) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders.Approval of Performance Scale under 2005 Short Term2006 Short-Term Incentive Plan20052006 Short-Term Incentive Plan, (STIP)or STIP, under which officers of PG&E Corporation and the Utility are provided an opportunity to receive annual incentive cash payments. For PG&E Corporation executivethese officers, the STIP award will be based entirely on the achievement ofcorporate financial objectives,performance, as measured by corporate earnings from operations. The executive officersoperations, will account for 70 percent of the award and Utility will have an opportunity to receive annual cash incentives based on three criteria: the achievement of financial objectivesoperational performance, as measured by PG&E Corporation's earnings from operations (weighted 25%),11 equally weighted financial, operating, and service measures, will account for 30 percent of the Utility's contribution to PG&E Corporation's earnings from operations (weighted 50%), and the success of key strategic initiatives (weighted 25%).award. At its meeting on February 16, 2005,15, 2006, the Committee approved the specific performance scale that will be used to determine the extent to which the corporate financial objective, as measured by earnings from operations, has been met.2005corporate financial performance portion of the 2006 STIP as was used for the 20042005 STIP. The corporate financial performance measure is based on PG&E Corporation's budgeted earnings from operations that were previously approved by the Board, of Directors, consistent with the basis for reporting and guidance to the financial community. As with previous earnings performance scales, unbudgeted items impacting comparability such as changes in accounting methods, workforce restructuring, and one-time occurrences will be excluded. 1. 94.0 96.0 2. Timely bills (% issued within 35 days) 99.38% 99.51% 3. Estimate of Outage Restoration Accuracy 47% 50% 4. 178.7 166 5. 1.344 1.31 6. 7. 75/20 76/20 8. Expense Per Customer $278 9. 98.2 98.2 10. Employee survey (Premier) index 64.0% 68.0% 11. 1.04 0.878 contained on pages 49 through 52 inat the end of Part I of this report. Other information responding to Item 10 is included under the heading "Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company" and under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the Joint Proxy Statement relating to the 20052006 Annual Meetings of Shareholders, which information is hereby incorporated by reference.both PG&E Corporation and Pacific Gas and Electric Company, One Market, Spear Tower, Suite 2400, San Francisco, California 94105.54 business days of the waiver.2004,2005," "Aggregated Option/SAR Exercises in 20042005 and Year-End Option/SAR Values," "Long-Term Incentive Program—Awards in 2004,2005," "Retirement Benefits," and "Employment ContractsTerminationContracts, Termination of Employment, and Change In Control Provisions" in the Joint Proxy Statement relating to the 20052006 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters20052006 Annual Meetings of Shareholders, which information is hereby incorporated by reference.2004,2005 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation's existing equity compensation plans.Plan Category (a)
Number of Securities to
be Issued Upon Exercise
of Outstanding Options,
Warrants, and Rights (b)
Weighted Average
Exercise Price of
Outstanding Options,
Warrants, and Rights (c)
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column(a)) Equity compensation plans approved by shareholders 21,021,916 $ 22.76 10,439,785 (1)
Equity compensation plans not approved by shareholders
—
$
—
—
Total equity compensation plans
21,021,916
$
22.76
10,439,785
Equity compensation plans approved by shareholders 12,012,774 $23.26 8,952,785(1) Equity compensation plans not approved by shareholders — $— — Total equity compensation plans 12,012,774 $23.26 8,952,785 (LTIP)or LTIP, as of December 31, 2004.2005. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock and phantom stock payable in an equal number of shares upon termination of employment or service as a director. No more than 5,000,000 of the reservedThe LTIP expired on December 31, 2005. The PG&E Corporation 2006 Long-Term Incentive Plan, or 2006 LTIP, became effective on January 1, 2006. The 2006 LTIP authorizes up to 12 million shares to be issued pursuant to awards granted under the LTIP may be awarded as restricted stock.2006 LTIP. For a description of the LTIP and the 2006 LTIP, see Note 1014 of the Notes to the Consolidated Financial Statements in the 2005 Annual Report.20052006 Annual Meetings of Shareholders, which information is hereby incorporated by reference.AccountantsAccounting Firm of PG&E Corporation and Pacific Gas and Electric Company" in the Joint Proxy Statement relating to the 20052006 Annual Meetings of Shareholders, which information is hereby incorporated by reference.(a)
1.1.auditors' reportregistered public accounting firm are contained in the 20042005 Annual Report which have beenand are incorporated by reference in this report:OperationsIncome for the Years Ended December 31, 2004, 2003, and 2002, for each of PG&E Corporation and Pacific Gas and Electric Company.Consolidated Balance Sheets at December 31,2005, 2004, and 2003, for each of PG&E Corporation and Pacific Gas and Electric Company.Statements of Common Shareholders' Equity for the Years EndedBalance Sheets at December 31, 2005, and 2004 2003, and 2002, for each of PG&E Corporation. 2002 for Pacific Gas and Electric Company. included at page 66 of this Form 10-K..3.Financial statement schedules:20042005 and 20032004 and for the Years Ended December 31, 2005, 2004, 2003, and 2002.2003, and 2002.4. to be filed by Item 601 of Regulation S-K: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 Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2) 3.1 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 January 1, 200520063.4 Bylaws of PG&E Corporation amended as of April 20, 20053.5Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3) 3.63.5 Bylaws of Pacific Gas and Electric Company amended as of January 1, 200520063.74.1Bylaws of Pacific Gas and Electric Company amendedIndenture, dated as of April 20,22, 2005,4.1 supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporatedas supplemented by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)4.2a First Supplemental Indenture, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.2)4.3a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY WesternThe Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K10-Q filed April 12, 2004May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4)4.1)4.4Escrow Deposit and Disbursement Agreement, dated as of March 23, 2004, among Pacific Gas and Electric Company and BNY Western Trust Company as escrow agent and trustee (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.3)4.5Calculation Agency Agreement, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.4)4.64.2 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). 4.74.3 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) 4.8Warrant Agreement, dated as of June 25, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.9).4.94.4 Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2) 10.1 Credit Agreement dated as of March 5, 2004,April 8, 2005, among Pacific Gas and Electric Company, as borrower, the Several Lenders from time to time parties thereto, Citicorp North America, Inc., as Administrative Agent, Banc One Capital Markets,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 Syndication Agent,documentation agents and lenders, ABN Amro Bank N.V., Lehman Commercial Paper Inc.Brothers Bank, FSB, Mellon Bank, N.A., Credit Suisse First Boston, acting through its Cayman Islands Branch,Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and UBS Securities LLC,Union Bank of California, N.A., as Co- Documentation Agentssenior 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 8-K10-Q filed March 10, 2004May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 99)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. 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.)99)10.345 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 December 15, 2004,November 16, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.10.410.6 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) 10.510.7 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) 10.610.8 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) 10.710.9 PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.6) 10.810.10 Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, initially effective as of March 31, 1998, as amended to date (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)10.910.11 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) * 10.1010.12 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, 2004) (File No. 1-12609), Exhibit 10.10) 46 * 10.1110.13 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) * 10.1210.14 Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3) * 10.1310.15 Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18,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)* 10.1410.16 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) * 10.15Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)*10.1610.17 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.3) * 10.1710.18Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 *10.19 Severance Agreement and Release by and between Pacific Gas and Electric Company and Gordon R. Smith dated September 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (File No. 1-2348), Exhibit 10.1) *10.20 Actions taken by the Nominating, Compensation and Governance Committee of the PG&E Corporation Board of Directors on October 19, 2005, regarding the 2006 Officer Compensation Program (incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (File No. 1-12609), Exhibit 10.2) *10.21 PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, 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 10.17) * 10.1810.22Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2006 *10.23 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2005 *10.19Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2004 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 20022004 (File No. 1-12609), Exhibit 10.24)10.18)* 10.2010.24Schedule of 2006 Base Salary and Short-Term Incentive Plan Target Participation Rates for certain officers of PG&E Corporation and its subsidiaries *10.25 Schedule of 2006 award values under the PG&E Corporation 2006 Long-Term Incentive Plan for certain officers of PG&E Corporation and its subsidiaries *10.26 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of December 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, 2004) (File No. 1-2348), Exhibit 10.20) * 10.2110.27 Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 20052006* 10.22.110.28.1 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.1) * 10.22.210.28.2 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2) * 10.22.310.28.3 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002 (incorporated by reference to PG&E Corporation'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) * 10.22.410.28.4 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002 (incorporated by reference to PG&E Corporation'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) * 10.22.5Agreement 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)*10.23.110.29.1 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.1) *10.23.2 47 *10.29.2 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.2) * 10.23.310.29.3 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.4) * 10.23.410.29.4 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.5) * 10.2410.30 Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16) * 10.2510.31 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16) * 10.2610.32PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)*10.272004)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, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)* 10.2810.33 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) * 10.2910.34* 10.3010.35*10.36 PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10) *10.37 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) * 10.3110.38 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) * 10.3210.39 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) * 10.3310.40Form 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) *10.41 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) * 10.3410.42Form 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) *10.43 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) * 10.3510.44 Form of Performance Share Award Agreement grantedfor 2006 grants under the PG&E Corporation 2006 Long-Term Incentive ProgramPlan (incorporated by reference to PG&E Corporation'sCorporation and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003 (File No. 1-12609),8-K filed January 9, 2006, Exhibit 10.38)99.2)48 * 10.3610.45 PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609) ) Exhibit 10. 2)* 10.3710.46PG&E Corporation Executive Stock Ownership Program Guidelines as amended February 15, 2006 *10.47 PG&E Corporation Officer Severance Policy, as amended 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 10.37) * 10.3810.48PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 *10.49 PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 *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) * 10.3910.51 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) * 10.4010.52 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) * 10.4110.53 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 20042005 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations,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 Operations,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,Firm." "Responsibility for Consolidated Financial Statements"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 SIGNATURES20042005 to be signed on their behalf by the undersigned, thereunto duly authorized, in the City and County of San Francisco, on the 18th day of February, 2005.authorized. PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY By /s/ R.R WORTHINGTONBy /s/ R.R WORTHINGTONDate: Date: Chief Executive Officer, and PresidentFebruary 18, 2005 *PETER A. DARBEE (PG&E Corporation) *PETER A. DARBEE *GORDON R. SMITHChairman of the Board, Chief Executive Officer and President (PG&E Corporation)February 17, 2006 *THOMAS B. KING President and Chief Executive Officer (Pacific Gas and Electric Company) February 18, 200517, 2006 (Pacific Gas and Electric Company)Senior Vice President, Chief FinancialFebruary 18, 2005 *CHRISTOPHER P. JOHNSOfficer and Controller (PG&E Corporation) *KENT M. HARVEY*CHRISTOPHER P. JOHNS Senior Vice President, Chief Financial Officer and Treasurer (PG&E Corporation and Pacific Gas and Electric Company ) February 18, 200517, 2006 Officer, and Treasurer (Pacific Gas and Electric Company)Senior Vice President, Chief FinancialFebruary 18, 2005 *CHRISTOPHER P. JOHNSOfficer, and Controller (PG&E Corporation) *DINYAR B. MISTRY*G. ROBERT POWELL Vice President-Controller (PacificPresident and Controller (PG&E Corporation and Pacific Gas and Electric Company)February 18, 200517, 2006D.Directors *LESLIE S. BILLERROBERT D. GLYNN, JR.
MARYELLEN C. HERRINGERDAVID M. LAWRENCE, M.D.*MARY S. METZ*BARBARA L. RAMBO*GORDON R. SMITH
THOMAS B. KINGand ElectricandElectric Company only)February 18, 2005
17, 2006
*By/s/ R.R WORTHINGTON
"Company"“Company”) and Pacific Gas and Electric Company and subsidiaries (the "Utility"“Utility”) as of December 31, 20042005 and 2003,2004, and for each of the three years in the period ended December 31, 2004, management's2005, management’s assessment of the effectiveness of the Company'sCompany’s and the Utility'sUtility’s internal control over financial reporting as of December 31, 2004,2005, and the effectiveness of the Company'sCompany’s and the Utility'sUtility’s internal control over financial reporting as of December 31, 2004,2005, and have issued our reports thereon dated February 16, 2005 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to accounting changes);15, 2006; such consolidated financial statements and reports are included in your 20042005 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference. Our audits also included the consolidatedcondensed financial statement schedules of the Company and the Utility listed in Item 15 (a) 2. These consolidatedcondensed financial statement schedules are the responsibility of the Company'sCompany’s and the Utility'sUtility’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidatedcondensed financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.16, 200515, 2006I—I — CONDENSED FINANCIAL INFORMATION OF PARENT Balance at December 31, 2004 2003 ASSETS Cash and cash equivalents $ 183 $ 673 Advances in affiliates 22 398 Other current assets 3 9 Total current assets 208 1,080 Equipment 15 20 Accumulated depreciation (13 ) (15 ) Net equipment 2 5 Restricted cash — 361 Investments in subsidiaries 8,848 4,810 Other investments 31 24 Deferred income taxes 104 478 Other 14 32 Total Assets $ 9,207 $ 6,790 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Accounts payable—related parties $ 3 $ 2 Accounts payable—other 15 28 Income taxes payable 83 258 Other 53 158 Total current liabilities 154 446 Noncurrent Liabilities: Long-term debt 280 883 Net investment in NEGT — 1,216 Other 140 30 Total noncurrent liabilities 420 2,129 Preferred stock — — Common Shareholders' Equity Common stock 6,518 6,468 Common stock held by subsidiary (718 ) (690 ) Unearned compensation (26 ) (20 ) Accumulated earnings (deficit) 2,863 (1,458 ) Accumulated other comprehensive loss (4 ) (85 ) Total common shareholders' equity 8,633 4,215 Total Liabilities and Shareholders' Equity $ 9,207 $ 6,790 Cash and cash equivalents $ 250 $ 183 Advances to affiliates 38 22 Other current assets 3 3 Total current assets 291 208 Equipment 15 15 Accumulated depreciation (14 ) (13 ) Net equipment 1 2 Investments in subsidiaries 7,401 8,848 Other investments 71 31 Deferred income taxes 127 104 Other 15 14 Total Assets $ 7,906 $ 9,207 Current Liabilities Accounts payable—related parties $ 27 $ 3 Accounts payable—other 17 15 Income taxes payable 28 83 Other 193 53 Total current liabilities 265 154 Noncurrent Liabilities: Long-term debt 280 280 Other 143 140 Total noncurrent liabilities 423 420 Preferred stock — — Common Shareholders' Equity Common stock 5,827 6,518 Common stock held by subsidiary (718 ) (718 ) Unearned compensation (22 ) (26 ) Reinvested earnings 2,139 2,863 Accumulated other comprehensive loss (8 ) (4 ) Total common shareholders' equity 7,218 8,633 Total Liabilities and Shareholders' Equity $ 7,906 $ 9,207 SCHEDULE I—— CONDENSED FINANCIAL INFORMATION OF PARENT — (Continued)OPERATIONSINCOME Administrative service revenue $ 97 $ 85 $ 101 Equity in earnings of subsidiaries 918 3,959 917 Operating expenses (97 ) (110 ) (133 ) Interest income 9 15 20 Interest expense (35 ) (132 ) (200 ) Other income (expense) (17 ) (91 ) 2 Income before income taxes 875 3,726 707 Income tax benefit 29 94 84 Income from continuing operations 904 3,820 791 Gain on disposal of NEGT 13 684 — Discontinued operations — — (365 ) Cumulative effect of changes in accounting principles — — (6 ) Net income before intercompany eliminations $ 917 $ 4,504 $ 420 372 398 385 $ 2.40 $ 10.80 $ 1.04 $ 2.37 $ 10.57 $ 1.02 Cash Flows from Operating Activities: Net income $ 917 $ 4,504 $ (420 ) Gain on disposal of NEGT (net of income tax benefit of $13 million in 2005 and income tax expense of $374 million in 2004) (13 ) (684 ) — Loss from operations of NEGT (net of income tax benefit of $320 million) — — 365 Cumulative effect of changes in accounting principles — — 6 Net income from continuing operations 904 3,820 791 Adjustments to reconcile net income to net cash provided by operating activities: Equity in earnings of subsidiaries (918 ) (3,959 ) (917 ) Deferred taxes (23 ) 27 265 NEGT settlement payment — (30 ) — Other 86 160 391 Net cash provided by operating activities 49 18 530 Cash Flows From Investing Activities: Capital expenditures (1 ) — — Investment in subsidiaries — (28 ) — Stock repurchase by subsidiary 1,910 — — Dividends received from subsidiaries 445 — — Increase in restricted cash — 361 — Other (38 ) — — Net cash provided by investing activities 2,316 333 — Common stock issued 243 162 166 Common stock repurchased (2,188 ) (350 ) — Common stock dividends paid (334 ) — — Long-term debt issued — — 581 Long-term debt redeemed (2 ) (652 ) (787 ) Other (17 ) (1 ) 1 Net cash used by financing activities (2,298 ) (841 ) (39 ) Net change in cash and cash equivalents 67 (490 ) 491 Cash and cash equivalents at January 1 183 673 182 Cash and cash equivalents at December 31 $ 250 $ 183 $ 673 PG&E Corporation adopted the consensus reached by Emerging Issues Task Force, or EITF, in EITF issue No. 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06, as ratified by the Financial Accounting Standards Board on March 31, 2004. PG&E Corporation currently has outstanding $280 million principal amount of convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes, which were issued in June 2002, meet the criteria of a participating security in the calculation of earnings per share using the "two-class" method. Accordingly, the basic and diluted earnings per share calculations for each of the years in the three year period ended December 31, 2005 reflect the allocation of earnings between PG&E Corporation common stock and the participating security. On April 15, July 15 and October 17, 2005, PG&E Corporation paid a quarterly common stock dividend of $0.30 per share, totaling approximately $356 million. Of the total dividend payments made by PG&E Corporation in 2005, approximately $22 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. PG&E Corporation did not pay any dividends during 2004 and 2003. 2004,2005, 2003 and 2002(in millions, except per share amounts)2004 2004 2003 2002 Administrative service revenue $ 85 $ 101 $ 96 Equity in earnings of subsidiaries 3,959 917 1,842 Operating expenses (110 ) (133 ) (141 ) Interest income 15 20 30 Interest expense (132 ) (200 ) (253 ) Other income (expense) (91 ) 2 81 Income before income taxes 3,726 707 1,655 Less: Income tax benefit (94 ) (84 ) (68 ) Income from continuing operations 3,820 791 1,723 Gain on disposal of NEGT 684 — — Discontinued operations — (365 ) (2,536 ) Cumulative effect of changes in accounting principles — (6 ) (61 ) Net income (loss) before intercompany eliminations $ 4,504 $ 420 $ (874 ) Weighted average common shares outstanding $ 398 $ 385 $ 371 Earnings (loss) per common share, basic(1) $ 10.80 $ 1.04 $ (2.30 ) Earnings (loss) per common share, diluted(1) $ 10.57 $ 1.02 $ (2.27 ) 2005 $ 93 $ 21 $ — $ 37 $ 77 2004: $ 68 $ 85 $ — $ 60 $ 93 2003: $ 59 $ 42 $ — $ 33 $ 68
__________________________________SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)CONDENSED STATEMENTS OF CASH FLOWSFor the Years Ended December 31, 2004, 2003, and 2002(in millions) 2004 2003 2002 Cash Flows from Operating Activities: Net income (loss) $ 4,504 $ 420 $ (874 ) Gain on disposal of NEGT (net of $30 million payment to NEGT) (684 ) — — Loss from discontinued operations — 365 2,536 Cumulative effect of changes in accounting principles — 6 61 Net income from continuing operations 3,820 791 1,723 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Equity in earnings of subsidiaries (3,959 ) (917 ) (1,842 ) Restricted cash 361 — — Deferred taxes 27 265 (660 ) NEGT settlement payment (30 ) — — Other—net 160 391 458 Net cash provided (used) by operating activities 379 530 (321 ) Cash Flows From Investing Activities: Capital expenditures — — (1 ) Investment in subsidiaries (28 ) — — Net cash used by investing activities (28 ) — (1 ) Cash Flows From Financing Activities(2): Common stock issued 162 166 217 Common stock repurchased (350 ) — — Long-term debt issued — 581 847 Long-term debt redeemed (652 ) (787 ) (908 ) Other—net (1 ) 1 — Net cash provided (used) by financing activities (841 ) (39 ) 156 Net change in cash and cash equivalents (490 ) 491 (166 ) Cash and cash equivalents at January 1 673 182 348 Cash and cash equivalents at December 31 183 673 182 PG&E Corporation adopted the consensus reached by Emerging Issues Task Force, or EITF, in EITF issue No. 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06, as ratified by the Financial Accounting Standards Board on March 31, 2004.PG&E Corporation currently has outstanding $280 million principal amount of convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes, which were issued in June 2002, meet the criteria of a participating security in the calculation of earnings per share using the "two-class" method.Accordingly, the basic and diluted earnings per share calculations for each of the years in the three year period ended December 31, 2004 reflect the allocation of earnings between PG&E Corporation common stock and the participating security.(2)PG&E Corporation did not receive any cash dividends during 2004, 2003 and 2002SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTSFor the Years Ended December 31, 2004, 2003 and 2002 Additions Description Balance
at Beginning of Period Charged to Costs and
Expenses Charged to Other
Accounts Deductions(3) Balance
at End of Period (in millions) Valuation and qualifying accounts deducted from assets: 2004 Allowance for uncollectible accounts(1)(2) $ 68 $ 85 $ — $ 60 $ 93 2003: Allowance for uncollectible accounts(1)(2) $ 59 $ 42 $ — $ 33 $ 68 2002: Allowance for uncollectible accounts(1)(2) $ 48 $ 36 $ (2 ) $ 23 $ 59 (1)2003 and 20022003 2005 $ 93 $ 21 $ — $ 37 $ 77 2004: $ 68 $ 85 $ — $ 60 $ 93 2003: $ 59 $ 42 $ — $ 33 $ 68 Additions Description Balance
at Beginning of Period Charged to Costs and
Expenses Charged to Other Accounts Deductions(2) Balance
at End of Period (in millions) Valuation and qualifying accounts deducted from assets: 2004 Allowance for uncollectible accounts(1) $ 68 $ 85 $ — $ 60 $ 93 2003: Allowance for uncollectible accounts(1) $ 59 $ 42 $ — $ 33 $ 68 2002: Allowance for uncollectible accounts(1) $ 48 $ 36 $ (2 ) $ 23 $ 59 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 Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2) 3.1 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 January 1, 200520063.4 Bylaws of PG&E Corporation amended as of April 20, 20053.5Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3) 3.63.5 Bylaws of Pacific Gas and Electric Company amended as of January 1, 200520063.74.1Bylaws of Pacific Gas and Electric Company amendedIndenture, dated as of April 20,22, 2005,4.1 supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporatedas supplemented by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)4.2a First Supplemental Indenture, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.2)4.3a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY WesternThe Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K10-Q filed April 12, 2004May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4)4.1)4.4Escrow Deposit and Disbursement Agreement, dated as of March 23, 2004, among Pacific Gas and Electric Company and BNY Western Trust Company as escrow agent and trustee (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.3)4.5Calculation Agency Agreement, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.4)4.64.2 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). 4.74.3 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) 4.8Warrant Agreement, dated as of June 25, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.9).4.94.4 Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2) 10.1 Credit Agreement dated as of March 5, 2004,April 8, 2005, among Pacific Gas and Electric Company, as borrower, the Several Lenders from time to time parties thereto, Citicorp North America, Inc., as Administrative Agent, Banc One Capital Markets,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 Syndication Agent,documentation agents and lenders, ABN Amro Bank N.V., Lehman Commercial Paper Inc.Brothers Bank, FSB, Mellon Bank, N.A., Credit Suisse First Boston, acting through its Cayman Islands Branch,Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and UBS Securities LLC,Union Bank of California, N.A., as Co- Documentation Agentssenior 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 8-K10-Q filed March 10, 2004May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 99)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. 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.)99)10.357 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 December 15, 2004,November 16, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.10.410.6 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) 10.510.7 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) 10.610.8 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) 10.710.9 PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.6) 10.810.10 Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, initially effective as of March 31, 1998, as amended to date (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)10.910.11 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) * 10.1010.12 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, 2004) (File No. 1-12609), Exhibit 10.10) * 10.1110.13 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) * 10.1210.14 Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3) * 10.1310.15 Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18,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)* 10.1410.16 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) * 10.15Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)*10.1610.17 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.3) * 10.1710.18Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 58 *10.19 Severance Agreement and Release by and between Pacific Gas and Electric Company and Gordon R. Smith dated September 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (File No. 1-2348), Exhibit 10.1) *10.20 Actions taken by the Nominating, Compensation and Governance Committee of the PG&E Corporation Board of Directors on October 19, 2005, regarding the 2006 Officer Compensation Program (incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (File No. 1-12609), Exhibit 10.2) *10.21 PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, 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 10.17) * 10.1810.22Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2006 *10.23 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2005 *10.19Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2004 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 20022004 (File No. 1-12609), Exhibit 10.24)10.18)* 10.2010.24Schedule of 2006 Base Salary and Short-Term Incentive Plan Target Participation Rates for certain officers of PG&E Corporation and its subsidiaries *10.25 Schedule of 2006 award values under the PG&E Corporation 2006 Long-Term Incentive Plan for certain officers of PG&E Corporation and its subsidiaries *10.26 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of December 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, 2004) (File No. 1-2348), Exhibit 10.20) * 10.2110.27 Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 20052006* 10.22.110.28.1 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.1) * 10.22.210.28.2 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2) * 10.22.310.28.3 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002 (incorporated by reference to PG&E Corporation'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) * 10.22.410.28.4 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002 (incorporated by reference to PG&E Corporation'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) * 10.22.5Agreement 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)*10.23.110.29.1 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.1) * 10.23.210.29.2 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.2) * 10.23.310.29.3 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.4) * 10.23.410.29.4 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.5) * 10.2410.30 Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16) * 10.2510.31 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16) * 10.2610.32PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)*10.272004)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, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27) 59 * 10.2810.33 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) * 10.2910.34* 10.3010.35*10.36 PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10) *10.37 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) * 10.3110.38 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) * 10.3210.39 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) * 10.3310.40Form 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) *10.41 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) * 10.3410.42Form 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) *10.43 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) * 10.3510.44 Form of Performance Share Award Agreement grantedfor 2006 grants under the PG&E Corporation 2006 Long-Term Incentive ProgramPlan (incorporated by reference to PG&E Corporation'sCorporation and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003 (File No. 1-12609),8-K filed January 9, 2006, Exhibit 10.38)99.2)* 10.3610.45 PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609) ) Exhibit 10. 2)* 10.3710.46PG&E Corporation Executive Stock Ownership Program Guidelines as amended February 15, 2006 *10.47 PG&E Corporation Officer Severance Policy, as amended 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 10.37) * 10.3810.48PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 *10.49 PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 *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) * 10.3910.51 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) * 10.4010.52 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) 60 * 10.4110.53 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 20042005 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations,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 Operations,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,Firm." "Responsibility for Consolidated Financial Statements"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 Securities registered pursuant to Section 12(b) of the ActSecurities registered pursuant to Section 12(g) of the Act: NoneDOCUMENTS INCORPORATED BY REFERENCETABLE OF CONTENTSUNITS OF MEASUREMENTPART IItem 1. Business.Corporate Structure and BusinessEmployeesForward-Looking Statements and Risk FactorsAppeals of the Utility's Plan of Reorganization and Settlement AgreementOperating EnvironmentLegislative and Regulatory Environment and Pending LitigationCompetitionElectric Utility OperationsDWR Power PurchasesThird Party Power Purchase AgreementsOther Power Purchase AgreementsElectricity TransmissionNatural Gas Utility OperationsNatural Gas Operating StatisticsNatural Gas SuppliesGas Gathering FacilitiesInterstate and Canadian Natural Gas Transportation Services AgreementsCompetitionItem 2. Properties.Item 3. Legal Proceedings.Pacific Gas and Electric Company Chapter 11 FilingPacific Gas and Electric Company vs. Michael Peevey, et al.Diablo Canyon Power PlantComplaints Filed by the California Attorney General and the City and County of San FranciscoCompressor Station Chromium LitigationItem 4. Submission of Matters to a Vote of Security HoldersEXECUTIVE OFFICERS OF THE REGISTRANTSPART IIItem 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationNomination for Election as DirectorsAmendment of BylawsApproval of Performance Scale under 2005 Short Term Incentive PlanPART IIIItem 11. Executive CompensationItem 12. Security Ownership of Certain Beneficial Owners and ManagementEquity Compensation Plan InformationItem 13. Certain Relationships and Related TransactionsItem 14. Principal Accountant Fees and ServicesItem 15. Exhibits and Financial Statement SchedulesSIGNATURESCONDENSED BALANCE SHEETS (in millions)SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)PG&E CORPORATIONSCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2004, 2003 and 2002PACIFIC GAS AND ELECTRIC COMPANYSCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2004, 2003 and 2002EXHIBIT INDEX