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SECURITIES AND EXCHANGE COMMISSION
FORMForm 10-K
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the Fiscal Year Ended December 31, | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the transition period fromto | ||
| Commission | Exact Name of Registrant | State of | IRS Employer | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
| File Number | as specified in its charter | |||||||||
| 1-12609 | PG&E CORPORATION | California | 94-3234914 | |||||||
| 1-2348 | PACIFIC GAS AND ELECTRIC COMPANY | California | 94-0742640 |
|
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class | Name of Each Exchange on Which Registered | ||||
| PG&E Corporation | |||||
| Common Stock, no par value Preferred Stock Purchase Rights | New York Stock Exchange and Pacific Exchange | ||||
| Pacific Gas and Electric Company | |||||
| First Preferred Stock, cumulative, par value $25 per share: | |||||
| Redeemable: 7.04%, 5% Series A, 5%, 4.80%, 4.50%, 4.36% Mandatorily Redeemable: 6.57%, 6.30% Nonredeemable: 6%, 5.50%, 5% | American Stock Exchange and Pacific Exchange | ||||
| 7.90% Deferrable Interest Subordinated Debentures | American Stock Exchange and Pacific Exchange | ||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /X/þ No / /o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant'sregistrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /X/10-K:
PG&E Corporation o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes /X/ No / /:
| PG&E Corporation | Yes þ | No o | ||
| Pacific Gas and Electric Company | Yes o | No þ |
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrantregistrants as of June 28, 2002,30, 2003, the last business day of the second fiscal quarter:
| PG&E Corporation Common Stock | $ | |
| Pacific Gas and Electric Company Common Stock | Wholly owned by PG&E Corporation |
Common Stock outstanding as of February 17, 2004:
| PG&E Corporation: | ||
| Pacific Gas and Electric Company: | Wholly owned by PG&E Corporation |
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved.
| Designated portions of the combined Annual Report to Shareholders for the year ended December 31, | Part I (Item 1), Part II (Items 5, 6, 7, 7A and 8), Part IV (Item 15) |
TABLE OF CONTENTS
i ii iii Corporate Structure and Business PG&E Corporation, incorporated in California in 1995, is an energy-based holding company On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the On December 19, 2003, the CPUC, PG&E Corporation and the Utility entered into a settlement agreement, or the Settlement Agreement, that contemplated a plan of reorganization, or the Plan of Reorganization, which fully incorporates the Settlement Agreement. The Plan of Reorganization provides that the Utility will pay allowed creditor claims in full, plus applicable interest, and emerge from Chapter 11 as an investment grade entity. On December 22, 2003, the bankruptcy court confirmed the Plan of Reorganization. The Settlement Agreement and Plan of Reorganization are discussed further below, in the MD&A and in Note 2 of the Notes to the On July 8, 2003, NEGT filed a voluntary petition for relief under the provisions of Chapter 11 in the 1 The factors that caused NEGT and its subsidiaries NEGT’s proposed plan of reorganization, if implemented, would eliminate PG&E The principal executive office of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive office of Employees The Utility’s Plan of Reorganization and Settlement Agreement The Plan of Reorganization provides that the Utility The Settlement Agreement permits the Utility to emerge from Chapter 11 as an investment grade entity by generally ensuring that the Utility will have the opportunity to collect in rates reasonable costs of providing its utility service. The Settlement Agreement provides that the Utility’s authorized return on equity will be no less than 11.22% per year and, except for 2004 and 2005, its authorized equity ratio will be no less than 52% until the Utility’s credit rating has increased to a specified level. The Settlement Agreement establishes a 2 On January 20, 2004, several parties filed applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the Settlement Agreement. Although the CPUC is not required to act on these applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review. In addition, the two CPUC Commissioners who did not vote to approve the Settlement Agreement and a municipality have appealed the bankruptcy court’s confirmation order in The Settlement Agreement and Plan of Reorganization are discussed further in the Under the Settlement Agreement, PG&E Corporation and the Utility 3 The Utility would Forward-Looking Statements and Risk Factors Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include: Operating Environment 4 Legislative and Regulatory Environment and Pending Litigation Competition 5 Electric Utility Operations The Utility’s electricity distribution network extends throughout all or a part of 46 of California’s 58 counties, comprising most of northern and central California. The Utility’s network consists of 120,428 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 89 transmission substations and 45 transmission switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. There are 609 distribution substations and 117 low voltage distribution substations. There are 264 combined transmission and distribution substations. Combined transmission and distribution substations have both transmission and distribution transformers. The Utility’s distribution network interconnects to the Utility’s electricity transmission system at 1,012 points. This interconnection between the Utility’s distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the 2003 Electricity Deliveries The following table shows the percentage of the (80,156 GWhs) 6 Electricity Distribution Operating Statistics The following table shows certain of the 7 Electricity Resources The following table shows the percentage of the Utility’s total sources of electricity for Generation Facilities At December 31, 2003, the Utility owned and operated the following generation facilities, all located in California, listed by energy source: Diablo Canyon Power Plant.The Utility’s Diablo Canyon power plant consists of two nuclear power reactor units, each capable of generating up to approximately 1,087 MW of electricity. Unit 1 began commercial operation in May 1985 and the operating license for this unit expires in September 2021. Unit 2 began commercial operation in March 1986 and the operating license for this unit expires in April 2025. For the ten-year period ended December 31, 2003, the Utility’s Diablo Canyon power plant achieved a capacity factor of approximately 88.5%. 8 The following table outlines the Diablo Canyon power plant’s refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 19 to 21 months. The average length of a refueling outage over the last five years has been approximately 35 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the steam generator replacements in 2008 and 2009 discussed below. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of up to 80 days to accommodate non-routine tasks, such as expanded steam generator inspection and repair, low pressure turbine rotor replacement and the first of two proposed steam generator replacements. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors. During a routine inspection conducted as part of the last refueling of Unit 2 in February 2003, the Utility found indications of steam generator tube cracking in locations and of a size not previously expected. After careful inspection and analysis, Unit 2 was able to safely restart after that outage and the Utility received the approval of the NRC to operate without further steam generator inspection until the next scheduled refueling in the fall of 2004. The Utility, however, is planning to accelerate the replacement of the steam generators in Unit 2 from 2009 to 2008. The Utility plans to replace Unit 1’s steam generators in 2009. The capital expenditures necessary to complete these projects are discussed further in the MD&A. The Utility has several types of nuclear insurance for its Diablo Canyon power plant and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay additional annual premiums of up to $36.7 million. NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.9 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for the Diablo Canyon power plant. The balance of the $10.9 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of reactors 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $100.6 million per reactor, with payments in each year limited to a maximum of $10 million per incident until the Utility has fully paid its share of the liability. Since the Diablo Canyon power plant has two nuclear reactors over 100 MW, the Utility may be assessed up to 9 In addition, the Utility has $53.3 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance. Hydroelectric Generation Facilities.The Utility’s hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe and 5 miles of natural waterways. The system also includes water rights as specified in 83 permits and licenses and 163 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses, all of the Utility’s powerhouses are licensed by the FERC. Pursuant to the Federal Power Act, the term of a hydroelectric project license issued by the FERC is between 30 and 50 years. In the last three years, the Utility has received six renewed hydroelectric project licenses from the FERC. Licenses associated with approximately 928 MW expire within the next five years. Licenses associated with approximately 2959 MW expire between 2009 and 2043. In January 2001, because of the deteriorating credit conditions of the California investor-owned electric utilities, the State of California authorized the DWR to purchase electricity to meet the portion of the demand of the utilities’ customers, plus applicable reserve margins, not satisfied from their own generation facilities and existing electricity contracts. California Assembly Bill 1X, or AB 1X, passed in February 2001, authorized the DWR to enter into contracts for the purchase of electricity and to issue revenue bonds to finance electricity purchases. The Utility and the other California investor-owned electric utilities act as the billing and collection agent for the DWR’s sales of electricity to retail customers. On September 19, 2002, the CPUC issued a decision allocating electricity from 19 of the DWR’s contracts, or the DWR allocated contracts, to the Utility’s customers. Electricity from DWR allocated contracts represented approximately 29% of the Utility’s total sources of electricity in 2003. In January 2003, the Utility became responsible for scheduling and dispatching the electricity subject to the 19 DWR allocated contracts on a least-cost basis and for many The DWR is currently legally and financially responsible for these contracts. The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility 10 The Settlement Agreement does not limit the CPUC’s discretion to review the prudence of the Utility’s administration and dispatch of the assumed DWR power purchase contracts consistent with applicable law. The Utility is required by CPUC decisions to purchase energy and capacity from independent power producers that are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA. Under PURPA, the CPUC required California investor-owned electric utilities to enter into a series of long-term power purchase agreements with qualifying facilities and approved the applicable terms, conditions, price options and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility’s actual electrical output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the facility fails to meet or exceeds performance requirements specified in the applicable power purchase agreement. As a result of the energy crisis, the Utility owed approximately $1 billion to qualifying facilities when it filed its Chapter 11 proceeding. Through December 31, 2003, the principal payments made to the qualifying facilities amounted to $998 million. At December 31, 2003, the Utility had agreements with 300 qualifying facilities for approximately 4,400 megawatts, or MW, that are in operation. Agreements for approximately 4,000 MW expire between 2004 and 2028. Qualifying facility power purchase agreements for approximately 400 MW have no specific expiration dates and will terminate only when the owner of the qualifying facility exercises its termination option. The Utility also has agreements with 50 qualifying facilities that are not currently providing or expected to provide electricity. The total of approximately 4,400 MW consists of approximately 2,600 MW from cogeneration projects, 800 MW from wind projects and 1,000 MW from other projects, including biomass, waste-to-energy, geothermal, solar and hydroelectric. On January 22, 2004, the CPUC adopted a decision that requires California investor-owned electric utilities to allow owners of qualifying facilities with power purchase agreements expiring before the end of 2005 to extend these contracts for five years. Qualifying facility power purchase agreements accounted for approximately 20% of the Utility’s 2003 electricity sources, approximately 25% of the Utility’s 2002 electricity sources, and approximately 21% of the Utility’s 2001 electricity resources. No single qualifying facility accounted for more than 5% of the Utility’s 2003, 2002 or 2001 electricity sources. In a proceeding pending at the CPUC, the Utility has requested refunds in excess of $500 million for overpayments from June 2000 through March 2001 made to qualifying facilities. Under the Settlement Agreement, the net after-tax amount of The Utility has contracts with various irrigation districts and water agencies to 11 On January 1, 2003, the Utility resumed buying electricity to meet its residual net open position. During that year, more than 14,000 GWh of energy was bought and sold in the wholesale market to manage the 2003 residual net open position. Most of the Utility’s contracts entered into in 2003 had terms of less than one year. During 2004 the Utility plans to enter into contracts of longer duration to satisfy its near-term residual net open position. California law requires that, beginning in 2003, each California investor-owned electric utility must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. The Utility estimates the annual procurement target will initially require it to purchase about 750 GWh, of electricity from renewable resources each year. The Utility met its 2003 commitment and the CPUC has approved several contracts intended to meet its 2004 renewable energy requirement. In 1967, the Utility and the Western Area Power Administration, or WAPA, entered into several long-term power contracts governing the interconnection of the Utility’s and WAPA’s electricity transmission systems, the use of the Utility’s electricity transmission and distribution system by WAPA, and the integration of the Utility’s and WAPA’s customer demands and electricity resources. The contracts give the Utility access to WAPA’s excess hydroelectric power and obligate the Utility to provide WAPA with electricity when its own resources are not sufficient to meet its requirements. The contracts are scheduled to terminate on December 31, 2004, but termination is subject to FERC approval, which the Utility expects to receive. The costs to fulfill the Utility’s obligations to WAPA under the contracts cannot be accurately estimated at this time since both the purchase price and the amount of electricity WAPA will need from the Utility in 2004 are uncertain. However, the Utility expects that the cost of meeting its contractual obligations to WAPA will be greater than the price the Utility receives from WAPA under the contracts. Although it is not indicative of future sales commitments or sales-related costs, WAPA’s net amount purchased from the Utility was approximately 4,804 GWh, in 2003, 3,619 GWh in 2002 and 4,823 GWh in 2001. For more information regarding the Utility’s power purchase contracts, see Note 12 of the Notes to the Consolidated Financial Statements of the Annual Report. At December 31, 2003, the Utility owned 18,612 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 42,798 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 120,428 circuit miles of distribution lines and substations with a capacity of 24,218 MVA. In 2003, the Utility delivered 80,156 GWh to its customers, including 8,979 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the Western Electricity Coordinating Council which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico. In connection with electricity industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the ISO, in 1998. The FERC has jurisdiction over these transmission facilities, and the revenue requirements and rates for transmission service are set by the FERC. The ISO which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The ISO also is responsible for maintaining the reliability of the transmission system. 12 The Utility has been working closely with the ISO to continue expanding the capacity on the Utility’s electric transmission system. The Utility is engaged in the following significant expansion projects: Natural Gas Utility Operations The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 38 of California’s 58 counties and includes most of northern and central California. In 2003, the Utility served approximately 3.9 million natural gas distribution customers. The total volume of natural gas throughput during 2003 was approximately 804 Bcf. At December 31, 2003, the Utility’s natural gas system consisted of 39,510 miles of distribution pipelines, 6,350 miles of transportation pipelines and three storage facilities. The Utility’s distribution network connects to the Utility’s transportation and storage system at approximately 2,200 major interconnection points. The Utility’s Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation, a subsidiary of NEGT, at the California-Oregon border. This line has a receipt capacity at the border of 2.0 Bcf per day. The Utility’s Line 300, which interconnects with the U.S. southwest and California-Oregon pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity at the California-Arizona border of approximately 1.1 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada and the southwestern United States. The Utility also is supplied by natural gas fields in California. The Utility also owns and operates three underground natural gas storage fields located along the Utility’s transportation and storage system in close proximity to approximately 90% of the Utility’s end-user demand. These storage fields have a combined annual cycle capacity of approximately 42 Bcf. In addition, two independent storage operators are interconnected to the Utility’s northern California transportation system. Since 1991, the CPUC has divided the Utility’s natural gas customers into two categories — core and noncore customers. This classification is based largely on a customer’s annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial and larger commercial natural gas customers. In 2003, core customers represented over 99% of the Utility’s total customers and 35% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility’s total customers and 65% of its total natural gas deliveries. The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility’s system in its service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have the Utility provide both delivery service and natural gas supply. When the Utility provides both supply and delivery, the Utility refers to the service as natural gas bundled service. Currently, over 99% of core customers, representing over 98% of core market demand, receive natural gas bundled services from the Utility. 13 In accordance with a ratemaking settlement agreement implemented in 1998 called the Gas Accord, the Utility stopped providing procurement service to noncore customers in March 2001. During the winter of 2000-2001 when there was a steep increase in natural gas prices, many noncore customers switched to core service in order to receive procurement service from the Utility. In December 2003, the CPUC approved the Utility’s request to prohibit electricity generation, cogeneration, enhanced oil recovery and refinery, and other large noncore customers from electing to transfer to core service, and requiring smaller noncore customers to sign up for a minimum five-year term if they elect to transfer to core service. The Utility made this request because of its concern that large increases in the Utility’s natural gas supply portfolio demand from significant transfers of noncore customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce it’s pipeline system to provide core service reliability on a short-term basis to serve this new load. The Utility offers transportation, distribution and storage services as separate and distinct services to its noncore customers. These customers may elect to receive storage services from the Utility or competitive storage providers. Noncore customers interconnected at a transportation level only pay for transportation service, while those interconnected at a distribution level pay for both transportation and distribution service. Noncore customers formerly were able to subscribe for natural gas bundled service as if they were core customers but are no longer allowed to do so. Access to the Utility’s transportation system is available for all natural gas marketers and shippers, as well as noncore customers. Customers pay a distribution rate that reflects the Utility’s costs to serve each customer class. The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility’s results of operations over the long term are not The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and natural gas utilities. The 2002 California Gas Report updated the Utility’s annual natural gas requirements forecast for the years 2002 through 2023, forecasting average annual growth in the Utility’s natural gas deliveries of approximately 1.8%. The natural gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, and the number and location of electricity generation facilities. 2003 Natural Gas Deliveries The following table shows the percentage of the Utility’s total 2003 natural gas deliveries represented by each of the Utility’s major customer classes: (804 Bcf) 14 The following table shows the Utility’s operating statistics from 1999 through 2003 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service: 15 The Utility purchases natural gas to serve the Utility’s core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. During 2003, the Utility purchased approximately 292,000 MMcf of natural gas (net of the sale of excess supply) from 48 suppliers. Substantially all this natural gas was purchased under contracts with a term of less than one year. The Utility’s largest individual supplier represented approximately 9.6% of the total natural gas volume the Utility purchased during 2003. The following table shows the total volume and the average price of natural gas in dollars per Mcf of the Utility’s natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In 2003, the sale of excess supplies to parties located in California exceeded purchases from parties located in California. The Utility’s gas gathering system collects and processes natural gas from third-party wells in California. During 2003, approximately 4% of the Utility’s natural gas supplies came from various California producers and from supplies transported into California by others. The natural gas is processed to remove various impurities from the natural gas stream and to odorize the natural gas so that it may be In 2003, approximately 67% of the Utility’s natural gas supplies came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers’ service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- Canadian border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System. These companies’ pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest Corporation which provides natural gas transportation services to interconnection points with the Utility’s natural gas transportation system in the area of California near Malin, Oregon. The Utility has a firm transportation agreement with Gas Transmission Northwest Corporation for these services. During 2003, approximately 29% of the Utility’s natural gas supplies came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Co., 16 The following table shows certain information about the Utility’s firm natural gas transportation agreements, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System, and the FERC in all other cases. The Utility recovers these demand charges through the CPIM. The Utility may, upon prior notice, extend each of these natural gas transportation agreements for additional minimum terms ranging, depending on the particular agreement, from one to ten years. On the FERC-regulated pipelines, the Utility has a right of first refusal allowing it to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term. Competition Historically, energy utilities operated as regulated monopolies within service territories where they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport and distribute energy. Services were priced on a combined, or bundled, basis with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities undertake a continuing obligation to serve their customers, in return for which the 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 17 The In July 2003, in order to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and In 1998, California implemented AB 1890, which mandated the In October 2003, the CPUC instituted a rulemaking implementing AB 117, which permits California cities and counties to purchase and sell electricity for their residents once they have registered as community choice aggregators. Under AB 117, the Utility 18 The Utility faces competition in the electricity distribution business as a result of A number of local governments and districts in California are considering various forms of providing electric distribution services within the Utility’s service territory. The City and County of San Francisco (along with other California communities) have been considering municipalization of the Utility’s electricity distribution system within their jurisdictions. In addition, the Sacramento Municipal Utility District currently is considering annexing portions of the Utility’s service territory, with the objective of enabling the district to replace the Utility within these areas. Some existing public power entities, such as the Modesto and Merced Irrigation Districts, also are expanding their services in the Utility’s service area. Finally, some districts that are not currently distributing electricity, including the El Dorado Irrigation District and the South San Joaquin Irrigation District, are considering building facilities that would duplicate the Utility’s facilities. In May 2003, the South San Joaquin Irrigation District revealed its plans to invest over $40 million to duplicate the Utility’s distribution facilities and begin serving existing and new customers in and around Manteca. In 2002, the City of Hercules formed its own municipal utility for the purpose of competing with the Utility to serve new customers within the city. In 2003, the City of Hercules began providing electricity service to a 200-home subdivision and a large commercial customer, and has been actively pursuing additional residential and commercial customers. The Utility cannot currently predict the impact of these actions on the Utility’s business, although one possible outcome is a decline in the demand for the electricity that the Utility provides, which FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service regardless of In 1998, the Utility implemented the Gas Accord under which the natural gas transportation and storage services the Utility provides were separated for ratemaking purposes from the Utility’s distribution services. The Gas Accord changed the terms of service and rate structure for natural gas transportation, allowing the Utility’s core customers to purchase natural gas from competing suppliers. The Utility’s noncore customers purchase their natural gas from producers, marketers and brokers, and purchase their preferred mix of transportation, storage and distribution services from the Utility. Although they can select the gas suppliers of their choice, substantially all core customers buy natural gas, as well as transportation and distribution services, from the Utility as bundled service. The Gas Accord market structure has been extended by the CPUC through 2005. The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas and the quality and reliability of transportation services. The most important competitive factor affecting the Utility’s market share for transportation of natural gas to the southern California market is 19 PG&E PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935, or During 2003, proposed federal energy legislation was considered by the U.S. Senate. If adopted, the legislation would, among other things, repeal PUHCA. PUHCA currently imposes significant regulatory barriers to mergers and acquisitions involving public utilities and public utility holding companies. The repeal of PUHCA could trigger a period of consolidation among public utilities, as well as acquisitions of public utilities by other businesses. As a result, the repeal of PUHCA could increase competitive pressures on the energy utility industry, including competition from sources the Utility does not currently view as competitors. The proposed effective date for the repeal of PUHCA, as well as the proposed effective date for proposed legislation that would replace PUHCA, is December 1, 2004. Under the proposed legislation that would replace PUHCA, public utilities and public utility holding companies would remain under the regulatory oversight of the FERC, but not the SEC. PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such by the CPUC. However, the CPUC approval authorizing 20 The CPUC also has adopted complex and detailed rules governing transactions between The CPUC also has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations. On April 3, 2001, the CPUC issued an order instituting an investigation into whether the California 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 21 In PG&E Corporation and the Utility believe that they have complied with applicable statutes CPUC decisions, rules and orders. Under the Settlement Agreement the CPUC has agreed to dismiss PG&E Corporation from the CPUC’s investigation as to past practices. On January 10, 2002, the Various aspects of the Utility’s business are subject to a complex set of energy, environmental and other governmental laws, regulations and regulatory proceedings at the federal, state and local levels. This section and the In response to the 22 In February 2004, the During 2003, the FERC confirmed most of the administrative law judge’s findings, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The Under the Settlement Agreement, the Utility and PG&E Corporation agreed to continue to cooperate with the CPUC and the State of California in seeking refunds from generators and other energy suppliers. The The Utility has recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to compromise. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. The Utility currently estimates that the claims filed would have been reduced to approximately $1.2 billion based on the refund methodology recommended in the administrative law judge’s initial decision, resulting in a net liability of approximately $1.0 billion after the approximately $200 million pre-petition offset. The recalculation of market prices according to the revised methodology adopted by the FERC in its October 2003 decision could further reduce the amount of the suppliers’ claims by several hundred million dollars. However, this reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology. The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility’s Diablo Canyon 23 One of PG&E Corporation and the Utility’s obligations under the Settlement Agreement is seeking to refinance the remaining unamortized pre-tax balance of the 24 The California Energy Resources Conservation and The The Utility has over 520 franchise agreements with various cities and counties that Frozen electricity rates, which began on January 1, 1998, were designed to allow the Utility to recover its authorized utility costs, and On January 26, 2004, the Utility filed revised electricity rates with the CPUC based on the Utility’s 2004 forecast revenue requirements and requested implementation of the rate changes. These rates reflect allocation of the Utility’s revenue requirements in accordance with a January 20, 2004 rate design settlement agreement entered into with a number of consumer groups and government agencies, including 25 Based on the revised rates filed by the Utility on January 26, 2004, current electricity revenues are expected to be reduced by approximately $860 million as compared to revenues generated at current rates. On February 11, 2004, a The February 11, 2004 proposed decision orders the Utility to revised electricity rates before March 1, 2004. The Before the rates for the transmission, transportation, The Utility’s primary revenue requirement proceeding is the general rate case, or 26 The CPUC generally conducts an annual cost of capital The CPUC sets and periodically revises a baseline allowance for the Utility’s residential gas and electricity customers. A customer’s baseline allowance is the amount of its monthly usage that is covered under the lowest possible natural gas or electric rate. Electricity baseline usage is also As AB 1X allows the DWR to recover its costs of electricity and associated transmission and related services, principal and interest on bonds issued to finance the Under AB 1X, the The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricity customers of the three California investor-owned electric utilities through what is known as a power 27 The DWR provided approximately 29% of the electricity delivered to the Utility’s customers for the year ended December 31, 2003. The DWR purchased the electricity under contracts with various generators and through open market purchases. The Utility is responsible for administration and dispatch of the DWR’s electricity procurement contracts allocated to the Utility, for purposes of meeting a portion of the Utility’s net open position. The DWR remains legally and financially responsible for the electricity procurement contracts. The contracts terminate at various times through 2012 and consist of must-take and capacity charge contracts. Under must-take contracts, the DWR must take and pay for electricity generated by the applicable generating facility regardless of whether the electricity is needed. Under capacity charge contracts, the DWR must pay a capacity charge but is not required to purchase electricity unless that The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility to On January 1, 2003, the California investor-owned electric utilities resumed responsibility for procuring electricity to meet their residual net open positions. They also became responsible for scheduling and In December 2003, the CPUC approved the Utility’s short-term 2004 procurement plan. In the January 2004 CPUC decision discussed below, the CPUC also adopted short-term procurement authority for 2005 for the utilities in order to allow them to begin the normal cycle for procuring products required for summer 2005, but contracts for 2005 cannot exceed one year. On January 22, 2004, the CPUC adopted an interim decision establishing the long-term regulatory framework under which the California investor-owned electric utilities are required to plan for and procure 28 Effective January 1, 2003, under California law, the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the Under the The The Utility derives the majority of 29 The Utility is a party to At December 31, 2003, the ISO had RMR agreements for It is possible that the Utility may receive a refund of RMR costs that the Utility previously paid to the ISO. In June 2000, a FERC administrative law judge issued an initial decision approving rates that, if affirmed by the FERC, would require the subsidiaries of Mirant Corporation, or Mirant, that are parties to three RMR agreements with the RMR refund. The Utility The ISO bills the Utility for reliability services based on payments that the ISO makes to generators under reliability In March 2000, the ISO 30 In purposes of The Utility sets the natural gas procurement rate for core customers monthly based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates. Under the core procurement incentive mechanism, or the CPIM, the Utility’s natural gas purchase costs (including Canadian and interstate capacity and volumetric transportation charges) are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility On The 31 In July 2002, the CPUC ordered California investor-owned electric utilities to contract for additional amounts of El Paso pipeline capacity Under a previous CPUC decision, the Utility could not recover in rates any costs paid to Transwestern for natural gas pipeline capacity through 1997. The Utility Environmental Matters The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental compliance. The information below reflects current estimates 32 The penalties for violation of these laws and requirements can be severe, and may include significant fines, damages and criminal or civil sanctions. Generally, the In 1994, the CPUC established a ratemaking mechanism 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. There also is a special sharing of the costs incurred pursuing recovery under insurance contracts. In connection with electricity industry restructuring, this mechanism may no longer be used to recover electricity generation-related clean-up costs for contamination caused by events occurring after January 1, 1998. The Utility cannot The Various multi-pollutant initiatives have been introduced in the U.S. Senate and House of As a result of the with these rules. The 33 In addition, The The Utility’s Diablo Canyon In October 2000, the Utility and the Central Coast Board In 34 Many of the The The Utility The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, compressor stations and sites where the Utility stores, recycles and disposes of potentially hazardous materials. 35 Operations at the In addition, the federal Toxic Substances Control Act regulates the use, disposal and cleanup of polychlorinated biphenyls, or PCBs, which are used in certain electrical equipment. During the 1980s, the Utility initiated two major programs to remove from service all of the distribution capacitors and network transformers containing high concentrations of PCBs. These programs removed the vast majority of PCBs existing in the Under environmental laws such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of In addition, the Utility has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Utility is responsible for performing or paying for remedial action at sites that The cost of 36 The Utility had an undiscounted environmental remediation liability of approximately $314 million at December 31, The Utility’s undiscounted future costs could increase to as much as $422 million if the other potentially responsible parties are not financially able to contribute to these costs or The California Attorney General, on behalf of various state environmental agencies, filed claims in the Under the Nuclear Waste Policy Act of 1982, or Nuclear Waste Act, 37 Under current operating procedures, the Utility believes that the Diablo Canyon power plant’s existing spent fuel pools have sufficient capacity to enable it to operate through approximately 2007. It is unlikely that an interim or permanent DOE storage facility will be available by 2007. Therefore, the Utility has applied to the NRC for a license to build an on-site dry cask storage facility to store spent fuel at the Diablo Canyon power plant, pending disposal or storage at a DOE facility. The NRC has provided initial approvals for the facility and is expected to complete its authorization process in early 2004. The Utility also has initiated the process for obtaining a required California Costal Commission permit for the facility. If the dry cask storage facility is not approved or is delayed, the Utility also is pursuing NRC approval of another storage option to install a temporary rack in each unit that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 to 2011. During this additional period of time, the Utility also would pursue NRC approval for a high density reracking of both units, which, if approved, would allow the Utility to operate both units until shortly before the licenses expire in 2021 for Unit 1 and 2025 for Unit 2. If the Utility is unsuccessful in permitting and constructing the on-site dry cask storage facility, and it is otherwise unable to increase its on-site storage capacity it is possible that the operations of Diablo Canyon may have to be curtailed or halted until such time as spent fuel can be safely stored. In July 1988, the NRC gave the Utility final approval The Utility The estimated The CPUC has established the Nuclear Decommissioning Costs Triennial Proceeding to determine the Utility’s estimated 38 Decommissioning costs recovered in rates are placed in In 2003, the Utility collected approximately $22.6 million in rates and contributed approximately $21.3 million, on an after-tax basis, to the nuclear decommissioning trusts. For 2004, the Utility is authorized to collect approximately $18.5 million in rates for decommissioning Humboldt Bay Unit 3. Of this amount, the Utility expects to contribute approximately $13.3 million, on an after-tax basis, to the qualified and non-qualified trusts for Humboldt Bay Unit 3. The Utility has requested the IRS approve the new amounts to be contributed to the qualified trusts for Humboldt Bay Unit 3. If the IRS does not approve the request, the Utility must withdraw any contributions it made to the qualified trusts for 2003 and contribute the withdrawn amounts, on an after-tax basis, to the non-qualified trust. The Utility would likely request that the CPUC approve an increase in revenue requirements to make up for the reduced amount contributed to the non-qualified trust due to the reduced rate of return attributable to taxes The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility’s nuclear facilities. The trusts maintain substantially all of their investments in debt and equity securities. All earnings on the funds held in the trusts, net of authorized disbursements from the trusts and management and administrative fees, are reinvested. Electric In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMFs from new 39 In October 2002, the California Department of Health Services released its report, based primarily on its review of studies by others, evaluating the possible risks from It is not yet clear what actions the CPUC will take to respond to this report. Possible outcomes include, but are not limited to, continuation of current policies and imposition of more stringent measures to mitigate EMF exposures. The Utility cannot estimate the costs of such mitigation measures with any certainty at this time. However, such costs could be significant, depending on the particular mitigation measures undertaken, especially if The Utility currently is not involved in third-party litigation concerning EMFs. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of The PG&E Corporation also leases approximately 40 Pacific Gas and Electric Company On April 6, 2001, David A. Coulter, a director of the In September 2001, PG&E Corporation and the On December 30, 2003, the City of Palo Alto filed On January 20, 2004, the City of Palo Alto, the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, filed separate applications with the CPUC requesting that the CPUC rehear and reconsider its 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 The Settlement Agreement generally terminates nine years after the effective date of the Plan of Reorganization, except that the rights of the parties to the Settlement Agreement that vest on or before termination, including any rights arising from any default under the Settlement Agreement, will survive termination for the purpose of enforcement. The parties agreed that the bankruptcy court will have jurisdiction 41 As required by the Settlement Agreement, the Utility has requested a stay of all proceedings before the FERC, the NRC, the SEC and of reorganization. On On November 19, 2003, the Ninth Circuit Although the Ninth Circuit The Utility’s current Settlement Agreement and the confirmed Plan of Reorganization do not rely on the bankruptcy law preemption issues addressed in the Ninth Circuit decision. Implementation of the Plan of Reorganization is subject to 42 On July 8, 2003, NEGT and certain of its subsidiaries filed voluntary petitions for relief under the In anticipation of NEGT’s Chapter 11 filing, PG&E Corporation’s representatives who previously served as directors of NEGT resigned on For more information, see Note 5 of the Pacific Gas and Electric Company vs. On November 8, 2000, The On In August 2001, On On August 23, 2002, the 43 Under the Settlement Agreement, the Utility will dismiss the filed rate case with prejudice on or as soon as practicable after the later of the effective date of the Plan of Reorganization and the date on which CPUC approval of the Settlement Agreement is no longer subject to appeal. Therefore, the Utility filed a In re: Natural Gas Royalties Qui Tam Litigation This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Under procedures established by the False Claims Act, the United States, The complaints allege that the various defendants, The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties In 44 The California Attorney General has filed a On June 13, 2002, the Utility received a draft In April 2003, the Utility signed a final settlement The Utility Complaints Filed by the California Attorney General, On January 10, 2002, the California utilities and their parent holding companies appealed the The complaint seeks injunctive relief, the appointment of a receiver, restitution in an amount according to proof, civil penalties of $2,500 against each defendant for each violation of 45 On August 9, 2002, the California On February 11, 2002, a complaint entitledCity and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in San Francisco Superior Court. The complaint contains some of the same allegations contained in the After removing the entitledCynthia Behr v. PG&E Corporation, et al. In its June 2002 ruling The San Francisco Superior Court has coordinated the California Attorney General’s case with the cases filed by the City and County of San Francisco and Cynthia Behr. On July 24, 2003, the District Court heard oral argument on the appeal and cross-appeal 46 The defendants filed a motion to seek clarification from the District Court regarding whether the District Court’s October 2003 order reaches the restitution claims against the director defendants, as distinct from PG&E Corporation. At a hearing in November 2003, the District Court confirmed that its October 2003 order holds that the defendants’ restitution claims against the directors are also the property of the Utility’s estate. PG&E Corporation believes that the The following 14 civil suits are pending in several California courts against the Utility relating to alleged chromium contamination: (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995, in Los Angeles County Superior Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996, in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November 27, 1996, in Los Angeles County Superior Court, (4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed July 25, 2000, in Los Angeles County Superior Court, (5) Baldonado v. Pacific Gas and Electric Company, filed October 25, 2000, in Los Angeles County Superior Court, (6) Gale v. Pacific Gas and Electric Company, filed January 30, 2001, in Los Angeles County Superior Court, (7) Fordyce v. Pacific Gas and Electric Company, filed March 16, 2001, in San Bernardino Superior Court, (8) Puckett v. Pacific Gas and Electric Company, filed March 30, 2001, in Los Angeles County Superior Court, (9) Alderson, et al. v. PG&E Corporation, Pacific Gas and Electric Company, Betz Chemical Company, et al., filed April 11, 2001, in Los Angeles County Superior Court, (10) Bowers, et al. v. Pacific Gas and Electric Company, et al., filed April 20, 2001, in Los Angeles County Superior Court, (11) Boyd, et al. v. Pacific Gas and Electric Company, et al., filed May 2, 2001, in Los Angeles County Superior Court, (12)Martinez, et al. v. Pacific Gas and Electric Company, filed June 29, 2001, in San Bernardino County Superior Court, (13) Miller v. Pacific Gas and Electric Company, filed November 21, 2001, in Los Angeles County Superior Court, and (14) Lytle v. Pacific Gas and Electric Company, filed March 22, 2002, in Yolo County Superior Court. In general, plaintiffs and claimants allege that exposure to chromium at or near the Utility’s gas compressor stations located at Kettleman and Hinkley, California, and the area of California near Topock, Arizona caused personal injuries, wrongful death, or other injury and seek related damages. The bankruptcy court has granted certain claimants’ motion for relief from stay so that the state court lawsuits pending before the Utility’s Chapter 11 filing can proceed. 47 The Utility is responding to the suits in which the Utility has been served and is asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including the statute of limitations, exclusivity of workers’ compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select plaintiffs from theAguayo, AcostaandAguilar cases for a test trial. Plaintiffs’ counsel selected ten of these initial trial plaintiffs,, defense counsel selected seven of the plaintiffs, and one plaintiff and two alternates were selected at random. The Utility has filed 13 summary judgment motions or motions in limine (motions to exclude potentially prejudicial information) challenging the The Utility has Not applicable. All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation. 48 49 All officers of 50 Information responding to part of Item 5, for each of PG&E Corporation and Pacific Gas and Electric Company, is set forth On Pacific Gas and Electric Company did not make any sales of unregistered equity securities during A summary of selected financial information, for each of PG&E Corporation and Pacific Gas and Electric Company for each of the last five fiscal years, is set forth A discussion of PG&E 51 Information responding to Item 7A appears in the Information responding to Item 8 appears Not applicable. Based on an evaluation of PG&E Corporation’s and Pacific Gas and Electric Company’s disclosure controls and procedures as of December 31, 2003, PG&E Corporation’s and Pacific Gas and Electric Company’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and Pacific Gas and Electric Company’s 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. There were no changes in internal controls over financial reporting that occurred during the quarter ended December 31, 2003, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or Pacific Gas and Electric Company’s controls over financial reporting. Directors The authorized number of directors of PG&E Corporation currently is 10, and the authorized number of directors of the Utility currently is 11. On February 18, 2004, each Board of Directors approved amendments to the respective company’s bylaws to reduce the authorized number of directors effective upon adjournment of the 2004 Joint Annual Meeting of shareholders. After these amendments become effective, the bylaws will provide that the authorized number of directors of PG&E Corporation will be eight, and the authorized number of directors of Pacific Gas and Electric Company will be nine. Information is provided below about the directors of PG&E Corporation and the Utility, including their principal occupations for the past five years, certain other directorships, age, and length of service as a director 52 David R. Andrews. Mr. Andrews is Senior Vice President Government Affairs, General Counsel, and Secretary of PepsiCo, Inc. (food and beverage businesses), and has held that position since February 2002. Prior to joining PepsiCo, Inc., Mr. Andrews was a partner in the law firm of McCutchen, Doyle, Brown & Enersen, LLP from May 2000 to January 2002 and from 1981 to July 1997. From August 1997 to April 2000, he served as the legal advisor to the U.S. Department of State and former Secretary Madeleine Albright. Mr. Andrews, 62, has been a director of PG&E Corporation and the Utility since 2000. He also serves as a director of UnionBanCal Corporation. Leslie S. Biller. Mr. Biller is retired Vice Chairman and Chief Operating Officer of Wells Fargo & Company (financial services and retail banking). He held that position from November 1998 until his retirement in October 2002. Mr. Biller was President and Chief Operating Officer of Norwest Corporation (bank holding company) from 1997 until it merged with Wells Fargo & Company in 1998. Mr. Biller, 55, has been an advisory director of PG&E Corporation and the Utility since January 2003, and was elected a director of PG&E Corporation and the Utility on February 18, 2004. He also serves as a director of Ecolab Inc. David A. Coulter. Mr. Coulter is Vice Chairman of J.P. Morgan Chase & Co. and J.P. Morgan Chase Bank, responsible for its investment bank, investment management, and private banking., and has held that position since January 2001. Prior to the merger with J.P. Morgan & Co. Incorporated, he was Vice Chairman of The Chase Manhattan Corporation (bank holding company) from August 2000 to December 2000. He was a partner in the Beacon Group, L.P. (investment banking firm) from January 2000 to July 2000, and was Chairman and Chief Executive Officer of BankAmerica Corporation and Bank of America NT&SA from May 1996 to October 1998. Mr. Coulter, 56, has been a director of PG&E Corporation and the Utility since 1996. He also serves as a director of Strayer Education, Inc. C. Lee Cox. Mr. Cox is retired Vice Chairman of AirTouch Communications, Inc. and retired President and Chief Executive Officer of AirTouch Cellular (cellular telephone and paging services). He was an executive officer of AirTouch Communications, Inc. and its predecessor, PacTel Corporation, from 1987 until his retirement in April 1997. Mr. Cox, 62, has served as a director of PG&E Corporation and the Utility since 1996. William S. Davila. Mr. Davila is President Emeritus of The Vons Companies, Inc. (retail grocery). He was President of The Vons Companies, Inc. from 1986 until his retirement in May 1992. Mr. Davila, 72, has been a director of the Utility since 1992 and a director of PG&E Corporation since 1996. He also serves as a director of The Home Depot, Inc. Robert D. Glynn, Jr. Mr. Glynn is Chairman of the Board, Chief Executive Officer, and President of PG&E Corporation and Chairman of the Board of the Utility. He has been an officer of PG&E Corporation since December 1996 and an officer of the Utility since January 1988. Mr. Glynn, 61, has been a director of the Utility since 1995 and a director of PG&E Corporation since 1996. David M. Lawrence, MD Dr. Lawrence is retired Chairman and Chief Executive Officer of Kaiser Foundation Health Plan, Inc. and Kaiser Foundation Hospitals, and was an executive officer of those companies from 1991 until his retirement in 2002. Dr. Lawrence, 63, has been a director of the Utility since 1995 and a director of PG&E Corporation since 1996. He also serves as a director of Agilent Technologies Inc. and McKesson Corporation. Mary S. Metz. Dr. Metz is President of S. H. Cowell Foundation, and has held that position since January 1999. Prior to that date, she was Dean of University Extension, University of California, Berkeley from July 1991 to June 1998. Dr. Metz, 66, has been a director of the Utility since 1986 and a director of PG&E Corporation since 1996. She also serves as a director of Longs Drug Stores Corporation, SBC Communications Inc., and UnionBanCal Corporation. Carl E. Reichardt. Mr. Reichardt served as Vice Chairman of Ford Motor Company from October 2001 to July 2003. He is retired Chairman of the Board and Chief Executive Officer of Wells Fargo & 53 Gordon R. Smith. Mr. Smith is President and Chief Executive Officer of the Utility, and has been an officer of the Utility since 1980. Mr. Smith, 56, has been a director of the Utility since 1997. Barry Lawson Williams. Mr. Williams is President of Williams Pacific Ventures, Inc. (business investment and consulting), and has held that position since 1987. He also served as interim President and Chief Executive Officer of the American Management Association (management development organization) from November 2000 to June 2001. Mr. Williams, 59, has been a director of the Utility since 1990 and a director of PG&E Corporation since 1996. He also serves as a director of CH2M Hill Companies, Ltd., The Northwestern Mutual Life Insurance Company, R.H. Donnelley Corporation, The Simpson Manufacturing Company Inc., and SLM Corporation. Executive Officers Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included in a separate item captioned Section 16 Beneficial Ownership Reporting Compliance In accordance with Section 16(a) of the Securities Exchange Act of 1934 and Securities and Exchange Commission (SEC) regulations, PG&E Corporation’s and the Utility’s directors and certain officers, and persons who own greater than 10 percent of PG&E Corporation’s or the Utility’s equity securities must file reports of ownership and changes in ownership of such equity securities with the SEC and the principal national securities exchange on which those securities are registered, and must furnish PG&E Corporation or the Utility with copies of all such reports they file. Based solely on its review of copies of such reports received or written representations from certain reporting persons, PG&E Corporation and the Utility believe that during 2003 all filing requirements applicable to their respective directors, officers, and 10 percent shareholders were satisfied, except that a Statement of Changes of Beneficial Ownership of Securities on Form 4 was filed late for Thomas B. King due to internal corporate administrative delays. No information Audit Committee Members and Financial Expert The members of the Audit Committees for each of PG&E Corporation and the Utility are C. Lee Cox, David R. Andrews, William S. Davila, Mary S. Metz, and Barry Lawson Williams. The Boards of Directors of PG&E Corporation and the Utility each have determined that both C. Lee Cox and Barry Lawson Williams, members of each company’s Audit Committee, each are “audit committee financial experts” as defined by the SEC regulations, implementing Section 407 of the Sarbanes-Oxley Act of 2002. Each Board of Directors has determined that Mr. Cox and Mr. Williams each are “independent” as defined by current listing standards of the New York Stock Exchange and the American Stock Exchange, as applicable. Website Availability of Corporate Governance and Other Documents The following documents are available both on PG&E Corporation’s website www.pgecorp.com, and Pacific Gas and Electric 54 If any amendments are made to, or any waivers are granted with respect to, provisions of the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company that apply to their respective Chief Executive Officers, Chief Financial Officers or Controllers, the company whose code is Compensation of Directors Each director who is not an officer or employee of PG&E Corporation or the Utility receives a quarterly retainer of $7,500 plus a fee of $1,000 for each Board or Board committee meeting attended. Non-employee directors who chair Board committees receive an additional quarterly retainer of $625. Under the Deferred Compensation Plan for Non-Employee Directors, directors of PG&E Corporation or the Utility may elect to defer all or part of such compensation for varying periods. Directors who participate in the Deferred Compensation Plan may convert their deferred compensation into common stock equivalents, the value of which is tied to the market value of PG&E Corporation common stock. Alternatively, participating directors may elect that their deferred compensation be invested in the Utility Bond Fund. No director who serves on both the PG&E Corporation and Utility Boards and corresponding committees is paid additional compensation for concurrent service on the Utility’s Board or its committees, except that separate meeting fees are paid for each meeting of the Utility Board, or a Utility Board committee, that is not held concurrently or sequentially with a meeting of the PG&E Corporation Board or a corresponding PG&E Corporation Board committee. It is the usual practice of PG&E Corporation and the Utility that meetings of the respective Boards and corresponding committees are held concurrently and, therefore, that a single meeting fee is paid to each director for each set of meetings. Directors of PG&E Corporation or the Utility are reimbursed for reasonable expenses incurred for participating in Board meetings, committee meetings, or other activities undertaken on behalf of PG&E Corporation or the Utility. Effective January 1, 1998, the PG&E Corporation Retirement Plan for Non-Employee Directors was terminated. Directors who had accrued benefits under the Under the Non-Employee Director Stock Incentive Plan, which is a component of the PG&E Corporation Long-Term Incentive Program, on the first business day of January of each year, each non-employee director of PG&E Corporation is entitled to receive stock-based grants with a total aggregate equity value of $30,000, composed of (1) restricted shares of PG&E Corporation common stock valued at $10,000 (based on the closing price of PG&E Corporation common stock on the first business day of the year), and (2) a combination, as elected by the director, of non-qualified stock options and common stock equivalents with a total equity value of $20,000, based on equity value increments of $5,000. The exercise price of stock options is equal to the market value of PG&E Corporation common stock (i.e., the closing price) on the date of grant. Restricted stock and stock options vest over the five-year period following the date of grant, except that restricted stock and stock options will vest immediately upon mandatory retirement from the Board, upon a director’s death or disability, or in the event of a change in control. Common stock equivalents awarded to non-employee directors are payable only in the form of PG&E Corporation common stock following a 55 On January 2, 2003, each non-employee director received 684 restricted shares of PG&E Corporation common stock. In addition, directors who were granted stock options received options to purchase 1,101 shares of PG&E Corporation common stock for each $5,000 increment of equity value (subject to the aggregate $20,000 limit) at an exercise price of $14.61 per share, and directors who were granted common stock equivalents received 342 common stock equivalent units for each $5,000 increment of equity value (subject to the aggregate $20,000 limit). This table summarizes the principal components of compensation paid to the Chief Executive Officers and the other most highly compensated executive officers of PG&E Corporation and the Utility during the past year. 56 57 58 Option/SAR Grants in 2003 This table summarizes the distribution and the terms and conditions of stock options granted to the executive officers named in the Summary Compensation Table during the past year. 59 Aggregated Option/SAR Exercises in 2003 and Year-End Option/SAR Values This table summarizes exercises of stock options and tandem stock appreciation rights (granted in prior years) by the executive officers named in the Summary Compensation Table during the past year, as well as the number and value of all unexercised options held by such named executive officers at the end of 2003. Long-Term Incentive Program — Awards in 2003 This table summarizes the long-term incentive grants made to the executive officers named in the Summary Compensation Table during the past year. 60 Retirement Benefits PG&E Corporation and the Utility provide retirement benefits to some of the executive officers named in the Summary Compensation Table. The benefit formula for eligible executive officers is 1.7 percent of the average of the three highest combined salary and annual Short-Term Incentive Plan payments during the last ten years of service multiplied by years of credited service. During 2002 and 2003, annuities were purchased to replace a significant portion of the unfunded retirement benefits for certain officers whose entire accrued benefit could not be provided under the Termination of Employment and Change in Control Provisions The PG&E Corporation Officer Severance Policy, which covers most officers of PG&E Corporation and its subsidiaries, including the executive officers named in the Summary Compensation Table, provides benefits if a covered officer is terminated without cause. In most situations, benefits under the policy include (1) a lump sum payment of one and one-half or two times annual base salary and Short-Term Incentive Plan target (the applicable severance multiple being dependent on an officer’s level), (2) continued vesting of equity-based incentives for 18 months or two years after termination (depending on the applicable severance multiple), (3) accelerated vesting of up to two-thirds of the common stock equivalents granted under the Executive Stock Ownership Program (depending on an officer’s level), and (4) payment of health care insurance premiums for 18 months or two years after termination (depending on the applicable severance multiple). In lieu of all or a portion of the lump sum payment, a terminated officer who is covered by PG&E Corporation’s Supplemental Executive Retirement Plan can elect additional years of service and/or age for purposes of calculating pension benefits. Effective July 21, 1999, the policy was amended to provide covered officers with alternative benefits that apply upon actual or constructive termination following a change in control or potential change in control. For these purposes, “change in control” has the same definition as under the Long-Term Incentive Program (see below). Constructive termination includes certain changes to a covered officer’s responsibilities. In the event of a change in control or potential change in control, the policy provides for a lump sum payment of the total of (1) unpaid base salary earned through the termination date, (2) Short-Term Incentive Plan target calculated for the fiscal year in which termination occurs (Target Bonus), (3) any accrued but unpaid vacation pay, and (4) three times the sum of Target Bonus and the officer’s annual base salary in effect immediately before either the date of termination or the change in control, whichever base salary is greater. Change in control termination benefits also include reimbursement of excise taxes levied upon the severance benefit pursuant to Internal Revenue Code Section 4999. The Long-Term Incentive Program (LTIP) permits the grant of various types of stock-based incentives, including performance shares, stock options, restricted stock, performance units, and incentives granted under the Non-Employee Director Stock Incentive Plan. The LTIP and the component plans provide that, upon the occurrence of a change in control, (1) any time periods relating to the 61 Security Ownership of Management The following table sets forth the number of shares of PG&E Corporation common stock beneficially owned (as defined in the rules of the Securities and Exchange Commission) as of January 31, 2004, by the respective directors of PG&E Corporation and the Utility, the executive officers of PG&E Corporation and the Utility named in the Summary Compensation Table, and all directors and executive officers of PG&E Corporation and the Utility as a group. As of January 31, 2004, no director, nominee for director, or executive officer owned shares of any class of the Utility’s securities. The table also sets forth common stock equivalents credited to the accounts of directors and executive officers under PG&E Corporation’s deferred compensation and equity plans. 62 63 Principal Shareholders The following table presents certain information 64 The following table provides information as of December 31, Not applicable. Item 14. Principal Accountant Fees and Services Fees Paid to Independent Public Accountants The Audit Committees have reviewed the audit and non-audit fees that PG&E Corporation, Pacific Gas and Electric Company, and their respective subsidiaries have paid to the independent public accountants for purposes of considering whether such fees are compatible with maintaining the auditor’s independence. Audit Fees.Estimated fees billed for services rendered by Deloitte & Touche LLP for the reviews of Forms 10-Q and for the audits of the financial statements of PG&E Corporation and its subsidiaries were $9.8 million for 2002 and $6.5 million for 2003. These amounts include fees for stand-alone audits of various subsidiaries, including estimated fees of $4.4 million for 2002 and $2.8 million for 2003 for Pacific Gas and Electric Company and its subsidiaries. Tax Fees.Aggregate fees billed for permissible tax services rendered by Deloitte & Touche LLP to PG&E Corporation and its subsidiaries consisted of $2.2 million of fees during 2002 and $1.1 million of fees during 2003. These amounts for 2002 include $4,000 for Pacific Gas and Electric Company and its subsidiaries. Specific services in both years include services to support IRS audit appeals and questions, tax 65 All Other Fees.Aggregate fees billed for all other services rendered by Deloitte & Touche LLP to PG&E Corporation and its subsidiaries consisted of $1.1 million in 2002. These services were consulting services for the implementation of risk management software. None of these services were for Pacific Gas and Electric Company. No such services were rendered in 2003. Pre-Approval of Services Provided by the Independent Public Accountant As of June 2002, PG&E Corporation and its controlled subsidiaries have entered into new engagements with Deloitte & Touche LLP and its affiliate, Deloitte Consulting, only for audit services, audit-related services, or tax services, which Deloitte & Touche LLP and its affiliates may provide to Deloitte & Touche LLP’s audit clients under the Sarbanes-Oxley Act of 2002. PG&E Corporation and its subsidiaries traditionally have obtained these types of services from its independent public accountants. Since November 2002, the Audit Committees have been responsible for pre-approving all audit and non-audit services provided by Deloitte & Touche LLP to PG&E Corporation, Pacific Gas and Electric Company, or their controlled subsidiaries, pursuant to Committee pre-approval procedures that are reviewed and amended from time to time. At the beginning of each Following the initial annual pre-approval, the Audit Committees must pre-approve any proposed engagement of the independent public accountants for any audit, audit-related, and Each Audit Committee has delegated to one or more members of the Committee the authority to pre-approve audit and non-audit services provided by the respective company’s independent public accountants. Any pre-approvals granted pursuant to this authority must be presented to the During 2003, 66 (a) 67 68 69 70 71 72 73 (b) The 75 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated. To the Shareholders and the Boards of Directors of We have audited the consolidated financial statements of PG&E Corporation and subsidiaries and of Pacific Gas and Electric Company (a Debtor-in-Possession) and subsidiaries (collectively, the “Companies”) as of December 31, DELOITTE & TOUCHE LLP San Francisco, California CONDENSED BALANCE SHEETS 78 CONDENSED STATEMENTS OF 79 SCHEDULE 80 SCHEDULE 81TABLE OF CONTENTSPage GlossaryUnits of TermsMeasurement iii
PART IItem 1. Business 1 GENERAL1 Corporate Structure and Business 1 Proposed Plans of Reorganization of the Utility2Risk Factors4REGULATION8Regulation of PG&E Corporation8Regulation of Pacific Gas and Electric Company10 Federal Regulation10 State Regulation11 Assembly Bill 1890—California Electric Industry Restructuring11 Assembly Bill 1X—California Department Of Water ResourcesThe Utility 141 Assembly Bill 6X—Prohibition on Disposition of Retained Utility-Owned Generating AssetsNEGT 141 Senate Bill 1976—Resumption of ProcurementCorporate and Other Information 152 Local Regulation, Licenses and PermitsEmployees16 Regulation of PG&E National Energy Group, Inc. Businesses2 16 Federal RegulationThe Utility’s Plan of Reorganization and Settlement Agreement 162 State and Other RegulationsRefinancing Supported by a Dedicated Rate Component17 COMPETITION3 18The Electric Industry18The Natural Gas Industry18Electric Generation and Natural Gas Transmission19UTILITY OPERATIONS20Ratemaking Mechanisms20 Electric RatemakingForward Looking Statements and Risk Factors 214 Electric DistributionUtility Operations 226 Electric TransmissionElectricity Distribution Operations 226 Electric GenerationElectricity Resources 248 Electric ProcurementElectricity Transmission 2412 Natural Gas RatemakingUtility Operations 2713 Natural Gas DistributionSupplies 2716 Natural Gas Transportation and StorageGathering Facilities 2816 Interstate and Canadian Natural Gas ProcurementTransportation Services Agreements28 Public Purpose Programs16 29ELECTRIC UTILITY OPERATIONS30Electric Distribution30Electric Distribution Operating Statistics30Electric Resources32 Retained GenerationCompetition 3217 Allocation of DWR Electricity to the California Investor-Owned Utilities 33The Electric Industry18 Qualifying Facility Agreements 34The Natural Gas Industry19 Renewable Resource Energy ContractsPG&E Corporation’s Regulatory Environment 3520 Other Third-Party Power Agreements 35Federal Energy Regulation Electric Transmission20 36GAS UTILITY OPERATIONS37 Gas Operating Statistics 39State Energy Regulation20 Natural Gas SuppliesThe Utility’s Regulatory Environment 4022 Natural Gas Gathering Facilities 41Federal Energy Regulation22 Natural Gas Transportation and Storage Services Agreements 41State Energy Regulation24 PG&E NATIONAL ENERGY GROUP, INC. 42Other Regulation25 i ENVIRONMENTAL MATTERSRatemaking Mechanisms 4825 Overview 25 DWR Electricity and DWR Revenue Requirements 27 DWR Allocated Contracts 28 Procurement Resumption and Procurement Plans 28 Electricity Transmission 29 Natural Gas 31 Environmental Matters 4832 Environmental Protection Measures 48General32 Air Quality 48Air Quality33 Water Quality 50Water Quality34 Endangered Species 52Endangered Species35 Hazardous Waste Compliance and Remediation 5235 Potential Recovery of Hazardous Waste Compliance and Remediation Costs 54Nuclear Fuel Disposal37 Nuclear Fuel Disposal 55Nuclear Decommissioning38 Nuclear Decommissioning 56Electric and Magnetic Fields Compressor Station Litigation39 57 Electric and Magnetic Fields57 Low Emission Vehicle Programs57Item 2. Properties 5840 Page Item 3. Legal Proceedings 5840 Pacific Gas and Electric Company Chapter 11 Filing 41 Chapter 11 Filing of NEGT 43 Pacific Gas and Electric Company vs. Michael Peevey, et al. 43 In. re: Natural Gas Royalties Qui Tam Litigation 44 Diablo Canyon Power Plant 44 Complaints Filed by the California Attorney General, City and County of San Francisco and Cynthia Behr 45 Compressor Station Chromium Litigation 47 Item 4. Submission of Matters to a Vote of Security Holders 7248 EXECUTIVE OFFICERS OF THE REGISTRANTSExecutive Officers of the Registrants 7248
PART IIItem 5. Market for the Registrant'sRegistrant’s Common Equity and Related StockholderShareholder Matters 7651 Item 6. Selected Financial Data 7751 Item 7. Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations 7751 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 7752 Item 8. Financial Statements and Supplementary Data 7752 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 7752
Item 9A.Controls and Procedures 52 PART III Item 10. Directors and Executive Officers of the Registrant 7852 Directors 52 Executive Officers 54 Section 16 Beneficial Ownership Reporting Compliance 54 Audit Committee Members and Financial Expert 54 Website Availability of Corporate Governance and Other Documents 54 Item 11. Executive Compensation 7855 Compensation of Directors 55 Summary Compensation Table 56 Option/SAR Grants in 2003 59 Aggregated Option/SAR Exercises in 2003 and Year-End Option/SAR Values 60 Long Term Incentive Program-Awards in 2003 60 Retirement Benefits 61 Termination of Employment and Change in Control Provisions 61 Item 12. Security Ownership of Certain Beneficial Owners and Management 7862 Security Ownership of Management 62 Principal Shareholders 64 Equity Compensation Plan Information 65 Item 13. Certain Relationships and Related Transactions 7865 Item 14. ControlsPrincipal Accountant Fees and ProceduresServices 7965 Fees Paid to Independent Public Accountants 65 Pre-Approval of Services Provided by the Independent Public Accountant 66 PART IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 7967 SIGNATURESSignatures88 Certifications76 89 Independent Auditors'Auditors’ Report 9377 Financial Statement Schedules 9478 AB 1890 Assembly Bill 1890, the California electric industry restructuring legislationBACT Best available control technologyBCAPUNITS OF MEASUREMENT 1 Kilowatt (kW) Biennial Cost Allocation Proceedingbcf= One thousand watts 1 Kilowatt-Hour (kWh) = One kilowatt continuously for one hour 1 Megawatt (MW) = One thousand kilowatts 1 Megawatt-Hour (MWh) = One megawatt continuously for one hour 1 Gigawatt (GW) = One million kilowatts 1 Gigawatt Hour (GWh) = One gigawatt continuously for one hour 1 Kilovolt (kV) = One thousand volts 1 MVA = One megavolt ampere 1 Mcf = One thousand cubic feet 1 MMcf = One million cubic feet 1Bcf = One billion cubic feet BFM1MDth block forward marketBTA= best technology availableBtuBritish thermal unitCCAACalifornia Clean Air ActCECCalifornia Energy CommissionCEQACalifornia Environmental Quality ActCERCLAComprehensive Environmental Response, Compensation, and Liability Actcore customersresidential and smaller commercial gas customerscore subscription customersnoncore customers who choose bundled serviceCPIMcore procurement incentive mechanismCPUCCalifornia Public Utilities CommissionDiablo CanyonDiablo Canyon Nuclear Power PlantDOEUnited States Department of EnergyDWRCalifornia Department of Water ResourcesEMFelectric and magnetic fieldsEPAUnited States Environmental Protection AgencyFERCFederal Energy Regulatory CommissionGRCGeneral Rate CaseHumboldt Unit 3Humboldt Bay Power Plant (Unit 3)HWRChazardous waste remediation costsIPPindependent power producerIOU or IOUsinvestor owned utility or utilitiesISOIndependent System OperatorKVKilovoltsKVakilovolt-amperesKWKilowattsMcfthousand cubic feetMDtOne thousand decatherms MMcfmillion cubic feetMWMegawattsMWhmegawatt-hournoncore customersindustrial and larger commercial gas customersNPDESNational Pollutant Discharge Elimination SystemNRCNuclear Regulatory CommissionORAOffice of Ratepayer Advocates, a division of the California Public Utilities CommissionPG&E EnergyPG&E NEG's integrated energy and marketing segmentPG&E ETPG&E Energy Trading Holdings Corporation and its subsidiariesPG&E Gen LLCPG&E Generating Company, LLC and its affiliatesPG&E GTCPG&E Gas Transmission Corporation and its subsidiariesPG&E GTNPG&E Gas Transmission, Northwest CorporationPG&E NBPPG&E North Baja Pipeline, LLCPG&E NEGPG&E National Energy Group, Inc.PG&E PipelinePG&E NEG's interstate pipeline operationsPURPAPublic Utility Regulatory Policies Act of 1978PXCalifornia Power ExchangeQFqualifying facilityRCRAResource Conservation and Recovery ActRTOregional transmission organizationTCBATransition Cost Balancing Accountthroughputthe amount of natural gas transported through a pipeline systemTRATransition Revenue AccountTURNThe Utility Reform NetworkUSGenNEUSGen New England, Inc.ITEMItem 1. Business.headquartered in San Francisco, California whichthat conducts its business principally through two principal subsidiaries: Pacific Gas and Electric Company, or the Utility, an operatinga public utility engaged principallyoperating in northern and central California. The Utility engages primarily in the businessbusinesses of providing electricity and natural gas distribution, electricity generation, electricity transmission, and transmission services throughout mostnatural gas transportation and storage. PG&E Corporation became the holding company of northernthe Utility and centralits subsidiaries on January 1, 1997. The Utility, incorporated in California andin 1905, is the predecessor of PG&E Corporation. PG&E Corporation also currently owns National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., or PG&E NEG, a company engagedwhich engages in powerelectricity generation wholesale energy marketing and trading, risk management, and natural gas transmission.transportation in the United States, or U.S.The Utility Pacific GasThe Utility served approximately 4.9 million electricity distribution customers and Electric Company was incorporatedapproximately 3.9 million natural gas distribution customers at December 31, 2003. The Utility had approximately $29.1 billion of assets at December 31, 2003, and generated revenues of approximately $10.4 billion in 2003. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California in 1905. Effective January 1, 1997,Public Utilities Commission, or the UtilityCPUC, and its subsidiaries became subsidiaries of PG&E Corporation, which was incorporated in 1995. In the holding company reorganization,Federal Energy Regulatory Commission, or the Utility's outstanding common stock was converted on a share-for-share basis into PG&E Corporation common stock. The Utility's debt securities and preferred stock were unaffected and remain as outstanding securities of Pacific Gas and Electric Company. TheFERC.United StatesU.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California on April 6, 2001. Pursuant to Chapter 11,California. The factors that caused the Utility retainsto take this action 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 2003 Annual Report to Shareholders, or the Annual Report, which is incorporated by reference into this report. The Utility has retained control of its assets and is authorized to operate its business as a debtor-in-possession while being subjectduring its Chapter 11 proceeding.jurisdiction ofConsolidated Financial Statements in the Bankruptcy Court. The Utility is regulated primarily by the California Public Utilities Commission, or CPUC, and the Federal Energy Regulatory Commission, or FERC.Annual Report.NEGT PG&E NEG, headquartered in Bethesda, Maryland,NEGT was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter,NEGT’s subsidiaries include: Gas Transmission Northwest Corporation (formerly PG&E Corporation contributed various subsidiaries toGas Transmission Northwest Corporation), North Baja Pipeline, LLC, National Energy Power Company, LLC (formerly PG&E NEG. PG&E NEGGenerating Power Group, LLC) and its subsidiaries, are principally locatedUSGen New England, Inc. and its affiliates, and National Energy & Gas Transmission Trading Holdings Corporation and its subsidiaries.United States and Canada. PG&E NEG's principalU.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. On the same day, each of the following indirect wholly owned subsidiaries include: PG&E Generating Company, LLC, and its subsidiaries, or PG&E Gen;of NEGT filed a voluntary petition for relief under Chapter 11: PG&E Energy Trading Holdings Corporation (now NEGT Energy Trading Holdings Corporation), PG&E Energy Trading-Power, L.P. (now NEGT Energy Trading — Power, L.P.), PG&E Energy Trading — Gas Corpora-orto take this action are discussed in the MD&A and in Note 5 of the Notes to the Consolidated Financial Statements in the Annual Report. Pursuant to Chapter 11, NEGT and its subsidiaries that filed Chapter 11 petitions retain control of their assets and are authorized to operate their businesses as debtors-in-possession while they are subject to the jurisdiction of the bankruptcy court.ET;Corporation’s equity interest in NEGT and its subsidiaries. In anticipation of NEGT’s Chapter 11 filing, PG&E Corporation’s representatives, who previously served as directors of NEGT resigned on July 7, 2003, and were replaced with directors who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retains significant influence over NEGT. Accordingly, effective July 8, 2003, NEGT’s results of operations no longer are consolidated with those of PG&E Corporation. NEGT’s results of operations through July 7, 2003, and for prior years have been reclassified as discontinued operations and PG&E Gas Transmission Corporation andnow accounts for its subsidiaries, or PG&E GTC, which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries, or PG&E GTN, and North Baja Pipeline, LLC, or NBP. PG&E NEG also has other less significant subsidiaries.investment in NEGT using the cost method of accounting.Corporate and Other Information Pacific Gas and Electric Companythe Utility is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. PG&E Corporation and the Utility and PG&E NEG each file various reports with the Securities and Exchange Commission, or the SEC. TheThese reports, that PG&E Corporationincluding Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Utility file with the SECSecurities Exchange Act of 1934, as amended, are available free of charge on both PG&E Corporation'sCorporation’s website,www.pge-corp.com, and the Utility'sUtility’s website,www.pge.com. PG&E NEG's reports also are available free of chargeThe information contained on PG&E Corporation's website,www.pge-corp.com. PG&E Corporation has identified three reportable operating segments:•Utility,•Integrated Energy and Marketing (or the Generation Business), and•Interstate Pipeline Operations (or the Pipeline Business) These segments were determined based on similarities in the following characteristics: economics, products and services, types of customers, methods of distribution, regulatory environment, and how informationthese websites is reported to and used by PG&E Corporation's chief operating decision makers. These three reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdictions. Financial information about each reportable operating segment is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the 2002 Annual Report to Shareholders and in Note 17 of the "Notes to Consolidated Financial Statements" of the 2002 Annual Report to Shareholders, which information isnot incorporated by reference into this report. As result of the sustained downturn in the power industry during 2002, PG&E NEGAnnual Report on Form 10-K and its affiliates have experienced a financial downtown which caused the major credit rating agencies to downgrade PG&E NEG's and1its affiliates' credit ratings to below investment grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.5 billion, but this debt is non-recourse to PG&E NEG. PG&E NEG and these subsidiaries continue to negotiate with their lenders regarding a restructuringshould not be considered part of this indebtedness and these commitments. During the fourth quarter of 2002, PG&E NEG and certain subsidiaries have agreed to sell or have sold certain assets, have abandoned other assets, and have significantly reduced energy trading operations. As a result of these actions, PG&E NEG has incurred pre-tax charges to earnings of approximately $3.9 billion in 2002. PG&E NEG and its subsidiaries are continuing their efforts to abandon, sell, or transfer additional assets in an ongoing effort to raise cash and reduce debt, whether through negotiation with lenders or otherwise. As a result, PG&E NEG expects to incur additional substantial charges to earnings in 2003 as it restructures its operations. In addition, if a restructuring agreement is not reached and if the lenders exercise their default remedies or if the financial commitments are not restructured, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced into a proceeding under the U.S. Bankruptcy Code. PG&E Corporation does not expect that the liquidity constraints at PG&E NEG and its subsidiaries will affect the financial condition of PG&E Corporation or the Utility.report.The consolidated financial statements of PG&E Corporation incorporated in this report reflect the accounts of PG&E Corporation, the Utility, PG&E NEG, and other wholly owned and controlled subsidiaries. The separate consolidated financial statements of the Utility reflect the accounts of the Utility and its wholly owned and controlled subsidiaries. As ofAt December 31, 2002, PG&E Corporation had approximately $34 billion in assets. Of this amount, Pacific Gas and Electric Company had $25 billion in assets. PG&E Corporation generated approximately $12 billion in operating revenues for 2002. Of this amount, the Utility generated $11 billion in operating revenues for 2002. As of December 31, 2002,2003, PG&E Corporation and its subsidiaries and affiliates (excluding NEGT) had 21,814approximately 20,600 employees, (including 19,575including approximately 20,300 employees of the Utility).Utility. Of the Utility'sUtility’s employees, approximately 13,00013,500 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 International Union of Security Officers/SEIU, Local24/ 24/7,, or IUSO.SEIU. The ESC and IBEW collective bargaining agreements with IBEW and ESC remain in effect until the earlier ofexpire on December 31, 2003 or the date on which a new2007. The SEIU collective bargaining agreement is completed, and the agreement with the IUSO expires on February 28, 2003. 2008.currentlywill pay all allowed creditor claims in full (except for the claims of holders of certain pollution control-related bond obligations that will be reinstated) from the proceeds of a public offering of long-term debt, cash on hand, and draws on revolving credit facilities. At December 31, 2003, allowed claims in the Utility’s Chapter 11 proceeding amounted to approximately $12.3 billion.negotiationsthe U.S. District Court for renewalthe Northern District of California, or the District Court. On January 5, 2004, the bankruptcy court denied a request to stay the implementation of the collective bargaining agreements with IBEW and ESC and is beginning negotiations with IUSO.Proposed PlansPlan of Reorganization until the appeals are resolved. The District Court will set a schedule for briefing and argument of the Utilityappeals at a later date. No additional parties may request rehearings or make appeals of the CPUC’s approval of the Settlement Agreement or the bankruptcy court’s confirmation order.The Utility willImplementation of the Plan of Reorganization is subject to various conditions, including the consummation of the public offering of long-term debt, the receipt of investment grade credit ratings and final CPUC approval of the Settlement Agreement. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not emerge from bankruptcy untilsubject to any pending appeal or further right of appeal, or approval on behalf of the CPUC that, although subject to a planpending appeal or further right of reorganizationappeal, has been confirmedagreed by the Bankruptcy Court and the confirmed plan has been implemented. A plan sets forth the means for satisfying both claims against and equity interests in a debtor. The Utility and PG&E Corporation submitted a proposed planto constitute final approval. Thus, the terms of reorganization, described below asthe Plan of Reorganization permit the Utility Plan.and PG&E Corporation to cause the Plan of Reorganization to become effective (and permit the Utility to issue the long term debt) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. Until certain conditions or events regarding the effectiveness of the Plan of Reorganization discussed above are resolved further, PG&E Corporation and the Utility cannot conclude that the applicable accounting probability standard needed to record the regulatory assets contemplated by the Settlement Agreement has been met. PG&E Corporation and the Utility believe that the Utility and the long-term debt to be issued will receive investment grade credit ratings. The CPUC submitted a competing proposed planUtility has targeted April 2004 to complete the sale of reorganization. During the summerlong-term debt, which the Utility expects to be the last condition of 2002, holdersthe Plan of claims against,Reorganization to be satisfied. The Plan of Reorganization provides that the effective date will occur 11 business days after all the conditions have been satisfied or, with respect to all conditions except those relating to investment grade credit ratings, waived by PG&E Corporation and equity intereststhe Utility. There can be no assurance that the Settlement Agreement will not be overturned on rehearing or appeal or that the Plan of Reorganization will become effective.Utility were requested to vote whether to accept or reject the competing plans. On September 9, 2002, an independent voting agent announced that nineMD&A and in Note 2 of the ten voting classes underNotes to the Consolidated Financial Statements in the Annual Report.Refinancing Supported by a Dedicated Rate Component Plan approved the Utility Plan. The CPUC's plan was approved by one of the eight voting classes under the CPUC's plan. In August 2002, 10 days after the voting period ended, the CPUC and the Official Committee of Unsecured Creditors, or OCC, announced that the OCC had joined the CPUCagreed to support a modified alternative plan of reorganization. On August 30, 2002, the CPUC and the OCC jointly submitted an amended plan of reorganization to the Bankruptcy Court (the CPUC/OCC Plan). The Bankruptcy Court began confirmation hearings in November 2002 to determine whether to confirm the Utility Plan, the CPUC/OCC Plan, or neither plan. The Bankruptcy Court currently has scheduled trial dates through March 2003. The Utility Plan. The Utility Plan proposes to restructure the Utility's current businesses andseek to refinance the restructured businesses so that all allowed creditor claims would be paid in full with interest. The Utility Plan is designed to align the businesses under the regulators that best match the business functions. Assets used in the retail distribution business would remain under the retail regulator, the CPUC, and assets used in the wholesale electric generation and transmission, and interstate natural gas transportation, would be placed under wholesale2regulators, the FERC and the Nuclear Regulatory Commission, or NRC. After this alignment, the retail-focused, state-regulated business would be a natural gas and electricity distribution company, the Reorganized Utility, representing approximately 70%remaining unamortized pre-tax balance of the book value$2.21 billion after-tax regulatory asset and related federal, state and franchise taxes, up to a total of the Utility's assets. The Utility would retain four small generating facilities. The wholesale businesses, electric transmission, interstate gas transmission, and generation, would be federally regulated$3.0 billion, as to price, terms, and conditions of service. In contemplation of the Utility Plan becoming effective, the Utility has created three new limited liability companies, the LLCs, which currently are owned by the Utility's wholly owned subsidiary, Newco Energy Corporation, or Newco. On the effective date of the Utility Plan, the Utility would transfer•substantially all the assets and liabilities primarily related to the Utility's electricity generation business to Electric Generation LLC, or Gen;•the assets and liabilities primarily related to the Utility's electricity transmission business to ETrans LLC, or ETrans; and•the assets and liabilities primarily related to the Utility's natural gas transportation and storage business to GTrans LLC, or GTrans. The Utility also would enter into agreements under which the Utility, Gen, ETrans and GTrans would allocate responsibility and indemnification for liabilities that survive the bankruptcy. Although the Utility would be legally separated from the LLCs, the Utility's operations would remain connected to the operations of the LLCsexpeditiously as practicable after the effective date of the Utility Plan. For example•Utility would rely on Gen for a significant portion of the electricity the Utility needed to meet its electricity distribution customers' demand during the 12-year term of a power purchase and sale agreement between the Utility and Gen, or the Gen power purchase and sale agreement.•• Authorizing California legislation satisfactory to the CPUC, The Utility Reform Network, or TURN, and the Utility is passed and signed into law allowing securitization of the regulatory asset and associated federal and state income and franchise taxes and providing for the collection in the Utility’s rates of any portion of the associated tax amounts not securitized; • The CPUC determines that, on a net present value basis, the refinancing would save customers money over the term of the securitized debt compared to the regulatory asset; • The refinancing will not adversely affect the Utility’s issuer or debt credit ratings; and • The Utility obtains, or decides it does not need, a private letter ruling from the Internal Revenue Service, or IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event. rely on ETrans forbe permitted to complete the Utility's electricity transmission needs because the transmission lines proposedrefinancing in up to be transferredtwo tranches up to ETrans are currently the only transmission lines directly connected to the Utility's electricity distribution system.•The Utilityone year apart, and would rely on GTrans for the Utility's natural gas transportation needs because the facilities proposed to be transferred to GTrans are currently the only transportation facilities directly connected to the Utility's natural gas distribution system. In addition, the Utility would rely on GTrans for a substantial portionissue sufficient callable debt or debt with earlier maturities as part of the Utility's natural gas storage requirements for at least 10 years underPlan of Reorganization to accommodate the refinancing supported by a transportationdedicated rate component. Upon refinancing with securitization, the equity and storage services agreement between the Utility and GTrans, though the Utility does have storage options with third party providers to meet a portion of their requirements.•The Utility also would have significant operating relationships with the LLCs covering a range of functions and services.•Finally, the Utility would continue to rely on its natural gas transportation agreement with PG&E Gas Transmission Northwest Corporation, or PG&E GTN, for the transportation of western Canadian natural gas. The Utility Plan also proposes that on the effective datedebt components of the Utility Plan the Utility would distribute to PG&E Corporation all of the outstanding common stock of Newco. Each of ETrans, GTrans, and Gen would continue to be an indirect wholly owned subsidiary of PG&E Corporation. Finally, on the effective date of the Utility Plan or as promptly thereafter as practicable, PG&E Corporation would distribute all the shares of the Utility's common stock that it then holds to its existing shareholders in a spin-off transaction. After the spin off, the Utility would be an independent publicly held company. The Utility would retain the name "Pacific Gas and Electric Company." Allowed claims would be satisfied by cash, long-term notes issued by the LLCs or a combination of cash and such notes. Each of ETrans, GTrans, and Gen would issue long-term notes to the reorganized Utility and the Utility will then transfer the notes to certain holders of allowed claims. In addition, each of the reorganized Utility, ETrans, GTrans, and Gen would issue "new money" notes in registered public offerings. The LLCs would transfer the proceeds of the sale of the new money notes, less working capital reserves, to the Utility for payment of allowed claims. The Utility Plan currently also would reinstate nearly $1.59 billion of preferred stock and pollution control loan agreements. On February 19, 2003, Standard & Poor's (S&P), a major credit rating agency, announced that it had re-affirmed its preliminary rating evaluation, originally issued in January 2002, of the corporate credit ratings of, and the securities proposed to be issued by, the reorganized Utility and the LLCs in connection with the3implementation of the Utility Plan. Subject to the satisfaction of various conditions, S&P stated that the approximately $8.5 billion of securities proposed to be issued by the reorganized Utility and the LLCs, as well as their corporate credit ratings, would be capable of achieving investment grade ratings of at least BBB-. In order to satisfy some of the conditions specified by S&P, on February 24, 2003, the Utility filed amendments to the Utility Plan with the Bankruptcy Court that, among other modifications:•permit the reorganized Utility and the LLCs to issue secured debt instead of unsecured debt,•permit adjustments in the amount of debt the reorganized Utility and the LLCs would issue so that additional new money notes could be issued if additional cash is required to satisfy allowed claims or to deposit in escrow for disputed claims and such debt can be issued while maintaining investment grade ratings, or so that less debt could be issued in order to obtain investment grade ratings or if less cash is required to satisfy allowed claims and be deposited into escrow for disputed claims,•require Gen to establish a debt service reserve account and an operating reserve account,•under certain circumstances, permit an increase in the amount of cash creditors receiving cash and notes will receive,•permit the Utility's mortgage-backed pollution control bonds to be redeemed if the reorganized Utility issues secured new money notes, and•commit PG&E Corporation to contribute up to $700 million in cash to the Utility's capital from the issuance of equity or from other available sources, to the extent necessary to satisfy the cash obligations of the Utility in respect of allowed claims and required deposits into escrow for disputed claims, or to obtain investment grade ratings for the debt to be issued by the reorganized Utility and the LLCs. In addition to the amendments to the Plan, amendments to various filings at the FERC, and possibly other regulatory agencies, will be required in order to implement the changes to the Plan. The CPUC/OCC Plan. The CPUC/OCC Plan does not call for realignment of the Utility's businesses, but instead provides for the continued regulation of all of the Utility's current operations by the CPUC. The CPUC/OCC Plan proposes to reinstate nearly $1 billion of preferred stock and pollution control bonds and satisfy remaining creditor claims in full in cash, using a combination of cash on hand and the proceeds of the issuance of $7.3 billion of new senior secured debt, $1.5 billion of unsecured notes and preferred securities. The CPUC/OCC Plan proposes to establish a $1.75 billion regulatory asset that would be amortized over 10 years and would earn the fullUtility’s rate of return on rate base.the regulatory asset would be eliminated. Instead the utility would collect from customers amounts sufficient to service the securitized debt. The Utility would use the securitization proceeds to rebalance its capital structure in order to maintain the capital structure provided for under the Settlement Agreement.The CPUC/OCC Plan also provides that it would not become effective untilThis combined Annual Report on Form 10-K, including the Utility and the CPUC enter into a "reorganization agreement" under which the CPUC promises it would establish retail electric rates on an ongoing basis sufficient for the Utility to achieve and maintain investment grade credit ratings and to recover in rates (1) the interest and dividends payable on, and the amortization and redemptionportions of the securities to be issued under the CPUC/OCC Plan, and (2) certain recoverable costs (defined as the amounts that the Utility is authorizedAnnual Report incorporated by the CPUC to recover in retail electric rates in accordance with historic practice for all of its prudently incurred costs, including capital investment in property, plant and equipment, a return of capital and a return on capital and equity to be determined by the CPUC from time to time in accordance with its past practices). PG&E Corporation and the Utility believe the CPUC/OCC Plan is not credible or confirmable. PG&E Corporation and the Utility do not believe the CPUC/OCC Plan would restore the Utility to investment grade status if it were to become effective. Additionally, PG&E Corporation and the Utility believe the CPUC/OCC Plan would violate applicable federal and state law.Risk Factors This report includesreference, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on the information currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes," "could," "should," "would," "may,"“estimates,” “expects,” “anticipates,” “plans,” “believes,” “could,” “should,” “would,” “may” and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements.4 RecoveryWhether and on What Terms the Plan of Undercollected Power Procurement and Transition Costs Previously Written Off.Reorganization is Implemented• The timing and resolution of the pending applications for rehearing of the CPUC’s approval of the Settlement Agreement and any appeals that may be filed with respect to the disposition of the rehearing applications; • The timing and resolution of the pending appeals of the bankruptcy court’s confirmation of the Plan of Reorganization; • Whether the investment grade credit ratings and other conditions required to implement the Plan of Reorganization are obtained or satisfied; and • Future equity and debt market conditions, future interest rates, and other factors that may affect the Utility’s ability to implement the Plan of Reorganization or affect the amounts and terms of the debt proposed to be issued under the Plan of Reorganization. • Unanticipated changes in operating expenses or capital expenditures; • The level and volatility of wholesale electricity and natural gas prices and supplies and the Utility’s ability to manage and respond to the levels and volatility successfully; • Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns and other events or hazards that affect demand, result in power outages, reduce generating output, or cause damage to the Utility’s assets or operations or those of third parties on which the Utility relies; • Unanticipated population growth or decline, changes in market demand and demographic patterns, and general economic and financial market conditions, including unanticipated changes in interest or inflation rates; • The extent to which the Utility’s residual net open position (i.e., the amount of electricity the Utility needs to meet its customers’ electricity demands that is not provided by Utility-owned generation, Utility power purchase contracts, or the electricity provided by the California Department of Water Resources, or DWR, and allocated to the Utility) increases or decreases due to changes in customer and economic growth rates, the periodic expiration or termination of Utility or DWR power purchase contracts, the reallocation of the DWR power purchase contracts, whether various counterparties are able to meet their obligations under their power sale agreements with the Utility or with the DWR; the retirement or other closure of the Utility’s electricity generation facilities, the performance of the Utility’s electricity generation facilities, and other factors; • The operation of the Utility’s Diablo Canyon nuclear power plant, which exposes the Utility to potentially significant environmental and capital expenditure outlays, and, to the extent the Utility is unable to increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close its Diablo Canyon power plant and purchase electricity from more expensive sources; • Actions of credit rating agencies; • Significant changes in the Utility’s relationship with its employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur; and • Acts of terrorism. • The impact of current and future ratemaking actions of the CPUC, including the outcome of the Utility’s 2003 General Rate Case, or the GRC; • Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, U.S. Congress, the CPUC, the FERC and the Nuclear Regulatory Commission, or the NRC, with regard to allowed rates of return, industry and rate structure, recovery of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities; • The extent to which the CPUC or the FERC delays or denies recovery of the Utility’s costs, including electricity purchase costs from customers due to a regulatory determination that such costs were not reasonable or prudent or for other reasons; • How the CPUC administers the capital structure, stand-alone dividend and first priority conditions of the CPUC’s decisions permitting the establishment of holding companies for California investor-owned electric utilities; • Whether the Utility is in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses; • Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws, regulations, and policies; and • The outcome of pending litigation. • Increased competition as a result of the takeover by condemnation of the Utility’s distribution assets, duplication of the Utility’s distribution assets or services by local public utility districts, self-generation by its customers and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and • The extent to which the Utility’s distribution customers switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers and the extent to which cities, counties and others in the Utility’s service territory begin directly serving the Utility’s customers with their own facilities or combine to form community choice aggregators. Electricity Distribution Operations Utility is ableelectricity transmission system transmits electricity, ranging from 500 kV to recover its undercollected power procurement and transition costs previously written off depends on many factors, including:•what costs the CPUC determines are eligible60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for recovery as transition costs;•when the Utility's rate freeze ended, as determined by the CPUC;•sales volatility and the level of direct access customers (i.e., those customers who choose an alternative energy provider);•changes in the California Department of Water Resources' (DWR) revenue requirements required to be remitteddistribution to the DWRUtility’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 existing retail rates;•changes in the Utility's authorized revenue requirements;•future regulatory or judicial decisionseach substation are primary and secondary distribution lines connected to local transformers and switching equipment that determine whetherlink distribution lines and provide delivery to end-users. In some cases, the Utility is allowed under state law to recover undercollected power procurement and transition costssells electricity from its customers afterdistribution lines or facilities to entities, such as municipal and other utilities, that then resell the endelectricity.rate freeze; and•the outcomeUtility’s total 2003 electricity deliveries represented by each of its major customer classes:Agricultural and Other Customers 6 % Industrial Customers 18 % Residential Customers 36 % Commercial Customers 40 % Utility's claims againstUtility’s operating statistics from 1999 to 2003 for electricity sold or delivered, including the CPUC Commissionersclassification of sales and revenues by type of service. 2003 2002 2001 2000 1999 Customers (average for the year): Residential 4,286,085 4,171,365 4,165,073 4,071,794 4,017,428 Commercial 493,638 483,946 484,430 471,080 474,710 Industrial 1,372 1,249 1,368 1,300 1,151 Agricultural 81,378 78,738 81,375 78,439 85,131 Public street and highway lighting 26,650 24,119 23,913 23,339 20,806 Other electric utilities 4 5 5 8 12 Total 4,889,127 4,759,422 4,756,164 4,645,960 4,599,238 Deliveries (in GWh):(1) Residential 29,024 27,435 26,840 28,753 27,739 Commercial 31,889 31,328 30,780 31,761 30,426 Industrial 14,653 14,729 16,001 16,899 16,722 Agricultural 3,909 4,000 4,093 �� 3,818 3,739 Public street and highway lighting 605 674 418 426 437 Other electric utilities 76 64 241 266 167 Subtotal 80,156 78,230 78,373 81,923 79,230 DWR (23,342 ) (21,031 ) (28,640 ) — — Total non-DWR electricity 56,814 57,199 49,733 81,923 79,230 Revenues (in millions): Residential $ 3,671 $ 3,646 $ 3,396 $ 3,062 $ 2,975 Commercial 4,440 4,588 4,105 3,110 2,980 Industrial 1,410 1,449 1,554 1,053 1,044 Agricultural 522 520 525 420 404 Public street and highway lighting 69 73 60 43 49 Other electric utilities 24 10 39 26 17 Subtotal 10,136 10,286 9,679 7,714 7,469 DWR (2,243 ) (2,056 ) (2,173 ) — — Direct access credits (277 ) (285 ) (461 ) (1,055 ) (348 ) Miscellaneous(2) (52 ) 193 244 202 162 Regulatory balancing accounts 18 40 37 (7 ) (51 ) Total electricity operating revenues $ 7,582 $ 8,178 $ 7,326 $ 6,854 $ 7,232 Other Data: Average annual residential usage (kWh) 6,772 6,577 6,444 7,062 6,905 Average billed revenues (cents per KWh): Residential 12.65 13.29 12.65 10.65 10.72 Commercial 13.92 14.65 13.34 9.79 9.79 Industrial 9.62 9.84 9.71 6.23 6.24 Agricultural 13.35 13.00 12.83 11.00 10.81 Net plant investment per customer $ 2,689 $ 2,105 $ 2,018 $ 1,969 $ 2,388 (1) These amounts include electricity provided to direct access customers who procure their own supplies of electricity. (2) Miscellaneous revenues in 2003 include a $125 million reduction due to refunds to electricity customers from generation-related revenues in excess of generation-related costs. recovery of undercollected power procurement and transition costs based on the federal filed rate doctrine;
2003 represented by each major electricity resource:Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities) 36 % DWR 29 % Qualifying Facilities/ Renewables 23 % Irrigation Districts 5 % Other Power Purchases 7 % Refundability of Amounts Previously Collected. Whether the The Utility is required to refunddispatch all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. To the extent the Utility’s electricity resources are not sufficient to ratepayersmeet the demand of the Utility’s customers, the Utility purchases the electricity from the wholesale electricity market. At other times, least-cost dispatch requires the Utility to schedule more electricity than is necessary to meet its retail load and to sell this additional electricity on the wholesale electricity market. The Utility typically schedules excess electricity when the expected electricity sales proceeds exceed the variable costs to operate a generation facility or buy electricity on an optional contract. Number of Net Operating Generation Type County Location Units Capacity (MW) Nuclear:
Diablo Canyon San Luis Obispo 2 2,174 Hydroelectric:
Conventional 16 counties in northern and central California 107 2,684 Helms pumped storage Fresno 3 1,212 Hydro electric subtotal 110 3,896 Fossil fuel: Humboldt Bay(1) Humboldt 2 105 Hunters Point(2) San Francisco 2 215 Mobile turbines Humboldt 2 30 Fossil fuel subtotal 6 350 Total 118 6,420 (1) The Humboldt Bay facilities consist of a retired nuclear generation unit, or Humboldt Bay Unit 3, and two operating fossil fuel-fired plants. (2) In July 1998, the Utility reached an agreement with the City and County of San Francisco regarding the Utility’s Hunters Point fossil fuel-fired plant, which has been designated as a “must run” facility by the California Independent System Operator, or ISO, to support system reliability. The agreement expresses the Utility’s intention to retire the plant when it is no longer needed. 2004 2005 2006 2007 2008 Refueling March October — April — Duration (days) 48 45 — 35 — Startup May November June Refueling October April February Duration (days) 42 — 42 — 80 Startup December — May — April previously collected dependsrecovered by NEIL for these losses from reinsurance. Under the Terrorism Risk Insurance Act of 2002, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign terrorism. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.DWR Power Purchases factors, including:•CPUC determineselectricity is needed. A total average capacity for 2004 of approximately 1,200 MW of the electricity under DWR allocated contracts is subject to provisions that certain transition or procurement costs recovered in revenues collected byrequire the DWR to pay a capacity charge, but do not require the purchase of electricity unless that electricity is dispatched and delivered.werewithout the consent of the CPUC. The Settlement Agreement provides that the CPUC will not eligible transition costsrequire the Utility to accept an assignment of, or otherwise reducesto assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:• After assumption, the Utility’s issuer rating by Moody’s will be no less than A2 and the Utility’s long-term issuer credit rating by Standard & Poor’s will be no less than A; • The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and • 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. Third Party Agreements Qualifying Facility Agreements revenues authorizedany qualifying facilities refunds, which the Utility actually realizes in cash, claim offsets or other credits, would reduce the $2.21 billion after-tax regulatory asset. PG&E Corporation and the Utility are unable to recover such transition or procurement costs dueestimate the outcome of this proceeding.Irrigation Districts and Water Agencies an overcollection of such costs;•whetherpurchase hydroelectric power. Under these contracts, the CPUC ultimately determines that certain pastUtility must make specified semi-annual minimum payments based on the irrigation districts’ and water agencies’ debt service requirements, regardless if any hydroelectric power procurementis supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. The Utility’s irrigation district and water agency contracts accounted for approximately 5% of 2003 electricity sources, approximately 4% of 2002 electricity sources and approximately 3% of 2001 electricity sources.Other Third Party Power Agreements Electricity Purchases to Satisfy the Residual Net Open Position Renewable Energy Contracts Western Area Power Administration Electricity Transmission Path 15 — WAPA and an independent transmission company, Trans-Elect NTD, Inc., are constructing a new 500 kV line to expand one segment of the transmission system, known as Path 15, which is located in the southern portion of the Utility’s service area, and serves as part of the primary transmission path between northern California and southern California. The improvements are intended to mitigate transmission constraints in this area. The Utility will interconnect the new 500 kV line at its existing substations at the line terminals and reconfigure its 230 kV and 115 kV facilities in the area to support a higher transfer capability through this section of the grid. This new 500 kV line is expected to be operational in October 2004. Jefferson-Martin — This project entails laying 28 miles of 230 kV underground transmission facilities from Redwood City to Daly City that will provide additional transmission system reliability in San Francisco and northern San Mateo County. This project is expected to be completed in December 2005. reasonably incurredaffected by their consumption levels. The Utility’s results of operations can, however, be affected by noncore consumption levels because there are no similar regulatory balancing accounts related to noncore customers. Approximately 96% of the Utility’s natural gas distribution base revenues are recovered from core customers and should4% are recovered from noncore customers.�� Residential Customers 25% Transport only Customers (noncore) 65% Commercial Customers 10% Natural Gas Operating Statistics 2003 2002 2001 2000 1999 Customers (average for the year): Residential 3,744,011 3,738,524 3,705,141 3,642,266 3,593,355 Commercial 208,857 206,953 205,681 203,355 203,342 Industrial 1,988 1,819 1,764 1,719 1,625 Other gas utilities 6 5 6 6 4 Total 3,954,862 3,947,301 3,912,592 3,847,346 3,798,326 2003 2002 2001 2000 1999 Gas supply (MMcf): Purchased from suppliers in: Canada 196,278 210,716 209,630 216,684 230,808 California (7,421 ) 19,533 20,352 32,167 18,956 Other states 102,941 67,878 76,589 75,834 107,226 Total purchased 291,798 298,127 306,571 324,685 356,990 Net (to storage) from storage 1,359 (218 ) (27,027 ) 19,420 (980 ) Total 293,157 297,909 279,544 344,105 356,010 Utility use, losses, etc.(1) (14,307 ) (16,393 ) (8,988 ) (62,960 ) (47,152 ) Net gas for sales 278,850 281,516 270,556 281,145 308,858 Bundled gas sales (MMcf): Residential 198,580 202,141 197,184 210,515 233,482 Commercial 79,891 78,812 72,528 66,443 70,093 Industrial 379 563 831 4,146 5,255 Other gas utilities — — 13 41 28 Total 278,850 281,516 270,556 281,145 308,858 Transportation only (MMcf): 525,353 508,090 646,079 606,152 484,218 Revenues (in millions): Bundled gas sales: Residential $ 1,836 $ 1,379 $ 2,308 $ 1,681 $ 1,543 Commercial 697 499 783 513 449 Industrial 1 3 16 35 24 Other gas utilities 1 1 — — — Miscellaneous (31 ) 127 (93 ) 84 (47 ) Regulatory balancing accounts 68 11 (253 ) 132 (260 ) Bundled gas revenues 2,572 2,020 2,761 2,445 1,709 Transportation service only revenue 284 316 375 338 287 Operating revenues $ 2,856 $ 2,336 $ 3,136 $ 2,783 $ 1,996 Selected Statistics: Average annual residential usage (Mcf) 53 54 53 59 65 Average billed bundled gas sales revenues
per Mcf: Residential $ 9.25 $ 6.82 $ 11.70 $ 7.98 $ 6.61 Commercial 8.73 6.33 10.80 7.72 6.40 Industrial 2.48 4.35 19.15 8.53 4.69 Average billed transportation only revenue
per Mcf 0.54 0.62 0.58 0.56 0.59 Net plant investment per customer $ 1,261 $ 1,006 $ 970 $ 1,003 $ 1,011 (1) Includes fuel for the Utility’s fossil fuel-fired generation plants. Natural Gas Supplies 2003 2002 2001 2000 1999 Avg. Avg. Avg. Avg. Avg. MMcf Price MMcf Price MMcf Price MMcf Price MMcf Price Canada 196,278 $ 4.73 210,716 $ 2.42 209,630 $ 4.43 216,684 $ 4.05 230,808 $ 2.50 California(1) (7,421 ) $ 3.39 19,533 $ 2.88 20,352 $ 11.55 32,167 $ 8.20 18,956 $ 2.45 Other states (substantially all U.S southwest) 102,941 $ 4.63 67,878 $ 3.04 76,589 $ 10.41 75,834 $ 5.99 107,226 $ 2.42 Total/weighted average 291,798 $ 4.73 298,127 $ 2.59 306,571 $ 6.40 324,685 $ 4.92 356,990 $ 2.47 (1) California purchases include supplies from various California producers and supplies transported into California by others. Gas Gathering Facilities disallowed;detected in the event of a leak. The facilities include 475 miles of gas gathering pipelines, as well as dehydration, separation, regulation, odorization and•purposesUtility’s gas gathering system.Interstate and Canadian Natural Gas Transportation Services Agreements Demand Charges Expiration Quantity for the Year Ended Pipeline Date MDth per day December 31, 2003 (In millions) El Paso Natural Gas Company 10/31/2003 100 $ 9.5 El Paso Natural Gas Company 12/31/2004 64 4.5 TransCanada NOVA Gas Transmission, Ltd. 12/31/2005 593 23.6 TransCanada PipeLines Ltd., B.C. System 10/31/2005 584 10.6 Gas Transmission Northwest Corporation 10/31/2005 610 55.0 Transwestern Pipeline Co. 03/31/2007 150 15.8 El Paso Natural Gas Company 03/31/2007 40 3.8 El Paso Natural Gas Company 04/30/2005 100 1.1 CPUC ultimately determinesutilities 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 surcharges approvedthese services were provided at fair prices. In recent years, energy utilities have faced intensifying pressures to unbundle, or price separately, those services that are no longer considered natural monopolies. The most significant of these services are the commodity components — the supply of electricity and natural gas.CPUCenergy industry. Regulators and legislators, to varying degrees, have required utilities to unbundle rates in January, March, and May 2001 may be used. Outcomeorder to allow customers to compare unit prices of the Utility's Bankruptcy Case.utilities and other providers when selecting their energy service provider.The Electricity Industry pace and outcome ofFERC’s policies have supported the Utility's bankruptcy case will be affected by:•whether the Bankruptcy Court confirms the Utility Plan, the CPUC/OCC Plan, or some other plan of reorganization;•whether regulatory and governmental approvals required to implement a confirmed plan are obtained and the timing of such approvals;•whether there are any delays in implementationdevelopment of a plan due to litigation related to regulatory, governmental, or Bankruptcy Court orders; and•future equity or debt market conditions, future interest rates, future credit ratings, and other factors that may affect the ability to implement either plan or affect the amount and value of the securities proposed to becompetitive electricity generation industry. FERC Order 888, issued under either plan. Utility's Operating Environment. The amount of operating income and cash flows that the Utility may record may be influenced by the following:•future regulatory actions regarding the Utility's procurement of power for its retail customers;•thein 1996, established standard terms and conditions for parties seeking access to regulated utilities’ transmission grids. The FERC’s subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations and advanced the view that a regulated, unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. The FERC’s standard market design proposal issued in July 2002 encourages unbundled transmission. The ISO also issued its own comprehensive market design proposal to effect changes to the structure and operation of the Utility's long-term generation procurement plan asCalifornia electricity market, subject to the FERC’s approval. The FERC has approved by the CPUC;•the abilityfirst phase of the UtilityISO’s new rules and implementation of the first phase is expected to timely recoverbe completed in full its costs including its procurement costs;•sales levels, which can be affected by general economicassuming FERC approval. The ISO is expected to file proposed tariff language with the FERC later in 2004 to address these issues. Both the timing and financial market conditions, changes in interest rates, weather, conservation efforts, outages,substance of the FERC’s regional transmission organization policy and the level of direct access customers (i.e., those customers who choose an alternative energy provider);5•demand for and pricing of transportation and storage services whichISO’s market design processes may be affected by weather, overall gas-firedany energy legislation Congress may pass.price spreads between various natural gas delivery points;•changesstandardizing interconnection procedures, and encourage needed investment in generator and transmission infrastructure, the Utility's authorized revenue requirements;FERC issued final rules on the interconnection of generators larger than 20 MW with a transmission system. The rules will require regulated transmission providers, such as the Utility or the ISO, generally to use standard interconnection procedures and•acts of terrorism, storms, earthquakes, accidents, mechanical breakdowns, or other events or perils that result in power outages or damage to a standard agreement for generator interconnections. These rules would require the Utility's assets or operations, to the extent not covered by insurance. Legislative and Regulatory Environment. PG&E Corporation's, the Utility's, and PG&E NEG's businesses may be impacted by legislative or regulatory changes affecting the electric and natural gas industries in the United States. Regulatory Proceedings and Investigations. PG&E Corporation'sUtility and the Utility's business may be affected by:•outcomeexisting agreements and procedures used when constructing facilities to interconnect new generators. Numerous parties have requested rehearing and a stay of the Utility's various regulatory proceedings pending at the CPUC and atgenerator interconnection rules. Although the FERC and•outcomerequests for rehearing, the FERC has ordered that the rules will not become effective until after the FERC accepts new tariff changes to implement the rules. The Utility, along with other transmission owners, filed proposed tariffs changes on January 20, 2004. It is uncertain when the FERC will act on the rehearing requests or the proposed tariff changes. Further, portions of the CPUC's pending investigation into whether the California investor-owned utilities, or IOUs, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. Pending Legal Proceedings. PG&E Corporation's and the Utility's future results of operations and financial conditionFERC’s rulemaking may be affected by any energy legislation Congress may pass.outcomes of:•the lawsuits filed by the California Attorney General and the City and County of San Francisco against PG&E Corporation alleging unfair or fraudulent business acts or practices based on alleged violations of conditions established in the CPUC's holding company decisions;•the outcomerestructuring of the California Attorney General's petition requesting revocationelectricity industry and established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity. AB 1890 also gave customers the choice of PG&E Corporation's exemptioncontinuing to buy electricity from the PublicCalifornia investor-owned electric utilities or, beginning in April 1998, entering into contracts to purchase electricity from alternate energy service providers(i.e., becoming direct access customers). The CPUC suspended the right of retail end-user customers to become direct access customers on September 20, 2001. The CPUC has assessed an additional charge on certain direct access customers to avoid a shift of costs from direct access customers to customers who receive bundled service.Holding Company Actwould continue to provide distribution, metering and billing services to the community choice aggregators’ customers and be those customers’ provider of 1935; and•other pending litigation. Competition. PG&E Corporation'selectricity of last resort. However, once registration has occurred, each community choice aggregator would procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. To prevent a shifting of costs to customers of a utility who receive bundled services, AB 117 requires the CPUC to determine a cost-recovery mechanism so that retail end-users of the community choice aggregator will pay an appropriate share of the DWR’s and the Utility's future resultsUtility’s costs. AB 117 also authorized the Utility to recover from each community choice aggregator any costs of operationsimplementing the program that are reasonably attributable to the community choice aggregator, and financial condition may be affected by:•threatprogram not reasonably attributable to a community choice aggregator.municipalization whichthe construction of duplicate distribution facilities to serve specific existing or new customers, condemnation of the Utility’s distribution facilities by local governments or districts, self-generation by the Utility’s customers and technological developments. These and other forms of competition may result in stranded Utility investment capital, loss of customer growth and additional barriers to cost recovery;•changesrecovery. As customers and local public officials explore their energy options in light of the level of direct access customer cost responsibilityrecent California energy crisis, these bypass risks are increasing and other surcharges related to direct access, and competition from other service providers tomay increase further if the extent restrictions on direct access are removed;•the development of alternative energy technologies;•the ability to compete for gas transmission services into Southern California and with alternative storage providers throughout California; and•the growth of distributed generation or self-generation. Environmental and Nuclear Matters. PG&E Corporation's and the Utility's future results of operations and financial condition may be affected by:•the effect of compliance with existing and future environmental laws, regulations, and policies,Utility’s rates exceed the cost of other available alternatives.could be significant;•outcomeUtility’s revenues.The Natural Gas Industry pending environmental matters or proceedings;•ablethe total delivered cost of western Canadian natural gas relative to fully recoverthe total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in ratesaddition to the commodity cost, transportation costs of complying with existing and future environmental laws, regulations, and policies,on all pipelines that are used to deliver the natural gas, which, in the Utility’s case, includes the cost of which could be significant;transportation of the natural gas from Canada to the California border and•whether the amount that the Utility incurs costs in connection with its nuclear facilities that exceedcharges for transportation from the Utility's insurance coverage andborder to southern California. In general, when the total cost of western Canadian natural gas increases relative to other amounts set aside for decommissioning and other potential liabilities.6 Accounting and Risk Management. PG&E Corporation's andcompeting natural gas sources, the Utility's future resultsUtility’s market share of operations and financial condition may be affected by:•the effect of new accounting pronouncements;•changes in critical accounting estimates;•volatility in income resulting from mark-to-market accounting and changes in mark-to-market methodologies;•the extent to which the assumptions underlying critical accounting estimates, mark-to-market accounting, and risk management programs are not realized;•the volatility of commodity fuel and electricity prices, and the effectiveness of risk management policies and procedures designed to address volatility; and•the ability of counterparties to satisfy their financial commitments and the impact of counterparties' nonperformance on PG&E NEG's liquidity. Efforts to Restructure PG&E NEG's Indebtedness. Whether PG&E NEG and certaintransportation services into southern California decreases. In addition, Kern River Pipeline Company completed a major expansion of its subsidiaries seek protection under or be forcedpipeline system in May 2003 that increased its capacity toproceeding underresult this expansion, the U.S. Bankruptcy Code will be affected by
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.•outcome of PG&E NEG's negotiations with lenders under various credit facilities as well as with representatives of the holders of PG&E NEG's Senior Notes to restructure PG&E NEG's and its subsidiaries' indebtedness and commitments;•the terms and conditions of any sale, transfer, or abandonment of certain of PG&E NEG's merchant assets, including its New England generating assets, that PG&E NEG may enter into; and•the terms and conditions under which certain generating projects will be transferredUtility delivers to the project lenders as required by recent restructuring agreements. PG&E NEG Operational Risks. PG&E Corporation's future results From time to time, existing pipeline companies propose to expand their pipeline systems for delivery of operationsnatural gas into northern and financial condition will be affected by:•the extent to which PG&E NEG incurs further charges to earnings ascentral California. As a result of the abandonment, sale or transfer of assets, or termination of contractual commitments, whether such transactions occur in connection with restructuring of PG&E NEG's indebtedness or otherwise;•any potential chargesCalifornia energy crisis, several new natural gas pipeline proposals were initiated to income that would result from the reductionserve proposed new generation facilities for northern and potential discontinuance of energy trading and marketing operations, including tolling transactions;•any potential charges to income that would result from the discontinuance or transfer of any of PG&E NEG's merchant generation assets;•the inability of PG&E NEG, its merchant asset and other subsidiaries, including USGen New England, Inc., to maintain sufficient liquidity necessary to meet their commodity and other obligations;•the extent to which PG&E NEG's current construction of generation, pipeline, and storage facilities is completed and the pace and cost of that completion, including the extent to which commercial operations of these construction projects are delayed or prevented because of financial or liquidity constraints, changes in the national energy markets and by the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others; or by various development and construction risks such as PG&E NEG's failure to obtain necessary permits or equipment, the failure of third-party contractors to perform their contractual obligations, or the failure of necessary equipment to perform as anticipated and the potential loss of permits or other rights in connection with PG&E NEG's decision to delay or defer construction;•the impact of layoffs and loss of personnel; and•future sales levels which can be affected by economic conditions, weather, conservation efforts, outages, and other factors. Current Conditions in the Energy Markets and the Economy. PG&E Corporation's future results of operations and financial condition will be affected by changes in the energy markets, changes in the general economy, wars,7embargoes, financial markets, interest rates, other industry participant failures, the markets' perception of energy merchants and other factors. Actions of PG&E NEG Counterparties. PG&E Corporation's future results of operations and financial condition may be affected by:•The extent to which counterparties demand additional collateral in connection with PG&E ET's trading and nontrading activities and the ability of PG&E NEG and its subsidiaries to meet the liquidity calls that may be made; and•The extent to which counterparties seek to terminate tolling agreements and the amount of any termination damages they may seek to recover from PG&E NEG as guarantor. As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from results or outcomes currently sought or expected. Various aspects of PG&E Corporation's and its subsidiaries' businesses, including the Utility, are subject to a complex set of energy, environmental, and other governmental laws and regulations at the federal, state and local levels. This section summarizes somecentral California. Many of the more significant laws and regulations affecting electricity generation projects have been cancelled or delayed, making it difficult for sponsors of the various gas pipeline projects to acquire enough firm capacity commitments to go forward with construction.Corporation's business at this time.Regulation of PG&E CorporationCorporation’s Regulatory EnvironmentFederal Energy Regulation the Holding Company Act. At present,PUHCA. Currently, PG&E Corporation has no expectation of becoming a registered holding company under the Holding Company Act. On July 7, 2001, thePUHCA. The California Attorney General or the AG,has filed a petition with the SEC requesting the SEC to review and revoke PG&E Corporation'sCorporation’s exemption from the Holding Company ActPUHCA and to begin fully regulating the activities of PG&E Corporation and its affiliates. The AG's petition requested the SEC to hold a hearing on the matter as soon as possible, and requested a response from the SEC no later than September 5, 2001. On August 7, 2001, PG&E Corporation responded in detail to the AG'sCalifornia Attorney General petition demonstrating that PG&E Corporation met the SEC's criteriaqualified for the intrastate exemption. On October 4, 2001, the AG filed a "supplement" to its petition requesting that the SEC consider additional issuesan exemption from PUHCA and to set the matter for hearing. PG&E Corporation responded to the supplement on October 30, 2001, and once again demonstrated that there was no basis for action by the SEC. In comments filed on November 14, 2002 on PG&E Corporation's 9(a)(2) filing made with the SEC in connection with the implementation of the Utility Plan, the AG reiterated the arguments made in its July 7, 2001 and October 4, 2001 filings with the SEC. In its response filed with the SEC on January 24, 2003, PG&E Corporation responded to those arguments and demonstrated that there was no basis for SEC action with respect to those issues. To date, the SEC has neither instituted an investigation nor ordered hearings regarding the matters raised in the AG'sCalifornia Attorney General’s petition.State Energy Regulation Pacific Gas and Electric Companythe Utility to form a holding company was granted subject to various conditions set forth in CPUC decisions issued in 1996 and 1999 related to finance, human resources, records and bookkeeping, and the transfer of customer information. As further discussed below, in January 2002, the CPUC issued a decision asserting that it maintains jurisdiction to enforce the conditions against PG&E Corporation and similar holding companies and to modify, clarify or add to the conditions. The financial conditions provide thatthat:•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 Pacific Gas and Electric Company 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 (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.8• the Utility is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC; • the Utility’s dividend policy must continue to be established by the Utility’s Board of Directors as though the Utility were a stand-alone utility company; • the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation’s Board of Directors, or (known as the first priority condition); and • 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. California'sCalifornia’s electricity and natural gas local distribution and electric utility companies and their non-regulated affiliates. The rules permit non-regulated affiliates of regulated utilities to compete in the affiliated utility'sutility’s service territory, and also to use the name and logo of their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUC. The rules also address the separation of regulated utilities and their non-regulated affiliates and information exchange among the affiliates. The rules prohibit the utilitieseach utility from engaging in certain practices that would discriminate against energy service providers that compete with the utility'sthat 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. IOUs,investor-owned electric utilities, including the Utility, have complied with past CPUC decisions, rules orand orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will investigate (1) the utilities'utilities’ transfer of money to their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties, (2)difficulties; the failure of the holding companies to financially assist the utilities when needed, (3)needed; the transfer by the holding companies of assets to unregulated subsidiaries,subsidiaries; and (4) the holding companies'companies’ actions to "ringfence"“ringfence” their unregulated subsidiaries. The CPUC will also determine whether additional rules, conditions or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the holding company structure. The CPUC will investigate whether it should modify, change or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions or recommend statutory changes to the California legislature. As a result of the investigation, the CPUC may impose remedies, prospective rules, or conditions, as appropriate. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders."infuse“infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve."” The three major California IOUsinvestor owned electric utilities and their parent holding companies had opposed this broader interpretation as being inconsistent with the prior 15 years'years’ understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The CPUC also interpreted the first priority condition as prohibiting a holding company from (1) acquiring assets of its utility subsidiary for inadequate consideration and (2) acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility'sutility’s ability to fulfill its obligation to serve or to operate in a prudent and efficient manner. In the other decision, the CPUC asserted that it maintains jurisdiction to enforce the conditions against PG&E Corporation and similar holding companies and to modify, clarify or add to the conditions.the othera related decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the interim decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to the proceeding. TheIn its written decision adopted on January 9, 2002, the CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum; i.e., the state court action discussed below,forum could decide expeditiously whether adoption of the Utility'sUtility’s original proposed plan of reorganization would violate the first priority condition. On November 26, 2003, the California Court of Appeals for the First Appellate District in San Francisco agreed to hear the petitions for review of the CPUC’s decisions. Oral argument before the appellate court is set for March 5, 2004.AGCalifornia 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 AGCalifornia Attorney General alleges that PG&E Corporation violated the various conditions established by the CPUC in decisions approving the holding company formation. After the AG'sCalifornia Attorney General’s complaint was filed, two other complaints containing substantially similar allegations were filed by the City and County of San Francisco and by a private plaintiff. These complaints are not affected by the Settlement Agreement. For more information, see "Item 3—“Item 3 — Legal Proceedings"Proceedings” below. PG&E CorporationThe Utility’s Regulatory EnvironmentUtility believe“Ratemaking Mechanisms” section below summarize some of the more significant energy laws, regulations and regulatory mechanisms affecting the Utility. These sections are not an exhaustive description of all the energy laws, regulations and regulatory proceedings that they have complied with applicable statutes, CPUC decisions, rules,affect the Utility. The energy laws, regulations and orders. Neitherregulatory proceedings may change or be implemented or applied in a way that the Utility nor PG&E Corporation can predict whatdoes not currently anticipate. For discussion of specific regulatory proceedings affecting the outcomes ofUtility, see the CPUC's investigation, the AG's petition to the SEC, and the related litigation will be or whether the outcomes will have a material adverse effect on their results of operations or financial condition.MD&A.Federal Energy Regulation The FERC 9Regulation of Pacific Gas and Electric CompanyFederal Regulation The FERC. The FERC is an independent agency within the U.S. Department of Energy, or the DOE. The FERCDOE, that regulates the interstate sale and transportation of natural gas, the transmission of electricity in interstate commerce and the sale for resale of electricity in interstate commerce. The FERC regulates electricelectricity transmission, ratesinterconnections, tariffs and access, interconnections, operationconditions of service of the California Independent System Operator, or ISO and the terms and rates of wholesale electric powerelectricity sales. The ISO has responsibilityis 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 and is subject to FERC regulation of tariffs and conditions of service.generation capacity. In addition, the FERC has jurisdiction over the Utility's electricUtility’s electricity transmission revenue requirements and rates. The FERC also regulatesrates, the licensing of substantially all of the Utility’s hydroelectric generation facilities and the interstate sale and transportation of natural gas. Further, most of the Utility's hydroelectric facilities are subject to licenses issued by the FERC. In an effort to support the development of competitive markets, the FERC announced in its Order 2000 a policy of promoting regional transmission organizations, or RTOs, which would perform specified functions similar to the ISO. Under the FERC's Order 2000, RTOs would generally span areas where multiple utilities may have operated in the past in order to enhance the efficiency of power markets, for example, by eliminating duplicative charges from one transmission system to the next in a region. Order 2000 encourages utilities owning transmission systems to form RTOs on a voluntary basis. The Utility is a participant in the ISO; however, the FERC has not yet approved the ISO's status as a RTO under Order 2000. In the FERC's proposal for a standard market design, the FERC has proposed additional changes to the open access transmission tariff initially established under the FERC's Order 888 to standardize transmission service and wholesale electric market design to address undue discrimination in interstate transmission services. The FERC has proposed that all public utilities with open access transmission tariffs file modifications to their tariffs to conform to the FERC's standard. These proposed changes would require all independent transmission providers or RTOs to participate in a regional planning process for grid upgrades and expansion to ensure grid reliability. The FERC proposed approving participant funding of certain new facilities, meaning those who would directly benefit from those facilities would be required to pay for them. PG&E Corporation filed comments on November 15, 2002 supporting the goals of the FERC's proposal, and is continuing to participate in the rulemaking process as it moves forward. The ISO issued its own Comprehensive Market Design Proposal to effect changes to the structure and operation of the California electricity market. Implementation of the first phase of the proposal, automated market mitigation procedures, occurred in the fourth quarter of 2002, with subsequent phases to address real-time economic dispatch, integrated forward markets, locational marginal pricing, and congestion management scheduled to occur in 2003 and 2004. In a separate proceeding, the FERC has proposed that all transmission providers use standard interconnection procedures and a standard agreement for generator interconnections. The generator interconnection rules, if adopted as proposed, would require the Utility to update and construct additional facilities based on decisions by new generators, and would preclude the Utility from disclaiming consequential damages for any claims or limiting the Utility's liability for its negligence in any new generator interconnection agreements. The FERC has also held that transmission providers, like the Utility, must upgrade existing facilities or construct new facilities to interconnect with new generators, and that while generators will generally be responsible for initially funding the costs of such facilities, some of which costs over time must be refunded by the Utility and recovered in the Utility's rates. The FERC recently held that generators are entitled to a credit for the cost of network upgrades which they funded even if the FERC previously had accepted agreements which directly assigned to the generators responsibility for the cost of those upgrades.unprecedented increase in wholesale electricity prices,California energy crisis, the FERC issued a series of orders in the spring and summer of 2001 and July 2002 aimed at prospectively mitigating future extreme wholesale energy prices like those that prevailed in 2000 and 2001. These orders established a cap on bids for real-time electricity and ancillary services of $250/$250 per MWh (unless a generator could demonstrate that its costs justified a rate in excess of $250 per MWh) and established various automatic mitigation procedures. Recently,As of December 2003, all sellersFERC'sFERC is expected to consider ISO market monitoring and oversight in connection with the FERC’s review of the ISO’s standard market design proposed rules, the FERC proposed to adopt a safety net bid cap as part of theproposals. Market monitoring and mitigation plan for wholesalealso may be affected by any energy markets and has requested comments on the appropriate value for such a bid cap.legislation Congress may pass.Also, in June and July 2001, the FERC's chief administrative law judge conducted settlement negotiations among power sellers, the State of California and the California IOUs in an attempt to resolve disputes regarding10past power sales. The negotiations did not result in a settlement, but the judge recommended that the FERC conduct further hearings to determine possible refunds and what the power sellers and buyers are each owed. The FERC has asserted that it would not order refunds for periods before October 2, 2000, because under a federal statute it can only consider ordering refunds as far back as 60 days after a complaint for overcharges was filed. The first complaint for overcharges was filed with the FERC in August 2000. These hearings, in which various parties,Various entities, including the Utility and the State of California, which isare seeking up to $8.9 billion in refunds for electricity overcharges on behalf of buyers, including the Utility, were concluded in October 2002. However, an August 21, 2002, orderCalifornia electricity purchasers from the U. S. Court of Appeals for the Ninth Circuit ordered the FERCJanuary 2000 to allow the California parties "to adduce additional evidence of market manipulation by various sellers...."June 2001. In November 2002, the FERC gave parties until February 28, 2003 to submit more evidence and conduct fact-finding on whether California's energy market was manipulated. On December 17, 2002, a FERC administrative law judge issued a ruling permitting the California parties to conduct discovery of potential market manipulation affecting California ISO and PX markets within all 14 western states and parts of Canada comprising the Western Electricity Coordinating Council to support claims for refunds. The judge also ruled new evidence is admissible on market manipulation and artificially inflated prices for natural gas, the chief fuel used to generate electricity. On December 12, 2002, a FERC administrative law judge issued an initial decision finding that power companiessuppliers overcharged the utilities, the State of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001 by $1.8 billion,(the only time period for which the FERC permitted refund claims), but that California buyers still owe the power companies $3suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.time period reviewedFERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the FERC hearings excludes the claims for refunds for overcharges that occurred before October 2, 2000 and after June 2001 when the DWR entered into contracts to buy power. After the final round of evidence-gathering ends,refund methodology. In addition, the FERC commissioners must decide whetherdirected the ISO and the California Power Exchange, or PX, which operates solely to uphold or changereconcile remaining refund amounts owed, to make compliance filings establishing refund amounts by March 2004. The ISO has indicated that it plans to make its compliance filing by August 2004. The actual refunds will not be determined until the initial decision. ItFERC issues a final decision following the ISO and PX compliance filings. The FERC is uncertain when the FERCit will issue a decision.final decision in this proceeding. In addition, future refunds could increase or decrease as a result of an alternative calculation proposed by the ISO, which incorporates revised data provided by the Utility and other entities.NRC.net after-tax amount of any refunds, claim offsets or other credits from generators or other energy suppliers relating to the Utility’s ISO, PX, qualifying facilities or energy service provider costs that are actually realized in cash or by offset of creditor claims in its Chapter 11 proceeding would reduce the balance of the $2.21 billion after-tax regulatory asset created by the Settlement Agreement.The NRC Nuclear Power Plant (Diablo Canyon)power plant and the retired nuclear generating unit at Humboldt Bay Unit 3. NRC regulations require extensive monitoring and review of the safety, radiological, environmental and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. Safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at the Utility’s Diablo Canyon power plant and additional significant capital expenditures could be required in the future.State Energy Regulation The CPUC State Regulation The CPUC.The CPUC has jurisdiction to set retailthe rates, terms and conditions of service for the Utility's electricUtility’s electricity distribution, natural gas distribution and natural gas transmissiontransportation and storage services in California. The CPUC also has jurisdiction over the Utility's salesUtility’s issuances of securities, dispositions of utility property,assets and facilities, energy procurementpurchases on behalf of its electricthe Utility’s electricity and natural gas retail customers, rate of return, rates of depreciation, and certain aspects of the Utility's siting and operation of its electricnatural gas transportation assets, oversight of nuclear decommissioning and gasaspects of the siting of the electricity transmission and distribution systems.system. Ratemaking for retail sales from the Utility's remainingUtility’s generation facilities is under the jurisdiction of the CPUC. To the extent such powerthis electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. TheIn addition, the CPUC also conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms.California Legislature The CEC. The California Energy Resources Conservation and Development Commission, also called the California Energy Commission, or the CEC, makes electricity-demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines additional energy sources and conservation program needs. The CEC has jurisdiction over the siting and construction of new thermal electric generating facilities 50 MW and greater in size. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs, and maintains a statewide plan of action in case of energy shortages. In addition, the CEC certifies power plant sites and related facilities within California. The CEC also administers funding for public purpose research and development, and renewable technologies programs. California Legislature. The California Legislature also has an active role in the regulation of California IOUs. Over the last several years, the Utility'sUtility’s operations have been significantly affected by statutes passed by the California Legislature.legislature, including:• Assembly Bill 1890. Assembly Bill 1890—California Electric Industry Restructuring. In 1998, California implemented Assembly Bill 1890, or AB 1890 which mandated the restructuring of the California electricity industry, commencing in 1998 with the implementation of a market framework for electricity generation in which generators and other energy providers were permitted to charge market-based rates for wholesale electricity and the Utility’s customers were given the choice of becoming direct access customers;• Assembly Bill 6X.AB 6X, enacted in January 2001 in response to the California energy crisis, prohibited disposition of utility-owned generation facilities before January 1, 2006; • Assembly Bill 1X.AB 1X authorized the DWR, beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities’ retail customers. AB 1X required the California investor-owned electric utilities, including the Utility, to deliver that electricity and act as the DWR’s billing and collection agent; • Senate Bill 1976.SB 1976, enacted in September 2002, required the CPUC to allocate electricity from contracts that the DWR entered into under AB 1X among the customers of the California investor-owned electric utilities, required the utilities to file short- and long-term procurement plans with the CPUC, contemplated that the utilities would resume buying electricity pursuant to these plans by January 1, 2003, and mandated new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under approved procurement plans; and • Senate Bill 1078. SB 1078, enacted in September 2002, creates a renewable portfolio standard for investor-owned utilities that requires annual 1% increases of renewable electrical procurement purchases until renewable resources equal 20% of total retail sales in 2017. California electric industryregulatory asset and establishedrelated federal, state and franchise taxes using a market framework for electric generation in which generators and other power providers were permitted to charge11market-based prices for wholesale power. The CPUC also issued many decisions to implement electric industry restructuring. Electric industry restructuring included the following components: The Rate Freeze and Transition Cost Recovery—Beginning January 1, 1997, electric rates for all customers were frozen at the level in effect on June 10, 1996, except that on January 1, 1998, rates for residential and small commercial customers were reducedsecuritized financing supported by a further 10% and frozen atdedicated rate component that level. The rate freeze for each IOU was supposed to end when that IOU had recovered its eligible "transition" costs (costswould require enactment of utility generation-related assets and obligations that were expected to become uneconomic under the new competitive generation market structure), but not later than March 31, 2002. Under limited circumstances, some transition costs could be recovered after the transition period. Costs eligible for recovery as transition costs, as determined by the CPUC, include (1) above-market sunk costs associated with utility generating facilities that are fixed and unavoidable and that were included in customer rates on December 20, 1995, and future unavoidable above-market firm obligations, such as costs related to plant removal, (2) costs associated with pre-existing long-term contracts to purchase power at then above-market prices from qualifying facilities, or QFs, and other power suppliers, and (3) generation-related regulatory assets and obligations. Frozen rates were designed to recover authorized utility costs and, to the extent the frozen rates generated revenues in excess of authorized utility costs, recover the Utility's transition costs. Transition costs also were to be recovered by other revenue sources including (1) the portion of the market value of generation assets sold by the Utility or market valued by the CPUC that is in excess of book value, (2) revenues from energy sales from the utilities' remaining electric generation facilities that exceeded the allowed revenue requirements for the utilities' costs to generate or obtain such electricity, and (3) revenues provided after the end of the transition period for rate reduction bond principal repayments to recover deferred transition costs associated with the financed 10% rate reduction and issuance of the rate reduction bonds to finance such reduction. For the first two years of the transition period, the revenues from frozen retail rates exceeded the generation costs included in retail rates. Based on the resulting net revenues and other revenue sources used to recover transition costs, it appeared that the Utility's transition costs would be recovered before March 31, 2002, thus allowing the rate freeze to end sooner than the statutory end date. Although the Utility informed the CPUC in late 2000 that it had satisfied the statutory conditions for ending the rate freeze by no later than August 31, 2000, the CPUC adopted changes to its regulatory accounting rules in March 2001 that had the effect of changing the classification of costs recovered in the Utility's regulatory balancing accounts and reversing the Utility's prior collection of transition costs. In June 2000, wholesale electricity prices began to increase and reached unprecedented levels in November 2000 and later months. During theauthorizing California energy crisis, frozen rates were insufficient to cover the Utility's electricity procurement and other costs. By December 31, 2000, the Utility had accumulated approximately $6.9 billion in undercollected purchased power and transition costs that the CPUC would not allow the Utility to collect from its customers. Because the Utility could no longer conclude that such costs were probable of recovery, the Utility charged this $6.9 billion to earnings during 2000. In the first quarter of 2001, the CPUC authorized the Utility to begin collecting energy surcharges totaling $0.04 per kWh (composed of a $0.01 per kWh surcharge inlegislation. On January and a $0.03 per kWh surcharge approved in March). Although the CPUC authorized the $0.03 per kWh surcharge in March 2001, the Utility did not begin collecting the revenues until June 2001. As a result, in May 2001, the CPUC authorized the Utility to collect an additional $0.005 per kWh surcharge revenue for 12 months to make up for the time lag in collection of the $0.03 surcharge revenues. Although the collection of this "half-cent surcharge" was originally scheduled to end on May 31, 2002, the CPUC issued a resolution ordering the Utility to continue collecting the half-cent surcharge until further consideration by the CPUC. The CPUC restricted the use of these surcharge revenues to pay for the Utility's "ongoing procurement costs" and "future power purchases." Due to these surcharges, the Utility has been collecting revenues in excess of its ongoing costs of utility service enabling the Utility to partially recover its undercollected power procurement and transition costs previously written off. The amount of undercollected power procurement and transition costs has been reduced to approximately $2.2 billion (after-tax) at December 31, 2002.12 In November 2002,22, 2004, the CPUC approved proposed legislation, Senate Bill 772, that would authorize a decision modifyingdedicated rate component to securitize the restrictionsregulatory asset and the related taxes. The California Assembly’s Utilities and Commerce Committee approved the proposed legislation on the use of revenues generatedFebruary 2, 2004. The proposed legislation will next be considered by the surchargesCalifornia Assembly’s Appropriations Committee. Under the Settlement Agreement, any adopted legislation must be satisfactory to permit the revenues to be used for the purpose of securing or restoring the Utility's reasonable financial health, as determined by the CPUC. The CPUC will determine in other proceedings how the surcharge revenues can be used, whether there is any cost or other basis to support specific surcharge levels, and whether the resulting rates are just and reasonable. After the CPUC, determines when the AB 1890 rate freeze ended (which the CPUC states ended no later than March 31, 2002), the CPUC will determine the extent and disposition of the Utility's undercollected costs, if any, remaining at the end of the rate freeze. If the CPUC determines that the Utility recovered revenues in excess of its transition costs or in excess of other permitted uses, the CPUC may require the Utility to refund such excess revenues. In a case currently pending before it relating to the CPUC's settlement with Southern California Edison, the Supreme Court of California is considering whether the CPUC has the authority to enter into a settlement which allows Southern California Edison to recover undercollected procurement and transition costs in light of the provisions of AB 1890. The Utility cannot predictReform Network, or TURN and the outcome of this case or whethersecuritization must not adversely affect the CPUC or others would attempt to apply any ruling to the Utility. If the Utility is ordered to refund material amounts to ratepayers the Utility's financial conditionUtility’s credit ratings among other conditions.The California Energy Resources Conservation and Development Commission results of operations would be materially adversely affected. Direct Access —AB 1890 gave the Utility's customers the choice of continuing to buy electricity fromDevelopment Commission, commonly called the California IOUsEnergy Commission, or buying electricity from independent power generators or retail electricity suppliers beginning April 1, 1998. Customers who choose to buy their electricity from independent power generators or retail electricity suppliers are called direct access customers. Most ofCEC, is the Utility's customers continued to buy electricity through the Utility. On September 20, 2001, the CPUC, pursuant to AB 1X, suspended the right of retail end-use customers to acquire direct access service, preventing additional customers from entering into contracts to purchase electricity from alternativestate’s primary energy providers. In a subsequent decision issued on March 21, 2002, the CPUC decided to allow all customers with direct access contracts entered into on or before September 20, 2001 to remain on direct access.policy and planning agency. The CPUC has established an exit fee, or non-bypassable charge, on those direct access customers to avoid a shift of costs from direct access customers to bundled service customers. For more information, see "Electric Ratemaking—Electric Procurement—Direct Access" below. The Power Exchange, the Independent System Operator, and the Buy/Sell Requirement —AB 1890 called for the creation of the California Power Exchange, or the PX. The PX provided an auction process, intended to be competitive, to establish hourly transparent market clearing prices for electricity in the markets operated by the PX. The PX operated the following energy markets:•the day-ahead market where market participants purchased power for their customers' needs for the following day,•the day-of market where market participants purchased power needed to serve their customers on the same day, and•the block forward market, or BFM, that matched bids to buy a specific amount of power for one month (and later one-quarter and annual terms) with offers to sell power for the same period in advance of the contracted delivery date. This short-term spot market approach represented a dramatic shift from the existing pricing approach based on a portfolio of short and longer-term contracts. At the time the PX was formed and in several subsequent decisions, the CPUC ruled that prices paid by utilities to the PX under the CPUC's "buy-sell" mandate were presumed to be prudent and reasonable for the purpose of recovery in retail rates. AB 1890 also called for the creation of the ISO to exercise centralized operational control of the statewide transmission grid. The California IOUs were obligated to transfer control, but not ownership, of their transmission systems to the ISO. The ISOCEC is responsible for ensuring the reliabilitysiting of all thermal power plants over 49 MW and administers public interest research and development funds, as well as renewable resource programs, including the transmission grid and keeping momentary supply and demand in balance. The PX market was augmented by a spot "real-time" market maintained by the ISO. If enough power was not purchased and scheduled to meet the actual real-time demands for power being placed on the transmission system, then the ISO was authorized under its FERC-approved tariffs to purchase and provide the electricity from any other sources within or outside of California, often at high rates, to make up the difference in order to keep the electrical grid operating reliably. The ISO billed the PX for such power deficiencies, and the PX in turn billed the IOUs to the extent the IOUs were unable to purchase sufficient supply from the PX for their retail customers.renewable energy portfolio standard program.Other Regulation PX's BFM provided the Utility a limited opportunity to hedge against prices in the PX day-ahead market only; it did not enable the Utility to hedge against ISO real-time market prices. In July 1999, the Utility obtained CPUC authority to participate in the BFM and the Utility subsequently entered into several BFM contracts.13 Due to the January 2001 downgrades in the Utility's credit ratings and the Utility's alleged failure to post collateral for all market transactions, the PX suspended the Utility's market trading privileges as of January 19, 2001. Further, the PX sought to liquidate the Utility's BFM contracts for the purchase of power. On February 5, 2001, the Governor, acting under California's Emergency Services Act, seized the Utility's BFM contracts for the benefit of the State. Under the Act, the State must pay the Utility the reasonable value of the contracts, although the PX may seek to recover monies that the Utility owes to the PX from any proceeds realized from those contracts. The Utility subsequently filed a complaint against the State to recover the value of the seized contracts. This litigation is still pending. Divestiture and Market Valuation of Generation Assets —The structure of the transition to a fully competitive generation market established by AB 1890 also required all of the Utility's generation assets to be market valued, if not through sale, then through appraisal or other divestiture. Under AB 1890, the CPUC was required to complete market valuation of all generation assets by December 31, 2001. Under AB 1890, once an asset had been market valued, it was no longer subject to rate regulation by the CPUC. The market valuation process was intended to be an integral and essential step in recovering transition costs and measuring whether the transition period had ended. The transition costs eligible for recovery were to be calculated by netting above-market assets against below-market assets. Once market valuation had occurred, the end of the rate freeze date was to be computed retroactively to the point at which all transition costs had been recovered. To date, the only assets of the Utility that the CPUC has valued have been those that were divested through sale, except with respect to the Utility's Hunters Point power plant, which the CPUC ruled had no market value. The Utility timely submitted proposed market valuations of retained generation facilities, so that those facilities could be valued by the CPUC and no longer subject to CPUC regulation. In August 2000, the Utility submitted an interim market valuation of $2.8 billion for its hydroelectric generation facilities. Additionally, in June and December 2000, the Utility submitted testimony to the CPUC providing a market valuation of its hydroelectric facilities of $4.1 billion. In 1995, in anticipation of the transition to a competitive wholesale electric market, the CPUC ordered the California IOUs to file plans to divest at least 50% of their fossil fuel-fired generation assets. Moreover, as an incentive to sell the remainder of the Utility's generation assets, the CPUC reduced the return on equity that the Utility could earn on any retained generation asset substantially below its otherwise authorized return to a level equivalent to 90% of the Utility's embedded cost of debt (or 6.77%). The Utility sold virtually all of its fossil-fuel fired and geothermal generation capacity with CPUC authorization and approval. By January 2000, the Utility owned only its large nuclear power generating facility at Diablo Canyon, its hydroelectric generation facilities, and two smaller, older fossil facilities. As the amount of the Utility's own generation resources decreased, the Utility was forced to rely on power supplied by third-party power producers through the PX to meet the electricity demands of its customers. Assembly Bill 1X—California Department of Water Resources. In late December 2000 and early January 2001, the Utility's creditworthiness deteriorated and was no longer able to comply with the ISO's creditworthiness criteria, spelled out in the ISO tariff, for scheduling third-party power transactions through the ISO. The Utility was unable to continue financing its wholesale power purchases in light of its downgraded credit ratings. On January 17, 2001, the Governor of California signed an order declaring an emergency and authorizing the California Department of Water Resources, or the DWR, to purchase power to maintain the continuity of supply to retail customers. On February 1, 2001, the Governor signed Assembly Bill 1X, or AB 1X, to authorize the DWR to purchase power and sell that power directly to the utilities' retail end-use customers. AB 1X also required the Utility to deliver the power purchased by the DWR over its distribution systems and to act as a billing and collection agent on behalf of the DWR, without taking title to such power or reselling it to its customers. AB 1X allows the DWR to recover, as a revenue requirement, among other things: (1) amounts necessary to pay for the power and associated transmission and related services, (2) amounts needed to pay the principal and interest on bonds issued to finance the purchase of power, (3) administrative costs, and (4) certain other amounts associated with the program. AB 1X authorizes the CPUC to set rates to cover the DWR's revenue requirements (but prohibits the CPUC from increasing electric rates for residential customers who use less power than 130% of their existing baseline quantities). Assembly Bill 6X—Prohibition on Disposition of Retained Utility-Owned Generating Assets. In January 2001, the California legislature also enacted AB 6X, which prohibits disposition of utility-owned generating facilities before January 1, 2006. On December 21, 2001, the assigned CPUC Commissioner issued a ruling for comment in which she expressed her opinion that the requirement of AB 1890 to market value retained generation by December 31, 2001 had been superseded by AB 6X. On January 15, 2002, the Utility filed its comments on the14proposal stating that AB 6X did not relieve the CPUC of its statutory obligation to market value the retained generation by December 31, 2001. The CPUC has not yet issued a decision on this matter. On January 2, 2002, the CPUC issued a decision finding that AB 6X had materially affected the implementation of AB 1890. The CPUC scheduled further proceedings to address the impact of AB 6X on the AB 1890 rate freeze for the Utility and to determine the extent and disposition of the Utility's remaining unrecovered transition costs. In its November 2002 decision regarding the surcharge revenues, discussed above, the CPUC reiterated that it had yet to decide when the rate freeze ended and the disposition of any undercollected costs remaining at the end of the rate freeze. On January 17, 2002, the Utility filed an administrative claim with the State of California Victim Compensation and Government Claims Board alleging that AB 6X violates the Utility's statutory rights under AB 1890. The Utility's claim seeks compensation for the denial of its right to at least $4.1 billion market value of its retained generating facilities. On March 7, 2002, the Claims Board formally denied the Utility's claim. Having exhausted remedies before the Claims Board, on September 6, 2002, the Utility filed a complaint against the State of California in the California Superior Court. On January 9, 2003, the Superior Court granted the State's request to dismiss the Utility's complaint, finding that AB 1890 did not constitute a contract. The Utility has 60 days to file an appeal and intends to do so. Senate Bill 1976—Resumption of Procurement. Under AB 1X, the DWR was prohibited from entering into new electricity purchase contracts and from purchasing electricity on the spot market after December 31, 2002. In September 2002, the Governor signed California Senate Bill 1976, or SB 1976, into law. SB 1976 required the CPUC to allocate electricity subject to existing DWR contracts among the customers of the California IOUs, including the Utility's customers. Each IOU had to submit, within 60 days of the CPUC's allocation of the existing DWR contracts, a proposed electricity procurement plan to the CPUC specifying the date that the IOU intends to resume procurement of electricity for its retail customers. As part of the resumption of the procurement function, each IOU would procure electricity for that portion of its customers' needs that is not covered by the combination of the allocation of electricity from existing DWR contracts to that IOU's customers and the IOU's own electric resources and contracts (referred to as the residual net open position). SB 1976 requires that each procurement plan include one or more of the following features:•A competitive procurement process under a format authorized by the CPUC, with the costs of procurement obtained in compliance with the authorized bidding format being recoverable in rates;•A clear, achievable, and quantifiable incentive mechanism that establishes benchmarks for procurement and authorizes the IOUs to procure from the market subject to comparison with the CPUC-authorized benchmarks; and/or•Upfront and achievable standards and criteria to determine the acceptability and eligibility for rate recovery of a proposed transaction and an expedited CPUC pre-approval process for proposed bilateral contracts to ensure compliance with the individual utility's procurement plan. The CPUC must review each procurement plan but SB 1976 provides that the CPUC may not approve a procurement plan if it finds the plan contains features or mechanisms that would impair restoration of the IOU's creditworthiness or would lead to a deterioration of the IOU's creditworthiness. A procurement plan approved by the CPUC must accomplish the following objectives, among others:•Enable the IOU to fulfill its obligation to serve its customers at just and reasonable rates;•Eliminate the need for after-the-fact reasonableness review of actions in compliance with an approved procurement plan, including resulting electricity procurement contracts and related expenses, subject to verification and assurance that each contract was administered in accordance with the terms of the contract and that contract disputes that arise are resolved reasonably; and•Moderate the price risk associated with serving its customers by authorizing the IOU to enter into financial and other electricity-related product contracts. SB 1976 requires the CPUC to:•create electric procurement balancing accounts to track and allow recovery of the differences between recorded revenues and costs incurred under an approved procurement plan;•review the revenues and costs associated with the IOU's procurement plan at least semi-annually and adjust rates or order refunds as necessary; and15•establish the schedule for amortizing the overcollections or undercollections in the electric procurement balancing accounts at least through January 1, 2006, so that the aggregate overcollection or undercollection reflected in the accounts does not exceed 5% of the IOU's actual recorded generation revenues for the prior calendar year, excluding revenues collected on behalf of the DWR. On September 19, 2002, the CPUC issued a decision allocating electricity subject to the DWR contracts to the generation portfolios of the three California IOUs for operational and scheduling purposes, with the DWR retaining legal title and financial reporting and payment responsibilities associated with these contracts. The IOUs will, however, become responsible for scheduling and dispatch of the quantities subject to the allocated contracts and for many administrative functions associated with those contracts. On October 24, 2002, the CPUC issued a decision establishing an accelerated schedule for submission and approval of procurement plans for each California IOU with a view to these utilities resuming procurement responsibility for their net open position on January 1, 2003. On December 19, 2002, the CPUC adopted, in large part but with modifications, the Utility's revised 2003 interim procurement plan. The CPUC also authorized the IOUs to extend their planning into the first quarter of 2004 and directed them to hedge their 2004 first quarter residual net short positions with transactions entered into in 2003. The Utility is required to submit its long-term procurement plan covering the next 20 years by April 1, 2003. In December 2002, the CPUC determined that the maximum risk of potential disallowance each IOU should face for all of its procurement activities should be limited to twice its annual administrative costs of managing procurement activities. The Utility anticipates that its annual administrative costs of managing procurement activities will be approximately $18 million in 2003. On January 1, 2003, the California IOUs resumed the function of procuring electricity to meet their customers' residual net open position and became responsible for the operational and scheduling functions associated with the DWR contracts allocated to their customers. The IOUs continue to act as billing and collection agents for the DWR.Local Regulation, Licenses and Permits Pacific Gas and Electric Company obtains a number of permits, authorizations and licenses in connection with the construction and operation of its generating plants,the Utility’s generation facilities, electricity transmission lines, natural gas transportation pipelines and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the mostmore significant examples. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. The Utility currently has eightseven hydroelectric projects and one transmission line project undergoing FERC license renewal.relicensing. The Utility will begin relicensing proceedings on two additional hydroelectric projects within the next two years.allowpermit the Utility to install, operate and maintain itsthe Utility’s electric, natural gas, oil and water facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties under the franchises. Franchise fees are computed accordingpursuant to statute depending on whether the particular franchise was granted under either the Broughton Act or the Franchise Act of 1937; however,1937. However, there are 38 "charter cities"charter cities that can set a fee of their own determination. The Utility also periodically obtains permits, authorizations and licenses in connection with our distribution of electricity and natural gas. Pursuant to theUnder these permits, licenses,authorizations and franchises,licenses the Utility has rights to occupy and/or use public property for the operation of itsthe Utility’s business and to conduct certain related operations. The Utility's operationsRatemaking MechanismsOverview Transition from Frozen Rates to Cost of Service Ratemaking assets are also regulated by a varietyto the extent frozen rates generated revenues in excess of other federal, state, and local agencies.Regulation of PG&E National Energy Group, Inc. BusinessesFederal Regulation The rates, terms, and conditions ofthese costs, to recover the wholesale sale of power byUtility’s transition costs. Although the generating facilities owned or leased by PG&E NEG through PG&E Generating Company LLC, its subsidiaries and affiliates, and of power contractually controlled by them is subject to FERC jurisdictionsurcharges implemented in 2001 effectively increased the actual rate, under the Federal Power Act. Various PG&E NEG subsidiaries and affiliates have FERC-approved market-basedfrozen rate schedules and accordingly have been granted waivers of16many ofstructure, increases in the accounting, record keeping, and reportingUtility’s authorized revenue requirements imposed on entities with cost-based rate schedules. This market-based rate authority may be revoked or limited at any time bydid not increase the FERC. PG&E NEG-affiliated projects are also subject to other differing federal regulatory regimes. Those qualifying as qualifying facilities, or QFs,Utility’s revenues. In addition, DWR revenue requirements reduced the Utility’s revenues under the Public Utility Regulatory Policies Act of 1978, or PURPA, are exempt from the Holding Company Act, certainfrozen rate filings, and accounting, record keeping, and reporting requirements that the FERC otherwise imposes and from certain state laws. Others qualify as Exempt Wholesale Generators under the National Energy Policy Act of 1992. These generators are not regulated under the Holding Company Act, but are subject to FERC and state regulation, including rate approval. The FERC also regulates the rates, terms, and conditions for electric transmission in interstate commerce. Tariffs established under FERC regulation provide PG&E NEG with the necessary access to transmission lines which enables PG&E NEG to sell the energy PG&E NEG produces into competitive markets for wholesale energy. In April 1996, the FERC issued an order requiring all public utilities to file "open access" transmission tariffs. Some utilities are seeking permission from the FERC to recover costs associated with stranded investments through add-ons to their transmission rates. To the extent that the FERC will permit these charges, the cost of transmission may be significantly increased and may affect the cost of PG&E NEG operations. The FERC also licenses all of PG&E NEG's hydroelectric and pumped storage projects. These licenses, which are issued for 30 to 50 years, will expire at different times between 2002 and 2020. The relicensing process often involves complex administrative processes that may take as long as 10 years. The FERC may issue a new license to the existing licensee, issue a license to a new licensee, order that the project be taken over by the federal government (with compensation to the licensee), or order the decommissioning of the project at the owner's expense. PG&E NEG's natural gas transmission business is also subject to FERC jurisdiction. Certificates of public convenience and necessity have been obtained from the FERC for construction and operation of the existing pipelines and related facilities and properties, construction and operation of the North Baja Pipeline, and construction and operation on the PG&E GTN pipeline currently underway. An application has also been filed with the FERC to construct a further expansion on PG&E GTN. The rates, terms, and conditions of the transportation and sale (for resale) of natural gas in interstate commerce is subject to FERC jurisdiction. As necessary, PG&E NEG subsidiaries and affiliates file applications with the FERC for changes in rates and charges that allow recovery of costs of providing services to transportation customers. An October 1999 order permits individually negotiated rates in certain circumstances. The U.S. Department of Energy, or DOE, also regulates the importation of natural gas from Canada and exportation of power to Canada.State and Other Regulations In addition to federal laws and regulation, PG&E NEG businesses are also subject to various state regulations. First, public utility regulatory commissions at the state level are responsible for approving rates and other terms and conditions under which public utilities purchase electric power from independent power projects.structure. As a result power sales agreements, which PG&E NEG affiliates enter into with such utilities, are potentially subject to reviewof revised electricity rates discussed below and a January 2004 CPUC decision determining that the rate freeze ended on January 18, 2001, the Utility expects that once approved by the public utility commissions, through the commissions' power to approve utilities'CPUC, its rates and cost recoveries. Second, state public utility commissions also have the authority to promulgate regulations for implementing some federal laws, including certain aspects of PURPA. Third, some public utility commissions have asserted limited jurisdiction over independent power producers. For example, in New York the state public utility commission has imposed limited requirements involving safety, reliability, construction, and the issuance of securities by subsidiaries operating assets located in that state. Fourth, state regulators have jurisdiction over the restructuring of retail electric markets and related deregulation of their electric markets. Finally, states may also assert jurisdiction over the siting, construction, and operation of PG&E NEG's generation facilities. In addition, the National Energy Board of Canada and the Canadian gas-exporting provinces issue licenses and permits for removal of natural gas from Canada. The Mexican Comisión Reguladoro de Energía, or CRE, issues various licenses and permits for the importation of gas into Mexico. These requirements are similar to the requirements of the U.S. Department of Energy for the importation and exportation of gas. Other regulatory matters are described throughout this report. For a discussion of environmental regulations to which PG&E Corporation andwill reflect its subsidiaries are subject, see the section entitled "Environmental Matters" below.17 Historically, energy utilities operated as regulated monopolies within specific service territories where they were essentially the sole suppliers of natural gas and electricity services. Under this model, the energy utilities owned and operated all of the businesses necessary to procure, generate, transport, and distribute energy. These services were priced on a combined, or "bundled" basis, with rates charged by the energy companies designed to include all of the costs of providing these services. Under traditional cost-of-service regulation, there is a regulatory compact in which the utilities undertake a continuing obligation under state law to serve their customers, in return for which the utilities are authorized to charge regulated rates sufficient to recover their costs of service whereby the Utility’s rates are calculated based on the aggregate of various authorized rate components. Changes in any individual revenue requirement will change customers’ electricity rates.timely recoveryTURN and the CPUC’s Office of their operating expensesRatepayer Advocates, or ORA. The rate design settlement agreement has been submitted to the• The Utility’s 2003 GRC; • The allocation of the DWR’s 2004 revenue requirements; • Pending energy supplier refunds, claim offsets or other credits pursuant to the Settlement Agreement; and • The calculation of any over-collection of the surcharge revenues for 2003. reasonable return on their invested capital. The objective of this regulatory policyproposed decision was issued which, if ultimately approved by the CPUC, instead is expected to provide universal access to safe and reliable utility services. Regulation was designed in part to takereduce the place of competition and ensure that these services were provided at fair prices. In recent years, energy utilities faced intensifying pressures to "unbundle," or price separately, those activities that are no longer considered natural monopoly services.Utility’s current electricity revenues by $799 million. The most significant portion of these were the commodity components—electricity and natural gas. The driving forces behind these competitive pressures have been customers who believe they can obtain energy at lower unit prices and competitors who want access to those customers. Regulators and legislators responded to these customers and competitors by providing for more competitiondifference between the $799 million included in the energy industry. Regulatorsdraft decision and legislators required utilitiesthe $860 million filed by the Utility relates to unbundle ratesa proposed decrease in orderthe DWR’s revenue requirement included in the Utility’s January 26, 2004 rate filing. In the January 26, 2004 rate filing, the Utility had estimated that the DWR’s revenue requirement would be reduced by approximately $79 million related to allow customers to compare unit pricesthe DWR’s share of the utilities and other providers when selecting their energy service provider.The Electric Industry As discussed above, in 1998, California implemented AB 1890, which mandatedsettlement agreement of CPUC litigation reached with El Paso. However, the restructuringDWR protested the Utility’s rate filing, indicating that the amount of its share of the California electric industryEl Paso settlement was unknown and established a market framework for electric generation in which generators and other power providers were permitted to charge market-based prices for wholesale power. During the first two years of the transition period, the revenues from frozen retail rates exceeded the generation costs included in retail rates. Beginning in June 2000, wholesale prices for electricity in California began to increase. Prices moderated somewhat in the fall of 2000, before increasing to unprecedented levels in mid-November of 2000 and later months. Revenues from the Utility's frozen retail rates were insufficient to recover the cost of purchasing wholesale power. In January 2001, as wholesale power prices continued to far exceed retail rates, the major credit rating agencies lowered their ratings for the Utility and PG&E Corporation to non-investment grade levels. Consequently, the Utility lost access to its bank facilities and the capital markets, and could no longer continue buying power to deliver to its customers. As a result, the California Legislature authorizedthat the DWR to purchase electricity for the Utility's customers. The DWR's authority to enter into new contracts or purchase power on the spot market expired on December 31, 2002. On January 1, 2003, the California IOUs resumed procuring power to cover their retail customers' residual net open position. The FERC's policy has supported the development of a competitive electric generation sector. The FERC's Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities' transmission grids. The FERC's subsequent Order 2000, issued in 1999, established national standards for RTOs and advanced the view that a regulated, unbundled transmission sector should facilitate competition in both wholesale electric generation and retail electricity markets. The FERC's more recent standard market design proposal continues to uphold this view. The Utility faces increased competition in the electricity distribution functionhad not changed its revenue requirement as a result of the construction of duplicate distribution facilities to service specific existing or new customers, potential municipalization of the Utility's existing distribution facilities by a local government or district, self-generation by the Utility's customers, and other forms of competition that may result in stranded investment capital, loss of customer growth and additional barriers to cost recovery. If the number of Utility customers declines due to these forms of competition and the Utility's rates are not increased in a timely manner to allowEl Paso settlement.fully recoveramend its investment and procurement costs,January 26, 2004 filing containing the Utility's financial condition and results of operations could be materially adversely affected.Natural Gas Industry FERC Order 636, issued in 1992, required interstate pipeline companiesCPUC is expected to divide their services into separate gas commodity sales, transportation, and storage services. Under Order 636, interstate gas pipelines must provide transportation service regardless of whetherconsider the customer (often a local gas distribution company) buys the gas commodity from the pipeline.18 In August 1997, the CPUCrate design settlement at its meeting on February 26, 2004. If approved, the Gas Accord settlement agreement,new rates will be effective March 1, 2004 or Gas Accord, which restructuredshortly thereafter, and the Utility's gas services and its role in the gas market through 2002. Among other matters, the Gas Accord unbundledrevenue reduction will be retroactive to January 1, 2004.Revenue Requirements Utility's gas transportation services from the rates for its distribution services. As a result, the Utility's customers may buy gas directly from competing suppliers and purchase transportation-only and distribution-only services from the Utility. The Utility's industrial and larger commercial customers, or noncore customers, now purchase their gas from producers, marketers and brokers. Substantially all residential and smaller commercial customers, or core customers, buy gas as well as transmission and distribution services from the Utility as a bundled service. Although the Gas Accord originally was scheduled to expire on December 31, 2002, the Utility filed an application to extend the Gas Accord for two years, known as the Gas Accord II Application, or Gas Accord II. In August 2002, the CPUC approved a settlement agreement among the Utility and other parties that provided for a one-year extension through 2003 of the Utility's existing gas transportation and storage rates and terms and conditions of service, as well as rules governing contract extensions and an open season for new contracts. The Gas Accord II settlement left open to subsequent litigation the issues raised in the application insofar as they relate to the second year of the two-year application. In January 2003, the Utility filed an application proposing Gas Accord II rates for 2004. For more information about the Gas Accord and regulatory changes affecting the California natural gas industry, see "Utility Operations—Ratemaking Machanisms—Gas Ratemaking" below. The Utility competes with other natural gas pipeline companies for transportation customers into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas and the quality and reliability of transportation services. The most important competitive factor affecting the Utility's market share for transportation of gas to the southern California market is the total cost of western Canadian gas, including transportation costs, delivered to southern California from the Utility's transportation system relative to the total cost of gas, including transportation costs, delivered to southern California on other pipeline systems from supply basins in the southwestern United States and Rocky Mountains. In general, when the total cost of western Canadian gas increases, the Utility's market share in southern California decreases. In addition, Kern River Pipeline Company expects to complete a major expansion of its pipeline system in 2003 that will increase its capacity to deliver natural gas into the southern California market by approximately 900 million cubic feet, or MMcf, per day. As a result of Kern River's expansion, the volume of gas that the Utility delivers to the southern California market may decrease in the short term. The Utility also competes for storage services with other third party storage providers, primarily in northern California. The most important competitive factors affecting the Utility's market share are overall product design and pricing terms. From time to time, existing pipeline companies propose to expand their pipeline systems for delivery of natural gas into northern and central California. Although the record gas-fired electric generation gas demands in late 2000 and 2001 spurred several new natural gas pipeline proposals for northern and central California, many of the power generation projects have been cancelled or delayed, making it difficult for sponsors of the various gas pipeline projects to acquire enough firm capacity commitments to go forward with construction.Electric Generation and Natural Gas Transmission During 2002, adverse changes in the national energy markets affected PG&E NEG's business including:•Contractions and instability of wholesaleUtility’s electricity and energy commodity markets;•Significant decline in generation margins (spark spreads) caused by excess supply and reduced demand in most regions of the United States;•Loss of confidence in energy companies due to increased scrutiny by regulators, elected officials, and investors as a result of a string of financial reporting scandals;•Heightened scrutiny by credit rating agencies prompted by these market changes and scandals which resulted in lower credit ratings for many market participants; and•Resulting significant financial distress and liquidity problems among market participants leading to numerous financial restructurings and less market participation. PG&E NEG has been significantly impacted by these adverse changes. New generation came online while the demand for power was dropping. This oversupply and reduced demand resulted in low spark spreads (the net of power prices less fuel costs) and depressed operating margins. These changes in the energy industry have had a significant negative impact on the financial results and liquidity of PG&E NEG as discussed in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations."19 Competitive factors may also affect the results of PG&E NEG's operations including new market entrants (e.g. construction by others of more efficient generation assets), retirements, and a participant's number of years and extent of operations in a particular energy market. PG&E NEG's Generation Business competes against a number of other participants in the merchant energy industry including Mirant, Calpine, Duke Energy, Reliant, AES, and NRG. Competitive factors relevant to this industry include financial resources, credit quality, development expertise, insight into market prices, conditions and regulatory factors, and community relations. PG&E NEG's competitors have greater financial resources than PG&E NEG does and have a lower cost of capital. When economic circumstance force fuel suppliers into bankruptcy, fuel supply contracts are at risk of being terminated, especially if the current market prices are substantially higher than the prices committed to in long-term contracts. Under such circumstances, PG&E NEG is at risk for having its power sales agreements and fuel supply agreements uncoupled. As states review the need for electric industry restructuring, there is a risk that current contracts are found to be too expensive and attempts may be made to abrogate such contracts. PG&E NEG's Pipeline Business competes with other pipeline companies for transportation customers on the basis of transportation rates, access to competitively priced gas supply and growing markets, and the quality and reliability of transportation services. The competitiveness of a pipeline's transportation services to any market is generally determined by the total delivered natural gas price from a particular natural gas supply basin to the market served by the pipeline. The cost of transportation on the pipeline is only one component of the total delivered cost. PG&E NEG's transportation service on the PG&E GTN pipeline accesses supplies of natural gas primarily from western Canada and serves markets in the Pacific Northwest, California and Nevada. PG&E NEG must compete with other pipelines for access to natural gas supplies in western Canada. PG&E NEG's major competitors for transportation services for western Canadian natural gas supplies include TransCanada Pipelines, Alliance Pipeline, Southern Crossing Pipeline and Northern Border Pipeline Company and Westcoast Energy Gas Transmission. The three markets PG&E NEG serves may access supplies from several competing basins in addition to supplies from western Canada. Historically, natural gas supplies from western Canada have been competitively priced on the PG&E GTN pipeline in relation to natural gas supplied from the other supply regions serving these markets. Supplies transported from western Canada on the PG&E GTN pipeline compete in the California market with Rocky Mountain natural gas supplies delivered by Kern River Gas Pipeline and Southwest natural gas supplies delivered by Transwestern Pipeline Company, El Paso Natural Gas and Southern Trails Pipeline. In the Pacific Northwest market, supplies transported from Western Canada on the PG&E GTN pipeline compete with Rocky Mountain gas supplies delivered by Northwest Pipeline Corporation and with British Columbia supplies delivered by Westcoast Transmission Company for redelivery by Northwest Pipeline Corporation. Transportation service on NBP provides access to natural gas supplies from both the Permian basin, located in western Texas and southeastern New Mexico, and the San Juan basin, primarily located in Northwestern New Mexico. The North Baja system delivers gas to Gasoducto Bajanorte Pipeline, at the Baja California—California border, which transports the gas to markets in northern Baja California, Mexico. While there are currently no direct competitors to deliver natural gas to NBP's downstream markets, the pipeline may compete with fuel oil which is an alternative to natural gas in the operation of some electric generation plants in the North Baja region. Moreover, NBP's market is near locations of interest for liquefied natural gas development companies who may be interested in delivering foreign natural gas supplies to the area. Overall, PG&E NEG's transportation volumes are also affected by other factors such as the availability and economic attractiveness of other energy sources. Hydroelectric generation, for example, may become available based on ample snowfall and displace demand for natural gas as a fuel for electric generation. Finally, in providing interruptible and short-term transportation service, PG&E NEG competes with release capacity offered by shippers holding firm contract capacity on PG&E NEG's pipelines. The Utility is the principal provider of electricity and natural gas distribution and transmission services in northern and central California. The Utility's service territory covers 70,000 square miles, serving 4.8 million electricity customers and 4.0 million natural gas customers.Ratemaking Mechanisms In setting the retail rates for the Utility's electric and natural gas utility services the CPUCcan be set, revenue requirements must first determines the Utility's revenue requirements.be determined. The components of revenue requirements for electricelectricity 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/20generation/generation, procurement and public purpose programs. The CPUC then allocates the revenueRevenue requirements among customer classes (mainly residential, commercial, industrial, and agricultural) and sets specific ratesare designed to produce the required revenue. The concept underpinning the determination of revenue requirements and rates is to allow a utility a fairan opportunity to recover its reasonable costs of providing adequate utility service,services, including a reasonablereturn of, and a fair rate of return of and on, its investment in utility facilities.facilities, or rate base. Revenue requirements are then allocated among customer classes and specific rates designed to produce the required revenue are established. In the Utility’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. If the Utility and the intervenors can settle these issues, these settlements are submitted to the regulatory agency for approval.General Rate Cases GRC.GRC, filed with the CPUC. In the GRC, the CPUC authorizes the Utility to collect from ratepayerscustomers an amount known as "base revenues"base revenues to recover basicbase business and operational costs for itsrelated to the Utility’s electricity and natural gas distribution and electricity generation operations. The general rate caseGRC typically sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in general rate caseGRC proceedings generally every three years based on a forecast of costs for the first, or "test"test, year. The Utility's pending general rate case request is for test year 2003. For the remaining two years of a general rate case period, the Utility has indicated that it intends to apply for annual increases in base revenues (known as attrition rate adjustments) to reflect inflation and increases in invested capital. After authorizing the revenue requirement,requirements, the CPUC allocates revenue requirements among customer classes (mainly residential, commercial, industrial and agricultural) and establishes specific rate levelslevels. Typical intervenors in separate proceedings.the Utility’s GRC include the ORA and TURN.Attrition Rate Adjustments Another majorThe CPUC proceedingmay authorize the Utility to receive annual increases for determiningthe years between GRCs in the base revenues authorized for the test year of a GRC to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is theauthorized to collect in rates for electricity and natural gas distribution and electricity generation operations.Cost of Capital Proceedings proceeding. Each year,proceeding to determine the CPUC determinesUtility’s authorized capital structure and the adoptedauthorized rate of return that the Utility may earn on its electricelectricity and natural gas distribution assets and recover from ratepayers. On November 7, 2002,electricity generation assets. The cost of capital proceeding establishes the percentage components that common equity, preferred equity and debt will represent in the Utility’s total authorized capital structure for a specific year. The CPUC issued a final decision that retainedthen establishes the Utility'sauthorized return on common equity, atpreferred equity and debt that the currentUtility will have the opportunity to collect in its authorized levelrates. For 2005, this proceeding also will set the authorized rate of 11.22%. This final decisionreturn for the Utility’s gas transportation and storage assets.Baseline Allowance increased the Utility's authorized cost of debt to 7.57%exempt from 7.26%, and heldcertain surcharges. Natural gas or electricity usage in place the current authorized capital structure of 48% common equity, 46.2% long-term debt, and 5.8% preferred equity. The final decision also holds open the proceeding to address the impact on the Utility's return on equity, costs of debt and preferred stock, and ratemaking capital structureexcess of the implementation and financing of a bankruptcy plan of reorganization. The return on the Utility's electric transmission-related assetsbaseline allowance is determinedcovered by the FERC. See "Electric Ratemaking" below. The return on the Utility's natural gas transmission and storage business was incorporated inhigher rates established in the Gas Accord. See "Gas Ratemaking" below.Electric Ratemakingthat increases with usage.DWR Electricity and DWR Revenue Requirements requireda consequence of the California energy crisis, on January 17, 2001, the Governor of California signed an order declaring an emergency and authorizing the DWR to purchase electricity to maintain the continuity of supply to retail customers. This was followed by AB 1890, electric rates for all1X, which authorized the DWR to purchase electricity and sell that electricity directly to the California investor-owned utilities’ retail end-user customers were frozen at the level in effect on June 10, 1996, and beginning January 1, 1998, rates for residential and small commercial customers were further reduced by 10%. In the first quarter of 2001, the CPUC authorizedto issue revenue bonds to finance electricity purchases. AB 1X also required the Utility to begin collecting energy surcharges totaling $0.04 per kWh (composed ofdeliver the electricity purchased by the DWR over the Utility’s distribution systems and to act as a $0.01 per kWh surcharge approved in Januarybilling and a $0.03 per kWh surcharge approved in March). Although the CPUC authorized the $0.03 per kWh surcharge in March 2001, the Utility did not begin collecting the revenues until June 2001. As a result, in May 2001, the CPUC authorized the Utility to collect an additional $0.005 per kWh surcharge revenue for 12 months to make upcollection agent for the time lag in collectionDWR, without taking title to DWR purchased electricity or reselling it to the Utility’s customers.$0.03 surcharge revenues. Although the collectionpurchase of this "half-cent surcharge" was originally scheduled to end on May 31, 2002, the CPUC issued a resolution ordering the Utility to continue collecting the half-cent surcharge until further consideration by the CPUC. The CPUC initially restricted the use of these surcharge revenues to pay for the Utility's "ongoing procurement costs" and "future power purchases." Under AB 1890, the rate freeze was supposed to end on the earlier of March 31, 2002, or when the Utility had recovered its eligible transition costs. Most transition costs must be recovered during a transition period that ends the earlier of December 31, 2001, or when the Utility had recovered its eligible transition costs. The Utility repeatedly has advised the CPUC that it had recovered all of its transitionelectricity, administrative costs and has asked the CPUC to recognize that the rate freeze already has ended for the Utility's customers. After the rate freeze, changes in the Utility's electriccertain other amounts associated with purchasing electricity through a revenue requirements in general will be reflected in rates. However, the CPUC has not yet determined that the rate freeze has ended for the Utility's customers. After the CPUC has determined when the Utility's rate freeze ended, the Utility expectsrequirement. AB 1X also authorizes the CPUC to set rates to recover:•Utility's approved utility cost components,•the cost of energy sold to customers, and•the DWR'sDWR’s revenue requirement allocated to the Utility's customers. The Utility refers to this structure as "bottoms-up" billing. At this time, the Utility does not know when or under what conditionsrequirements, but prohibits the CPUC will determine thatfrom increasing electricity rates for residential customers who use less electricity than 130% of their existing baseline quantities.Utility's rate freeze has endedDWR was prohibited after December 31, 2002 from entering into new electricity purchase contracts and from purchasing electricity on the Utility will begin bottoms-up billing orspot market. SB 1976, which became law in September 2002, required the CPUC to which periods these rates would apply.21 In April 2001,allocate electricity from existing DWR contracts among the customers of the California Public Utilities Code was amended to require thatinvestor-owned electric utilities, including the CPUC ensure that errors in estimates of demand elasticity or sales by the Utility do not result in material over or undercollections of costs by the Utility. The Utility intends to address implementation of this new law in connection with pending proceedings at the CPUC relating to recovery of components of its costs of service.Electric Distribution. 2003 General Rate Case.Utility’s customers. On November 8, 2002, the Utility filed its 2003 general rate case application requesting an increase in electric revenue requirements of $447 million over the current authorized amount of $2.269 billion to maintain current service levels to existing customers, and to adjust for wages and inflation. The Utility also indicated that it will seek an attrition rate adjustment increase for 2004 and 2005. The attrition rate adjustment mechanism is designed to avoid a reduction in earnings in years between general rate cases to reflect increases in rate base and expenses. The CPUC has ruled that the revenue requirements to be determined in the Utility's 2003 general rate case will be effective January 1, 2003, even though the CPUC will not issue a final decision on the 2003 GRC until after that date. The Utility cannot predict what amount of revenue requirements, if any, the CPUC will authorize for the 2003 through 2005 period. The administrative law judge presiding over the 2003 GRC has adopted a schedule for this proceeding that includes a target date of February 5, 2004. 2002 Attrition Rate Adjustment Request. In the 2003 GRC, the CPUC asked parties to comment on the Utility's need for a 2002 attrition rate adjustment. The Utility informed the CPUC in November 2001 that the Utility would need a 2002 attrition rate adjustment to recover escalating electric and gas distribution service costs. In April 2002, the CPUC issued a ruling authorizing any attrition rate adjustment that ultimately may be granted to become effective as of April 22, 2002. In June 2002, the Utility filed its application, requesting a $76.7 million increase to its annual electric distribution revenue requirement, and a $19.5 million increase to its annual gas distribution revenue requirement. In December 2002, the CPUC issued a proposed decision that would deny this request. The Utility filed comments in late December 2002 arguing that the proposed decision was based on a fundamental misunderstanding of the facts. In February 2003, the CPUC issued an alternate proposed decision granting a $63.5 million increase to the Utility's annual electric distribution revenue requirement, and a $10.3 million increase to the Utility's annual gas distribution revenue requirement. A final decision is expected to be issued in the first quarter of 2003. Baseline Allowance Increase. On April 9,September 19, 2002, the CPUC issued a decision allocating electricity from the DWR contracts to the customers of the three California investor-owned electric utilities. The DWR continues to be legally and financially responsible for these contracts. The electricity provided under 19 of the DWR contracts was allocated to the Utility’s customers. The Utility is responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with these contracts.DWR Allocated Contracts requiredelectricity is dispatched and delivered.increase baseline allowancesaccept an assignment of, or to assume legal or financial responsibility for, certain residential customers by May 1, 2002. An increase to a customer's baseline allowance increases the amount of their monthly usage that will be covered under the lowest possible rate and that is exempt from surcharges. The decision deferred consideration of corresponding rate changes until a later phaseDWR power purchase contracts unless each of the proceedingfollowing conditions has been met:• After assumption, the Utility’s issuer rating by Moody’s Investors Services will be no less than A2 and the Utility’s long-term issuer credit rating by Standard & Poors will be no less than A; • The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and • The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review. Procurement Resumption and Procurement Plans ordereddispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. The utilities also were required by SB 1976 to submit short-term and long-term procurement plans to the CPUC for approval. In December 2002, the CPUC adopted a 2003 short-term procurement plan for the Utility. The CPUC also authorized the California investor-owned electric utilities to extend their planning into the first quarter of 2004 and directed the Utility to hedge its 2004 first quarter residual net open position with transactions entered into in 2003.undercollectionsdifference between the recorded electricity procurement revenues and actual costs incurred under the Utility’s authorized procurement plans, excluding the costs associated with these baseline quantity changes inthe DWR allocated contracts and certain other items. The CPUC must review the revenues and costs associated with an interest-bearing balancing account. The Utility estimatesinvestor-owned utility’s electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate when the annual revenue shortfall to be approximately $96 million foraggregate over-collections or under-collections exceed 5% of the utility’s prior year electricity service, and $6 million for natural gas service. The total electricity revenue shortfall estimatedprocurement revenues,, excluding amounts collected for the period May through December 2002 was $70 million. In the second phase of the proceeding, the CPUC will consider issues involving demographic revisions to baseline allowances, a special allowance for well water pumping, revisions applicable to usage at vacation homes, and changes to baseline territories or seasons. The resolution of these issues could result in an additional revenue shortfall of approximately $102 million spread out over three to five years. Hearings on these issues concluded in September 2002 and a final CPUC decision is expected to be issued in early 2003. The Utility has charged the electricity revenue shortfall to earnings andDWR. These mandatory adjustments will continue to charge the shortfall to earnings. This charge reduces revenue available to recover the Utility's previously written-off undercollected power procurement costs and transition costs.Electric Transmissionuntil January 1, 2006.Electricity Transmission �� ElectricThe Utility’s electricity transmission revenues and bothits wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two sources of transmission revenues, those from charges under itsthe Utility’s transmission owner tariff or TO Tariff, and those from charges under specific contracts with existing wholesale transmission customers that pre-date the Utility'sUtility’s participation in the ISO. Customers that receive transmission services under suchthese pre-existing contracts, referred to as existing transmission contract customers, or ETC customers, are charged individualized rates based on the terms of their respective contracts. The Utility's ETC customers include various municipal utilitiesTransmission rates established by the FERC are included by the CPUC in the Utility’s retail electricity rates and state and federal agencies. These customers typically own and operate distribution systems that carry electricity to municipal, state or federal facilities, such as city halls, and the water pumps along the22California aqueduct. The Utility's municipal utility ETC customers distribute electricity to municipal facilities and, in many cases to the homes and businesses ofcollected from retail electricity customers located inside their municipality.receiving bundled service under the federal filed rate doctrine.Transmission Owner Rate Cases FERC'sFERC’s regulatory regime, the Utility is able to file a new base transmission rate case under the Utility's TO TariffUtility’s transmission owner tariff whenever the Utility deems it necessary to increase its rates.rates within certain guidelines set forth by the FERC. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.Utility's TO TariffUtility’s transmission owner tariff includes two rate components: (1) base• Base transmission rates, (from 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. itsthe Utility’s transmission revenues) which are intendedrevenue from base transmission rates.Transmission Control Agreement recovera Transmission Control Agreement, or TCA, with the Utility's operatingISO and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity and (2) the ratesother participating transmission owners. As a transmission owner, the Utility charges its TO Tariff customersis required to recover various billsgive two years notice and receive regulatory approval if it wishes to withdraw from the TCA. Under this agreement, the transmission owners, which also include Southern California Edison, or SCE, San Diego Gas & Electric Company and several municipal utilities, assign operational control of their electricity transmission systems to the ISO. In addition, as a party to the TCA, the Utility is responsible for a share of the costs of reliability must-run, or RMR, agreements between the ISO and owners of the power plants subject to RMR agreements, or RMR Plants. The Utility also is an owner of some of these RMR Plants for which the Utility receives revenue from the ISO. Under the RMR agreements, RMR Plants must remain available to generate electricity when needed for local transmission system reliability upon the ISO’s demand.reliability servicewhich the Utility could be obligated to pay the ISO an estimated $446 million in net costs andduring the ISO's transition charge associatedperiod January 1, 2004 to December 31, 2005. These costs are recoverable under applicable ratemaking mechanisms.ISO's high-voltage blended rate methodology. Transmission Owner Rate Cases. On January 29, 2003, the FERC approved a settlement filed by the Utility that allows the UtilityISO to recover $292 million on an annual basis from March 31, 1998 until October 29, 1998 and $316 million on an annual basis from October 30, 1998 until May 30, 1999 in TO Tariff electric transmission rates. During that period, somewhat higher rates were collected, subjectrefund to refund. As a result of the approval, the Utility will refund $30 million it had accrued for potential refunds related to the 14-month period ended May 30, 1999. In April 2000, the FERC approved a settlement that permitted the Utility to recover $329 million on an annual basis in TO Tariff electric transmission rates retroactively for the 10-month period from May 31, 1999 to March 31, 2000. In September 2000, the FERC approved another settlement that permitted the Utility to recover $352 million annually in TO Tariff electric transmission rates and made this retroactive to April 1, 2000. Further, in July 2001, the FERC approved another settlement that permits the Utility to collect $379 million annually in TO Tariff electric transmission rates retroactive to May 6, 2001. The transmission rates charged to TO Tariff customers are adjusted for other transmission revenue credits related to ISO congestion management charges and other transmission related services billed by the ISO, and remittedthe ISO to refund to the Utility, asexcess payments of approximately $340 million, including interest, for availability of Mirant’s RMR Plants under these agreements. However, on July 14, 2003, Mirant filed a transmission owner. On January 13,petition for reorganization under Chapter 11 and on December 15, 2003, the Utility filed claims in Mirant’s Chapter 11 proceeding including a claim for an application requesting to recover $545 million in electric retail transmission rates annually, a 44% increase over the revenue requirement currently in effect. The requested increase is mainly attributable to significant capital additions made to the Utility's system to accommodate load growth, to maintain the infrastructure, and to ensure safe and reliable service. In addition, the request includes a 15-year useful life for transmission plant coming into service in 2003 and a return on equity of 13.5%. The January 13 filing date will allow proposed rates to go into effect, subject to refund, no later than August 13, 2003.recovers certain ISO costs described below in balancing accounts. In general, for each of these types of costs,is unable to predict at this time when the difference betweenFERC will issue a final decision on this issue, what the ISO's actual charges and revenues collected by the UtilityFERC’s decision will be, and the forecasted costs willamount of any refunds, which may be used to either offset or increaseimpacted by Mirant’s Chapter 11 filing. It is uncertain how the specific revenue requirement for such costs for the next period when the Utility files an annual balancing account rate case related to such costs.resolution of this matter would be reflected in rates.Reliability Services Costs •Reliability Services Costs—must-run contractsmust run agreements and for locational out-of-market calls requiredto others to support reliability of the Utility’s transmission system. The costs of reliability must run agreements attributed to supporting the Utility’s historic transmission control area are charged to the Utility as a participating transmission owner. These costs were approximately $330 million in 2003. Under the Utility’s transmission owner tariff, the Utility charges its customers rates designed to recover these reliability service charges, without mark-up or service fees. The Utility records these customer charges as operating revenue, and records a corresponding expense under its cost of power line item to reflect the fact that the Utility must pass this revenue on to the ISO. Coststracks costs and revenues related to reliability services are tracked in the reliability services balancing account.•Transition Charges—Beginning on January 1, 2001, Periodically, the Utility pays the ISO's high-voltage blendedUtility’s electricity transmission rate which is higher than the Utility-specific high-voltage transmission rate. The difference between the ISO's rate and the Utility's rate is tracked in the Utility's transmission access charge balancing account and will be collected once frozen retail rates are changed by the CPUC. Grid Management Costs. The ISO also bills the Utility for grid management services attributableadjusted to refund over-collections to the Utility's ETCUtility’s customers or to collect any under-collections from customers. These grid management services costs are passed on to the Utility's ETC customers through the Grid Management Charge Tariff. The Utility records grid management costs billed byTransmission Access Charge in operating and maintenance expenses and passes these costs to its ETC customers, without mark-up or service fees, subject to refund pending the outcome of the FERC ratemaking review process expected to take place in the first half of 2003. Scheduling Coordinator Costs. The Utility serves as the scheduling coordinator to schedule transmissionfiled an application with the ISO for its ETC customers. The ISO bills the Utility for providing certain services associated with these23contracts. These ISO charges are referred to as the "scheduling coordinator costs." These costs historically have been tracked in the transmission revenue balancing account, or TRBA, in order to recover these costs from its TO Tariff customers. In 2002, the FERC ruled that the Utility should refund to TO Tariff customers the scheduling coordinator costs that the Utility collected from them. As of December 31, 2002, TO Tariff customers had already paid the Utility $107 million for these costs. In January 2000, the FERC accepted a filing by the Utility to establish a separate tariff to allow the Utility to recover both the shortfall and future scheduling coordinator costs from its ETC customers. The FERC has authorized the separate tariff, subject to refund, which has been challenged by ETC customers. For the period beginning April 1998 through December 31, 2002, the Utility transferred $107 million of scheduling coordinator costs from the TRBA to accounts receivable net of a $66 million reserve for potential uncollectible costs. The Utility also has disputed approximately $27 million of these costs as incorrectly billed by the ISO.Electric Generation The CPUC has approved a 2002 revenue requirement of $3 billion for recovery of costs of generation that the Utility retains, including purchased power expenses, depreciation, operating expenses, taxes, and return on investment, based on the net regulatory value of generation assets as of December 31, 2000. The Utility's retained generation costs incurred in 2002 are subject to reasonableness review. A pending proposal by The Utility Reform Network, or TURN, a non-profit organization representing small utility customers, would continue this treatment. Before 2002, these costs have been forecast as with other costs in the general rate case, with rates set to recover the forecast, regardless of actual cost. The Utility's 2003 revenue requirement for retained generation is being considered in the Utility's 2003 general rate case proceeding. The Utility's 2003 general rate case application, as updated on February 20, 2003, requested an increase in non-fuel generation revenue requirements of $149 million from $872 million, the amount currently authorized. This requested revenue requirement excludes the Utility's estimated fuel and procurement costs recorded in the Energy Resource Recovery Account, or ERRA, and the DWR's power charges.Electric Procurement 2001 Annual Transition Cost Proceeding: Review of Reasonableness of Electric Procurement. On January 11, 2002, as directed by the CPUC, the Utility filed a report at the CPUC detailing the reasonableness of the Utility's electric procurement and generation scheduling and dispatch activities for the period July 1, 2000 through June 30, 2001. In this proceeding, the CPUC will review the reasonableness of the Utility's procurement of wholesale electricity from the PX and the ISO during the height of the 2000-2001 California energy crisis. With the exception of a limited right to purchase electricity from third parties beginning in August 2000, all of the Utility's wholesale power purchases during this period were required to be made exclusively from or through the PX and ISO markets pursuant to FERC-approved tariffs. Prior CPUC decisions have determined that such purchases should be deemed reasonable. In addition, the Utility's complaint against the CPUC Commissioners asserts that the costs of such purchases are recoverable in the Utility's retail rates without further review by the CPUC under the federal filed rate doctrine. However, an administrative law judge of the CPUC is asserting jurisdiction to review the reasonableness of the Utility's wholesale electricity purchases from the PX and ISO in the proceeding. A report from the CPUC's Office of Ratepayer Advocates regarding the Utility's procurement activities for the covered period is due April 28, 2003. It is possible that this proceeding could result in some disallowance of the Utility's costs incurred during the 2000-2001 period associated with its purchases from the PX and ISO markets. Energy Resource Recovery Account, or ERRA. As of January 1, 2003, the California IOUs have resumed procuring electricity to meet the amount of their customers' electricity needs that cannot be met with utility-owned generation, electricity supplied under QF and other contracts, and electricity allocated to their customers under the DWR contracts. Effective January 1, 2003, the Utility established the Energy Resource Recovery Account, or ERRA, to record and recover electricity costs, excluding the DWR's power contract costs, associated with the Utility's authorized procurement plan. Electricity costs recorded in ERRA include, but are not limited to, fuel costs for retained generation, QF contracts, inter-utility contracts, ISO charges, irrigation district contracts and other power purchase agreements, bilateral contracts, forward hedges, pre-payments and collateral requirements associated with procurement (including disposition of surplus electricity), and ancillary services. The Utility offsets these costs by reliability-must-run revenues, the Utility's allocation of surplus sales revenues and the ERRA revenue requirement. The CPUC has authorized the Utility to file an expedited trigger application at any time that its forecast indicates the undercollection in the ERRA will be in excess of 5% of the Utility's recorded generation revenues for the prior year excluding amounts collected for the DWR. The Utility currently estimates that its 5% threshold amount will be24approximately $224 million. When filing an expedited trigger application, the CPUC has directed the Utility to propose an amortization period of not less than 90 days for the undercollected amount to insure timely recovery. The CPUC has approved, on a preliminary basis, a starting ERRA revenue requirement of $2.035 billion for the Utility. On February 3, 2003, the Utility filed its 2003 ERRA forecast application requesting that the CPUC reset the Utility's 2003 ERRA revenue requirement to $1.413 billion and that the ERRA trigger threshold of $224 million be adopted. The CPUC will examine the Utility's forecast of costs for 2003 and will finalize the Utility's starting ERRA revenue requirement and ERRA trigger threshold when it reviews the Utility's ERRA application. Qualifying Facilities and Other Existing Bilateral Agreements. Costs of the Utility's existing contracts with qualifying facilities and other electricity providers are passed through to ratepayers dollar for dollar as approved by the CPUC in the retained generation ratemaking proceeding for 2002 and generation procurement proceeding for 2003. See "Electric Generation" and "Electric Resource Recovery Account" discussions, above. Direct Access. To avoid a shift of costs from direct access customers to bundled customers, the CPUC has established a direct access cost responsibility surcharge, or CRS, to implement utility-specified non-bypassable charges on direct access customers for their share of the bond costs and power costs incurred by the DWR and above-market cost related to the Utility's own generation resources and power contracts. The decision establishes four components comprising the CRS:• DWR Bond Charge. This charge is applicable to all direct access customers, except customers who were on direct access before the DWR began purchasing power and have continued to remain on direct access since the DWR began purchasing power (continuous direct access customers). The bond charge for direct access customers will include amounts accruing since November 15, 2002. The actual amount of this charge on direct access customers is being determined in the DWR bond charge allocation proceeding.• DWR Electricity Charge for the September 21, 2001, through December 31, 2002 Period. This charge is applicable to direct access customers who previously took bundled service at any time on or after February 1, 2001. The charge is designed to recover direct access customers' share of the DWR's procurement costs between September 21, 2001, and December 31, 2002. Since bundled customers already have paid this amount to the DWR, these charges collected from direct access customers would reduce the amount of bundled customers' bills remitted to the DWR.• DWR Electricity Charge for Future DWR Costs. This charge is applicable to direct access customers who previously took bundled service at any time on or after February 1, 2001. This charge is designed to recover direct access customers' share of the uneconomic portion of the DWR's procurement costs for 2003 and thereafter. This charge will be adjusted on an annual basis or more frequently if the DWR's revenue requirement is adjusted more frequently.• The Utility's Procurement and Generation Charge. This charge is applicable to all direct access customers regardless of the date on which a customer switched to direct access. This charge is designed to recover direct access customers' share of the ongoing uneconomic portion of the Utility's generation and procurement costs. This charge will be based on an estimate of above-market costs for the Utility's procurement contracts and qualifying facility arrangements, which in turn is based on a $0.043 per kWh benchmark for 2003. This benchmark for determining above-market costs will be updated annually. The decision imposes a cap on the CRS of $0.027 cents per kWh which was implemented on January 1, 2003. The CPUC has indicated that it will establish an expedited review schedule to determine whether the cap should be adjusted and has set a goal of reaching a decision on whether this cap should be adjusted, and whether trigger mechanisms for adjusting the cap would be established, by July 1, 2003.25 Funds remitted under the CRS will be applied first to the DWR bond charges, second to the DWR electricity charges, and third to the Utility's ongoing procurement and generation costs. Direct access customers who have returned to bundled service will be responsible for their share of the unrecovered costs resulting from the CRS. To the extent the cap results in an undercollection of DWR charges, the shortfall would have to be remitted to DWR from bundled customers' funds. Interest on undercollections will be assessed at the DWR's bond interest rate on an interim basis while the CPUC examines a long-term plan for financing the CRS. The Utility does not expect that the CPUC's implementation of this decision or the level of the CRS cap will have a material adverse effect on its results of operations or financial condition. DWR Revenue Requirements, Servicing Order and Operating Order. The CPUC has adopted rates for the DWR that allow the DWR to collect electricity and bond-related charges from ratepayers to recover what it spent to procure electricity for the customers of the California IOUs during 2001 and 2002. The recovery is being financed partially through a statewide revenue requirement allocated among the three California IOUs and partially through the DWR's November 2002 issuance of $11.3 billion in revenue bonds, which will be repaid by the customers of the three California IOUs through the bond charge discussed below. In February 2002, the CPUC approved a decision that set the statewide DWR revenue requirement for 2001 and 2002. In March 2002, the CPUC reallocated the amounts contained in the February 2002 decision among the customers of the three California IOUs. The March 2002 decision allocated $4.4 billion of a total statewide power charge revenue requirement of approximately $9.0 billion to the Utility's customers. Of the $4.4 billion allocated to the customers of the Utility, approximately $2.6 billion related to 2001 power charges and approximately $1.8 billion related to 2002 power charges. In December 2002, the CPUC issued a decision allocating approximately $2 billion of the DWR's 2003 power charge-related revenue requirements to the Utility's customers. This revenue requirement includes the variable costs of the DWR contracts allocated to the Utility's customers by an earlier decision in September 2002. The DWR plans to submit a revised 2003 power charge-related revenue requirement to the CPUC in late March 2003. A separate proceeding will consider a revision or true-up for the revenue requirements remitted to the DWR for 2001 and 2002 costs, once final 2002 cost data is available. This true-up proceeding is scheduled for April 2003. Before the DWR's 2003 statewide revenue requirement filing with the CPUC in August 2002, the Utility filed comments with the DWR alleging that major portions of the DWR's revenue requirements were not "just and reasonable" as required by AB 1X and that the DWR was not complying with the procedural requirements of AB 1X in making its determination. On August 26, 2002, the Utility filed with the DWR a motion for reconsideration of the DWR's determination that its revenue requirements were "just and reasonable." The DWR denied the Utility's motion on October 8, 2002. On October 17, 2002, the Utility filed a lawsuit in a California court asking the court to find that the DWR's revenue requirements had not been demonstrated to be "just and reasonable" and lawful, and that the DWR had violated the procedural requirements of AB 1X in making its determination. In part, the Utility based its allegations on the State of California's petition pending before the FERC seeking to set aside many of the DWR contractsestablish its own transmission access charge as directed by AB 1890. The ISO’s transmission access charge methodology provides for transition to a uniform statewide high-voltage transmission rate, based on the basis that they are not "just and reasonable." The Utility asked that the court order that the DWR's revenue requirement determination be withdrawn as invalid, and that the DWR be precluded from imposing its revenue requirements onof all participating transmission owners associated with facilities operated at 200 kV and above. The transmission access charge methodology also requires the Utility and its customers until it has complied withother transmission owners, during a ten-year transition period, to pay a charge intended to reimburse other transmission owners (who are generally new ISO participants) whose costs are higher than that embedded in the law. No schedule has yet been setuniform rate. Under the ISO’s application, the Utility’s obligation for consideration ofthis cost differential would be capped at $32 million per year during the lawsuit.ten-year transition period. A hearing in this matter was conducted at the FERC in October and November 2003 and an initial decision from the presiding administrative law judge is scheduled to be issued in March 2004.Natural Gas The Gas Accord May 2002,1998, the Utility implemented a ratemaking pact called the Gas Accord, 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 gas storage rates. On December 18, 2003, the CPUC approved a servicing order between the UtilityUtility’s application to retain the Gas Accord market structure for 2004 and 2005, and resolved the DWR which sets forth therates, and terms and conditions under which the Utility provides the transmission and distribution of the DWR-purchased electricity; addresses billing, collection and related services performed on behalf of the DWR; and addresses the DWR's compensation to the Utility for providing these services. In October 2002, the DWR filed a proposed amendment to the CPUC's May 2002 servicing order. The DWR's proposed amendment changes the calculation that determines the amount of revenues that the Utility must pass through to the DWR. This proposed amendment would also be used to true up previous amounts passed through to the DWR as well as future payments. Under its statutory authority, the DWR may request the CPUC to order the utilities to implement such amendments, and the CPUC has approved such amendments in the past without significant change. In December 2002, the CPUC approved an operating order requiring the Utility to perform the operational, dispatch, and administrative functionsservice for the DWR's allocated contracts beginning on January 1, 2003.Utility’s natural gas transportation and storage system for 2004. The operating order, which applies prospectively, includes the DWR's proposed methodUtility continues to be at risk of calculating the amount of revenues that the Utility must pass through to the DWR. As a result, as of December 31, 2002, the Utility has accrued an additional $369 million (pre-tax) liability for pass-through revenues for electricity provided by the DWR to the Utility's customers in 2001not recovering its natural gas transportation and 2002. In December 2002, the CPUC adopted an operating order requiring the Utility to perform the operational, dispatch,storage costs and administrative functions for the DWR's allocated contracts beginning on January 1, 2003. (Similar operating orders were also adopted for the other two California IOUs.) The operating order sets forth the terms26and conditions under which the Utility will administer the DWR allocated contracts and requires the Utility to dispatch all the generating assets within its portfolio on a least-cost basis for the benefit of the Utility's customers. The order specifies that the DWR will retain legal and financial responsibility for the DWR allocated contracts and that the order does not result in an assignmenthave regulatory balancing account protection for over-collections or under-collections of the allocated DWR contracts to the Utility. The CPUC had previously ordered the IOUs to work with the DWR to submit to the CPUC proposed operating agreements governing the DWR allocated contracts. When the operating orders were issued, the DWR and the IOUs had not yet finalized their separate operating agreements. In its decision issuing the operating order, the CPUC noted that if the IOUs and the DWR eventually reach mutual agreement, the CPUC would consider modifying its decision on an expedited basis to terminate the operating orders and approve the operating agreements, assuming that the operating agreements adopted a framework that was substantially similar to the one imposed by the operating orders. On December 20, 2002, the Utility and the DWR executed an operating agreement following several months of negotiation. The agreement provides that it will not become effective unless approved by the CPUC. The Utility has submitted the agreement to the CPUC for approval and has requested that the CPUC terminate the operating order and approve the operating agreement. Although the operating order and the operating agreement have fundamentally the same objectives, the operating agreement, among other things:• provides an adequate contractual basis for establishing a limited agency relationship between the Utility and the DWR;• limits the Utility's contractual liability to the DWR and other parties to $5 million per year plus 10 percent of damages in excess of $5 million with a limit of $50 million over the term of the agreement; and• clarifies that the DWR does not intend to review, nor is it responsible for a review of the Utility's least-cost dispatch performance, other than to verify compliance with the supplier contracts. On December 30, 2002, the Utility filed an application for rehearing of the operating order decision with the CPUC. On January 1, 2003, after having reserved all rights associated with challenges to the operating order, the Utility commenced providing contract administration, scheduling and dispatch services to the DWR under the CPUC's operating order. DWR Bond Charges. On October 24, 2002, the CPUC approved a decision that, in part, imposes bond charges to recover the DWR's bond costs from most bundled customers effective November 15, 2002, although the decision found that the Utility would not need to increase customers' overall rates to incorporate the bond charge. The DWR bond charge also will be imposed on all direct access customers, as described above. On December 30, 2002, the CPUC adopted a 2003 bond charge of $0.005 per kWh to start January 6, 2003. The Utility expects to accrue DWR bond-related charges of approximately $336 million during the 12 months ended November 14, 2003. Until the CPUC implements bottoms-up billing (billing for specific rate components) for the Utility, any bond charges will reduce the amount of revenue available to recover previously written-off undercollected purchase power costs and transition costs.Gas RatemakingNatural Gas Distribution The Utility's 2003 general rate case, or GRC, application requested an increase in natural gas distribution revenue requirements of $105 million over the currently authorized amount of $894 million, to maintain current service levels to existing customers, and to adjust for wages and inflation. The Utility also indicated that it will seek an attrition rate adjustment increase for 2004 and 2005. The attrition rate adjustment mechanism is designed to avoid a reduction in earnings in years between general rate cases to reflect increases in rate base and expenses. The CPUC has ruled that the revenue requirements to be determined in the Utility's 2003 general rate case will be effective January 1, 2003, even though the CPUC will not issue a final decision on the 2003 GRC until after that date. The Utility cannot predict what amount of revenue requirements, if any, the CPUC will authorize for the 2003 through 2005 period, nor when such decision will be made.transportation or storage revenues.Biennial Cost Allocation Proceeding GasThe Utility’s natural gas distribution costs and balancing account balances are allocated to customers in the Biennial Cost Allocation Proceeding, or BCAP. The BCAPProceeding. This proceeding normally occurs every two years and is updated in the interim year for27amortizingadjusting natural gas rates to recover from customers any accumulationunder-collection, or refund to customers any overcollection, in the balancing accounts. Balancing accounts for gas distribution and public purpose program revenue requirements accumulate differences between authorized revenue requirements and actual base revenues. In April 2000,Natural Gas Procurement filed its 2000 BCAP application to covertypically purchases natural gas. Costs that fall within a tolerance band, which is currently between 99% and 102% of the period January 1, 2000 through December 31, 2002, requesting a decreasebenchmark, are considered reasonable and 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. Any awards associated with the CPIM are reflected annually in the purchased natural gas balancing account after the close of the annual base revenue requirement of $132 million comparedperiod ending October 31 that is used to measure the authorized revenue requirement of $941 million atCPIM. These awards are not included in earnings until approved by the time the application was filed. CPUC.November 8, 2001,January 22, 2004, the CPUC issuedopened a decision approving the Utility's BCAP settlement filedrulemaking proceeding to establish policies and rules to ensure reliable, long-term supplies of natural gas to California. The order poses a series of questions and requires all gas utilities in October 2000. The decision adopted a decrease in annual base revenue requirements of $113 million, effective January 1, 2002. The adopted BCAP rates were implemented on January 1, 2002. At the end of 2002, the Utility filed an annual true-up of balancing accountsCalifornia to provide information related to their natural gas procurement activities and their transportation and storage facilities. Among other gas transportation rate changes that went into effect January 1, 2003. This filing increased core and noncore transportation rates and revenue requirements by $103 million resulting from the annual true-up, changes authorized in the second year of the BCAP, an increase in the 2002 California Alternate Rates for Energy administration budget, the adopted 2003 cost of capital, an increase in the low income energy efficiency program budget for 2003, the increase inthings, the CPUC reimbursement account fee, and the extensionindicated that it may adopt rules whereby utilities could receive CPUC pre-approval of the Gas Accord.Natural Gas Transportation and Storagecontracts for interstate pipeline capacity to support their natural gas procurement activities.Interstate and Canadian Natural Gas Transportation and Storage Utility'sUtility’s interstate and Canadian natural gas transportation agreements with third party service providers are governed by tariffs whichthat detail rates, rules and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. TheseUnited States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process and the applicable Canadian tariffs by the Alberta Energy and Utilities Board and the National Energy Board forBoard. The Utility’s agreements with interstate and Canadian tariffs. Since March 1998, the natural gas transportation and storage services that the Utility has obtained over its owned pipelines have been governed by the rates, terms and conditions approved by the CPUC in the Gas Accord and Gas Accord II settlement agreements through 2003, or, together, the Gas Accord. The Gas Accord separated, or "unbundled," the Utility's natural gas transportation and storage services from its distribution services, changed the terms of service and rate structure for natural gas transportation and storage services, fixed natural gas transportation and storage rates and allowed core customers to purchase natural gas from competing suppliers. On January 13, 2003, the Utility filed an amended Gas Accord II application with the CPUC proposing to permanently retain the Gas Accord market structure, and requesting a $55 million increase in the Utility's rates for gas transmission and storage for 2004, or in the case of certain storage provisions from April 1, 2004, to March 31, 2005. Under the Gas Accord, the Utility is at risk for recovery of its gas transportation and storage costs, and does not have regulatory balancing account protection for over- or undercollections of revenues. Under the Gas Accord, the Utility sells a portionproviders are administered as part of the transportation and storage capacity at competitive market-based rates. Revenues are sensitive to changes in the weather, natural gas fired generation and price spreads between two delivery or pricing points. The existing gas transportation and storage rates will continue until the CPUC approves such changes. The Gas Accord II proposal includes rates set based on a demand or throughput forecast basis. In addition it proposes that, at the beginning of the adopted Gas Accord II agreement period, a contract extension and an open season be held for any uncontracted capacity rights. If the Utility were unable to renew or replace existing transportation contracts at the beginning or throughout the Gas Accord II period, or the Utility were to renew or replace those contracts on less favorable terms than adopted by the CPUC, or if overall demand for transportation and storage services were less than adopted by the CPUC in setting rates, the Utility may experience a material reduction in operating revenues. In either case, the Utility's financial condition and results of operations could be adversely affected.Natural Gas Procurement The Gas Accord also established the core procurement incentive mechanism, or CPIM, which is used to determine the reasonableness of the Utility's cost of procuring natural gas for the Utility's customers. The Gas Accord II settlement agreement extended the CPIM for one year. Under the CPIM, the Utility's procurement costs are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas prices at the locations where the Utility typically purchases natural gas. If costs fall within a range, or tolerance band currently 99% to 102%, around the benchmark, they are considered reasonable and fully recoverable in customer rates. Ratepayers and shareholders share costs and savings outside the tolerance band.28 The Utility sets theUtility’s core natural gas procurement rate monthly based onbusiness. Their purpose is toforecasted costspoints at which the Utility takes delivery of natural gas — typically in Canada and corethe southwestern United States — to the points at which the Utility’s natural gas transportation system begins.Capacity Purchases on El Paso and Transwestern Pipelines and storage costs. The Utility reflectsto gain firm access to the difference between actualsouthwest natural gas procurement costs and forecasted natural gas procurement costs in several gas procurement balancing accounts, with under-and overcollections taken into account in subsequent monthly rates. Any awards associated with the CPIM normally are reflected annually in the purchased natural gas balancing account after the close of the CPIM period, which is the 12-month period ending October 31. These awards are not included in earnings until approval by the CPUC. On December 17, 2002, the CPUC's Office of Ratepayer Advocates submitted its report agreeing with the Utility's CPIM performance for the period November 2000 through October 2001. The Utility requested that the CPUC approve a shareholder award of $7.7 million to be effective February 1, 2003.producing basins. The CPUC has not acted onbelieved that if the Utility's request. In accordance withutilities had firm access rights, they would have been able to mitigate the Gas Accord,gas price spikes that occurred during the Utility stopped providing procurement service to noncore customers in March 2001. Duringenergy crisis when shippers raised the winterprice of 2000/2001 when there was a steep increase in gas commodity prices, many noncore customers switched to core service in order to receive procurement service fromat the Utility. InCalifornia border. The CPUC pre-approved the costs of these contracts as just and reasonable. Since the July 2002 the Utility filed a request with the CPUC to limit the number of noncore customers that could switch to core service because the Utility was concerned that large increases in its gas supply portfolio demand 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. Consistent with rules adopted for southern California gas utilities in 2002,decision, the Utility has requested that electric generation, cogeneration, enhanced oil recovery and refinery customers be prohibited from electing core service and that remaining noncore customers elect core servicesigned contracts for a minimum five-year term. On June 27, 2002, the CPUC opened a proceeding in response to a FERC order authorizing marketers in California to turn back up to 725 million cubic feet per day of firm capacity on the El Paso Pipeline Company, or El Paso, interstate pipeline. The first phase of the proceeding dealt with rulespipeline costing approximately $50.8 million for the majorperiod from November 2002 to December 2007. The July 2002 decision also ordered the California investor-owned electric utilities to obtain El Paso turned-backretain their then-current interstate pipeline capacity not subscribedlevels and sell any excess capacity to by otherthird parties under short-term capacity release arrangements. It also ordered that, to the extent the California replacement shippers. On July 17, 2002,investor-owned electric utilities comply with the CPUC ordered utilitiesdecision, they will be able to obtain such capacity, and stated that if the utilities complied with this order that they would also receive full recovery forfully recover their costs associated with existing capacity rights on interstate pipelines.contracts.obtained 204 MDth/daypays approximately $22 million in annual reservation charges under the Transwestern contract. The Gas Accord provided for partial recovery of capacity on El Paso in compliance withTranswestern costs after 1997. In January 2004, the CPUC decision. On December 19, 2002, the CPUC foundapproved a settlement with TURN that the Utility had met the objectives, terms and conditions set forth in the CPUC's July 17, 2002 order. The CPUC authorizedallows the Utility to fully recover all costs associated with the subscription to El Paso pipeline capacity on an equal-cents-per-therm basis from core and noncore customers, subject to reallocation in a later phase of the proceeding. The Utility filed core and noncore transportation rates proposed to be effective March 2003 to recover $47.1 million of annual El Paso costs and costs previously incurred through December 2002. The CPUC also ordered the Utility to continue to treat Transwestern pipeline charges and brokering credits under its core procurement incentive mechanism, or CPIM. The Transwestern costs not currently authorized under the CPIM will be addressed in the second phase of this proceeding. On February 7, 2003, the Utility filed its proposal requesting full recovery of the Transwestern costs and El Paso turned back capacity costs from core customers and inclusion of these costs in its CPIM.retroactive to July 2003.Public Purpose Programs The Utility continues to administer and/or fund several state-mandated public purpose programs. In December 2002, the CPUC authorizedgranted the Utility to fund electric energy efficiency, low-income energy efficiency, research and development, and renewable energy resources programs in the amount of $232 million. The costs will be recovered in electric rates following the rate design phase of the Utility's 2003 general rate case. The CPUC also has authorized the Utility to collect $46 million in gas rates to fund gas energy efficiency, low-income energy efficiency, and research and development programs. The Utility also provides the California Alternate Rates for Energy, or CARE, low-income discount rate, a rate subsidy paid for by the Utility's other customers, which is currently about $107 million per year. The CPUC is responsible for authorizing the programs, funding levels, and cost recovery mechanisms for the Utility's operation of both the cost-effective energy efficiency and low-income energy efficiency programs. The CEC administers both the electric public interest research and development program and the renewable energy program on a statewide basis. In 2002, the Utility transferred $99 million to the CEC for these two programs. Until 2002, the Utility was eligible to receive incentives for administering the energy efficiency program activities. The Utility files an annual earnings claim each year in the annual earnings assessment proceeding, which is the forum for stakeholders to comment on and for the CPUC to evaluate the Utility's claim. Earned incentives can be collected over as long as a 10-year period. In 2002, the CPUC eliminated the opportunity for the IOUs to29earn incentives on their 2002 energy efficiency programs, replacing it with a mechanism keeping up to 15% of the energy efficiency expenditures subject to refund if the programs unreasonably miss targets or expenditures are unreasonably high. The CPUC has also declined to allow the IOUs the opportunity to earn incentives on the 2003 energy efficiency programs. This decision does not affect the mechanismUtility’s request to recover incentives in connection with energy efficiency programs for previous years. In May 2000, 2001, and 2002, the Utility filed its annual applications claiming incentives totaling to approximately $106 million. In early 2002, the CPUC requested and received briefs on whether the incentive mechanism giving rise to $74 million of the $106 million should be modified to reduce the earnings potential. The CPUC has not yet acted on any of these applications or ruled on the incentive mechanism issue, but has scheduled a prehearing conference to begin the process for addressing the claims. In October 2002, the CPUC opened a rulemaking to implement the nonbypassable gas public purpose program surcharge mandated by state legislation in 2001. The legislation requires all California gas users, even those users who are not utility customers, to fund public purpose energy efficiency, low-income energy efficiency, research and development, and CARE rate subsidies for qualifying low-income utility customers. The funds are collected by a surcharge on gas consumption, with utilities, many non-utility customers, and interstate pipelines remitting the surcharge revenues to the State Board of Equalization. These funds are allocated to the gas public purpose programs by the CPUC. The CPUC rulemaking proceeding will formalize the processes for administering the gas consumption surcharge as well as identifying appropriate programs and funding levels for public purpose gas research and development programs.ELECTRIC UTILITY OPERATIONSElectric Distribution The Utility's electric distribution network extends throughout all or a portion of 47 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of approximately 117,955 circuit miles of distribution lines (of which approximately 20% are underground and 80% are overhead) and 730 distribution substations. The Utility's distribution network connects to an electric transmission system at approximately 975 points of contact. This contact 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 electric transmission system transmits electricity, ranging from 60 kilovolts to 500 kilovolts, or kV, to lower voltages, ranging from 4 kV to less than 60 kV, suitable for distribution to customers. The distribution substations serve as the central hubs of the distribution system 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 which link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or facilities to entities such as municipal and other utilities that then resell the electricity. In certain cases, the distribution system is directly connected to generation facilities.Electric Distribution Operating Statistics In 2002, the Utility's electric distribution business delivered a total of approximately 78,230 gigawatt-hours, or GWh, of electricity to approximately 4.8 million electric distribution customers in our service territory, including 21,031 GWh purchased by the DWR and 7,433 GWh provided by direct access service providers.30 The following table shows the Utility's operating statistics (excluding subsidiaries) for electric energy sold or delivered, including the classification of sales and revenues by type of service. 2002 2001 2000 1999 1998 Customers (average for the year): Residential 4,171,365 4,165,073 4,071,794 4,017,428 3,962,318 Commercial 483,946 484,430 471,080 474,710 469,136 Industrial 1,249 1,368 1,300 1,151 1,093 Agricultural 78,738 81,375 78,439 85,131 85,429 Public street and highway lighting 24,119 23,913 23,339 20,806 18,351 Other electric utilities 5 5 8 — 14 Total 4,759,422 4,756,164 4,645,960 4,599,226 4,536,341 Deliveries (in GWh): Residential 27,435 26,840 28,753 27,739 26,846 Commercial 31,328 30,780 31,761 30,426 28,839 Industrial(1) 14,729 16,001 16,899 16,722 16,327 Agricultural(1) 4,000 4,093 3,818 3,739 3,069 Public street and highway lighting 674 418 426 437 445 Other electric utilities 64 241 266 167 2,358 California Department of Water Resources Allocation (2001 and 2002 only) (21,031 ) (28,640 ) Total energy delivered(2) 57,199 49,733 81,923 79,230 77,884 Revenues (in thousands): Residential(3) $ 3,641,582 $ 3,364,466 $ 3,007,675 $ 2,961,788 $ 2,891,424 Commercial(3) 4,468,465 3,925,218 2,693,316 2,837,111 2,793,336 Industrial(3) 1,275,033 1,312,280 509,486 863,951 933,316 Agricultural(3) 531,983 520,855 385,961 391,876 350,445 Public street and highway lighting 73,423 59,875 43,403 49,209 51,195 Other electric utilities 10,028 39,420 26,269 16,501 50,166 Subtotal 10,000,514 9,222,114 6,666,110 7,120,436 7,069,882 California Department of Water Resources pass-through revenues (2,056,037 ) (2,172,666 ) — — — Miscellaneous 193,519 240,276 194,947 162,105 161,156 Regulatory balancing accounts 39,578 36,494 (6,765 ) (50,780 ) (40,408 ) Total electricity operating revenues $ 8,177,574 $ 7,326,217 $ 6,854,292 $ 7,231,761 $ 7,190,630 2002 2001 2000 1999 1998 Other Data: Average annual residential usage (kWh) 6,577 6,463 7,062 6,905 6,776 Average billed revenues (cents per kWh): Residential 13.27 12.50 10.46 10.68 10.77 Commercial 14.26 12.68 8.48 9.32 9.69 Industrial(1) 8.66 7.78 3.02 5.17 5.72 Agricultural(1) 13.30 12.55 10.11 10.48 11.42 Net plant investment per customer ($) 2,105 2,018 1,969 2,388 2,705 (1)The deliveries per kWh and average billed revenues per kWh include electricity provided to direct access customers who procure their own supplies of electricity.(2)Of the 78,230 GWh the Utility delivered in 2002, 49,766 GWh were procured or generated by the Utility (excluding energy loss and net deliveries to the Western Area Power Administration), 7,433 GWh were procured by direct access service providers and 21,031 GWh were procured by the DWR. Of the 78,373 GWh the Utility delivered in 2001, 45,751 GWh were procured or generated by the Utility (excluding energy loss and net deliveries to the Western Area Power Administration), 3,982 GWh were procured by the Utility's direct access customers and delivered by the Utility and 28,640 GWh were procured by the DWR and delivered by the Utility.(3)Revenues include direct access revenues, but exclude direct access credits.31Electric Resources The Utility's sources of electricity delivered to customers during 2002 were as follows: 11.31% from the Utility's hydroelectric assets, 19.60% from the Utility's nuclear facilities at Diablo Canyon, 1.02% from the Utility's fossil-fuel fired plants, 33.86% from QFs and other power suppliers, and 25.28% from power procured on behalf of customers by the DWR and 8.93% from power procured by direct access service providers.Retained Generation At December 31, 2002, the Utility's generation facilities, consisting primarily of hydroelectric and nuclear generating plants, had an aggregate net operating capacity of 6,420 megawatts, or MW. Except as otherwise noted below, at December 31, 2002, the Utility owned and operated the following generating plants, all located in California, listed by energy source:Generation Type County Location Number
of Units Net
Operating
Capacity kWHydroelectric: Conventional Plants 16 counties in northern and central California 107 2,684,200 Helms Pumped Storage Plant Fresno 3 1,212,000 Hydroelectric Subtotal 110 3,896,200 Steam Plants: Humboldt Bay Humboldt 2 105,000 Hunters Point(1) San Francisco 1 163,000 Steam Subtotal 3 268,000 Combustion Turbines: Hunters Point(1) San Francisco 1 52,000 Mobile Turbines(2) Humboldt 2 30,000 Combustion Turbines Subtotal 3 82,000 Nuclear: Diablo Canyon San Luis Obispo 2 2,174,000 Total 118 6,420,200 (1)In July 1998, the Utility reached an agreement with the City and County of San Francisco regarding the Hunters Point fossil-fuel fired power plant, which the ISO has designated as a "must-run" facility. The agreement expresses the Utility's intention to retire the plant when it is no longer needed by the ISO.(2)Listed to show capability; subject to relocation within the system as required.(3)One mobile turbine (15 MW) is not currently connected to the system. Hunters Point Units 2 and 3 (214 MW) were converted to synchronous condenser operations during 2001. 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. Hydroelectric Generation Assets. The Utility's hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe, and 5 miles of natural waterways. The system also includes 84 permits and licenses 94 contracts for water rights and 164 statements of water diversion and use. Diablo Canyon Nuclear Power Plant. Diablo Canyon consists of two nuclear power reactor units, each capable of generating up to approximately 26 million kWh of electricity per day. Diablo Canyon Units 1 and 2 began commercial operation in May 1985 and March 1986, respectively. The operating license expiration dates for Diablo Canyon Units 1 and 2 are September 2021 and April 2025, respectively. As of December 31, 2002, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 82.45% and 85.35%, respectively.32 The table below outlines Diablo Canyon's refueling schedule for the next five years. Diablo Canyon refueling outages typically are scheduled every 19 to 21 months. The schedule below assumes that a refueling outage for a unit will last approximately 35 days, depending on the scope of the work required for a particular outage. The schedule is subject to change in the event of unscheduled plant outages.20032004200520062007Unit 1RefuelingMarchOctoberAprilStartupAprilNovemberMayUnit 2RefuelingFebruaryOctoberAprilStartupMarchNovemberMay The Utility has purchase contracts for, and inventories of, uranium concentrates, uranium hexafluoride, and enriched uranium, as well as one contract for fuel fabrication. Based on current Diablo Canyon operations forecasts and a combination of existing contracts and inventories, the requirements for uranium supply, conversion of uranium to uranium hexafluoride, and the requirement for the enrichment of the uranium hexafluoride to enriched uranium, will be met through 2004. The fuel fabrication contract for the two units will supply their requirements for the next five operating cycles of each unit. In most cases, the Utility's nuclear fuel contracts are requirements-based, with the Utility's obligations linked to the continued operation of Diablo Canyon. The Utility has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear generating facilities. Under these insurance policies, if the nuclear generating facility of a member utility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum retrospective premium assessments of $25 million with respect to property damage and $8 million with respect to business interruption losses per year if losses exceed the resources of NEIL. Effective November 15, 2001, in the event that one or more acts of terrorism cause property damage under any of the nuclear insurance policies issued by NEIL within 12 months from the date the first property damage occurs, the maximum recovery under all the nuclear insurance policies will be an aggregate of $3.24 billion, plus the additional amount recovered by NEIL for the losses from reinsurance, indemnity, and any other applicable sources. Under the Terrorism Risk Insurance Act of 2002, NEIL would be entitled to receive substantial reinsurance for an act caused by a foreign terrorist. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005. The Price-Anderson Act, as amended by Congress in 1988, limits public liability claims that could arise from a nuclear incident to a maximum of $9.5 billion per incident. The Utility has purchased primary insurance of $300 million for the Diablo Canyon Power Plant for public liability claims resulting from a nuclear incident. The Utility has secondary financial protection that provides an additional $9.2 billion of coverage, as required by the Price-Anderson Act. Under the Price-Anderson Act, secondary financial protection is required for all nuclear electrical generation reactors having a rated operating capacity of at least 100 MW. There are 105 currently licensed reactors having a rated capacity in excess of 100 MW, including Diablo Canyon's Units 1 and 2. The Price-Anderson Act provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $300 million, the Utility may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident. The Utility also has $53.3 million of private liability insurance for Humboldt Bay Power Plant, where the Utility has a shutdown nuclear unit. In addition, the Utility 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 private liability insurance for Humboldt Bay Power Plant. The Price-Anderson Act expired on August 1, 2002. By the terms of the act itself, the provisions of the act will remain in effect until Congress renews the act. The current draft of the bill to renew this act would increase the maximum assessment per nuclear incident per unit to $99 million from $88 million, with payments in each year limited to a maximum of $15 million per nuclear incident per unit, increased from $10 million.Allocation of DWR Electricity to the California Investor-Owned Utilities Under the authority of AB 1X, the DWR entered into 35 long-term electricity procurement contracts, representing in the aggregate an average annual capacity of 10,780 MW over the next seven years. The California33IOUs act as billing and collection agents for the DWR's sales of its electricity to retail customers. The DWR's authority under AB 1X to enter into new electricity procurement arrangements expired on December 31, 2002. In September 2002, the CPUC issued a decision that allocates the electricity provided through the DWR contracts among the customers of the three California IOUs. The DWR allocation generally consists of electricity quantities under contracts with specified delivery points in the Utility's service territory. The power available under the contracts is to be dispatched in conjunction with the IOU's existing resources on a least-cost basis, with surplus energy sales allocated pro rata between the DWR and the IOU's resources based on their relative amounts of generation. Some of the DWR contracts are firm commitments requiring the DWR to make purchases of specified quantities of electricity, others give the DWR the option as to whether to purchase the quantity of electricity set forth in the contract, and others have a combination of mandatory and optional purchases. Of the 19 DWR contracts allocated to the Utility, 11 involve mandatory purchase commitments, for a total average capacity of 3,010 MW, and the remaining 8 contracts involve optional purchase commitments, for a total average capacity of 1,610 MW. The September 2002 CPUC decision orders the DWR to allocate its variable costs on a contract-by-contract basis. The allocation of both fixed and variable costs was decided in the annual DWR revenue requirement proceeding described above. The California IOUs began performing all the day-to-day scheduling, dispatch and administrative functions associated with the DWR contracts allocated to their portfolios on January 1, 2003. The DWR retains legal title to electricity purchased under the allocated contracts as well as financial reporting and payment responsibility associated with these contracts. The IOUs continue to act as billing and collection agents for the DWR. Although the IOUs will be held to a reasonableness standard in their scheduling and dispatch decision-making and their administration of the DWR contracts, the CPUC has determined that the maximum risk of potential disallowance each IOU should face for all of its procurement activities, including the operation and dispatch of DWR's contracts, should be limited to twice the IOU's annual administrative costs of managing procurement activities. The Utility anticipates that its annual administrative costs of managing procurement activities will be approximately $18 million in 2003. The DWR has stated publicly that it intends to transfer full legal title of, and responsibility for, the DWR electricity contracts to the IOUs as soon as possible. However, SB 1976 does not contemplate a transfer of title of the DWR contracts to the IOUs. In addition, the operating order issued by the CPUC on December 19, 2002, implementing the Utility's operational and scheduling responsibility with respect to the DWR allocated contracts specifies that the DWR will retain legal and financial responsibility for the contracts and that the December 19, 2002, order does not result in an assignment of the DWR allocated contracts. The Utility's proposed plan of reorganization prohibits the Utility from accepting, directly or indirectly, assignment of legal or financial responsibility for the DWR contracts. There can be no assurance that either the State of California or the CPUC will not seek to provide the DWR with authority to effect such a transfer of legal title in the future. The Utility has informed the CPUC, the DWR and the State that the Utility would vigorously oppose any attempt to transfer the DWR allocated contracts to the Utility without the Utility's consent.Qualifying Facility Agreements The Utility is required by CPUC decisions to purchase electric energy and capacity from independent power producers that are qualifying facilities, or QFs, under the Public Utility Regulatory Policies Act of 1978 or PURPA. Pursuant to PURPA, the CPUC required California utilities to enter into a series of QF long-term power purchase agreements and approved the applicable terms, conditions, price options, and eligibility requirements. The agreements require the Utility to pay for energy and capacity. Energy payments are based on the QF project's actual electrical output and capacity payments are based on the QF project's total available capacity and contractual capacity commitment. Capacity payments may be reduced or increased if the facility fails to meet or, alternatively, exceeds performance requirements specified in the applicable power purchase agreements. As of December 31, 2002, the Utility had agreements with 285 QFs for approximately 4,200 MW. The 4,200 MW consist of 2,600 MW from cogeneration projects, 700 MW from wind projects and 900 MW from other projects, including biomass, waste-to-energy, geothermal, solar and hydroelectric. Power purchase agreements for 2,100 MW expire between 2013 and 2015 while agreements for an additional 1,600 MW expire between 2016 and 2028. Power purchase agreements for 500 MW have no specific expiration date and will terminate upon exercise of a termination option by the QF. QF power purchase agreements accounted for approximately 25.01% of the Utility's 2002 deliveries and no single agreement accounted for more than 5% of its electricity deliveries.34 In August 2002, the CPUC ordered the IOUs to offer transitional standard offer no. 1 contracts, or TSO1 contracts, to certain QFs whose power purchase agreements with the IOU had expired or were about to expire. The term of these transitional contracts will end when the IOU fully implements its CPUC-approved long-term procurement plan or on December 31, 2003, whichever occurs first. The Utility signed TSO1 contracts with nine QFs. These new contracts have been approved by the Bankruptcy Court and the CPUC and became effective on January 1, 2003. Since December 2001, the Bankruptcy Court has approved supplemental agreements between the Utility and most QFs to resolve the applicable interest rate to be applied to pre-petition amounts owed to QFs. The supplemental agreements•set the interest rate for pre-petition payables at 5%,•provide for a "catch-up payment" of all accrued and unpaid interest through the initial payment date, and•depending on the amount owed, either (a) provide for the immediate payment of the principal and interest amount of the pre-petition payables or (b) payment in 12 or 6 equal monthly payments beginning on the last business day of the month during which Bankruptcy Court approval was granted. If the effective date of the Utility's Plan occurs before the last monthly payment is made, the remaining unpaid principal and unpaid interest would be paid on the effective date. Additionally, since January 2002, the Utility has entered into agreements with additional QFs to assume their power purchase agreements, which agreements also contained the same interest and payment terms contained in the supplemental agreements described above. At December 31, 2002, $901 million in principal and $60 million in interest have been paid to the QFs. Through December 31, 2002, 264 of 313 QFs have signed assumption and/or supplemental agreements. The Utility believes that some of the remaining QFs also will wish to enter into similar supplemental agreements.Renewable Resource Energy Contracts An August 22, 2002, the CPUC issued a decision requiring the California IOUs to contract for electricity from renewable resources for an additional 1% each year beginning January 1, 2003, until a 20% renewable resource portfolio is achieved by no later than 2017. Interim renewable resources contracts should range from 5 to 15 year terms. In addition, the CPUC decision determined that any renewable resources contract prices that meet or are less than a provisional benchmark of 5.37 cents per kWh will be deemed reasonable, although prices above the benchmark also may be pre-approved for cost recovery through the pre-approval process adopted in the decision. The Utility currently estimates that the annual 1% increase in renewable resource electricity in its portfolio will initially require between 80 and 100 MW of additional renewable capacity to be added per year. On September 16, 2002, the Utility issued a request for offers to meet the 1% annual renewable resource requirement and on November 15, 2002, the Utility submitted the offers selected to the CPUC for approval. These submissions, which the CPUC approved in December 2002, will meet the Utility's renewable resource requirement for 2003.Other Third-Party Power Agreements The Utility also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments whether or not any energy is supplied (subject to the supplier's retention of the FERC's authorization) and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. Costs associated with these contracts to purchase power are eligible for recovery by the Utility as transition costs through the collection of the non-bypassable competition transition charge. At December 31, 2002, the undiscounted future minimum payments under these contracts are approximately $32.9 million for each of the years 2003 and 2004 and a total of $247 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate accounted for approximately 4.24% of the Utility's 2002 electric power requirements. The Utility also has two power purchase agreements representing an aggregate of 450 MW, both of which expire at the end of 2003. The Utility's minimum payments due under these contracts are $196 million for 2003.35 The amount of electric power received and the total payments made under QF, irrigation district, water agency, and bilateral agreements are as follows: 2002 2001 2000 1999 1998 Gigawatt-hours received 28,088 23,732 26,027 25,910 25,994 Energy payments (in millions) $ 1,051 $ 1,454 $ 1,549 $ 837 $ 943 Capacity payments (in millions) $ 506 $ 473 $ 519 $ 539 $ 529 Irrigation district and water agency payments (in millions) $ 57 $ 54 $ 56 $ 60 $ 53 Bilateral contract payments $ 196 $ 155 $ 53 0 0 Western Area Power Administration. In 1967, the Utility and the Western Area Power Administration, or WAPA, entered into a long-term power contract governing (1) the interconnection of the Utility's and WAPA's transmission systems, (2) WAPA's use of the Utility's transmission and distribution system, and (3) the integration of the Utility's and WAPA's loads and resources. The contract gave the Utility access to surplus hydroelectric generation and obligates the Utility to provide WAPA with electricity when its own resources are not sufficient to meet its requirements. The contract terminates on December 31, 2004. As a result of California's electric industry restructuring in 1998, the Utility was required to procure the electric power that it needed to meet its own and WAPA's requirements from the PX. This caused the Utility to be exposed to market-based energy pricing rather than the cost of service-based energy pricing that had been presumed when the contract was executed. As a result, the Utility paid substantially more for the energy it purchased on behalf of WAPA than it received for the sales of energy to WAPA. The cost to fulfill the Utility's obligations to WAPA under the contract is uncertain. However, the Utility expects that the cost of meeting its obligation to WAPA will be greater than the price that the Utility receives from WAPA under the contract. In part, the amount of electricity the Utility will be required to deliver to WAPA depends on the amount of electricity available from WAPA's hydroelectric resources. Under AB 1890, the Utility's retail ratepayers pay for this difference as a stranded power purchase cost. The amount of the difference between the Utility's cost to meet its obligations to WAPA and the revenues it receives from WAPA cannot be accurately estimated at this time since both the purchase price and the amount of energy WAPA will need from the Utility through the end of the contract are uncertain. Though it is not indicative of future sales commitments or sales-related costs, WAPA's net amount purchased from the Utility was 3,619 GWh in 2002, 4,823 GWh in 2001, and 5,120 GWh in 2000.Electric Transmission To transmit electricity to load centers, the Utility, at December 31, 2002, owned approximately 18,605 circuit miles of interconnected transmission lines operated at voltages of 60 kV to 500 kV and transmission substations having a capacity of approximately 47,596 megavolt-amperes (MVA), including spares, and excluding power plant interconnection facilities. Electricity is distributed to customers through approximately 118,033 circuit miles of distribution system and distribution substations having a capacity of approximately 24,020 MVA. For the year ended December 31, 2002, the Utility sold 104,499,158 MWh to its bundled retail customers and transmitted 7,433,238 MWh to direct access customers. In connection with electric industry restructuring, in 1998 the IOUs relinquished to the ISO control, but not ownership, of their transmission facilities. The FERC has jurisdiction over the transmission facilities, and revenue requirements and rates for transmission service are set by the FERC. The ISO commenced operations on March 31, 1998. The ISO, regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. As control area operator, the ISO also is responsible for assuring the reliability of the transmission system. In 1998, the FERC approved the forms of agreements for Reliability Must-Run, or RMR, service that have been entered into between RMR facility owners and the ISO to ensure grid reliability and avoid the exercise of local market power. The costs of RMR contracts attributed to supporting the Utility's historic transmission control area are charged to the Utility as a Participating Transmission Owner, or PTO. These costs, which were approximately $311 million in 2002, are currently recovered from the Utility's retail customers and, subject to FERC filings to be made by March 31, 2003, wholesale transmission customers. In March 2000, the ISO filed an application with the FERC seeking to establish its own Transmission Access Charge (TAC) as directed in AB 1890. The FERC accepted the ISO's TAC filing, subject to refund, but suspended the proceeding to allow interested parties to enter into settlement discussions. After settlement discussions proved unsuccessful, in December 2002 FERC set the case for hearing. In late December 2000, the ISO made a further36implementation filing, also accepted by the FERC subject to refund, to establish specific TAC rates which was triggered by a transmission-owning municipality's application to become a new PTO. The ISO's TAC methodology provides for transition to a uniform statewide high voltage transmission rate, based on the revenue requirements of all PTOs associated with facilities operated at 200 kV and above. The TAC methodology also requires the IOUs, such as the Utility, to pay during a ten-year transition period a charge based on certain costs incurred by new PTOs resulting from joining the ISO and the cost differential from these higher-cost systems being included in the ISO controlled transmission grid. The Utility's obligation for this cost shift is proposed to be capped at $32 million per year. The Utility has been working closely with the ISO to continue expanding the capacity on the Utility's electric transmission system. One segment of the transmission system proposed to be addressed by the Utility are the transmission facilities 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. At times, the current facilities cannot accommodate all low-cost power intended to be transmitted between southern California and northern California. (For transmission purposes, the Diablo Canyon Nuclear Power Plant is located south of Path 15.) This transmission constraint historically has resulted in significant wholesale power price differentials between northern and southern California, with relatively high power prices in northern California and relatively low power prices in southern California. Following an analysis of the economic benefits of relieving transmission system constraints performed by the ISO, the Utility agreed to participate in a project sponsored by WAPA to upgrade the transfer capability of Path 15. The project entails construction of a new 84 mile, 500 kV transmission line by WAPA between two of the Utility's existing substations. The Utility has agreed to interconnect WAPA's new 500 kV line at the Utility's substations by installing necessary substation equipment and to modify other portions of its transmission system. WAPA will own and operate the new 500 kV line with financing provided by Trans-Elect, Inc., an independent electric transmission company. All participants in the WAPA-sponsored project have agreed to turn over operational control of the transmission system upgrade to the ISO upon completion of the project. In January 2002, the Utility received Bankruptcy Court approval to participate in the WAPA project including spending up to $75 million under its current five-year plan for the substation and system modifications necessary to interconnect to WAPA's new line. In May 2002, the FERC approved a letter agreement between the participants outlining ownership, financing and cost recovery associated with the project. The Utility is in the process of negotiating additional agreements with the project participants to develop schedules and coordinate construction of the project and for the coordinated operation and interconnection of the project with its existing facilities. The Utility's expenditure commitment is contingent upon WAPA meeting construction milestones. The Utility's investment in its transmission system has been growing substantially over the past several years. The Utility made an additional capital investment of approximately $374 million in its transmission system in 2002 and plans to make an additional capital investment of approximately $504 million in 2003. Through the ISO's Long-Term Grid Planning Process, the Utility files annually with the ISO its transmission system upgrade and expansion plans and provides the ISO and other interested parties the opportunity to review and modify the Utility's planned upgrades and expansions.GAS UTILITY OPERATIONS The Utility owns and operates an integrated gas transmission, storage, and distribution system in California that extends throughout all or a portion of 38 of California's 58 counties and includes most of northern and central California. In 2002, the Utility served approximately 3.9 million natural gas distribution customers. At December 31, 2002, the Utility's system consisted of approximately 6,300 miles of transmission pipelines, three gas storage facilities, and approximately 38,944 miles of gas distribution lines. The Utility's Line 400/401 interconnects with PG&E GTN's natural gas transmission system. The PG&E GTN pipeline begins at the border of British Columbia, Canada and Idaho, and extends through northern Idaho, southeastern Washington, and central Oregon, and ends on the Oregon-California border where it connects with the Utility's Line 400/401. The Utility's Line 400/401 has a capacity at the border of approximately 2 billion cubic feet, or Bcf. The Utility's Line 300, which connects to the U.S. Southwest pipeline systems (Transwestern, El Paso Questar,pipeline capacity costs and Kern River) owned by third parties has a capacity at the California/Arizona border of 1,140 MMcf per day. The Utility's underground gas storage facilities located at McDonald Island, Los Medanos, and Pleasant Creek, have a total working gas capacity of 100 Bcf.37 Through the interconnection with other interstate pipelines, the Utility can receive natural gasprepayments made to El Paso from all the major natural gas basins in western North America, including basins in western Canada, the southwestern United States, and the Rocky Mountains, as well as natural gas fields in California. Since 1991, the CPUC has divided the Utility's natural gas customers into two categories—core and noncore customers. This classification is based largely on a customer's annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial and larger commercialUtility began recovering these costs from all natural gas customers.customers in March 2003. In 2002,January 2004, the CPUC re-allocated all the costs, including Transwestern costs incurred since July 2003, to the Utility’s core customers, represented over 99% ofbecause the Utility's total customers and 41% of its total natural gas deliveries while noncore customer comprised less than 1% of its total customers and 59% of its total natural gas deliveries. The Utility provides natural gas delivery services to all its core and noncore customers. Core customers can purchase gas from third-party suppliers or can elect to have the Utility provide both delivery service and natural gas supply. Where the Utility provides both supply and delivery, the Utility refers to the service as "bundled service." The Utility offers transmission, distribution, and storage services as separate and distinct services to its non-core customers. These customers have the opportunity to select from a menu of services offered by the Utility and to pay only for the services that they use. Access to the transmission system is possible for all gas marketers and shippers, as well as non-core end-users. The Utility's core customers can select the commodity gas supplier of their choice, but the Utility continues to purchase gas as a regulated supplier for those core customers who do not select another supplier. Currently, over 99% of core customers, representing over 97% of core market demand, choose to receive bundled services from the Utility. The Utility ended its core subscription service in March 2001. The Utility earns a return on its investment in natural gas distribution facilities. Customers pay a volumetric distribution rate that reflects the Utility's costs to serve each customer class. The Utility has regulatory balancing accounts for core customers designed so that the Utility's results of operations over the long term are not affected by their consumption levels. Results of operations can, however, be affected by noncore consumption levels because there are no similar regulatory balancing accounts related to noncore customers. Approximately 97% of the Utility's natural gas base revenues are recovered from core customers and 3% are recovered from noncore customers. The Utility Gas Accord II application for 2004 requests 100% balancing account treatment for noncore gas distribution revenues. The Utility's peak day send-out of natural gas on its integrated system in California during the year ended December 31, 2002 was 4,077MMcf. The total volume of natural gas throughput during 2002 was approximately 749,981 MMcf, of which 733,585 MMcf was sold or transported to direct end-use or resale customers, 15,298 MMcf was used by the Utility primarily for its fossil-fuel fired electric generating plants, and 1,098 MMcf was transported off-system as customer-owned natural gas. The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and gas utilities. A comprehensive biennial report is prepared in even-numbered years. A supplemental report is prepared in intervening odd-numbered years updating recorded data for the previous year. The 2002 California Gas Report updated the Utility's annual gas requirements forecast for the years 2002 through 2022, forecasting average annual growth in gas throughput served by the Utility of approximately 1.8%. The gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, and amount and location of electric generation. The 2003 report is due to be filed July 1, 2003, and will include recorded data for 2002.38Gas Operating Statistics The following table shows Pacific Gas and Electric Company's operating statistics (excluding subsidiaries) for gas, including the classification of sales and revenues by type of service: 2002 2001 2000 1999 1998 Customers (average for the year): Residential 3,738,524 3,705,141 3,642,266 3,593,355 3,536,089 Commercial 206,953 205,681 203,355 203,342 200,620 Industrial 1,819 1,764 1,719 1,625 1,610 Other gas utilities 5 6 6 4 5 Total 3,947,301 3,912,592 3,847,346 3,798,326 3,738,324 Gas supply—thousand cubic feet (Mcf) (in thousands): Purchased from suppliers in: Canada 210,716 209,630 216,684 230,808 298,125 California 19,533 10,425 32,167 18,956 17,724 Other states 67,878 76,589 75,834 107,226 122,342 Total purchased 298,127 296,644 324,685 356,990 438,191 Net (to storage) from storage (218 ) (27,027 ) 19,420 (980 ) (14,468 ) Total 297,909 269,617 344,105 356,010 423,723 Pacific Gas and Electric Company use, losses, etc.(1) 16,394 (939 ) 62,960 47,152 129,305 Net gas for sales 281,515 270,556 281,145 308,858 294,418 Bundled gas sales—Mcf (in thousands): Residential 202,141 197,184 210,515 233,482 223,706 Commercial 78,812 72,528 66,443 70,093 66,082 Industrial 563 831 4,146 5,255 4,616 Other gas utilities 0 13 41 28 14 Total 281,516 270,556 281,145 308,858 294,418 Transportation only—Mcf (in thousands): Vintage system (Substantially all Industrial)(2) 508,090 646,079 606,152 484,218 396,872 Revenues (in thousands): Bundled gas sales: Residential $ 1,379,036 $ 2,307,677 $ 1,680,745 $ 1,542,705 $ 1,414,313 Commercial 499,214 783,080 513,080 448,655 426,299 Industrial 2,447 15,904 35,347 24,638 24,634 Other gas utilities 829 2 0 77 1,072 Bundled gas revenues 1,881,526 3,106,663 2,229,172 2,016,075 1,866,318 Transportation only revenue: Vintage system (Substantially all Industrial) $ 308,212 $ 365,550 $ 324,319 $ 267,544 $ 232,038 PG&E Expansion (Line 401) 8,275 9,380 13,392 19,091 42,194 Transportation service only revenue 316,487 374,930 337,711 286,635 274,232 Miscellaneous 126,415 (92,531 ) 84,526 (47,311 ) 41,364 Regulatory balancing accounts 11,431 (253,476 ) 131,762 (259,648 ) (448,351 ) Operating revenues $ 2,335,859 $ 3,135,586 $ 2,783,171 $ 1,995,751 $ 1,733,563 (1)Includes fuel for Pacific Gas and Electric Company's fossil-fuel fired generating plants.(2)Does not include on-system transportation volumes transported on the PG&E Expansion of 382 MMcf, 259 MMcf, 4,833 MMcf, 1,251 MMcf, and 34,169 MMcf for 2002, 2001, 2000, 1999, and 1998, respectively.39 2002 2001 2000 1999 1998 Selected Statistics: Average annual residential usage (Mcf) 54.1 53.2 59 65 63 Heating temperature—% of normal(1) 104.6 105.1 101.2 108.5 93.0 Average billed bundled gas sales revenues per Mcf: Residential $ 6.82 $ 11.70 $ 7.98 $ 6.61 $ 6.32 Commercial 6.33 10.80 7.72 6.40 6.45 Industrial 4.35 19.15 8.53 4.69 5.36 Average billed transportation only revenue per Mcf: Vintage system 0.61 0.56 0.54 0.66 0.66 PG&E Expansion (Line 401) 7.54 1.78 2.04 0.53 0.54 Net plant investment per customer(2) $ 1,006 $ 970 $ 1,003 $ 1,011 $ 1,040 (1)Over 100% indicates colder than normal.Natural Gas Supplies The Utility purchases natural gas directly from producers and marketers in both Canada and the United States. The composition of the Utility's portfolio of natural gas procurement contracts has fluctuated, generally based on market conditions. The Utility's CPUC-approved core procurement incentive mechanism, or CPIM, uses published monthly and daily natural gas prices for determining the Utility's benchmark price. During the year ended December 31, 2002, the Utility purchased approximately 298,127 Mcf of natural gas from approximately 54 suppliers. Substantially all this supply was purchased under contracts with a term of less than one year. The Utility's largest individual supplier represented approximately 9.4% of the Utility's total natural gas purchases during the year ended December 31, 2002. Approximately 70% of the Utility's natural gas supplies come from western Canada. The Utility has firm transportation agreements for western Canadian natural gas with TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System. These systems transport the natural gas to the U.S. and Canadian border, where it enters the transportation pipeline of PG&E GTN near Kingsgate, British Columbia. Approximately 28% of the Utility's natural gas supplies come from the southwestern United States and the Rocky Mountains. The Utility has firm transportation agreements with Transwestern Pipeline Company and El Paso Natural Gas Company to transport this natural gas to interconnections with the Utility's gas transportation and storage system near Topock, Arizona. The following table shows the total volume and average price of gas in dollars per thousand cubic feet (Mcf) purchased by the Utility from these sources during each of the last five years. 2002 2001 2000 1999 1998 Thousands of Mcf Avg.
Price(1) Thousands of Mcf Avg.
Price(1) Thousands of Mcf Avg.
Price(1) Thousands
of Mcf Avg.
Price(1) Thousands of Mcf Avg.
Price(1)Canada 210,716 $ 2.42 209,630 $ 4.43 216,684 $ 4.05 230,808 $ 2.50 298,125 $ 2.00 California 19,533 2.88 10,425 16.68 32,167 8.20 18,956 2.45 17,724 2.44 Other states (substantially all U.S. Southwest) 67,878 3.04 76,588 10.41 75,835 5.99 107,227 2.42 122,342 2.62 Total/Weighted Average 298,127 $ 2.59 296,643 $ 6.40 324,686 $ 4.92 356,991 $ 2.47 438,191 $ 2.19 (1)The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or reservation charges, transportation charges, and other pipeline assessments, including direct bills allocated over the quantities received at the California border. Beginning March 1, 1998, the average price for gas also includes intrastate pipeline demand and reservation charges. These costs previously were bundled in gas rates. Under the CPIM, the Utility's procurement costs are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas prices at the locations where the Utility typically purchases natural gas. If costs fall within a range, or tolerance band, currently between 99% to 102%, around the benchmark, they are considered reasonable and the Utility may fully recover them in customer rates. Ratepayers and shareholders share costs and savings outside the tolerance band.40Natural Gas Gathering Facilities The Utility's natural gas gathering system collects and processes natural gas from third-party wells in California. The natural gas is processed to remove various impurities from the natural gas stream and to odorize the natural gas so that it may be detected in the event of a leak. The facilities include approximately 510 miles of gas gathering pipelines as well as dehydration, separation, regulation, odorization and metering equipment located at approximately 60 stations. The natural gas gathering system is geographically dispersed and is located in 16 California counties. Approximately 190 MMcf per day of natural gas flows through the Utility's gas gathering system.Natural Gas Transportation and Storage Services Agreements Since March 1998, the Utility's natural gas transportation and storage services have been governed by the rates, terms, and conditions approved by the CPUC in the Gas Accord. The Gas Accord separated, or "unbundled," the Utility's natural gas transportation and storage services from its distribution services, changed the terms of service and rate structure for natural gas transportation and storage services, and fixed natural gas transportation and storage rates. As required by the CPUC, in October 2001, the Utility filed an application with the CPUC requesting a two-year extension, without modification, of the Gas Accord. In August 2002, the CPUC approved a settlement agreement among the Utility and other parties that provided for a one-year extension of the Gas Accord. The Gas Accord II settlement left unresolved the issues raised in the application insofar as they relate to the second year of the two-year application. Following the CPUC administrative law judge's rulings which required the Utility to also file a cost and rate proposal for 2004, the Utility filed an amended application, on January 13, 2003, which proposes, among other things, retention of the basic Gas Accord market structure, transmission and storage costs and rates for 2004, a 13.4% equity return for gas transmission and storage assets, a 1-in-10 reliability standard, and for the Utility to remain at risk for recovery of all transmission and storage facility costs. Testimony by interested parties is due by February 28, 2003, and rebuttal testimony by March 24, 2003, with hearings to begin on April 1, 2003. The Utility has a number of arrangements for natural gas transportation services. These agreements include provisions for payment of fixed demand charges for reserving firm pipeline capacity as well as volumetric transportation charges. The total demand charges may change periodically as a result of changes in regulated tariff rates. Additionally, the forward market value for the firm capacity is subjectused to change. The Utility held hedge agreements for a portion of this forward value at the time it defaulted in April 2001, which caused the hedge counterparties to terminate their agreements and demand termination payments. The Utility recognized a total of $111 million in losses related to these terminated agreements in 2001. The combined charges the Utility incurred under the transportation agreements and hedge agreements, including losses on terminated contracts, were $101 million, $239 million, and $94 million in 2002, 2001, and 2000, respectively. These amounts include payments that the Utility made to PG&E GTN of $47 million, $40 million, $46 million in 2002, 2001, and 2000, respectively, which are eliminated in the consolidated financial statements of PG&E Corporation. Under a firm transportation agreement with PG&E GTN that runs through October 31, 2005, the Utility currently retains capacity of approximately 610 MDth/d on the PG&E GTN system to support itsserve core customers. The Utility has been able to broker its unused capacity on PG&E GTN's system, when not neededUtility’s noncore customers and core aggregation customers will receive a refund or bill credit for core customers. Pursuant to the CPUC's order requiring the utilities to subscribe for capacity on El Paso's pipeline, the Utility has obtained 204 MDth/day of El Paso capacity rights on interstate pipeline under three natural gas transportation agreements commencing on November 1, 2002. The costs are currently allocated to core and noncorepaid by these customers subject to reallocation in a future CPUC proceeding. The Utility may recover demand charges through the CPIM and through brokering activities. The Utility may, upon prior notice, extend each of these natural gas transportation contracts for additional minimum terms ranging, depending on the particular contract, from 1 to 10 years with demand charges to be set by tariffs approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System and the FERC in all other cases. For the contracts under FERC jurisdiction, the Utility has a right of first refusal allowing the Utility to renew pipeline service agreements at the end of their terms. If another prospective shipper wants the capacity, the Utility would be required to match the competing bid with respect to both price and term. In the past, FERC policy required only that the existing shipper match the price and a term of up to five years. In a recent order on remand from an appellate court, the FERC removed the41five-year cap on matching bids. Under the new FERC policy, the existing shipper must match the competing bid with respect to both price and term, with no limit on the number of years that the shipper's bid must match.PG&E NATIONAL ENERGY GROUP, INC. PG&E NEG is currently focused on power generation and natural gas transmission in the United States. PG&E NEG reports its business segments as follows: interstate pipeline operations (or "Pipeline Business") and power generation also referenced as Integrated Energy and Marketing (or "Generation Business").Generation Business In the Generation Business segment, PG&E NEG engages in the generation of electricity in the continental United States. As of December 31, 2002, PG&E NEG had ownership or leasehold interests in 13 operating generating facilities with a net generating capacity of 1,476 megawatts (MW), as follows:Number of
Facilities Net
MW Primary
Fuel Type % of
Portfolio8 657 Coal/Oil 45 7 797 Natural Gas 54 1 12 Wind 1 16 1,476 100 PG&E NEG provides operating and/or management services for 14 of these 16 owned and leased generating facilities. Plant operations are focused on maximizing the availability of a facility to generate power during peak energy price hours, improving operating efficiencies and minimizing operating costs while placing a heavy emphasis on safety standards, environmental compliance and plant flexibility. These generating facilities sell all or a majority of their electrical capacity and output to one or more third parties under long-term power purchase agreements tied directly to the output of that plant. PG&E NEG holds interests in these projects through wholly owned indirect subsidiaries and typically manages and operates these facilities through an operation and maintenance agreement and/or a management services agreement. These agreements generally provide for management, operations, maintenance and administration for day-to-day activities, including financial management, billing, accounting, public relations, contracts, reporting and budgets. In order to provide fuel for PG&E NEG's independent power projects (IPPs), natural gas and coal supply commitments are typically purchased from third parties under long-term supply agreements. The revenues generated from long-term power sales agreements usually consist of two components: energy payments and capacity payments. Energy payments are typically based on the facility's actual electrical output and capacity payments are based on the facility's total available capacity. Energy payments are made for each kilowatt-hour of energy delivered, while capacity payments, under most circumstances, are made whether or not any electricity is delivered. However, capacity payments may be reduced if the facility does not attain an agreed availability level. The average life of the power sales agreements is 15 years.Description of Generating Facilities The following table provides information regarding each of PG&E NEG's owned or leased generating facilities, as of December 31, 2002, excluding assets to be abandoned and, assets held for sale or use, assets to be abandoned and, such as the USGenNE facilities, Lake Road, La Paloma, Attala, and the GenHoldings projects:Generating Facility State Total
MW(1) Net
Interest
in Total
MW(2) Structure Fuel Primary Output Sales
Method Date of
Commercial
Operation Contract
ExpirationNew England Region MASSPOWER MA 267 35 Owned Natural Gas Power Purchase Agreements 1993 2008 & 2013 Pittsfield MA 173 154 Leased Natural Gas Power Purchase Agreements 1990 2010 Subtotal 440 189 Mid-Atlantic and New York Region Selkirk NY 345 145 Owned Natural Gas Power Purchase Agreements and Competitive Market 1992 2008/2014 Carneys Point NJ 245 123 Owned Coal Power Purchase Agreements 1994 2024 Logan NJ 225 113 Owned Coal Power Purchase Agreement 1994 2024 Northampton PA 110 55 Owned Waste Coal Power Purchase Agreements 1995 2020 Panther Creek PA 80 44 Owned Waste Coal Power Purchase Agreement 1992 2012 Scrubgrass PA 87 44 Owned Waste Coal Power Purchase Agreement 1993 2017 Madison NY 12 12 Owned Wind Competitive Market 2000 N/A Subtotal 1,104 536 Midwest Region Ohio Peakers OH 149 149 Owned Natural Gas Competitive Market 2001 2005 Southern Region Indiantown FL 330 116 Owned Coal Power Purchase Agreement 1995 2025 Cedar Bay FL 258 165 Owned Coal Power Purchase Agreement 1994 2024 Subtotal 588 281 Western Region Hermiston OR 474 119 Owned Natural Gas Power Purchase Agreement 1996 2016 Colstrip MT 40 7 Owned Waste Coal Power Purchase Agreement 1990 2025 San Diego Peakers CA 84 84 Owned Natural Gas Competitive Market 2001 2003 Plains End CO 111 111 Owned Natural Gas Power Purchase Agreement 2002 2012 Subtotal 714 326 Total 2,990 1,476 (1)Megawatts are based on winter output.(2)PG&E NEG's net interest in the total MW of an independent power project is the current percentage ownership or leasehold interest in the project affiliate and does not necessarily correspond to PG&E NEG's percentage of the project's expected cash flow.Natural Gas Transmission Business In its Pipeline Business segment, PG&E NEG owns, operates and develops natural gas pipeline facilities, including the pipeline owned by PG&E GTN, an interest in the Iroquois Gas Transmission System, and the North Baja pipeline. The following table summarizes PG&E NEG's gas transmission pipelines:Pipeline Name Location In Service
Date Approx.
Capacity
(MMcf/d) 2001 Load
Factor Length
(miles) Ownership
Interest PG&E GTN ID, OR, WA 1961 2,700 91 % 1,356 100.0 % Iroquois Gas Transmission System NY, CT 1991 850 88 % 375 5.2 % North Baja AZ, CA 2002/2003 500 N/A 80 100.0 % PG&E GTN Pipeline System. The PG&E GTN pipeline consists of over 1,350 miles of natural gas transmission pipeline in the Pacific Northwest with a capacity of approximately 2.9 billion cubic feet of natural gas per day. This pipeline begins at the British Columbia-Idaho border, extends for approximately 612 miles through northern Idaho, southeastern Washington and central Oregon, and ends at the Oregon-California border, where it connects43with other pipelines. The PG&E GTN pipeline commenced commercial operation in 1961 and has subsequently expanded various times through 2002. This pipeline is the largest transporter of Canadian natural gas into the United States. The mainline system of this pipeline is composed of two parallel pipelines (along with 21 miles of a third parallel line) with 13 compressor stations totaling approximately 513,400 horsepower and ancillary facilities which include metering and regulating facilities and a communication system. PG&E GTN has approximately 639 miles of 36-inch diameter gas transmission lines (612 miles of 36-inch diameter pipe and 27 miles of 36-inch diameter pipeline looping) and approximately 611 miles of 42-inch diameter pipe. The PG&E GTN system also includes two laterals off of its mainline system, the Coyote Springs Extension, which supplies natural gas to an electric generation facility owned by Portland General Electric Company and other customers, and the Medford Extension, which supplies natural gas to Avista Utilities and Pacificorp Power Marketing. The Coyote Springs Extension is composed of approximately 18 miles of 12-inch diameter pipe, originating at a point on the PG&E GTN mainline system approximately 27 miles south of Stanfield, Oregon and connecting to Portland General Electric's electric generation facility near Boardman, Oregon. The Medford Extension consists of approximately 22 miles of 16-inch diameter pipe and 66 miles of 12-inch diameter pipe and extends from a point on the PG&E GTN mainline system near Bonanza, in Southern Oregon, to interconnection points with Avista Utilities at Klamath Falls and Medford, Oregon. PG&E GTN Interconnection With Other Pipelines. PG&E GTN's pipeline facilities interconnect with facilities owned by TransCanada PipeLines Ltd.'s B.C. System (TransCanada) and facilities owned by Foothills Pipe Lines South B.C. Ltd. (Foothills South B.C.) near the Idaho-British Columbia border. PG&E GTN's pipeline facilities also interconnect with the facilities owned by the Utility, at the Oregon-California border, with the facilities owned by Northwest Pipeline Corporation (Northwest Pipeline) in Northern Oregon and in Eastern Washington, and with the facilities owned by Tuscarora Gas Transmission Company (Tuscarora) in Southern Oregon. PG&E GTN also delivers gas along various mainline delivery points to two local gas distribution companies. TransCanada PipeLines Ltd. and Foothills South B.C. Ltd. PG&E GTN's pipeline facilities interconnect with the facilities of TransCanada and Foothills South B.C. near Kingsgate, British Columbia. Through the TransCanada and Foothills South B.C. systems, PG&E GTN's customers have access to natural gas from the Western Canadian Sedimentary Basin. TransCanada's Alberta System delivers gas from production areas to provincial gas distribution utilities and to all provincial export points, including the interconnect at the Alberta-British Columbia border to TransCanada's B.C. System and Foothills South B.C. for delivery south into PG&E GTN's system at the British Columbia-Idaho border. Northwest Pipeline Corporation. PG&E GTN's pipeline facilities interconnect with the facilities of Northwest Pipeline near Spokane and Palouse, Washington and near Stanfield and Klamath Falls, Oregon. Northwest Pipeline is an interstate natural gas pipeline which both delivers gas to and receives gas from PG&E GTN and competes with PG&E GTN for transportation of natural gas into the Pacific Northwest and California. Northwest Pipeline's gas transportation services are regulated by the FERC. Tuscarora Gas Transmission Company. PG&E GTN's pipeline facilities interconnect with the facilities of Tuscarora near Malin, Oregon. Tuscarora is an interstate natural gas pipeline that transports natural gas from this interconnection to the Reno, Nevada area. Tuscarora's gas transportation services are regulated by the FERC. Pacific Gas and Electric Company. PG&E GTN's pipeline interconnects with the Utility's gas transmission pipeline system at the Oregon-California border. The Utility's pipeline facilities deliver natural gas to customers in Northern and Central California and interconnect with other pipeline facilities at the California-Arizona border near Topock, Arizona. The Utility's gas transmission system is currently regulated by the CPUC. In April 2001, the Utility commenced a case under Chapter 11 of the U.S. Bankruptcy Code. As part of the Utility's proposed plan of reorganization, in November 2001, the Utility filed an application with the FERC requesting authorization to operate these facilities as a federally-regulated interstate pipeline system. In conjunction with that application, PG&E GTN filed an application with the FERC for authorization to abandon by sale to the Utility approximately 2.66 miles of 42-inch and 36-inch mainline pipe from the southernmost meter station in Oregon to the California border. The transaction implementing this abandonment closed into escrow on November 14, 2002, pending receipt of satisfactory authorizations from the FERC and the Bankruptcy Court. PG&E GTN's Expansion Projects. PG&E GTN has completed its 2002 Expansion Project, expanding its system by approximately 217 million cubic feet (MMcf) per day. Approximately 40 MMcf per day of that expansion capacity was placed in service in November 2001 and the remaining capacity was placed in service in November 2002. The total cost of the expansion is approximately $127 million. One shipper, contractually44committed to 175,000 decatherm (Dth) per day of capacity on this project, failed to provide PG&E GTN with adequate assurances of the shipper's ability to meet its obligations under its transportation contract. On October 25, 2002, PG&E GTN and that shipper terminated the transportation contract and PG&E GTN received $16.8 million from that shipper in settlement of the contract. In response to changing market conditions, PG&E GTN reached agreement with all shippers contractually committed on a second expansion (2003 Expansion Project) to terminate their firm transportation precedent agreements. Accordingly, on October 10, 2002, PG&E GTN filed with the FERC a request to vacate its 2003 Expansion Project proceeding and deferred the project. To date, PG&E GTN has spent $5.4 million on the project. PG&E GTN is continuing necessary development activities and expects to refile an application with FERC when market conditions improve. Related to the termination of the 2003 Expansion Project precedent agreements, all but one of the former 2003 Expansion shippers has committed to take capacity on PG&E GTN's system made available as a result of the 2002 shipper termination or capacity formerly held by Enron or other existing capacity on PG&E GTN's system. PG&E GTN anticipates that it will enter into additional contracts for capacity made available from these sources through open market sales. As of December 31, 2002, PG&E GTN had approximately 155,000 Dth per day of capacity available for subscription on a long-term basis. North Baja Pipeline. North Baja Pipeline, LLC (NBP) owns an approximately 80-mile interstate natural gas pipeline with a capacity of 512 MDth of natural gas per day. The NBP system originates near Ehrenberg, in western Arizona, and traverses southern California to a point on the Baja California, Mexico-California border. The NBP system began limited commercial operation in September 2002 and includes a single compressor station at Ehrenberg, which has approximately 28,800 certificated horsepower and ancillary facilities which include metering and regulating facilities and a communication system. The NBP mainline system consists of approximately 12 miles of 36-inch diameter gas transmission line and 68 miles of 30-inch diameter pipe. This new pipeline will deliver natural gas to a pipeline being constructed by Sempra Energy International. The 135-mile Sempra pipeline will interconnect with PG&E NBP at the California-Mexico border and transport gas into Northern Mexico and Southern California.North Baja System Interconnections with Other PipelinesEl Paso Natural Gas (EPNG) –NBP pipeline facilities interconnect with the facilities of EPNG near Ehrenberg, Arizona. EPNG is an interstate natural gas pipeline, with a pipeline network throughout west Texas, New Mexico and Arizona, that serves customers and other pipelines, including NBP, within those states. Through EPNG, NBP customers have access to gas primarily from the Permian and San Juan basins of Texas, New Mexico and Colorado. EPNG's transportation services are regulated by the FERC.Gasoducto Bajanorte (GB) –NBP pipeline facilities interconnect with the facilities of GB at the Baja California, Mexico-California border near Ogilby, California. GB is the pipeline that receives gas from NPB for the purpose of delivering the gas to customers located in the northern portion of Baja California, Mexico. GB's transportation services are regulated by the Comision Reguladora de Energia, Mexico, a regulatory agency in Mexico with responsibilities similar to those of FERC as they relate to natural gas pipelines. Iroquois Pipeline. PG&E NEG owns a 5.2% interest in the Iroquois Gas Transmission System, an interstate pipeline which extends 375 miles from the U.S.-Canadian border in northern New York through the State of Connecticut to Long Island, New York. This pipeline, which commenced operations in 1991, provides gas transportation service to local gas distribution companies, electric utilities and electric power generators, directly or indirectly through exchanges and interconnecting pipelines, throughout the Northeast. The Iroquois pipeline is owned by a partnership of six U.S. and Canadian energy companies, including affiliates of TransCanada Pipeline, Dominion Resources and Keyspan Energy. Iroquois has executed firm multi-year transportation services agreements totaling more than 1,000 MMcf per day. This pipeline also provides interruptible transportation services on an as available basis. On December 26, 2001, the FERC issued a certificate of public convenience and necessity authorizing Iroquois to expand its capacity by 220 MMcf per day of natural gas and extend the pipeline into the Bronx borough of New York City for a total investment of approximately $210 million. Iroquois also filed three additional applications with the FERC to expand its system capacity, and to extend the pipeline into Eastern Long Island.45Natural Gas Transportation Services Under the FERC's current policies, transportation services are classified as either firm or interruptible, and PG&E NEG's fixed and variable costs are allocated between these types of service for ratemaking purposes. PG&E GTN provides firm and interruptible transportation services to third party shippers on a nondiscriminatory basis. Firm transportation services means that the customer has the highest priority rights to ship a quantity of gas between two points for the term of the applicable contract. Firm transportation service customers pay both a reservation charge and a delivery charge. The reservation charge is assessed for a firm shipper's right to transport a specified maximum daily quantity of gas over the term of the shipper's contract, and is payable regardless of the actual volume of gas transported by the shipper. The delivery charge is payable only with respect to the actual volume of gas transported by the shipper. Interruptible transportation service shippers pay only a delivery charge with respect to the actual volume of gas transported by the shipper. As of December 31, 2002, PG&E GTN had 93.1% of its available long-term capacity held among 48 shippers under long-term transportation contracts. The terms of these long-term firm contracts range between 1 and 40 years into the future, with a volume-weighted average remaining term of these agreements of approximately 11 years as of December 31, 2002. Approximately 95.9% of total transportation revenue was attributable to long-term contracts in 2002. PG&E GTN also offers short-term firm and interruptible transportation services plus hub services, which allow customers the ability to park or borrow volumes of gas on its pipeline. If weather, maintenance schedules and other conditions allow, additional firm capacity may become available on a short-term basis. PG&E GTN provides interruptible transportation service when capacity is available. Interruptible capacity is provided first to shippers offering to pay the maximum rate and, if necessary, allocated on a pro-rata basis to shippers offering to pay the maximum rate. If capacity remains after maximum tariff nominations are fulfilled, PG&E GTN allocates discounted interruptible space on a highest to lowest total revenue basis. In 2002, PG&E GTN provided transportation services to 70 customers. These services include capacity utilized via long-term firm, short-term firm, interruptible and hub services contracts. Short-term firm, interruptible and hub services accounted for approximately 4.1% of total transportation revenues in 2002. Approximately 92.8% of transported volumes were attributable to long-term contracts utilization in 2002. Short-term firm and interruptible volumes accounted for the remaining 4.8% and 2.4%, respectively. The total quantities of natural gas transported on the PG&E GTN pipeline for the years ended December 31, 1998 through 2002 are set forth in the following table:Year Quantities (MDth) 1998 1,003,266 1999 925,118 2000 966,653 2001 963,126 2002 915,772 At December 31, 2002, 71.8% of North Baja's available long-term capacity was held under long-term firm transportation agreements. Contracts for the remaining long-term capacity on North Baja take effect in 2003, while long-term contracted capacities associated with some contracts increase betweenMarch 2003 and 2006. At that time 100% of the available long-term capacity on North Baja will be dedicated to long-term contracts ranging between approximately 4 and 22 years into the future. As of December 31, 2002, the volume-weighted average remaining term of all long-term contracted capacities on North Baja was approximately 20 years.January 2004. As of December 31, 2002, NBP was providing transportation services for four customers, all of which had long-term firm service transportation agreements. In 2002, all volumes transported on North Baja were associated with long-term transportation service. The total quantity of natural gas transported on the North Baja pipeline (service commenced on the North Baja pipeline on September 1, 2002) through December 31, 2002, was 11,416 MDth.Ratemaking PG&E GTN's firm and interruptible transportation services have both maximum rates, which are based upon total costs (fixed and variable) and minimum rates, which are based upon the related variable costs. Rates for GTN were established in its 1994 rate case. Rates for North Baja were established in FERC's initial order certificating46construction and operations of its system. The maximum and minimum rates for each service are set forth in tariffs on file with the commission. Both PG&E GTN and North Baja are allowed to vary or discount rates between the maximum and minimum on a non-discriminatory basis. Neither PG&E GTN nor North Baja have discounted long-term firm transportation service rates, but at times PG&E GTN discounts short-term firm and interruptible transportation service rates in order to maximize revenue. Both pipelines are also authorized to offer firm and interruptible service to shippers under individually negotiated rates. Such rates may be above the maximum rate or below the minimum rate, may vary from a straight-fixed-variable, or SFV, rate design methodology, and may be established with reference to a formula. Such negotiated rates may only be offered to the extent that, at the time the shipper enters into a negotiated rate agreement, that shipper had the option to receive the same service at the recourse rate, which is the maximum rate for that service under PG&E GTN's Tariff. Both PG&E GTN's and NBP's recourse rates for firm service are designed on an SFV methodology. Under the SFV rate design, a pipeline company's fixed costs, including return on equity and related taxes, associated with firm transportation service are collected through the reservation charge component of the pipeline company's firm transportation service rates. Both pipelines also offer FERC-mandated capacity release mechanisms, under which firm shippers may release capacity to other shippers on a temporary or permanent basis. In the case of a capacity release that is not permanent, a releasing shipper remains responsible to the pipeline for the reservation charges associated with the released capacity. With respect to permanent releases of capacity, the releasing shipper is no longer responsible for the reservation charges associated with the released capacity if the replacement shipper meets the creditworthiness provisions of the pipeline's tariff and agrees to pay the full reservation fee. Based on its 1994 rate case, PG&E GTN is permitted to recover approximately 97.0% of its fixed costs (as established in 1994) through reservation charges on long-term capacity. As of December 31, 2002, GTN had 93.1% of its available long-term capacity subscribed under long-term firm contracts. Based on its initial FERC certificate, NBP is permitted to recover 98.1% of its fixed costs through reservation charges on long-term capacity. As of December 31, 2002, North Baja had 71.8% of its available long-term capacity subscribed under long-term contracts. Since these contracts are for fixed negotiated rates, North Baja will only recover a portion of its fixed costs in the initial years.47whichthat are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner'sowner’s responsibility and the availability of recoveries or contributions from third parties.General PG&E Corporation, theThe Utility and various PG&E NEG affiliates (including USGen New England, Inc., or USGenNE), areis subject to a number of federal, state and local laws and regulationsrequirements relating to the protection of the environment and humanthe safety and health of the Utility’s personnel and safety.the public. These laws and requirements relate to a broad range of activities, including:•the discharge of pollutants into air, water and soil,•the identification, generation, storage, handling, transportation, disposal, record keeping, labeling, reporting of, and emergency response in connection with, hazardous, and toxic and radioactive materials; and•land use, including endangered species and habitat protection.• The discharge of pollutants into air, water and soil; • The identification, generation, storage, handling, transportation, disposal, record keeping, labeling, reporting of, remediation of and emergency response in connection with, hazardous, and radioactive substances; and • Land use, including endangered species and habitat protection. TheyThese laws and requirements also may require the Utility, under certain circumstances, the interruptionto interrupt or curtailment ofcurtail operations. To comply with all applicablethese laws and requirements, the Utility or PG&E NEG may need to spend substantial amounts from time to time to construct, acquire, modify or acquire newreplace equipment, acquire permits and/or marketable allowances or other emission credits for facility operations modify or replace existing equipment and clean up or decommission waste disposal areas at theirthe Utility’s current or former facilities and at other third-party sites where theythe Utility may have disposed of or recycled wastes. Inpast the Utility generally has recovered the costs of complying with environmental laws and regulations in its rates. the Utility’s rates, subject to reasonableness review. Environmental costs associated with sites that contain hazardous wastes are subject to a special ratemaking mechanism.for hazardous waste remediation costs under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims (e.g.(e.g., for cleaning up the Utility’s facilities and sites to whichwhere the Utility has sent hazardous wastes)substances) from ratepayers.customers. That mechanism assignsallows the Utility to include 90% of the includable hazardous substance cleanupwaste remediation costs to Utility ratepayers and 10% to Utility shareholdersin the Utility’s rates without a review of the underlying costs. Expenditures to cover environmentalreview. Hazardous waste remediation costs in the future are likely to be significant; however,significant. However, based on the Utility'sUtility’s past experience, PG&E Corporation and the Utility believe it will be able tobelieves that it can recover most of these costs from ratepayersin rates and its insurers. PG&E Corporation andthrough insurance claims.assure you,provide assurance, however, that these costs will not be material, or that the Utility will be able to recover its costs in the future.Environmental Protection Measures The estimated expenditures of PG&E Corporation's subsidiaries for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. It is likely that the stringency of environmental regulations will increase in the future.Air Quality Utility'sUtility’s generation plants and PG&E NEG's generating plantsnatural gas pipeline operations are subject to numerous air pollution control laws, including the Federal Clean Air Act and similar state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, or SO2, nitrogen oxides or NOx,oxide and particulate matter. Fossil fuel-fired electric utility plants and gas compressor stations used in the Utility’s pipeline operations are usually major sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies.Representatives, including Senate Bill 556 and House Resolutions 1256 and 1335.Representatives. These initiatives include limits on the emissions of NOx, SO2,nitrogen oxide, sulfur dioxide, mercury and carbon dioxide, (CO2). Certain of these proposalsand some would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules.48 A multi-state memorandum of understanding dealing with Hearings on legislation to amend the control of NOx air emissions from major emission sources was signed by the Ozone Transport Commission statesfederal Clean Air Act have been held in the Mid-Atlantic and Northeastern states. The memorandum of understanding and underlying state laws establish a regional three-phase plan for reducing NOx emissions from electric generating units and large industrial boilers within the Ozone Transport Region. The NOx allowances available to each facility under the ozone season budget decreases as the program progresses and thus forces an overall reduction in NOx emissions. Under regulatory systems of this type, PG&E NEG may purchase NOx allowances from other sourcesU.S. Senate but not in the area in addition to those that are allocated to PG&E NEG facilities, insteadHouse of installing NOx emission control systems. Depending on the market conditions, the purchase of extra allowances may minimize the total cost of compliance. During Phase 3, PG&E NEG will receive fewer allowances under a reduced NOx budget. PG&E NEG plans to meet the Phase 3 budget level for its Salem Harbor and Brayton Point generating facilities with a combination of allowance purchases and emission control technologies. PG&E NEG expects that the emission reductions to be required under regulations recently issued by the Commonwealth of Massachusetts, described below, significantly reduce its need for allowance purchases.Representatives.Utility'sUtility’s divestiture of most of its fossil-fuel fired power plantsfossil fuel-fired and its geothermal generation facilities, the Utility's NOxUtility’s nitrogen oxide emission reduction compliance costs have been reduced significantly. Pursuant to the California Clean Air Act and the Federal Clean Air Act, twoTwo of the local air districts in which the Utility owns and operates fossil-fuel fired generating plantsfossil fuel-fired generation facilities have adopted final rules under the California Clean Air Act and the federal Clean Air Act that require a reductionrequired reductions in NOxnitrogen oxide emissions from the power plantsfacilities of approximately 90% by 2004 (with numerous interim2004. The Utility is in compliance deadlines).Utility's Gas Accord authorized $42 millionUtility is permitted to be includedrecover in customer rates through 20022004 the Utility’s costs for gas NOxits nitrogen oxide retrofit projects related to natural gas compressor stations on the Utility'sUtility’s Line 300, which delivers gas from the Southwest. The Gas Accord II (the extension of Gas Accord through 2003) provides for recovery of these costs in rates through 2003, and the Gas Accord II 2004 application requests recovery in rates through 2004. Othersouthwest. Several air districts are considering NOxnitrogen oxide rules that would apply to the Utility'sUtility’s other natural gas compressor stations in California. Eventually, the rules are likely to require NOxnitrogen oxide reductions of up to 80% at many of these natural gas compressor stations. Substantially all of these costs will be capital costs.costs which the Utility expects to recover through rates. certain current regulatory initiatives, particularly at the federal level, could increase the Utility's and PG&E NEG'sUtility’s compliance costs and capital expenditures primarily with respect to the Utility’s gas transportation facilities, fleet and fuel storage tanks, to comply with laws such as laws relating to emissions of carbon dioxide and other greenhouse gases, particulates and various other toxic pollutants. If enacted, these programslaws could require the Utility and PG&E NEG 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 from ratepayers. The Utility will be required to incur substantialand capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission related issues.rates.Water Quality Federal Clean Air Act's acid rain provisions also require substantial reductions in SO2 emissions. Implementation of the acid rain provisions is achieved through a total cap on SO2 emissions from affected units and an allocation of marketable SO2 allowances to each affected unit. Operators of electric generating units that emit SO2 in excess of their allocations can buy additional allowances from other affected sources. The EPA also has been conducting a nationwide enforcement investigation regarding the historical compliance of coal-fueled electric generating stations with various permitting requirements of the Federal Clean Air Act. Specifically, the EPA and the U.S. Department of Justice recently have initiated enforcement actions against a number of electric utilities, several of which have entered into substantial settlements for alleged Federal Clean Air Act violations related to modifications (sometimes more than 20 years ago) of existing coal-fired generating facilities. In May 2000, USGenNE received an Information Request from the EPA pursuant to Section 114 of the Federal Clean Air Act. The Information Request asked USGenNE to provide certain information relative to the compliance of USGenNE's Brayton Point and Salem Harbor Generating Stations with the Federal Clean Air Act. No enforcement action has been brought by the EPA to date. USGenNE has had very preliminary discussions with the EPA to explore a potential settlement of this matter. It is not possible to predict whether any such settlement will occur or, in the absence of a settlement, the likelihood of whether the EPA will bring an enforcement action. In addition to the EPA, states may impose more stringent air emissions requirements. On May 11, 2001, the Massachusetts Department of Environmental Protection (DEP) issued regulations imposing new restrictions on emissions of Nox, SO2, mercury, and CO2 from existing coal- and oil-fired power plants. These restrictions will impose more stringent annual and monthly limits on NOx and SO2 emissions than currently exist and will take49effect in stages, beginning in October 2004 if no permits are needed for the changes necessary to comply, and beginning in 2006 if such permits are needed. The regulations contemplate that affected parties will file compliance plans, based on which the DEP would decide whether these permits were required. In addition, mercury emissions are capped as a first step and must be reduced by October 2006 pursuant to standards to be developed. CO2 emissions are regulated for the first time and must be reduced from recent historical levels. USGenNE believes that compliance with the CO2 caps can be achieved through implementation of a number of strategies, including sequestrations and offsite reductions. Various testing and record keeping requirements also are imposed. The new Massachusetts regulations affect primarily USGenNE's Brayton Point and Salem Harbor generating facilities. USGenNE filed its plan to comply with the new regulations with the DEP at the end of 2001. The DEP has ruled that Brayton Point is required to meet the newer, more stringent emission limitations for SO2 and NOX by 2006. It has also ruled that Salem Harbor is required to meet these limitations by 2004. Although USGenNE intends to appeal DEP's ruling that Salem Harbor must comply with the new reglations by 2004, in the absence of a successful appeal of DEP's ruling, the compliance date for Salem Harbor remains 2004. USGenNE will not be able to operate Salem Harbor unless it is in compliance with these emission limitations. USGenNE believes that it is impossible to meet the 2004 deadline. Consequently, it may be unable to operate the facility beyond the 2004 deadline. Through 2006, and assuming that USGenNE prevails in its appeal of the 2004 deadline, it may be necessary to spend approximately $266 million to comply with these regulations. It is possible that actual expenditures may be higher. USGenNE has not made any commitments to spend these amounts. In the event that USGenNE does not spend required amounts to meet each facility's compliance deadline, USGenNE may not be able to operate the facilities. The EPA is required under the Federal Clean Air Act to establish new regulations for controlling hazardous air pollutants from combustion turbines and reciprocating internal combustion engines. Although the EPA has yet to propose the regulations, the Federal Clean Air Act required that they be promulgated by November 2000. Another provision in the Federal Clean Air Act requires companies to submit case-by-case Maximum Achievable Control Technology (MACT) determinations for individual plants if the EPA fails to finalize regulations within eighteen months past the deadline. On April 5, 2002, the EPA promulgated a regulation that extends this deadline for the case-by-case permits until May 2004. The EPA intends to finalize the MACT regulations before this date, thus eliminating the need for the plant-specific permits. It is not possible to accurately quantify the economic impact of the future regulations until more details are available through the rulemaking process. Global climate change is a significant environmental issue that is likely to require sustained global action and investment over many decades. PG&E Corporation has been engaged on the climate change issue for several years and is working with others on developing appropriate public policy responses to this challenge. PG&E Corporation continuously assesses the financial and operational implications of this issue; however, the outcome and timing of these initiatives are uncertain. There are six greenhouse gases. The Utility and PG&E NEG emit varying quantities of these greenhouse gases, including carbon dioxide and methane, in the course of their operations. Depending on the ultimate regulatory regime put into place for greenhouse gases, PG&E Corporation's operations, cash flows and financial condition could be adversely affected. Given the uncertainty of the regulatory regime, it is not possible to predict the extent to which climate change regulation will have a material adverse effect on the Utility's or PG&E NEG's financial condition or results of operations. PG&E NEG and the Utility are taking numerous steps to manage the potential risks associated with the eventual regulation of greenhouse gases, including but not limited to preparing inventories of greenhouse gas emissions, voluntarily reporting on these emissions through a variety of state and federal programs, engaging in demand side management programs that prevent greenhouse gas emissions, and supporting market-based solutions to the climate change challenge.Water Quality The Federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or the U.S. Environmental Protection Agency, or the EPA. All of PG&E NEG'sThe Utility’s generation facilities that are required to have such permits either have them or have timely applied for extensions of expired permits and are operating in substantial compliance with the prior permit. At this time, three of the fossil-fuel plants owned and operated by USGenNE (Manchester Street, Brayton Point, and Salem Harbor stations) are operating pursuant to permits that have expired. For the facilities whose water50discharge permits (National Pollutant Discharge Elimination System (NPDES)) have expired, permit renewal applications are pending, and USGenNE anticipates that all three facilities will be able to continue to operate in substantial compliance with prior permits until new permits are issued. It is possible that the new permits may contain more stringent limitations than the prior permits. At Brayton Point, unlike the Manchester Street and Salem Harbor generating facilities, PG&E NEG has agreed to meet certain restrictions that were not in the expired NPDES permit. In October 1996, the EPA announced its intention to seek changes in Brayton Point's NPDES permit based on a report prepared by the Rhode Island Department of Environmental Management, which alleged a connection between declining fish populations in Mt. Hope Bay and thermal discharges from the Brayton Point once-through cooling system. In April 1997, the former owner of Brayton Point entered into a Memorandum of Agreement, or MOA, with various governmental entities regarding the operation of the Brayton Point station cooling water systems pending issuance of a renewed NPDES permit. This MOA, which is binding on PG&E NEG, limits on a seasonal basis the total quantity of heated water that may be discharged to Mt. Hope Bay by the plant. While the MOA is expected to remain in effect until a new NPDES permit is issued, it does not in any way preclude the imposition of more stringent discharge limitations for thermal and other pollutants in a new NPDES permit and it is possible that such limitations will in fact be imposed. On July 22, 2002 the EPA and the DEP issued a draft NPDES permit for Brayton Point that, among other things, substantially limits the discharge of heat by Brayton Point into Mount Hope Bay. USGenNE believes that the permit is excessively stringent and estimates that the cost to comply with it could be as much as $248 million through 2006. This is a preliminary estimate. There are various administrative and judicial proceedings that must be completed before the draft NPDES permit becomes final and these proceedings are not expected to be completed during 2003. In addition, the EPA, as well as local environmental groups, have previously expressed concern that the metal vanadium is not addressed at Brayton Point or Salem Harbor under the terms of the old NPDES permits and it may raise this issue in upcoming NPDES permit negotiations. Based upon the lack of an identified control technology, PG&E NEG believes it is unlikely that the EPA will require that vanadium be addressed pursuant to a NPDES permit. However, if the EPA does insist on including vanadium in the NPDES permit, PG&E NEG may have to spend a significant amount to comply with such a provision. If these more stringent discharge limitations are imposed, compliance with them could have a material adverse effect on PG&E NEG's financial condition, cash flows, and results of operations. The Utility's existing power plants, including Diablo Canyon, also are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Utility's fossil-fuel fired power plantsUtility’s steam-electric generation facilities comply in all material respects with the discharge constituents standards and the thermal standards. Additionally, pursuant to Section 316(b) ofIn addition, under the Federalfederal Clean Water Act, the Utility is required to demonstrate that the location, design, construction and capacity of power plantgeneration facility cooling water intake structures reflect the best technology available or BTA, for minimizing adverse environmental impacts at its existing water-cooled thermal plants. The Utility has submitted detailed studies of each power plant'ssteam-electric generation facility’s intake structure to various governmental agencies and each plant'spower plant’s existing intake structure was found to meet the BTAbest technology available requirements.Power Plantpower plant employs a "once through"“once-through” cooling water system that is regulated under a National Pollutant Discharge Elimination System, or NPDES, permit issued by the Central Coast Regional Water Quality Control Board, or the Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, recreation, commercial/sport fishing, marine and wildlife habitat, shellfish harvesting and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon'sCanyon power plant’s discharge was not protective of beneficial uses. and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility'sUtility’s discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology meets the BTAbest technology available requirements. As part of the Central Coast settlement agreement, the Utility willhas 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. The parties are negotiatingOn March 21, 2003, the documentation ofCentral Coast Board voted to accept the settlement. The finalCentral Coast settlement agreement. On June 17, 2003, the Central Coast settlement agreement will be subject to public comment prior to final approvalwas executed by the Utility, the Central Coast Board and once signed by the parties, will be incorporated in a consent decree to be entered in California Superior Court. A claim has been filed by 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. However, at its July 10, 2003 meeting, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported this settlement agreement, and the Central Coast Board requested its staff to develop additional information on possible mitigation measures. The California Attorney General filed a claim in the Utility's bankruptcyUtility’s Chapter 11 proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with the Diablo Canyon'sCanyon power plant’s operation of its cooling water system. The Utility is seeking withdrawal of this claim from the Utility’s Chapter 11 proceeding.51December 1999, the Utility was notified by the purchaser of the Utility's former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water from the intake, and that this procedure is not specified in the plant's NPDES permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. The purchaser notified the Central Coast Board of its findings. In March 2002, the Utility and the Central Coast Board reached a tentative settlement of this matter under which the Utility will fund approximately $5 million in environmental projects related to coastal resources. The final agreement will be subject to public comment and will be incorporated in a consent decree to be entered in the California Superior Court. The California Attorney General has filed a claim in the Utility's bankruptcy case to preserve the Board's claim. Additionally,addition, on April 9, 2002, the EPA proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing powerelectricity generation facilities using over 50 million gallons per day, (mgd), typically including some form of "once-through"“once-through” cooling. The Utility'sUtility’s Diablo Canyon, Hunters Point and Humboldt Bay power plants and PG&E NEG's Brayton Point, Salem Harbor, and Manchester Street generating facilities are among an estimated 539 plantsgenerationPG&E CorporationIn mid-January 2004, hexavalent chromium was detected in a sample taken from a groundwater monitoring well near the Utility’s natural gas compressor station located near Topock, Arizona. This monitoring well is located approximately 150 feet from the Colorado River. While hexavalent chromium had been detected during previous sampling of other monitoring wells located further from the river, previous samples from this well had not shown any detectable hexavalent chromium. The Utility is cooperating with the California Department of Toxic Substances Control, or DTSC, other state agencies and appropriate federal agencies to develop a plan to ensure that the hexavalent chromium does not impact the Colorado River. Although implementation of the plan poses several technical and regulatory obstacles, the Utility believedoes not expect the ultimate outcome of these matters will notin this matter to have a material impactadverse effect on their consolidated financial position orits results of operations.operations or financial condition.Endangered Species The issuance or modification of statutes, regulations, or water quality control plans at the federal, state, or regional level may impose increasingly stringent cooling water discharge requirements on the Utility's and PG&E NEG's power plants in the future. Costs to comply with new permit conditions required to meet more stringent requirements that might be imposed cannot be estimated at the present time.Endangered SpeciesUtility'sUtility’s facilities and operations are located in or pass through areas that are designated as critical habitats for federal or state-listed endangered, threatened or sensitive species. The Utility may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated near the Utility'sUtility’s facilities or operations.Hazardous Waste Compliance The Utility is seeking to secure “habitat conservation plans” to ensure long-term compliance with the state and Remediationfederal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.Hazardous Waste Compliance and Remediation Utility's and PG&E NEG'sUtility’s facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act, or RCRA, and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, along withas well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of required health studies. In the ordinary course of the Utility'sUtility’s operations, the Utility has generated, and continues to generate,generates waste that falls within CERCLA'sCERCLA’s definition of a hazardous substance and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.and PG&E NEG assess,assesses, on an ongoing basis, measures that may need to be takennecessary to comply with federal, state and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility and PG&E NEG havehas a comprehensive program to comply with hazardous waste storage, handling and disposal requirements issued by the EPA under RCRA and CERCLA, along with other state hazardous waste laws and other environmental requirements.52TheUnder federal and California laws, the Utility may be responsible for remediation of hazardous substances even if the Utilityit did not deposit those substances on the site.Utility'sUtility’s current and former power plantsgeneration facilities may have resulted in contaminated soil or groundwater. Although the Utility has sold most of its geothermal generation facilities and most of its fossil fuel-fired and geothermal power plants, in connection with electric industry restructuring, in many cases the Utility retained pre-closing environmental liability with respect to these plants under various environmental laws. The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies.Utility's electricUtility’s electricity distribution system.One part of the Utility's programThe Utility is aimed at assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation infrom the late 1800s andmid-1800s through the early 1900s, manufactured gas plants produced lampblack and tar residues. The lampblack and tar residues are byproducts of a process that the Utility, its predecessor companies, and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), the Utility'sUtility’s manufactured gas plants were removed from service. The residues that may remain at some sites contain chemical compounds that now are classified as hazardous. The Utility owns all or a portion of 28 manufactured gas plant sites. The Utility has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites that are owned by the Utility.these sites. The Utility spent approximately $4$8 million in 20022003 and expects to spend approximately $11$6 million in 20032004 on suchthese projects. The Utility expects that expenses will increase as remedial actions related to these sites are approved by regulatory agencies. In addition, approximately 68 other manufactured gas plants in the Utility'sUtility’s service territory are now owned by numerous third parties, andothers. The Utility has not incurred any significant costs associated with these non-owned sites, but it is possible that the Utility may incur additional cleanup costs related to these sites in the future.future if hazardous substances for which the Utility has liability are found.wasteswaste from the Utility'sUtility’s facilities, or to pay for associated cleanup costs or natural resource damages. The Utility is currently aware of 8eight such sites where investigation or cleanup activities are currently underway. For example, atAt 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.the Utilityit no longer owns or never owned. Remedial actions may include investigations, health and ecological assessments and removal of wastes.hazardous substanceenvironmental remediation ultimately undertaken by the Utility is difficult to estimate. It is reasonably possible that a change in the estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and the Utility can estimate a range of reasonably likely cleanup costs. The Utility reviews its remediation liability quarterly for each identified site.site where the Utility may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, enacted laws and regulations, experience gained at similar sites and the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the costs at the lower end of this range. AtIt 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.2002,2003, and $331 million at December 31, 2002. During 2003, the liability was reduced by approximately $17 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately $314 million accrued at December 31, 2003, includes approximately $104 million related to the pre-closing remediation liability associated with divested generation facilities, and approximately $210 million related to remediation costs for those generation facilities that the Utility expected to spend $331 million, undiscounted for the effect of future inflation, for hazardous waste remediation costs at identifiedstill owns, natural gas gathering sites, including divested fossil-fuel fired power plants, where such costscompressor stations, third-party disposal sites, and manufactured gas plant sites that are probable and quantifiable. (Althougheither owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites. Of the approximately $314 million environmental remediation liability, approximately $147 million has sold most of its fossil-fuel fired power plants,been included in prior rate-setting proceedings, and the Utility has retained pre-closing environmental liability with respectexpects that approximately $116 million will be allowable for inclusion in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to these plants.) Ifrefund to ratepayers.further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated,anticipated. The $422 million amount does not include an estimate for the Utility's future cost could be as much as $469 million. The Utility estimatedcosts of remediation at known sites owned or operated in the upper limit ofpast by the range of costs using assumptions least favorable toUtility’s predecessor corporations for which the Utility based upon a range of reasonably possible53outcomes. Costs may be higher if the Utility is foundhas not been able to be responsible for cleanup costs at additional sites or identifiable possible outcomes change.determine whether liability exists.On June 26, 2001, the Bankruptcy Court authorized the Utility to spend•up to $22 million in each calendar year in which the Chapter 11 case is pending to continue its hazardous substance remediation programs and procedures, and•any additional amounts necessary in emergency situations involving post-petition releases or threatened releases of hazardous substances, if such excess expenditures are necessary in the Utility's reasonable business judgment to prevent imminent harm to public health and safety or the environment (provided that the Utility seeks the Bankruptcy Court's approval of such emergency expenditures at the earliest practicable time).Utility's bankruptcy caseUtility’s Chapter 11 proceeding for environmental remediation at numerous sites totaling approximately $770 million. For most if not allof these sites, remediation is ongoing in the ordinary course of business or the Utility is in the process of remediating the sitesremediation in cooperation with the relevant agencies and othersother parties responsible for contributing to the cleanup or would be doing socleanup. Other sites identified in the future,California Attorney General’s claims may not, in the normal coursefact, require remediation or cleanup actions. The Utility’s Plan of business. The Utility's proposed plan of reorganizationReorganization provides that either the Utility or the LLCs will satisfyintends to respond to these types of claims in the regularordinary course of businesses,business and since the Utility has not argued that the bankruptcyChapter 11 proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the California Attorney General’s claims seeking specific cash recoveries are invalid. USGenNE assumed the onsite environmental liability associated with its acquisition of electric generating facilities from New England Electric System in 1998, but did not acquire any off-site liability associated with the past disposal practices at the acquired facilities. PG&E NEG has obtained pollution liability and environmental remediation insurance coverage to limit, to a certain extent, the financial risk associated with the on-site pollution liability at all of its facilities. Recently, the EPA indicated that it might begin to regulate fossil fuel combustion materials, including types of coal ash, as hazardous waste under RCRA. If the EPA implements its initial proposals on this issue, USGenNE may be required to change its current waste management practices and expend significant resources on the increased waste management requirements caused by the EPA's change in policy. During April 2000, an environmental group served various affiliates of PG&E NEG, including USGenNE, with a notice of intent to file a citizen's suit under RCRA. In September 2000, PG&E NEG signed a series of agreements with the Massachusetts Department ofunenforceable. Environmental Protection and the environmental group to resolve these matters that require USGenNE to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. USGenNE began the activities during 2000 and expects to complete them in 2003. USGenNE has incurred expenditures related to these agreements of approximately $4.7 million in 2002, $2.6 million in 2001 and $5.4 million in 2000. In addition to the costs incurred in 2000, 2001 and 2002, at December 31, 2002, USGenNE maintains a reserveclaims in the amountordinary course of $6 million relating to its estimate ofbusiness will not be discharged in the remaining environmental expenditures to fulfill its obligations under these agreements.Potential Recovery of Hazardous Waste ComplianceUtility’s Chapter 11 proceeding and Remediation Costs To the extent the Utility knows or can estimate the costs of hazardous waste compliance and remediation costs, the Utility intends to seek recovery for these costs in its filed rateswill pass through the normal ratemaking proceedings before the CPUC. In 1994, the CPUC established a ratemaking mechanism for hazardous waste remediation costs, or HWRC. That mechanism assigns 90% of the includable hazardous substance cleanup costs to utility ratepayers and 10% to utility shareholders, without a reasonableness review of such costs or of underlying activities. Under the HWRC mechanism, 70% of the ratepayer portion of the Utility's cleanup costs is attributed to its gas department and 30% is attributed to its electric department. Insurance recoveries are assigned 70% to shareholders and 30% to ratepayers until both are reimbursed for the costs of pursuing insurance recoveries. The balance of insurance recoveries is allocated 90% to shareholders and 10% to ratepayers until shareholders are reimbursed for their 10% share of cleanup costs. Any unallocated funds remaining are held for five years and then distributed 60% to ratepayers and 40% to shareholders over the next five years. The Utility can seek to recover hazardous substance cleanup costs under the HWRC in the rateChapter 11 proceeding that it deems most appropriate. In connection with electric industry restructuring, the HWRC mechanism may no longer be used to recover electric generation-related cleanup costs for contamination caused by events occurring after January 1, 1998.unimpaired.Nuclear Fuel Disposal 54 For each divested generation facility for which the Utility retained environmental remediation liabilities, the plant's decommissioning cost estimate was adjusted by the Utility's estimated forecast of environmental remediation costs. (The buyers assumed the non-environmental decommissioning liability for these plants.) The CPUC ordered that excess recoveries of environmental and non-environmental decommissioning accruals related to the divested plants be used to offset other transition costs. As of December 31, 2002, the Utility had recovered from ratepayers approximately $138 million for environmental decommissioning accrual related to the divested plants. This amount will earn interest at 3% per year that will be used to meet the future environmental remediation costs for the divested plants. The net decommissioning accruals recovered from ratepayers attributable to the non-environmental liability for the divested plants was approximately $50 million. Because the Utility no longer has this non-environmental decommissioning liability, it has used this excess recovery amount to reduce other transition costs. The $331 million accrued environmental remediation liability at December 31, 2002, mentioned above, includes•$138 million related to the pre-closing remediation liability, discounted to present value at 7%, associated with divested generation facilities (see further discussion in the "Generation Divestiture" section of Note 2 of the Notes to the Consolidated Financial Statements of the 2002 Annual Report to Shareholders), and•$193 million related to remediation costs for those generation facilities, manufactured gas plant sites, gas gathering sites, and compressor stations that the Utility still owns. Of the $331 million environmental remediation liability, the Utility has recovered $188 million through rates, and expects to recover another $84 million in future rates. The Utility is seeking recovery of the remainder of its costs from insurance carriers and from other third parties as appropriate. The ultimate amount of recovery from insurance coverage, either in the aggregate or with respect to a particular site, cannot be quantified at this time. Insurance recoveries are subject to the HWRC mechanism discussed above.Nuclear Fuel Disposal. the U.S. Department of Energy, or the DOE is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Waste Act mandates that one or more such permanent disposal sites be in operation by 1998. Consistent with the law, the Utility signedentered into a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Utility'sUtility’s nuclear power facilities beginning not later than January 1998. However, due to delays in identifying a storage site, theThe DOE has been unable to meet its contractcontractual commitment to begin accepting spent fuel by January 1998. Further, under the DOE's current estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel may not be accepted byfuel. First, there was a delay in identifying a storage site. Then, after the DOE for interim or permanent storage before 2010, at the earliest. At the projected level of operation for Diablo Canyon, the Utility's facilities are sufficient to store on-site all spent fuel produced through approximately 2007 while maintaining the capability for a full-core off-load. It is likely that an interim or permanent DOE storage facility will not be available for Diablo Canyon's spent fuel by 2007. In December 2001, the Utility filed a request with the NRC for a license to build a dry cask storage system to store spent fuel at Diablo Canyon, pending disposal or storage at a DOE facility. A hearing in this proceeding is scheduled for May 2003. In February 2002, the DOE formally recommended, and President Bush approved,selected Yucca Mountain, Nevada asfor the site, protracted litigation has prevented the DOE from constructing the storage facility. The DOE’s current estimate for a permanent spent fuel repository. The State of Nevada vetoed thisan available site but the U.S. Congress overrode this veto with a House of Representatives vote in May 2002 and a Senate vote in July 2002, and the bill was subsequently signed by President Bush. As a result, the State of Nevada has filed a number of suits in various federal courts to stop the NRC's licensingbegin accepting physical possession of the site. If Yucca Mountainspent nuclear fuel is ultimately determined to be acceptable as the repository site, the DOE will proceed with the licensing and eventual construction of the repository and may begin receipt of spent fuel as early as 2010. However, considerable uncertainty exists regarding the time frame under whichwhen the DOE will begin to accept spent fuel for storage or disposal. If Yucca Mountain is completedUnder the Utility’s contract with the DOE, if the DOE completes a storage facility by 2010, the earliest Diablo Canyon'sCanyon’s spent fuel would be accepted by Yucca Mountain for storage or disposal would be 2018.55 On January 22, 2004, the Utility filed separate complaints in the U.S. Court of Federal Claims against the DOE alleging that the DOE has breached its contractual obligation to move used nuclear fuel from Diablo Canyon and Humboldt Bay Unit 3 to a national repository beginning in 1998. The complaints seek recovery of the Utility’s costs incurred for the planning and development of on-site storage at both facilities as a result of the DOE’s failure to meet its obligations. The Utility’s complaints are similar to complaints filed by at least 20 other utilities with nuclear facilities. to the Utility to store radioactive waste from the Utility’s retired nuclear generating unitfacility, Humboldt Bay Unit 3, at the plant until 2015 before ultimately decommissioning the unit. The Utility has agreed to remove all spent fuel when the federal disposal site is available. In 1988, the Utility completed the first step in the decommissioning of Humboldt Bay Unit 3 and placed the unit into a custodial mode of decommissioning called SAFSTOR. This isSAFSTOR, a condition of monitored safe storage in which the unit will be maintained until the spent nuclear fuel is removed from the spent fuel pool and the facility is dismantled. The used fuel assemblies currently are stored in metal racks submerged in a pool of water i.e.,called a wet storage pool. The specially designed storage pool is constructed of steel-reinforced concrete and lined with stainless steel.currently is exploring licensing and permitting offiled an application in December 2003 with the NRC seeking authorization to build an on-site dry cask storage facility at Humboldt Bay Unit 3. The Utility plans to file an application with the California Coastal Commission for a permit to build the facility. Transfer of spent fuel to a dry cask facility would allow early decommissioning of Humboldt Bay Unit 3. The Utility anticipates that, if it were licensed to employ an on-site dry cask storage facility, itthe Utility would receive a 20-year initial license for on-site dry cask storage with the opportunity to receive a 20-year renewal term.Nuclear Decommissioning Nuclear Decommissioning The Utility's nuclear power facilities are scheduled to begin, for ratemaking purposes, decommissioning in 2015 and scheduled for completion in 2041. Nuclear decommissioning means (1)requires the safe removal of nuclear facilities from service and (2) the reduction of residual radioactivity to a level that permits termination of the Nuclear Regulatory CommissionNRC license and release of the property for unrestricted use. The Utility’s nuclear power facilities consist of two units at the Diablo Canyon power plant and the retired facility at Humboldt Bay Unit 3. For ratemaking purposes, the eventual decommissioning of Diablo Canyon Unit 1 is scheduled to begin in 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 2006 and be completed in 2015.total obligation for nuclear decommissioning costs based on a February 2002 site study, is $1.9for the Diablo Canyon power plant and Humboldt Bay Unit 3 are approximately $1.83 billion in 20022003 dollars (or $8.4approximately $5.25 billion in future dollars). The Utility's future estimate isThese estimates are based upon its 2001 estimated obligation assuming an annual escalation rate of 5.5% foron a 2002 decommissioning costs. This estimate includes labor, materials, waste disposal charges,cost study, prepared in accordance with CPUC requirements, and other costs. A contingency of 40% to capture engineering, regulatory, and business environment changes is includedused in the total estimated obligation. The Utility plans to fund these costs from independent decommissioning trusts, which receive annual contributionsUtility’s Nuclear Decommissioning Costs Triennial Proceeding discussed further below. The Utility estimates after-tax annual earnings, including realized gains and losses, on the tax-qualified decommissioning funds of 6.34% and non-tax-qualified decommissioning funds of 5.39%. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility'sUtility’s nuclear plants. Actual decommissioning costs are expected to vary from this estimate because of changes in assumed dates of decommissioning, regulatory requirements, technology, costs of labor, materials and equipment.total obligation is being recognized proportionately overdecommissioning costs and to establish the license term of each facility. At December 31,associated annual revenue requirement and escalation factors for consecutive three-year periods. In October 2003, the CPUC issued a decision in the 2002 Nuclear Decommissioning Costs Triennial Proceeding (covering 2003 through 2005) finding that the totalfunds in the Diablo Canyon nuclear decommissioning obligation accrued was $1.3 billion.trusts are sufficient to pay for the Diablo Canyon power plant’s eventual decommissioning. The decision also set the annual decommissioning fund revenue requirement forSince January 1, 1998,The Utility’s revenue requirements for nuclear decommissioning costs which are not transition costs, have been recovered from customersratepayers through a non-bypassablenonbypassable charge that will continue until those costs are fully recovered. Recovery of decommissioning costs may be accelerated to the extent possible under the rate freeze. For the year ended December 31, 2002, annual nuclear decommissioning trust contributions collected in rates were $24 million and this amount was contributed to the trusts. The CPUC has established a Nuclear Decommissioning Costs Triennial Proceeding to determine the decommissioning costs and to establish the annual revenue requirement and attrition factors over subsequent three-year periods. On March 15, 2002, the Utility filed its 2002 Nuclear Decommissioning Cost Triennial Proceeding application seeking to increase its nuclear decommissioning revenue requirements for the years 2003 through 2005 and to begin decommissioning of Humboldt Bay Unit 3 in 2006, instead of 2015. The Utility estimates a total decommissioning cost of approximately $299 million, stated in 2002 dollars, for Humboldt Bay Unit 3 presuming that the CPUC approves this earlier decommissioning schedule. The Utility seeks recovery of $24 million in revenue requirements relating to the Diablo Canyon Nuclear Decommissioning Trusts and $17.5 million in revenue requirements relating to the Humboldt Bay Power Plant Decommissioning Trusts. The Utility also seeks recovery of $7.3 million in CPUC-jurisdictional revenue requirements for Humboldt Bay Unit 3 SAFSTOR operating and maintenance costs, and escalation associated with that amount in 2004 and 2005. The Utility proposes continuing to collect the revenue requirement through a non-bypassable charge in electric rates, and to record the revenue requirement and the associated revenues in a balancing account. The CPUC held hearings on the application in September 2002 and is scheduled to issue a final decision in April 2003.externalnuclear decommissioning trusts. The Utility has three decommissioning trusts for its Diablo Canyon and Humboldt Bay Unit 3 nuclear facilities. The Utility has elected that two of these trusts be treated under the Internal Revenue Code as qualified trusts. If certain conditions are met, the Utility is allowed a deduction for the payments made to the qualified trusts. These payments cannot exceed the amount collected from ratepayers through the decommissioning charge. The qualified trusts are subject to a lower tax rate on income and capital gains, thereby increasing the trusts’ after-tax returns. Among other requirements, to maintain the qualified trust funds. Thesestatus, the Internal Revenue Service, or IRS, must approve the amount to be contributed to the qualified trusts for any taxable year. The remaining non-qualified trust is exclusively for decommissioning Humboldt Bay Unit 3. The Utility cannot deduct amounts contributed to the non-qualified trust until the decommissioning costs are actually incurred.MoniesAmounts may not be released from the externaldecommissioning trusts until authorized by the CPUC. At December 31, 2002,2003, the Utility had accumulated externaldecommissioning trust funds with an estimated liquidationfair value of $1.3approximately $1.4 billion, based on quoted market prices and net of deferred taxes on unrealized gains, to be used for the decommissioning of the Utility's nuclear facilities.gains.Electric and Magnetic Fields 56Compressor Station Litigation Several lawsuits have been filed against Pacific Gas and Electric Company seeking damages from alleged chromium contamination at the Utility's Hinkley, Topock, and Kettleman Compressor Stations. See Item 3 "Legal Proceedings—Compressor Station Chromium Litigation" below for a description of the pending litigation.Electric and Magnetic Fields and magnetic fields, or EMFs, naturally result from the generation, transmission, distribution and use of electricity. In January 1991, the CPUC opened an investigation into potential interim policy actions to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with EMFs from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMFs, but went on to state that a body of evidence has been compiled that raises the question of whether adverse health impacts might exist.andor upgraded utility facilities. California energy utilities were required to fund an EMF education program anditsthe Utility’s effort to educate the public about EMFs, the Utility provides interested customers with information regarding the EMF exposure issue. The Utility also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.electric and magnetic fieldsEMFs, to the CPUC and the public. The report'sreport’s conclusions contrast with other recent reports by authoritative health agencies in that the California Department of Health Services'Services’ report has assigned a higher probability to the possibility that there is a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis and miscarriages.relocation ofthe Utility must ultimately relocate existing power lines ultimately is required.lines.EMFEMFs from power lines. The Courtcourt expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMFs are similarly barred. The Utility was a defendantone of the defendants in civil litigation in which plaintiffs alleged personal injuries resulting from exposure to EMFs. In January 1998, the appeals court in this matter held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMFs and barred plaintiffs'plaintiffs’ personal injury claims. Plaintiffs filed an appeal of this decision with the California Supreme Court. The California Supreme Court declined to hear the case.Low Emission Vehicle Programs In December 1995, the CPUC issued its decision in the Low Emission Vehicle (LEV) proceeding, which approved approximately $42 million in funding for the Utility's LEV program for the six-year period beginning in 1996. The LEV program expired on December 20, 2001. On January 23, 2002, the CPUC approved bridge funding of $7 million for the LEV program. On March 25, 2002, the Utility requested the CPUC approve funding for the continuation of its LEV program. The other California utilities filed similar requests. In June 2002, the CPUC determined that issues related to research, development and demonstration, and customer education would be heard in the LEV proceeding, but that issues related to fleet vehicle acquisition, fueling and charging infrastructure, and operation and maintenance of Utility infrastructure would be addressed in the Utility's 2003 general rate case. Hearings in the LEV proceeding were held in August 2002. The 2003 general rate case was filed in November 2002. The Utility has requested funding of $5 million in the LEV proceeding and approximately $7.4 million for LEV-related costs in the 2003 general rate case. On December 19, 2002, LEV interim funding of57$7 million was extended pending the CPUC's final decisions in both the LEV proceedings and the general rate case. A final decision in the LEV proceeding is expected by the end of March 2003.ITEM 2. Properties. Information concerning Pacific Gas and Electric Company's electric generation units, electric and gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1 "Business." All of the Utility's real properties and substantially all of the Utility's personal properties are subject to the lien of an indenture that provides security to the holders of the Utility's First and Refunding Mortgage Bonds.Item 2. Properties. Utility'sUtility’s corporate headquarters consist of approximately 1.71.8 million square feet of owned office space located in several buildings in San Francisco, California. In addition to owned office space, the Utility leases approximately 628,000 square feet of office space from third parties in San Francisco. In addition to this corporate office space, the Utility owns or has obtained the right to occupy and/or use real property comprising its electricthe 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 "Electric“— Electricity Utility Operations"Operations” and "Gas“— Gas Utility Operations."” In total, the Utility occupies 9.3 million square feet, including approximately 975,000 square feet of leased office space. The Utility occupies or uses real property that it does not own chieflyprimarily through various leases, easements, rights-of-way, permits or licenses from private landowners or governmental authorities. The Utility alsocurrently owns approximately 170,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements or donate to public agencies or non-profit conservation organizations under the settlement agreement with the CPUC. Approximately 44,000 acres of this land may be either donated or encumbered with conservation easements. The remaining land contains the Utility’s or a joint licensee’s hydroelectric generation facilities and may only be encumbered with conservation easements.184 other facilities, including service centers, customer service offices, material distribution centers, training/conference centers, and74,000 square feet of office space totaling 5.9 million square feetfrom a third party in the aggregate.San Francisco, California. This lease expires in 2005.Item 3. Legal Proceedings. Information concerning properties and facilities owned by PG&E NEG and other PG&E Corporation subsidiaries is included in the discussion under the heading of this report entitled "PG&E National Energy Group, Inc."ITEM 3. Legal Proceedings. See Item 1 "Business" for other proceedings pending before governmental and administrative bodies. In addition to the following legal proceedings, PG&E Corporation and Pacific Gas and Electric Companythe Utility are subject to routine litigation incidental toinvolved in various legal proceedings in the ordinary course of their business.BankruptcyChapter 11 FilingPacific Gas and Electric Companythe Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Bankruptcy Code, in the U.S. Bankruptcy Court for the Northern District of California, or Bankruptcy Court. PursuantCalifornia. The factors that caused the Utility to take this action are discussed in MD&A and in Note 2 of the Notes to the Consolidated Financial Statements in the Annual Report, which is incorporated by reference into this report. During the Utility’s Chapter 11 of the U.S. Bankruptcy Code,proceeding, the Utility retainshas retained control of its assets and is authorized to operate its business as a debtor-in-possession while beingit is subject to the jurisdiction of the Bankruptcy Court. For more information aboutbankruptcy court.Utility's financial conditionUtility, is Vice Chairman of J.P. Morgan Chase & Co. and J.P. Morgan Chase Bank. J.P. Morgan Trust Co. of Delaware submitted a proof of claim in the Utility’s Chapter 11 case for approximately $1.45 million relating to its ownership interest in shares of the Utility’s preferred stock. J.P. Morgan Chase Bank submitted a proof of claim for approximately $173 million, related to its provision of a stand-by letter of credit which provides credit and liquidity support for certain of the Utility’s pollution control bonds. Both entities are subsidiaries of J.P. Morgan Chase & Co.factors leading upUtility submitted a plan of reorganization that proposed to disaggregate the filingUtility’s current businesses. The CPUC, later joined by the Official Committee of Unsecured Creditors, or OCC, submitted a competing proposed plan of reorganization that did not provide for bankruptcy protection, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 2disaggregation of the 2002 Annual ReportUtility’s businesses. As discussed above, on December 19, 2003, the CPUC, PG&E Corporation and the Utility entered into the Settlement Agreement that contemplated a new plan of reorganization to Shareholders, which portions are incorporated herein by reference andsupercede the competing plans. Under the Settlement Agreement, the Utility remains vertically integrated. On December 22, 2003, the bankruptcy court confirmed the Plan of Reorganization that fully incorporates the Settlement Agreement.as Exhibit 13 to this report. Bankruptcy law imposes an automatic stay to prevent parties from making certain claims or taking certain actions that would interferea motion with the estate or property of a Chapter 11 debtor. In general, the Utility may not pay pre-petition debts without the Bankruptcy Court's permission. Under the Bankruptcy Code, the Utility has the right to reject or assume executory contracts (contracts that require material future performance). Since the filing, the Bankruptcy Court has approved various requests by the Utility to permit the Utility to carry on its normal business operations (including payment of employee wages and benefits, refunds of certain customer deposits, use of certain bank accounts and cash collateral, the assumption of various hydroelectric contracts with water agencies and irrigation districts, and the continuation of environmental remediation and capital expenditure programs) and to fulfill certain post-petition obligations to suppliers and creditors. On April 9, 2001, the Utility filed a complaint in the Bankruptcy Court against the CPUC and its Commissioners requesting that thebankruptcy court declare that any attempt by the CPUC to implement or enforce the regulatory accounting changes approved by the CPUC on March 27, 2001 would violate the automatic stay imposed by bankruptcy law, and asking the Court to enjoin implementation or enforcement of such accounting changes. On June 1, 2001, the Bankruptcy Court issued a decision denying the Utility's request for an injunction and granted the CPUC's motion to dismiss the complaint. Although the Court held that the Eleventh Amendment to the U.S. Constitution did not bar the Utility's suit against the individual Commissioners, the Court concluded that the Utility was not entitled to a stay or an injunction to prevent implementation and enforcement of the regulatory58accounting order. First,bankruptcy court’s order confirming the Court held that, assumingPlan of Reorganization pending the Bankruptcy Code provision imposing an automatic stay on pre-petition proceedings might ordinarily apply (an issue thatCity of Palo Alto’s appeal of the Court expressly declined to decide), the Court determined that the Commissioners were acting pursuant to their police and regulatory power when issuing the order. Accordingly, the Court found that the CPUC's March 27, 2001confirmation order was exempt from the automatic stay provision pursuant to a statutory exemption for the commencement or continuation of an action or proceeding by a governmental unit to enforce such governmental unit's police and regulatory power. Second, the Court held that the Utility had not shown any actual or threatened violation of federal law sufficient to warrant injunctive relief, nor did the balance of equities favor an injunction. The Utility has appealed the Bankruptcy Court's decision to the U.S. District Court for the Northern District of California, or District Court. The two CPUC Commissioners who did not vote to approve the Settlement Agreement joined in the City of Palo Alto’s motion. On January 5, 2004, the bankruptcy court denied the request for a stay. In January 2004, the City of Palo Alto and the two CPUC Commissioners filed appeals in the District Court of the bankruptcy court’s confirmation order.Commissioners cross-appealed.decision approving the Settlement Agreement. CCSF, Aglet and the ORA also filed a joint application for rehearing. Although the CPUC is not required to act on the applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review.appeals have been deemed related to, and therefore have been assignedCPUC also consented to the same districtjurisdiction of any court judge as,or other tribunal or forum for those actions or proceedings, including the appeals discussed belowbankruptcy 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 Utility's complaint filed againstenforcement 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 Commissioners.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.PG&E Corporation have jointly proposed a proposedother regulatory agencies relating to approvals sought to implement the original plan of reorganization,reorganization. The Utility also has suspended all actions to obtain or transfer licenses, permits and franchises to implement the Utility Plan, that proposes to restructureoriginal plan of reorganization. On the Utility's current businesses and to refinance the restructured businesses so that all allowed creditor claims would be paid in full with interest. For a descriptioneffective date of the Utilityconfirmed Plan see Item 1 "Business" above and Note 2 of the Notes to Consolidated Financial Statements appearing in the 2002 Annual Report to Shareholders. On November 30, 2001,Reorganization or as soon thereafter as practicable, the Utility and PG&E Corporation on behalf of its subsidiaries ETrans, GTrans, and Gen, filed variouswill withdraw or abandon all applications with the FERC seeking approval to implement the transactions proposed under the Utility's Plan. For additional information about the proposed Plan and thefor these regulatory approvals required to implement the Plan, see Note 2 of the Notes to Consolidated Financial Statements appearing in the 2002 Annual Report to Shareholders.approvals.On January 25, 2002, the Bankruptcy Court held a hearing to consider arguments as to whether the Bankruptcy Court has the power to preempt various California state and local laws as requested in the Utility Plan, and whether such preemption would violate the sovereign immunity of the State of California and its agencies, including the CPUC. On February 7, 2002, the Bankruptcy Court issued an order concluding that bankruptcy law does not permit express preemption, but it could permit implied preemption under certain circumstances. It also concluded that the Utility Plan as drafted violated sovereign immunity because it seeks affirmative relief against the State and the CPUC, but that if the Utility Plan and disclosure statement were amended, then the Utility Plan would overcome the sovereign immunity defense. Otherwise, the Utility and PG&E Corporation would have to prove that there had been a waiver of sovereign immunity. The Bankruptcy Court rejected PG&E Corporation's and the Utility's argument that Section 1123(a)(5) of the Bankruptcy Code expressly authorized the Bankruptcy Court to preempt any state law to confirm and effectuate a plan of reorganization. Instead, the Bankruptcy Court interpreted Section 1123(a)(5) to permit preemption of a state law where it had been shown that enforcing the state law at issue would be an obstacle to the accomplishment and execution of the full purposes of the bankruptcy laws. The Bankruptcy Court stated that whether a restructuring (i.e., the disaggregation of the Utility's businesses as proposed in the Utility Plan) is necessary for a feasible reorganization is an issue to be determined at the confirmation hearing. In its February 7, 2002, the Bankruptcy Court held that "the Plan could be confirmed if ProponentsThere are able to establish with particularity the requisite elements of implied preemption." The Bankruptcy Court stated that PG&E Corporation and the Utility must show facts that would lead the Bankruptcy Court to find that the "application of those laws to the facts of [the Debtor's] proposed reorganization are economic in nature rather than directed at protecting public safety or other non-economic concerns, and that those particular laws stand as an obstacle to the accomplishment and execution of the purposes and objectives of Congress and the Bankruptcy Code." On March 18, 2002, the Bankruptcy Court entered an order and judgment disapproving the Utility's First Amended Disclosure Statement relating to the Utility Plan for the reasons set forth in its February 7, 2002 decision based upon the court's rejection of PG&E Corporation's and the Utility's express preemption theory. The Bankruptcy Court found that there was no just reason to delay appellate review of the court's ruling on express preemption, and directed the clerk to enter its order as a final judgment. The court stated that its order was not intended to address or finally adjudicate any issues or disputes other than express preemption, including but not limited to the implied preemption and sovereign immunity aspects of its February 7, 2002 decision, and reserved such issues for final rulingsseveral legal proceedings still pending in connection with the original plan confirmation process.March 22, 2002, PG&E Corporation andMay 14, 2003, the Utility filed a noticeU.S. Court of appeal fromAppeals for the Bankruptcy Court's March 18, 2002 order. PG&E Corporation and the Utility elected to haveNinth Circuit, or Ninth Circuit, heard oral argument in the appeal heardfiled by the United States District Court for the Northern DistrictCPUC and other parties of California, or the District Court. In addition, the CPUC, the City and59County of San Francisco, and the California Attorney General, on behalf of a number of State entities, filed cross-appeals. Generally stated, the two issues that these parties identified for cross-appeal are: (1) whether the Bankruptcy Court erred in entering a final judgment concerning its ruling on express preemption, and (2) whether it was an abuse of discretion for the Bankruptcy Court to determine that there was no just reason to delay the entry of judgment on its express preemption ruling. On June 24, 2002, in ruling on a motion to dismiss the Utility's and PG&E Corporation's appeal,order issued by the District Court issued an order rejecting these contentions. On August 30, 2002,finding that the District Court issued an order reversing the Bankruptcy Court's March 18, 2002 order and remanding the case back to the Bankruptcy Court for further proceedings. The District Court ruled that theU.S. Bankruptcy Code expressly preempts "nonbankruptcy“non-bankruptcy laws that would otherwise apply to bar, among other things, transactions necessary to implement the reorganization plan."” The CPUC,District Court’s order had reversed an earlier ruling by the California Attorney General, the City and County of San Francisco, and the California Hydropower Reform Coalition filed an appealbankruptcy court that found that bankruptcy law did not expressly preempt certain non-bankruptcy laws in connection with the U.S. Courtoriginal plan of Appeals forreorganization, but that it could be implied to preempt non-bankruptcy laws in certain circumstances.orissued a decision agreeing with the District Court’s finding that a Chapter 11 reorganization plan expressly preempts otherwise applicable non-bankruptcy laws. However, the Ninth Circuit and also filed a request withruled that the scope of such express preemption is limited to those non-bankruptcy laws relating to financial condition. The Ninth Circuit determined that neither the bankruptcy court nor the District Court to stay itshad applied the proper standard of express preemption. It therefore reversed the District Court’s August 30, 2002, decision pending their appealand remanded the matter back to the Ninth Circuit. On November 14, 2002,bankruptcy court for further proceedings to determine whether the District Court issued an order denyingUtility’s and PG&E Corporation’s original plan of reorganization satisfied the request for a stay and certifiying its August 30, 2002 decision for discretionary reviewexpress preemption standard announced by the Ninth Circuit. The CPUC and the other appellants proceeded with an appeal toand briefingstated that the question of implied preemption was not before it in the appeal, is now closed. All appellants exceptit reaffirmed that implied preemption could apply under the CPUC requested the Ninth Circuit to stay the District Court's August 30, 2002 decision pending the Ninth Circuit appeal. PG&E Corporation and the Utility filed their opposition to the motion for a stay onBankruptcy Code, even if express preemption did not. On December 9, 2002. On January 17,10, 2003, the Ninth Circuit denied the motion for a stay pending appeal. On October 30, 2002, the Utility and PG&E Corporation filed a motion askingpetition to rehear the Ninth Circuit’s decision with the panel that issued the decision, and suggested that the full Ninth Circuit should rehear the issue, since it conflicts with other Ninth Circuit cases and cases from other Circuits.expeditevarious conditions, including the consummation of the public offering of long-term debt, the receipt of investment grade credit ratings and final CPUC approval of the Settlement Agreement. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not subject to any pending appeal which was granted in partor further right of appeal, or approval on November 18, 2002, along withbehalf of the CPUC that, although subject to a statementpending appeal or further right of appeal, has been agreed by the Utility and PG&E Corporation to constitute final approval. Thus, the terms of the Plan of Reorganization permit the Utility and PG&E Corporation to cause the Plan of Reorganization to become effective (and permit the Utility to issue the long term debt) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. Until certain conditions or events regarding the effectiveness of the Plan of Reorganization discussed above are resolved further, PG&E Corporation and the Utility cannot conclude that the applicable accounting probability standard needed to record the regulatory assets contemplated by the Settlement Agreement has been met. PG&E Corporation and the Utility believe that the Utility and the long-term debt to be issued will receive investment grade credit ratings.The Utility has targeted April 2004 to complete the sale of the long-term debt, which the Utility expects to be the last condition of the Plan of Reorganization to be satisfied. The Plan of Reorganization provides that the effective date will occur 11 business days after all the conditions have been satisfied or, with respect to all conditions except those relatingwould be calendared as soon as is practicable.or that the Plan of Reorganization will become effective. In addition,Chapter 11 Filing of NEGTUnited States Departmentprovisions of JusticeChapter 11 in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. On July 29, 2003, two additional subsidiaries of NEGT also filed voluntary Chapter 11 petitions. NEGT also has filed anamicus brief with the Ninth Circuit in which it supports the CPUC's construction of Bankruptcy Code Section 1123 but argues in favor of a remand to the District Court on the issue of implied preemption. Two additional sets ofamici have filed briefs or have sought leave to file briefs in support of the CPUC's position in the appeal: (1) the National Association of Regulatory Commissioners, joining with a number of states (who do not require leave to file asamici); and (2) a number of California counties. On or about January 6, 2003, a number of public utility commissions from other states, as well as the State of Utah, filed a motion asking the Ninth Circuit for leave to join theamicus brief in support of the CPUC's position in the appeal. The Ninth Circuit has not yet set the appeal for oral argument. Pursuant to the Bankruptcy Court's February 7, 2002 decision, the Utility Plan was amended to (1) eliminate express preemption provisions and (2) state with specificity the facts demonstrating that the State and the CPUC have waived their sovereign immunity, and, if the Bankruptcy Court finds that such immunity has been waived, to provide for declaratory and injunctive relief against the State and the CPUC. After the Bankruptcy Court terminated the period during which only the Utility has the right to submit a proposed plan of reorganization the CPUC filed a proposed alternative plan of reorganization with the Bankruptcy Courtbankruptcy court that, if implemented, would eliminate PG&E Corporation’s equity interest in NEGT and its subsidiaries.April 15, 2002. After the Bankruptcy Court approved the disclosure statements relating to the Utility PlanJuly 7, 2003 and the CPUC's alternative plan, the disclosure statements relating to the competing plans were sent to creditors and equity holders entitled to vote on the plans in June 2002. Balloting was completed on August 12, 2002. On June 7, 2002,replaced with directors who are not affiliated with PG&E Corporation. As a result, PG&E no longer retains significant influence over NEGT. Accordingly, effective July 8, 2003, NEGT’s results of operations are no longer consolidated with those of PG&E Corporation and its results of operations through July 7, 2003 and for prior years have been reclassified as discontinued operations.Utility filed a motion withNotes to the Bankruptcy Court to extend, until December 31, 2002, the period during which no third parties, other than the CPUC, could submit an alternative proposed plan of reorganization. On June 24, 2002, the Official Committee of Unsecured Creditors, or the OCC, filed a responseConsolidated Financial Statements in the Bankruptcy Court requesting that the exclusivity period be modifiedAnnual Report, which is incorporated by reference and filed as Exhibit 13 to enable the OCC to submit an alternative plan. On July 9, 2002, the Bankruptcy Court issued an order granting the OCC's request and extending the exclusivity period until December 31, 2002, except as to the CPUC (which the court previously excepted) and the OCC.this report. In addition to other parties, the City of Palo Alto and the Northern California Power Agency, or NCPA, filed an objection to both proposed plans of reorganization. The objection asserts that, by virtue of the Utility's termination of a wholesale electric transmission contract between NCPA and the Utility, NCPA members, including Palo Alto, will now be subject to substantial charges from the California ISO. Palo Alto and NCPA assert that these charges, which are related primarily to congestion on the transmission system and a related ISO charge to entities that want to ensure delivery of power even in times when congestion is present, will increase dramatically if a proposed electric market redesign proposal is adopted for California. Palo Alto and NCPA further assert that the Utility's motivation for terminating the NCPA transmission contract was anticompetitive and violated the federal antitrust laws. They claim that damages associated with these increased ISO congestion charges could exceed $1 billion. In60January 2003, the Bankruptcy Court held an estimation hearing to determine what value to put on a possible future damages award that NCPA and Palo Alto might receive, should they file, pursue, and establish liability on their antitrust claim. On July 29, 2002, shortly before the voting period ended, the CPUC filed an application with the Bankruptcy Court alleging that the Utility, PG&E Corporation, and their third-party solicitor improperly solicited votes and seeking a temporary restraining order to prohibit the continuing solicitation of votes, an order to require the distribution of corrective materials, an order extending the deadline for creditors to vote on the competing plans of reorganization, and an order allowing creditors to recast their ballots. The Bankruptcy Court denied the application for such relief on August 5, 2002. The CPUC's underlying complaint, which also was filed with the Bankruptcy Court on July 29, 2002, against the Utility, PG&E Corporation, and their third-party solicitor, alleges that the defendants improperly solicited votes by allegedly making false and misleading statements to creditors and equity holders. On February 11, 2003, the Utility received notice that the CPUC had dismissed the complaint voluntarily. The dismissal is without prejudice, meaning that the CPUC could refile the complaint. On August 22, 2002, 10 days after the voting period ended, the CPUC and the OCC announced that the OCC had joined the CPUC to support a modified alternative plan. The CPUC and the OCC jointly filed an amended plan of reorganization on August 30, 2002, the CPUC/OCC Plan, and requested the Bankruptcy Court's permission to resolicit votes and preferences for the CPUC/OCC Plan. On September 9, 2002, an independent voting agent stated that nine of the ten voting classes under the Utility Plan approved the Utility Plan. The original plan sponsored by the CPUC was rejected by all but one of the eight voting creditor classes. In order to proceed to the confirmation trial, each plan of reorganization needed to obtain the acceptance of at least one class of creditors holding impaired claims. On September 20, 2002, the Bankruptcy Court denied the CPUC's and the OCC's request to reopen the voting. The Bankruptcy Court declined to rule on the CPUC's and the OCC's additional request for an order authorizing the resolicitation of creditor preferences. On November 6, 2002, the CPUC and the OCC filed a Second Amended CPUC/OCC Plan and also filed a motion asking the Bankruptcy Court to authorize the resolicitation of creditor preferences. The Bankruptcy Court heard oral arguments on the motion on November 27, 2002. On February 6, 2003, the Bankruptcy Court issued an order denying the CPUC's and the OCC's request. The trial on confirmation of the CPUC/OCC Plan began on November 18, 2002 and the trial on confirmation of the Utility Plan began as scheduled on December 16, 2002. On January 24, 2003, the Bankruptcy Court issued an order modifying the original confirmation trial schedule and extending the hearing dates for the Utility Plan to the end of March 2003. On December 20, 2002, the Utility filed a motion with the Bankruptcy Court requesting the Court to further extend the period during which only the Utility (with the exception of the CPUC and the OCC) can file a proposed plan of reorganization for the Utility from December 31, 2002 to April 30, 2003. On February 6, 2003, the Bankruptcy Court granted the Utility an indefinite extension of the exclusivity period. With respect to the application filed with the Nuclear Regulatory Commission (NRC) for permission to transfer the NRC operating licenses held by the Utility for its Diablo Canyon nuclear power plant to Gen (which will become a subsidiary of PG&E Corporation after consummation of the Utility Plan) as contemplated by the Utility Plan, on June 25, 2002, the NRC issued an order denying various petitions to intervene and requests for hearing that had been filed by the CPUC, the County of San Luis Obispo, and the OCC, among others. In particular, the NRC found that the CPUC and OCC did not have standing to participate at the NRC with respect to public health and safety matters, as opposed to economic regulatory matters. In addition, the NRC found that the County's petition was untimely. Finally, the NRC found that neither the CPUC nor the County had raised any litigable issues within the NRC's jurisdiction and within the scope of its review of a license transfer application. The CPUC's and the County's issues were being properly addressed in other forums, such as the Bankruptcy Court and the FERC. The CPUC and the County have filed a petition for review of this NRC decision in the United States Court of Appeals for the Ninth Circuit. The Utility has intervened in the case in support of the NRC's decision. The case is presently in the briefing process. No argument date has been set. Several other parties filed petitions to intervene at the NRC expressing concerns solely with regard to how the antitrust conditions in the current Diablo Canyon licenses will be addressed in the proposed license transfers. These parties supported the Utility's proposal to retain the antitrust conditions and to make the reorganized Utility, Gen, and ETrans (the new limited liability company formed to operate the electric transmission business of the Utility as contemplated in the Utility Plan) jointly and severally responsible to comply with the antitrust conditions.61The parties with an interest in the antitrust conditions sought intervention only if the NRC were to decide not to adopt the Utility's proposal. In its June 2002 decision, the NRC reserved its ruling as to these petitions. The NRC later sought additional briefs on legal issues presented by the Utility's antitrust proposal. On February 14, 2003, the NRC issued a final order with respect to the pending antitrust issues. The NRC's order specifically decided that the NRC will not transfer the existing antitrust license conditions to any new licensee. In view of the age of the antitrust conditions and changes in the law since those conditions were adopted (in particular, those changes providing for nondiscriminatory open access to transmission), the NRC declined to reenact the conditions as part of the license transfer. Consistent with this decision, the NRC also rejected other issues related to the transfer application raised by the antitrust petitioners and rejected the requests for hearing on antitrust issues for lack of a viable issue for hearing. With respect to the NRC license transfer application, the NRC has not yet issued its final order consenting to the transfer. No hearing issues remain to be decided. The NRC Staff must complete its safety evaluation and then would be authorized to issue the transfer order. With respect to the application filed with the FERC for approval of the bilateral power sales agreement between the reorganized Utility and Gen as contemplated in the Utility Plan, the FERC must find that the power sales agreement is just and reasonable consistent with Section 205 of the Federal Power Act. Because the power sales agreement is viewed as an agreement between affiliates, in order to demonstrate that the pricing and non-price terms and conditions of the proposed power sales agreement are just and reasonable, Gen submitted benchmark evidence of contemporaneous sales made by non-affiliated parties for similar services in the California electric market. In June 2002, FERC accepted the power sales agreement for filing and ordered a hearing to determine whether Gen had submitted a valid benchmark, including whether specific comparability criteria have been appropriately addressed. On October 10, 2002, the Administrative Law Judge, or ALJ, issued an initial decision finding that Gen successfully had "carried its burden" with respect to the benchmark analysis and had shown that the power sales agreement between the reorganized Utility and Gen was in fact comparable to the price and non-price terms and conditions of the selected benchmark contracts. The ALJ found no evidence in the record of any exercise of market power by Gen or any affiliate. In addition, the ALJ found that Gen's selection of contracts used as a comparison group in the benchmark analysis was appropriate and met all of the FERC's comparability criteria. The matter is now before the FERC for review of the hearing record and the ALJ's initial decision. The FERC will also consider the briefs on exceptions (addressing the ALJ's initial decision) that were filed by various parties. The ALJ's findings provide a basis for the FERC to find that the power sales agreement is just and reasonable. There is no specific time by which the FERC is required to take final action on the initial decision. Neither PG&E Corporation nor the Utility can predict what the outcome of the Utility's bankruptcy proceeding will be.California Public Utilities CommissionersMichael Peevey, et al.Pacific Gas and Electric Companythe Utility filed a lawsuit in the U.S. District Court for the Northern District of California against the CPUC Commissioners, askingcommissioners. In this lawsuit, the court to declareUtility seeks a declaration that the federally tariffed wholesale powerelectricity costs that the Utility had incurred to serve itsthe Utility’s customers are recoverable in retail rates under the federal filed rate doctrine (the "Filed Rate Case"), and also asserting claims under the Takings, Commerce and Due Process Clauses of the United States Constitution. On January 29, 2001, the Utility's lawsuit was transferred to the U.S. District Court for the Central District of California where a similar lawsuit filed by Southern California Edison was pending. On May 2, 2001, the District Court dismissed the Utility's amended complaint, without prejudice to refiling 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. On August 6, 2001, the Utility refiled its complaint in the U.S. District Court for the Northern District of California, based on the Utility's belief that the CPUC decisions referenced in the Court's May 2, 2001 order had become final under California law. On November 26, 2001, the case was transferred to United States District Court Judge Vaughn Walker in the Northern District of California as a related case to the Utility's appeal from the Bankruptcy Court's denial of the Utility's request for injunctive and declaratory relief against the retroactive accounting order adopted by the CPUC in March 2001, which is discussed above. At a joint case management62conference held on March 7, 2002 in the two related actions, the court indicated that it would place priority on the Filed Rate Case and that it was necessary to clarify issues further in the Filed Rate Case before proceeding in the appeal of the Bankruptcy Court order regarding the CPUC's March 2001 accounting order. At the Utility's request, the court therefore set no dates for oral argument in the bankruptcy appeal, but indicated that the CPUC would be free at any time to attempt to establish that it was appropriate to reactivate the bankruptcy appeal in light of developments in the Filed Rate Case.doctrine.Utility'sUtility’s complaint alleges that the wholesale powerelectricity costs that the Utility has prudently incurred are paid pursuant to filed tariffs that the FERC has authorized and approved, and that, under the U.S. Constitution and numerous court decisions, such costs cannot be disallowed by state regulators. The Utility'sUtility’s complaint also alleges that, to the extent that the Utility is denied recovery of these wholesale powerelectricity costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of the Utility'sUtility’s property. The Utility argues that the CPUC'sCPUC’s decisions are preempted by federal law under the filed rate doctrine, which requires the CPUC to allow the Utility to recover in full itsit’s reasonable procurementpurchase costs incurred under lawful rates and tariffs approved by the FERC, a federal governmental agency. The complaint also pleadsasserts claims under the Commerce Clause and the Due Process Clause, and Equal Protection Clause of the U.S. Constitution.April 18, 2002, the Utility filed a motion for summary judgment requesting the court to enter judgment in the first and second claims for relief pleaded in the complaint on the basis that federal law requires the CPUC to permit the Utility to recover its wholesale procurement costs incurred in FERC-tariffed markets. Also, on April 18, 2002, the CPUC Commissioners and TURN, an intervenor in the Filed Rate Case, filed motions to dismiss the Utility's claim as well as motions for summary judgment asking the court to rule against the Utility on its federal preemption claims as a matter of law. The principal ground for the CPUC's and TURN's motions was that, by adopting the retroactive change in the accounting mechanisms for recovery of transition and power procurement costs in MarchJanuary 29, 2001, the CPUC had already allowed the UtilityUtility’s lawsuit was transferred to recover its wholesale procurement costs. (The retroactive accounting change, adopted by the CPUC on March 27, 2001, appeared to eliminate the Utility's true undercollected wholesale electricity costs by applying amounts that were previously applied first to transition cost recovery to undercollected procurement costs, effectively transforming undercollected procurement costs to under-collected transition costs. As discussed above, the Utility requested the Bankruptcy Court to enjoin the CPUC from enforcing the accounting order but the Bankruptcy Court denied the Utility's request.) On July 25, 2002, the District Court issued an order denying the CPUC's and TURN's motions to dismiss the Filed Rate Case, as well as motions for summary judgment that had been filed by the CPUC, the Utility, and TURN. However, much of the District Court's order is a discussion of the merits of the Utility's federal preemption claims. The court rejected every argument advanced by the CPUC and TURN against the application of the filed rate doctrine, stating: "in most instances today a utility must purchase the power delivered to consumers pursuant to the rate filed with the appropriate federal agency." After concluding that the Utility's federal preemption claims as pleaded are meritorious, the District Court denied the motions to dismiss without substantial discussion. The court stated that despite the unique features of the regulatory context underlying the Filed Rate Case, and the lack of precedent specifically on point, "the filed rate doctrine applies in this case in much the same way as it does under a cost-of-service regime." The court further stated that "Costs of wholesale energy, incurred pursuant to rate tariffs filed with FERC, whether these rates are market-based or cost-based, must be recognized as recoverable costs by state regulators and may not be trapped by excessively low retail rates or other limitations imposed at the state level." The court recognized that under the dual system of utility regulation, adherence to the filed rate requirement, in conjunction with the requirement that utilities provide electricity to end users, prohibits state regulators from trapping the costs prudently incurred pursuant to FERC-filed tariffs. The court also noted that "allowing a utility to pass through these costs to consumers—if that is what is required—would not provide a windfall to the utility, but would merely properly allocate the burden of responsibility for the expense of providing a mandated service to the public." The court found, however, that the Utility's preemption claims could not be decided on summary judgment because two factual issues remained in dispute: (1) the appropriate time period for considering whether a net undercollection had occurred, and (2) the determination of which revenue sources, within Constitutional bounds, may be applied against the Utility's operating costs. At an August 16, 2002 case management conference, the court adopted the pretrial and trial schedule stipulated to by the parties, including a trial date set for June 9, 2003. On August 23, 2002, the defendants filed a Notice of Appeal from those portions of the July 25, 2002 order denying defendants' motion to dismiss on Eleventh Amendment (sovereign immunity) and Johnson Act grounds. (The Johnson Act prohibits the district63courts from enjoining, suspending, or restraining the operation of or compliance with any order affecting rates chargeable by a public utility and made by a state administrative agency as long as certain conditions are met.) On September 4, 2002, the Utility filed a motion with the District Court seeking written certification that the CPUC's appeal of the July 25, 2002 order on Eleventh Amendment and Johnson Act grounds was frivolous. On or about October 21, 2002, the District Court granted the Utility's motion and certified the CPUC's appeal as frivolous, which allowed the District Court to retain jurisdiction to proceed to trial while the CPUC's appeal to the Ninth Circuit was pending. On November 21, 2002, the Ninth Circuit without discussion granted the CPUC's motion to stay the District Court proceedings pending the CPUC's appeal of the District Court's July 25, 2002 order. As a consequence of the Ninth Circuit stay, the trial schedule previously set by the District Court, including the June 9, 2003, trial date, is inoperative. On January 8, 2003, the Utility filed its Ninth Circuit brief in opposition to the CPUC's appeal, together with a motion asking the Ninth Circuit to expedite the hearing and the decision on the appeal. On January 13, 2003, the Ninth Circuit notified the Utility that a hearing date for the appeal has been set for March 10, 2003. Briefing on the appeal has been completed. Neither PG&E Corporation nor the Utility can predict what the outcome of the Filed Rate Case litigation will be. In connection with the Utility Plan, before the distribution of the outstanding common stock of Newco to PG&E Corporation, the Utility would assign to Newco or a subsidiary of Newco the rights to an amount equal to 95% of the net after-tax proceeds from any successful resolution of this case and resulting CPUC rate order requiring collection of wholesale costs in retail rates. The reorganized Utility would retain the rights to 5% of such proceeds.Federal Securities Lawsuit On April 16, 2001, a complaint was filed against PG&E Corporation and the Utility in the U.S. District Court for the Central District of California, entitledJack Gillam; DOES 1 TO 5, Inclusive, and All Persons similarly situated vs. PG&E Corporation, Pacific Gas and Electric Company; and DOES 6 to 10, Inclusive. The Utilitywhere a similar lawsuit filed by Southern California Edison Company was subsequently dismissed, due to its Chapter 11 bankruptcy filing. By order entered on or aboutpending. On May 31,2, 2001, the casecourt dismissed the Utility’s complaints without prejudice to re-filing at a later date, on the ground that the lawsuit was transferred to the U.S. District Court for the Northern District of California. On August 9, 2001, plaintiff filed a first amended complaint entitledJack Gillam, et al. vs. PG&E Corporation, Robert D. Glynn, Jr., and Peter A. Darbee,premature, since two CPUC decisions referenced in the U.S. District Court for the Northern District of California.complaint had not become final under California law. The first amended complaint, purportedly brought on behalf ofcourt rejected all persons who purchased PG&E Corporation common stock or certain shares of the Utility's preferred stock between July 20, 2000, and April 9,CPUC’s other arguments for dismissal of the Utility’s complaint. claims that defendants caused PG&E Corporation's Condensed Consolidated Financial Statements for the second and third quarters of 2000 to be materially misleading in violation of federal securities laws by recording as a deferred cost and capitalizing as a regulatory asset the under-collections that resulted when escalating wholesale energy prices caused the Utility to pay far more to purchase electricity than it was permitted to collect from customers. The defendants filed a motion to dismissre-filed the first amended complaint, based largely on public disclosures by PG&E Corporation, the Utility, and others regarding the undercollections, the risk that they might not be recoverable, the financial consequences of non-recovery, and other information from which analysts and investors could assess for themselves the probability of recovery. On January 14, 2002, the District Court granted the defendants' motion to dismiss the plaintiffs' complaint with leave to amend the complaint. On February 4, 2002, the plaintiffs filed a second amendedUtility’s complaint in the District Court entitledJack Gillam, et al. vs. PG&E Corporation, and Robert D. Glynn, Jr. In addition to containing many ofbased on the same allegations as were containedUtility’s belief that the CPUC decisions referenced in the prior complaint,court’s May 2001 order had become final under California law. On October 31, 2001, the complaint contains allegations similarCPUC moved to dismiss the allegations made inaction. While the California Attorney General's complaint against PG&E Corporation discussed below.motion was under submission, the parties filed cross-motions for summary judgment.March 11,July 25, 2002, the defendants filed acourt denied the CPUC’s motion to dismiss on all grounds, as well as the second amended complaint. After a hearing on June 24,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.District Court issued an order granting the defendants' motion to dismiss the second amended complaint. The dismissal is with prejudice, prohibiting the plaintiffs from filing a further amended complaint. On November 15, 2002, plaintiffsCPUC filed an appeal ofto the District Court's order with the United StatesU.S. Court of Appeals for the Ninth Circuit, advancing substantiallyor Ninth Circuit. Pursuant to the same arguments thatUtility’s request, the District Court had rejected previously. The defendants filed an answering brief on January 2, 2003, and anticipate that oral argument may occurcertified the appeal as early as the fall of 2003.64 PG&E Corporation believes the case is“wholly without merit and, intendstherefore, frivolous,” and rejected the CPUC’s request to presentstay the proceedings. On November 21,vigorous defense. PG&E Corporation believes thatmotion to stay consideration of the ultimate outcomeappeal of this litigation will not havethe filed rate case. On August 11, 2003, the Ninth Circuit issued an order staying proceedings in the filed rate case. The Ninth Circuit has ordered the parties to file a material adverse effect on PG&E Corporation's financial condition or results of operations.status report by July 30, 2004.Gyrnberg (calledGrynberg (referred to as a relator in the parlanceterminology of the False Claims Act) on behalf of the United States of America against more than 330 defendants, including the Utility and PG&E GTN.Utility. The cases were consolidated for pretrial purposes in the U.S. District Court for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998.(actingacting through the Department of Justice, or the DOJ, is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the DOJ declined to intervene in any of the cases.(mostmost of whichwhom are natural gas pipeline companies or their affiliates)affiliates, incorrectly measured the volume and heating content of natural gas produced from federal or Indian leases. As a result, the relator alleges that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases.of not less than $5,000 and not more than $10,000 against each defendant for each violation of the False Claims Act, an order requiring the defendants to discontinue certain measurement practices, and reimbursement for reasonable expenses attorneys' fees, and costs incurred in connectionassociated with the litigation. The relator has filed a claim in the Utility's bankruptcyUtility’s Chapter 11 case for $2.48$2.5 billion, $2$2.0 billion of which is based upon the relator'srelator’s calculation of penalties against the Utility.PG&E Corporation and theThe Utility believebelieves the allegations to be without merit and intendintends to present a vigorous defense. PG&E Corporation and the The Utility believebelieves that the ultimate outcome of the litigation will not have a material adverse effect on theirthe Utility’s financial condition or results of operations.Moss LandingDiablo Canyon Power PlantIn December 1999, the Utility was notified by the purchaser of its former Moss LandingThe Utility’s Diablo Canyon power plant that it had identifiedemploys a cleaning procedure used at the plant that released heated“once-through” cooling water and organic debris from the intake, and that this proceduresystem, which is not specified in the plant's National Pollutant Discharge Elimination System, orregulated 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 purchaser notified the Central Coast Boardbeneficial uses of its findingswater in this region include industrial water supply, marine and the Central Coast Board requested additional information from the purchaser. The Utility initiated an investigationwildlife habitat, shellfish harvesting and preservation of these activities during the time it owned the plant. The Utility notified the Central Coast Board that it had undertaken an investigationrare and that it would present the results to the Central Coast Board when the investigation was completed.endangered species. In MarchJanuary 2000, the Central Coast Board requested the Utility to provide specific information regarding the "backflush" procedure used at Moss Landing. The Utility provided the requested information in April 2000. The Utility's investigation indicatedissued a proposed draft cease and desist order alleging that, while the Utility owned Moss Landing, significant amounts of water were discharged from the cooling water intake. While the Utility's investigation did not clearly indicate that discharged waters had a temperature higher than ambient receiving water, the Utility believes thatalthough the temperature limit has never been exceeded, the Utility’s Diablo Canyon power plant’s discharge was not protective of the discharged water was higher than that of the receiving water.beneficial uses.DecemberOctober 2000, the executive officer of the Central Coast Board made a settlement proposal to the Utility under which the Utility would pay $10 million, a portion of which would be used for environmental projects and the balance of which would constitute civil penalties. In March 2002, the Utility and the Central Coast Board reached a tentative settlement of this matter underwith the Central Coast Board pursuant to which the Utility would pay a totalCentral Coast Board agreed to find that the Utility’s discharge of $5 million to be used for environmental projects. No civil penalties would be paid undercooling water from the settlement. The parties are negotiatingUtility’s Diablo Canyon power plant protects beneficial uses and that the documentationintake technology reflects the best technology available as defined in the Federal Clean Water Act. As part of the settlement. The finalCentral Coast settlement agreement, the Utility agreed to take measures to preserve certain acreage north of the plant and will be subjectfund approximately $6 million in environmental projects and future environmental monitoring related to public comment and final approvalcoastal 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 once signed by the parties, will be incorporated into a consent decreeCalifornia Attorney General’s Office. A condition to be enteredthe effectiveness of theCalifornia Superior Court.March 2003, and the Central Coast Board requested its staff to develop additional information on possible mitigation measures.65proof of claim in the Bankruptcy CourtUtility’s Chapter 11 case on behalf of the Central Coast Board seeking unspecified penalties for alleged dischargesand other relief in connection with the Diablo Canyon power plant’s operation of heatedits cooling water at Moss Landing. PG&E Corporation and thesystem. The Utility believe that the ultimate outcomeis seeking withdrawal of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or results of operations.Diablo Canyon Power Plantclaim.Enforcement Orderenforcement order from the California Department of Toxic Substances Control, or DTSC, alleging that the Utility’s Diablo Canyon Power Plant, or Diablo Canyon,power plant failed to maintain an adequate financial assurance mechanism to cover closure costs for its hazardous waste storage facility for several months during 2001. Under the California Health and Safety Code, operators of hazardous waste facilities must demonstrate to the DTSC (using a limited number of alternative methods specified by regulation) that the operator can close and clean up the facility at the end of its useful life. The Utility has used a "balance sheet" method in the past, but was unable to do so after the Utility's financial condition deterioratedUtility’s Chapter 11 filing in early 2001. Nevertheless, the Utility was able to secure an endorsement to its existing insurance policy that met the DTSC's requirements. The draft order seekssought $340,000 in civil penalties for the period during which the Utility waswere unable to comply with the DTSC'sDTSC’s requirements. The draft order also directsdirected the Utility to maintain appropriate financial assurance on a going-forwardgoing forward basis. On September 4, 2002, the Utility received a draft Enforcement Orderenforcement order from DTSC alleging a variety of hazardous waste violations at the Utility’s Diablo Canyon. The violations were identified in an April 2001 inspection. TheCanyon power plant. This draft order seekssought $24,330 in civil penalties. A tentativehas been reachedagreement with DTSC, under which the Utility willagreed to pay approximately $165,000 in civil penalties and approximately $30,000 in costs. The final agreement, once signed by the parties, will be incorporated intoUtility paid these amounts in May 2003. The California Attorney General filed a consent decree to be entered in California Superior Court. PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on their financial condition or results of operations.Compressor Station Chromium Litigation There are 15 civil actions pending in California courts against the Utility relating to alleged chromium contamination, or the Chromium Litigation: (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995, in Los Angeles County Superior Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996, in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November 27, 1996, in Los Angeles County Superior Court, (4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed July 25, 2000, in Los Angeles County Superior Court, (5) Baldonado v. Pacific Gas and Electric Company, filed October 25, 2000, in Los Angeles County Superior Court, (6) Gale v. Pacific Gas and Electric Company, filed January 30, 2001, in Los Angeles County Superior Court, (7) Monice v. Pacific Gas and Electric Company, filed March 15, 2001, in San Bernardino County Superior Court, (8) Fordyce v. Pacific Gas and Electric Company, filed March 16, 2001, in San Bernardino Superior Court, (9) Puckett v. Pacific Gas and Electric Company, filed March 30, 2001, in Los Angeles County Superior Court, (10) 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, (11) Bowers, et al. v. Pacific Gas and Electric Company, et al., filed April 20, 2001, in Los Angeles County Superior Court, (12) Boyd, et al. v. Pacific Gas and Electric Company, et al., filed May 2, 2001, in Los Angeles County Superior Court, (13) Martinez, et al. v. Pacific Gas and Electric Company, filed June 29, 2001, in San Bernardino County Superior Court, (14) Kearney v. Pacific Gas and Electric Company, filed November 15, 2001, in Los Angeles County Superior Court, and (15) Miller v. Pacific Gas and Electric Company, filed November 21, 2001, in Los Angeles County Superior Court. All of these civil actions are now pendingclaim in the Los Angeles Superior Court, except theMonice case, still pending in San Bernardino County, and theLytle case, still pending in Yolo County. One additional suit,Kearney v. Pacific Gas and Electric Company, filed November 15, 2001, in Los Angeles County Superior Court, was filed after the Petition Date and was dismissed without prejudice as to PG&E and PG&E Corporation on March 26, 2002, while plaintiffs' counsel sought and obtained permission from the Bankruptcy Court to pursue late claims. The Bankruptcy Court ruled that the six adult plaintiffs could not file untimely bankruptcy claims against PG&E. This ruling should prohibit these adult plaintiffs from proceeding in state court against PG&E. The court also ruled that the twenty-four minor plaintiffs in the case could file untimely bankruptcy claims against PG&E, which should permit these minor plaintiffs to reinstate their claims against PG&E in the pending civil suit. Two of these suits,Alderson andKearney, also name PG&E Corporation as a defendant. The Utility has not yet been served with the complaints in theGale orLytle cases. There are now approximately 1,200 plaintiffs in the Chromium Litigation. The complaints allege personal injuries, wrongful death, and loss of consortium and seek compensatory and punitive damages based on claims arising from alleged exposure to chromium contamination in the vicinity of the Utility's gas compressor stations located at Kettleman and Hinkley, California, and the area of California near Topock, Arizona. The plaintiffs include current and former employees of the Utility and their relatives, residents in the vicinity of the compressor stations, and persons who allegedly visited the gas compressor stations. The plaintiffs also include spouses or children of these plaintiffs who claim loss of consortium or wrongful death. The Utility is responding to the suits in which it has been served and is asserting affirmative defenses. It will pursue appropriate legal defenses, including the statute of limitations, exclusivity of workers' compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. The discovery referee has set the procedures for selecting trial test plaintiffs and alternates in theAguayo,Acosta, andAguilar cases. Ten of these trial test plaintiffs were selected by plaintiffs' counsel, seven plaintiffs were selected by defense counsel, and one plaintiff and two alternates were selected at random. Although a date for the first test trial in these cases was set for July 2, 2001, in Los Angeles County Superior Court, theUtility’s Chapter 11 case automatically stayed all proceedings. On March 27, 2002, the seven plaintiffs in theFordycecase served their lawsuit on PG&E. The plaintiffs have all filed timely proofsbehalf of claim in the bankruptcy case. In theAdamscase, after a hearing on July 17, 2002, the state court dismissed 35 plaintiffs with prejudice because their claims are barred by the statute of limitations. The state court dismissed another 65 plaintiffs without prejudice, so these plaintiffs may attempt to plead that their claims are not barred by the statute of limitations. Thirty of these plaintiffs filed a Fourth Amended Complaint on October 16, 2002. The other 35 plaintiffs who were given leave to amend have been dismissed with prejudice for failure to amend. Approximately 1,260 individuals have filed proofs of claim in the Utility's bankruptcy case (nearly all are plaintiffs in the Chromium Litigation) asserting that exposure to chromium at or near the compressor stations has caused personal injuries, wrongful death, or related damages. Approximately 1,035 claimants have filed proofs of claim requesting an approximate aggregate amount of $580 million and another approximately 225 claimants have filed claims for an "unknown amount." On November 14, 2001, the Utility filed objections to these claims and requested the Bankruptcy Court to transfer the chromium claims to the U. S. District Court. On January 8, 2002, the Bankruptcy Court denied the Utility's request to transfer the chromium claims and granted the claimants' motion for relief from stay so that the state court lawsuits pending before the Utility filed its bankruptcy petition can proceed. Orders granting relief from stay have been entered. Before April 6, 2001, when the Utility filed its bankruptcy petition, the Utility was responding to the complaints in which it had been served and was asserting affirmative defenses. As of April 6, 2001, the Utility had filed 13 summary judgment motions challenging the claims of the trial test plaintiffs and had completed discovery of plaintiffs' experts. Plaintiffs' discovery of the Utility's experts was underway. Plaintiffs are completing discovery of the Utility's experts and of related issues, and four of the 13 summary judgment motions are scheduled for hearing in the first six months of 2003. At this stage of the proceedings and the claims objections, there is substantial uncertainty concerning the claims alleged,DTSC, and the Utility is attempting to gather information concerning the alleged type and durationcurrently seeking withdrawal of exposure, the nature of injuries alleged by individual plaintiffs, and the additional facts necessary to support its legal defenses. PG&E Corporation and the Utility believe that, in lightthose portions of the reserves that have already been accrued with respectclaim relating to this matter, the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or results of operations. See Note 16 of the "Notes to Consolidated Financial Statements" of the 2002 Annual Report to Shareholders, portions of which are filed as Exhibit 13 to this report.assurance and hazardous waste matters.Plan providesbelieves that the aggregate after-tax amount of any liability resulting from the chromium litigation would be divided among ETrans, GTrans, Gen and the reorganized Utility approximately as follows: 12.5%, 12.5%, 25% and 50%, respectively.67California Energy Trading Litigation PG&E Energy Trading Holdings Corporation and various of its affiliates (collectively ET-Power) have been named as defendants, along with other generators and market participants in the California electricity market, in connection with a variety of claims arising out of the California energy crisis. ET-Power has been served with complaints in the following cases. It is possible that it will be served with additional complaints and that some of these cases will be consolidated with other cases in which similar allegations have been raised respecting other market participants. These proceedings are administrative and judicial in nature. ET-Power has been named, along with multiple other defendants, in four class action lawsuits known asPier 23 against marketers and other unnamed sellers of electricity in California markets. These cases are (1) Pier 23 Restaurant v. PG&E Energy Trading Corporation, et al., filed on January 24, 2001, in San Francisco Superior Court and subsequently removed to the United States District Court for the Northern District of California; (2) Hendricks v. Dynegy Power Marketing, Inc., PG&E Energy Trading Corporation, et al., filed on November 29, 2000, in San Diego Superior Court and subsequently removed to the United States District Court for the Southern District of California; (3) Sweetwater Authority v. Dynegy Inc., PG&E Energy Trading Corporation, et al., filed on January 16, 2001, in San Diego Superior Court and subsequently removed to the United States District Court for the Southern District of California; and (4) People of the State of California v. Dynegy Power Marketing, Inc., PG&E Energy Trading Corporation, et al., filed on January 18, 2001, in San Francisco Superior Court and subsequently removed to the United States District Court for the Northern District of California. These cases are all currently pending in the U.S. District Court for the Southern District of California. Plaintiffs filed a motion to remand the proceedings to state court and in January 2003, the motion was granted. However, in view of various appeals of the remand order, the cases remain in federal court. These suits allege violation by the defendants of state antitrust laws and state laws against unfair and unlawful business practices. Specifically, the named plaintiffs allege that the defendants, including the owners of in-state generation and various power marketers, conspired to manipulate the California wholesale power market to the detriment of California consumers. Included among the acts forming the basis of the plaintiffs' claims are the alleged improper sharing of generation outage data, improper withholding of generation capacity, and the manipulation of power market bid practices. The plaintiffs seek unspecified treble damages and, among other remedies, disgorgement of alleged unlawful profits for sales of electricity beginning in 1999 or 2000, restitution, injunctive relief, and attorneys' fees. On May 13, 2002, ET-Power was named, along with multiple other defendants, in a complaint filed in San Francisco Superior Court by James A. Millar, individually and on behalf of the general public and as a representative taxpayer against energy suppliers and other unnamed sellers of electricity in the California market. In his complaint, plaintiff asserts the defendants violated state laws against unfair and fraudulent business practices by entering into certain long-term energy contracts with the DWR. The plaintiff claims that the contracts were made under circumstances that resulted in excessively high and unfair prices and, as a result, refunds should be made to the extent that the prices in the contracts were excessive. In addition, plaintiff seeks, among other remedies, an order enjoining enforcement of the allegedly unfair terms and conditions of the long-term contracts, declaratory relief, and attorneys' fees. The FERC is currently addressing the DWR contracts in the administrative actions before the FERC brought by the CPUC and California Electricity Oversight Board on February 25, 2002. On June 13, 2002, the defendants removed the case to the U.S. District Court for the Northern District of California based on federal preemption. The plaintiff filed a motion to remand the case to state court. On July 12, 2002 the Judicial Panel on Multidistrict Litigation entered a conditional order transferring this case to the U.S. District Court for the Southern District of California, where it is now before the same judge presiding over thePier 23 cases. The panel determined that the Millar case, as well as seven other pending lawsuits, involved common questions of law and fact. ET-Power is currently not a defendant in any of these other lawsuits. The plaintiff has renewed his motion to remand these cases to state court. On July 15, 2002, ET-Power was named among other sellers of power in an action filed by the Public Utility District No. 1 of Snohomish County,Public Utility District No. 1 of Snohomish County v. Dynegy Power Marketing, et al., in the U.S. District Court for the Central District of California. Plaintiff alleged various theories of manipulation of the deregulated California electricity market by the defendants in violation of state antitrust laws and state laws against unlawful and fraudulent business practices. Plaintiff claimed that the defendants manipulated the energy market, resulting in higher electricity prices and sought, among other remedies, disgorgement, restitution, injunctive relief, and treble damages. Plaintiff also claimed that the defendants failed to file their rates in advance with the FERC, which failure plaintiff asserts was a violation of the Federal Power Act. On October 11,682002, the Judicial Panel on Multidistrict Litigation entered a final order transferring the Snohomish case to the U.S. District Court for the Southern District of California and to the same judge presiding over thePier 23 andMillar proceedings. The defendants filed a joint motion to dismiss and to strike various elements of the complaint. On January 8, 2003, the U.S. District Court for the Southern District of California dismissed the complaint, finding that the issue of whether and how market manipulation affected electricity rates was one that should be determined by the FERC. Plaintiff has filed a notice of appeal of the district court's decision with the U.S. Court of Appeals for the Ninth Circuit. By letter dated May 7, 2002, ET-Power was advised by the California Attorney General, or AG, that it believes ET-Power (along with numerous other generators and market participants) violated state laws governing unfair and fraudulent business practices and that unless ET-Power settled the matter the AG would by June 1, 2002 file suit against ET-Power. The AG stated that he will claim that ET-Power failed to have its rates on file with FERC and that accordingly any sales made under such rates violated the Federal Power Act (a claim that the AG has made before FERC and which FERC has rejected) and that ET-Power exercised market-power in charging unjust and unreasonable prices. ET-Power has not yet been served with a complaint in this matter. In addition to these judicial proceedings, on March 20, 2002 the AG filed a complaint at the FERC against ET-Power and other named and unnamed public utility sellers of energy and ancillary services. The California AG alleges that wholesale sellers of energy to the California Independent System Operator, or ISO, the California Power Exchange, or PX, and the California Department of Water Resources, or DWR, failed to file their rates in accordance with the requirements of Section 205 of the Federal Power Act. Specifically, the California AG claims that the FERC has not been able to determine whether the rates charged by such sellers are just and reasonable, that the FERC's reporting requirements are insufficient to provide the FERC the information necessary to make this determination, and that even if the FERC's policies and procedures did comply with Section 205 of the Federal Power Act, the wholesale sellers failed to comply with its quarterly reporting requirements. As a result, the California AG requests that (1) sellers should be directed to comply, on a prospective basis, with the requirements of Section 205 of the Federal Power Act; (2) sellers should be required to provide transaction-specific information to the FERC regarding their short-term sales to the ISO, the PX, and the DWR for the years 2000 and 2001; (3) if rates were charged that were not just and reasonable, refunds should be ordered; (4) the FERC should declare that market-based rates are not subject to the filed rate doctrine; and (5) the FERC should institute proceedings to determine whether any further relief would be appropriate. On May 31, 2002, the FERC issued a decision denying most of the relief requested and on July 1, 2002, the California AG filed a petition with the FERC seeking rehearing of its order. The FERC denied rehearing on September 23, 2002. The California AG has filed an appeal of the FERC's decision with the U.S. Court of Appeals for the Ninth Circuit. PG&E Corporation believes that theultimate outcome of these matters will not have a material adverse affectimpact on PG&E Corporation'sthe Utility’s financial condition or results of operations.ComplaintCity and County of San Francisco and Cynthia BehrAGAttorney General filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200, or B&P, Code Section 17200. Among other allegations, the AGCalifornia Attorney General alleged that past transfers of money from the Utility to PG&E Corporation, and allegedly from PG&E Corporation to other affiliates of PG&E Corporation, violated various conditions established by the CPUC in decisions approving the holding company formation. The AGCalifornia 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. The AG alleged that these ringfencing transactions included conditions that restricted PG&E NEG's ability to provide any funds to PG&E Corporation, through dividends, capital distributions or similar payments, reducing PG&E Corporation's cash and thereby impairing PG&E Corporation's ability to comply with the capital requirements condition and subordinating the Utility's interests to the interests of PG&E Corporation and its other affiliates. (On January 9, 2002, the CPUC issued a decision interpreting the holding company condition regarding capital requirements condition (which it terms the "first“first priority condition"condition”) and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies "infuse“infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve."” The three major California investor-owned energy utilities and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years'years’ understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The three major California investor-owned69CPUC'sCPUC’s interpretation of the capital requirementsfirst priority condition to various state appellate courts. The CPUC moved to consolidate all proceedings in the San Francisco state appellate court. The CPUC'sCPUC’s request for consolidation was granted and all the petitions are now before the California Court of Appeal for the First Appellate District in San Francisco, California.) Oral argument is scheduled for March 5, 2004.B&P Code sectionSection 17200, that thea total penalty of be less than $500 million and costs of suit. In addition, the AG alleged that, through the Utility's bankruptcy proceedings, PG&E Corporation and the Utility engaged in unlawful, unfair, and fraudulent business practices by seeking to implement the transactions proposed in the proposed plan of reorganization filed in the Utility's bankruptcy proceeding. The AG'sCalifornia Attorney General’s complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility. In PG&E Corporation's view, the Bankruptcy Court has original and exclusive jurisdiction of these claims. Therefore, on February 8, 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Courtbankruptcy court to transfer the AG'sCalifornia Attorney General’s complaint to the Bankruptcy Court. After removing the California AG's complaint to the Bankruptcy Court, on February 15, 2002, PG&E Corporation filedbankruptcy court, as well as a motion to dismiss the lawsuit, or in the alternative, to stay the California AG's complaintsuit with the Bankruptcy Court.bankruptcy court. Subsequently, the California AGAttorney General filed a motion to remand the action to state court. The Bankruptcy Court held a hearing on April 24, 2002, to consider the remand motion. OnIn June 20, 2002, the Bankruptcy Court issued an Amended Order on Motion to Remand. (An initial order was issued on June 2, 2002). The Bankruptcy Courtbankruptcy court held that federal law preempted the California AG'sAttorney General’s allegations concerning PG&E Corporation'sCorporation’s participation in the Utility's bankruptcyUtility’s Chapter 11 proceedings. The Bankruptcy Courtbankruptcy court directed the California AGAttorney General to file an amended complaint omitting these allegations and remanded the amended complaint to the San Francisco Superior Court. Both parties have appealed the Bankruptcy Court'sbankruptcy court’s June 20, 2002 order. The appeal and cross-appeal are pending inorder to the United States District Court for the Northern District of California.Court.AGAttorney General filed its amended complaint in the San Francisco Superior Court, omitting the allegations concerning PG&E Corporation'sCorporation’s participation in the Utility's bankruptcyUtility’s Chapter 11 proceedings. PG&E Corporation and the directors named in the complaint have filed motions to strike certain allegations of the amended complaint. TheseOn February 28, 2003, the court denied the three motions are pending. PG&E Corporation believesto strike on the grounds that they were premature and stated that it would defer making a judgment on the allegationsmerits of the complaint are without merit and will vigorously respond to and defenddefendants’ arguments until the litigation. PG&E Corporation is unable to predict whether the outcome of this litigation will have a material adverse effect on its financial condition or results of operations.Complaint filed by the City and County of San Francisco, and the Peoplefactual context of the State of Californiacases was more fully developed.AG'sCalifornia Attorney General’s complaint, including allegations of unfair competition in violation of B&P Code Section 17200.competition. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation "took“took at least $5.2 billion from PG&E,"the Utility,” and for unjust enrichment. Among other allegations, plaintiffs allege that past transfers of money from the Utility to PG&E Corporation, allegedly used by PG&E Corporation to subsidize other affiliates of PG&E Corporation, violated various conditions established by the CPUC in decisions approving the holding company formation. The complaint also alleges that certain ring fencing transactions by which PG&E Corporation subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions. Plaintiffs also allege that by agreeing to certain restrictive covenants in certain financing agreements, PG&E Corporation also violated a holding company condition. The complaintCity seeks injunctive relief, the appointment of a receiver, restitution,payment to customers, disgorgement, the imposition of a constructive trust, civil penalties of $2,500 against each defendant for each violation of B&P Code Section 17200 as authorized by B&P Code Section 17206, and costs of suit.City'sCity’s action to the Bankruptcy Court onbankruptcy court in February 8, 2002, PG&E Corporation filed a motion to dismiss the complaint. Subsequently, the City filed a motion to remand the action to state court. OnIn June 20, 2002, the Bankruptcy Courtbankruptcy court issued an Amended Orderamended order on Motionmotion to Remand. (An initial order was issued70on June 2, 2002.) In its remand order,stating that the bankruptcy court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by the City and County, but remandedremanding the Section 17200 cause of action to the San Francisco Superior Court.state court. Both parties have appealed the Bankruptcy Court'sbankruptcy court’s remand order. The appeal and cross-appeal are pending inorder to the United States District Court for the Northern District of California.Court.Following remand, PG&E Corporation broughtIn addition, a motion to strike. This motion is pending. PG&E Corporation also moved to coordinate thisthird case, with the Section 17200 case brought by Cynthia Behr, which is discussed below. That motion was granted. PG&E Corporation believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation. PG&E Corporation is unable to predict whether the outcome of this litigation will have a material adverse effect on its financial condition or results of operations. On, was filed on February 14, 2002, this complaint was filed by a private plaintiff (who also has filed a claim under Chapter 11) in Santa Clara Superior Court against PG&E Corporation and its directors, Pacific Gas and Electric Company's directors, and other parties, also alleging a violation of B&P Code Section 17200. The Behr complaint also names the directors of PG&E Corporation and the Utility as defendants. The allegations of the complaint are similar to the allegations contained in the California Attorney General'sGeneral’s complaint, but also include allegations of conspiracy, fraudulent transfer and violation of the California bulk sales laws. PlaintiffThe plaintiff requests the same remedies as the California Attorney General's caseGeneral, and, in addition, requests damages, attachment and restraints upon the transfer of defendants'defendants’ property. OnIn March 8, 2002, PG&E Corporation filed a notice of removal in the bankruptcy court to transfer the complaint to the bankruptcy court. Subsequently, the plaintiff filed a motion to remand the action to state court.referred tomentioned above as to the California Attorney General's case,General’s and the City’s cases, the bankruptcy court retained jurisdiction over Behr'sBehr’s fraudulent transfer claim and bulk sales claim, finding them to belong to the Utility'sUtility’s estate. The bankruptcy court remanded Behr'sBehr’s Section 17200 claim to the Santa Clara Superior Court. Both parties have appealed the bankruptcy court'scourt’s remand order.order to the District Court.are pendingof the bankruptcy court’s remand order in the United Statesthree cases. On October 8, 2003, the District Court forreversed, in part, the Northernbankruptcy court’s June 2002 decision and ordered the California Attorney General’s restitution claims sent back to the bankruptcy court. The District of California. Following remand, PG&E Corporation moved to have the Behr case coordinatedCourt found that these claims, estimated along with the City's case described above. That motion was granted,City and County of San Francisco’s claims at approximately $5 billion, are the Behr case will now proceedproperty of the Utility’s Chapter 11Court.Court, where a status conference has been scheduled for February 24, 2004. The California Attorney General and the City and County of San Francisco have appealed this ruling to the Ninth Circuit. The defendants have filed motions to dismiss the appeals. No proceedings have been scheduled in bankruptcy court regarding the restitution claims. Under Section 17200, the California Attorney General is entitled to seek civil penalties of $2,500 against each defendant for each violation of Section 17200. The California Attorney General’s complaint asserted that the total civil penalties would be not less than $500 million. The bankruptcy court’s confirmation order provides that the California Attorney General’s and the City and County of San Francisco’s claims are not released in connection with implementation of the Plan of Reorganization.allegations of the complaint are without merit and will vigorously respond to and defend the litigation. PG&E Corporation is unable to predict whether the outcome of this litigation will haveapplicable calculation methodology for civil penalties, if any violations were found, would not result in a material adverse effect on its financial condition or results of operations.William Ahern,Compressor Station Chromium LitigationOn February 27, 2002, a groupAll of 25 ratepayersthese civil actions are now pending in the Los Angeles Superior Court, except the Lytle case, which is pending in Yolo County. Currently there are approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals have filed a complaint againstproofs of claim in the Utility’s Chapter 11 case, most of whom are plaintiffs in the chromium litigation. Approximately 1,035 claimants have filed proofs of claim requesting approximately $580 million in damages and another approximately 225 claimants have filed claims for an “unknown amount.”CPUC demanding an immediate reductionclaims of approximately 3.5 cents per kWh in allegedly excessive electric rates and a refundthe trial test plaintiffs. Two of alleged recent overcollections in electric revenue since June 1, 2001. The complaint claims that electric rate surcharges adoptedthese motions are scheduled for hearing in the first quarter of 2001 due to2004, with the high cost of wholesale power, surcharges that increased the average electric rate by 4.0 cents per kWh, became excessive later in 2001. (In January 2001, the CPUC authorized a 1.0 cent per kWh rate increase to pay for energy procurement costs. In March 2001, the CPUC authorized an additional 3.0 cent per kWh rate increase as of March 27, 2001, to pay for energy procurement costs, which the Utility began to collect in June 2001.) The only alleged overcollection amount calculated in the complaint is approximately $400 million during the last quarter of 2001. On April 2, 2002, the Utility filed an answer, arguing that the complaint should be denied and dismissed immediately as an impermissible collateral action and on the basis that the alleged facts, even if assumedothers to be true, do not establish that currently authorized electric rates are not reasonable. On May 10, 2002scheduled thereafter. The trial of the Utility filed atest cases is scheduled to begin in March 2004. The Utility’s motion to dismiss the complaint.complaint in theAdamscase was granted. The CPUCplaintiffs in that case have until April 12, 2004 to file an amended complaint.not yet issuedrecorded a decision. PG&E Corporation andreserve in the Utility’s financial statements in the amount of $160 million for these matters. The Utility believebelieves that, in light of the reserves that have already been accrued with respect to this matter, the ultimate outcome of this matter will not have a material adverse impact on theirthe Utility’s financial condition or future results of operations.PG&E NEG's Brayton Point Generating Station On March 27, 2002, the Attorney General of the State of Rhode Island notified USGenNE of his belief that Brayton Point is operating in violation of applicability statutory and regulatory provisions, including what he71characterized as "protections afforded by common law." The Attorney General purported to provide notice under the Massachusetts General Laws of his intention to seek judicial relief within the following thirty days to abate the alleged violations and to recover damages and to obtain other unexplained statutory and equitable remedies. PG&E NEG believes that Brayton Point Station is in full compliance with all applicable permits, laws and regulations. The complaint has not yet been filed or served. In May 2002, the Attorney General stated that he did not plan to file the action until the EPA issues a draft NPDES permit for Brayton Point. On July 22, 2002, the EPA and the Massachusetts Department of Environment, or DEP, issued a draft NPDES permit for Brayton Point that, among other things, substantially limits the discharge of heat by Brayton Point into Mt. Hope Bay. Based on its initial review of the draft permit, USGenNE believes that the draft permit is excessively stringent. It is estimated that USGenNE's cost to comply with the new permit conditions could be as much as $248 million through 2006, but this is a preliminary estimate. For more information, see Note 16 of the "Notes to Consolidated Financial Statements" of the 2002 Annual Report to Shareholders, portions of which are filed as Exhibit 13 to this report. The Rhode Island Attorney General has since stated that he has no intention of pursuing this matter until he reviews USGenNE's response to the draft permit, which was submitted on October 4, 2002. PG&E Corporation is unable to predict whether the Rhode Island Attorney General will pursue this matter and, if he does, the extent to which it will have a material adverse effect on PG&E Corporation's financial condition or results of operations.ITEMItem 4. Submission of Matters to a Vote of Security Holders.Submission of Matters to a Vote of Security Holders
EXECUTIVE OFFICERS OF THE REGISTRANTS"Executive“The names, ages and positions of PG&E Corporation executive officers,"” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, of PG&E Corporationor Exchange Act at December 31, 2003 are as follows:Name Name
AgeAge atDecember 31,2002Position R. D. Glynn, Jr. 6061 Chairman of the Board, Chief Executive Officer, and President P. A. Darbee 4950 Senior Vice President and Chief Financial Officer P. C. Iribe52Senior Vice President; Executive Vice President, PG&E National Energy Group, Inc.C. P. Johns 4243 Senior Vice President and Controller T. B. KingD. D. Richard, Jr. 4153 Senior Vice President; President, PG&E National Energy Group, Inc.L. E. Maddox47Senior Vice President; Executive Vice President, PG&E National Energy Group, Inc.D.D. Richard, Jr.52 Senior Vice President, Public Affairs; Senior Vice President, Public Affairs, Pacific Gas and Electric Company G. R. Smith 5455 Senior Vice President; President and Chief Executive Officer, Pacific Gas and Electric Company G. B. Stanley 5657 Senior Vice President, Human Resources B. R. Worthington 5354 Senior Vice President and General Counsel Name NamePosition Period Held Office R. D. Glynn, Jr. Chairman of the Board, Chief Executive Officer and President January 1, 1998 to present Chairman of the Board, Pacific Gas and Electric Company January 1, 1998 to present 72
P. A. Darbee
Senior Vice President and Chief Financial Officer
July 9, 2001 to present Senior Vice President, Chief Financial Officer, and Treasurer September 20, 1999 to July 8, 2001 Vice President and Chief Financial Officer, Advance Fibre Communications, Inc. June 30, 1997 to September 19, 1999 P. C. IribeSenior Vice PresidentJanuary 1, 1999 to presentExecutive Vice President, PG&E National Energy Group, Inc.August 9, 2002 to presentPresident and Chief Operating Officer, East Region, PG&E National Energy Group, Inc.July 1, 2000 to presentPresident and Chief Operating Officer, PG&E National Energy Group CompanyNovember 1, 1998 to presentExecutive Vice President and Chief Operating Officer, PG&E National Energy Group Company (formerly known as PG&E Generating Company)September 1, 1997 to October 31, 1998
C. P. Johns
Senior Vice President and Controller
September 19, 2001 to present Vice President and Controller July 1, 1997 to September 18, 2001 Vice President and Controller, Pacific Gas and Electric Company June 1, 1996 to December 31, 1999 T. B. KingSenior Vice PresidentJanuary 1, 1999 to presentPresident, PG&E National Energy Group, Inc.November 15, 2002 to presentPresident, PG&E Gas Transmission CorporationNovember 15, 2002 to presentPresident and Chief Operating Officer, Gas TransmissionAugust 9, 2002 to November 14, 2002President and Chief Operating Officer, West Region, PG&E National Energy Group, Inc.July 1, 2000 to August 8, 2002President and Chief Operating Officer, PG&E Gas Transmission CorporationNovember 23, 1998 to November 14, 2002President and Chief Operating Officer, Kinder Morgan Energy Partners, L.P.February 14, 1997 to November 22, 1998L. E. MaddoxSenior Vice PresidentJune 1, 1997 to presentExecutive Vice President, PG&E National Energy Group, Inc.November 15, 2002 to presentPresident and Chief Operating Officer, Merchant Energy, PG&E National Energy Group, Inc.August 9, 2002 to November 14, 2002President and Chief Operating Officer, Trading, PG&E National Energy Group, Inc.July 1, 2000 to August 8, 2002President and Chief Executive Officer, PG&E Energy Trading-Gas CorporationMay 12, 1997 to present73
D. D. Richard, Jr.
Senior Vice President, Public Affairs
October 18, 2000 to present Vice President, Governmental Relations July 1, 1997 to October 17, 2000 Senior Vice President, Public Affairs, Pacific Gas and Electric Company May 1, 1998 to present Senior Vice President, Governmental and Regulatory Relations, Pacific Gas and Electric Company July 1, 1997 to April 30, 1998
G. B. Stanley
Senior Vice President, Human Resources
January 1, 1998 to present Senior Vice President, PG&E National Energy Group,& Gas Transmission, Inc. July 1, 2000 to presentJuly 7, 2003 Vice President, Human Resources June 1, 1997 to December 31, 19771997
B. R. Worthington
Senior Vice President and General Counsel
June 1, 1997 to present Vice President, PG&E National Energy Group,& Gas Transmission, Inc. January 20, 1999 to July 1, 2000 "Executive“The names, ages and position’s of the Utility’s executive officers,"” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, of Pacific Gas and Electric Companyat December 31, 2003 are as follows:Name Name
AgeAge atDecember 31,2002Position G. R. Smith 5455 President and Chief Executive Officer K. M. Harvey 4445 Senior Vice President — Chief Financial Officer, and Treasurer R. J. PetersT. B. King 5242 Senior Vice President and General CounselJ. K. Randolph58 Senior Vice President and Chief of Utility Operations R. J. Peters 53 Senior Vice President and General Counsel D. D. Richard, Jr. 5253 Senior Vice President, Public Affairs G. M. Rueger 5253 Senior Vice President, Generation and Chief Nuclear Officer 74Pacific Gas and Electric Companythe Utility serve at the pleasure of the Board of Directors. During the past five years, the executive officers of Pacific Gas and Electric Companythe Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.Name NamePosition Period Held Office G. R. Smith President and Chief Executive Officer June 1, 1997 to present Senior Vice President, PG&E Corporation January 1, 1999 to present
K. M. Harvey
Senior Vice President — Chief Financial Officer, and Treasurer
November 1, 2000 to present Senior Vice President, Chief Financial Officer, Controller, and Treasurer January 1, 2000 to October 31, 2000 Senior Vice President, Chief Financial Officer, and Treasurer July 1, 1997 to December 31, 1999 R. J. PetersSenior Vice President and General CounselJanuary 1, 1999 to presentT. B. King Vice President and General CounselJuly 1, 1997 to December 31, 1998J. K. Randolph
Senior Vice President and Chief of Utility Operations
May 5, 2000November 1, 2003 to present Senior Vice President, and General Manager, Transmission, Distribution and Customer Service Business UnitPG&E Corporation January 24,1, 1999 to October 31, 2003President, 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 May 4, 2000August 8, 2002 President and Chief Operating Officer, PG&E Gas Transmission Corporation November 23, 1998 to September 10, 2002* R. J. Peters Senior Vice President and General Manager, Distribution and Customer Service Business UnitCounsel JulyJanuary 1, 19971999 to January 23, 2000present
NamePosition Period Held Office D. D. Richard, Jr.
Senior Vice President, Public Affairs (Please refer to description of business experience for executive officers of PG&E Corporation above.)
May 1, 1998 to present
G. M. Rueger
Senior Vice President, Generation and Chief Nuclear Officer
April 2, 2000 to present Senior Vice President and General Manager, Nuclear Power Generation Business Unit November 1, 1991 to April 1, 2000 75ITEM 5. Market for the Registrant's Common Equity and Related StockholderItem 5. Market for the Registrant’s Common Equity and Related Shareholder Matters. on page 173 under the heading "Quarterly“Quarterly Consolidated Financial Data (Unaudited)"” in the 20022003 Annual Report, to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. As of February 1, 2003,17, 2004, there were 117,812110,740 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York, Pacific, and Swiss stock exchanges. The discussion of dividends with respect to PG&E Corporation'sCorporation’s common stock is hereby incorporated by reference from "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Dividends" on page 34Operations — Liquidity and Financial Resources — Dividend Policy” of the 20022003 Annual Report to Shareholders.Report.June 25, 2002,July 2, 2003, PG&E Corporation issuedcompleted the offer and sale of $600 million of 6 7/8% Senior Secured Notes due 2008 pursuant to certain lenders warrants to purchase approximately 2.4 million shares of PG&E Corporation common stock at an exercise price of $0.01 per share. On October 18, 2002, PG&E Corporation issued to certain lenders additional warrants to purchase approximately 2.7 million shares of PG&E Corporation common stock. The terms and provisions of the warrants, includingexemption from, or in a warrant exercise price of $0.01 per share, are substantially identicaltransaction not subject to, the warrants issued on June 25, 2002. The issuanceregistration requirements of the warrants by PG&E Corporation was not registered under the Securities Act of 1933, in relianceor Act. The net proceeds of the offering, approximately $581 million, together with cash on hand, were used to repay the exemption afforded by Section 4(2). Also, on June 25, 2002,principal balance outstanding under PG&E Corporation issued $280Corporation’s October 2002 credit agreement of approximately $720 million, aggregate principal amountplus $15 million of 7.50% Convertible Subordinated Notes due June 30, 2007. On October 18, 2002,accrued in-kind interest and a $52 million prepayment premium. The payment resulted in the notestermination of PG&E Corporation’s existing credit agreement and the related indenturerelease of liens on PG&E Corporation’s shares of NEGT. Lehman Brothers acted as principal underwriters. The notes were amendedoffered and sold only to delete certain cross-default provisions,“qualified institutional buyers” as defined in Rule 144A under the Act in compliance with Rule 144A under the Act, and in offers and sales that occur outside the U.S. to increasepersons other than U.S. persons, or foreign purchasers, which include dealers or other professional fiduciaries in the interest rateU.S. acting on a discretionary basis for foreign beneficial owners, other than an estate or trust, in offshore transactions meeting the notes to 9.50% from 7.50%, to extendrequirements of Rule 903 of Regulation S under the maturity of the notes to June 30, 2010, from June 30, 2007, and to provide the holder of the notes with a one-time right to require PG&E Corporation to repurchase the notes on June 30, 2007, at a purchase price equalAct. For more information, see Note 3 to the principal amount plus accrued and unpaid interest (including any liquidated damages and pass-through dividends, if any). The notes are unsecured and are subordinate“Notes to other PG&E Corporation debt. PG&E Corporation has the right, subject to certain limitations, to pay interest by issuing additional notes in lieu of paying cash. In addition to interest, if PG&E Corporation pays cash dividends to holders of its common stock, note holders are entitled to receive cash equal to the dividends that would have been paid with respect to the number of shares that the holder would be entitled to receive if the notes had been converted on the dividend record date. The notes may be converted by the holders into sharesConsolidated Financial Statements” of PG&E Corporation common stock at a conversion price of $15.0873 per share. The conversion price is subject to adjustment under certain circumstances, including upon consummation of any spin-off transaction of the Utility as proposed in its plan of reorganization or a spin-off of the shares of PG&E NEG. The issuance of the notes by PG&E Corporation was not registered under the Securities Act of 1933 in reliance on the exemption afforded by Section 4(2). All obligations of PG&E Corporation with respect to certain loans are secured by a perfected first-priority security interestcontained in the outstanding common stock2003 Annual Report, which information is hereby incorporated by reference and filed as part of PG&E Corporation's subsidiary, the Utility, and all proceeds thereof. With respectExhibit 13 to 35% of such common stock pledged for the benefit of the lenders, the lenders have customary rights of a pledgee of common stock, provided that certain regulatory approvals may be required in connection with any foreclosure on such stock. With respect to the remaining 65%, such common stock has been pledged for the benefit of the lenders, but the lenders have no ability to control such common stock under any circumstances and do not have any of the typical rights and remedies of a secured creditor. However, the lenders do have the right to receive any cash proceeds received upon a disposition of such common stock. PG&E Corporation may substitute common stock of Newco, a new corporation formed to hold the equity interests in the LLCs, for the common stock of the Utility in connection with the consummation of the Utility's plan of reorganization. The loans are also secured by substantially all assets of PG&E Corporation and continue to be secured by PG&E Corporation's ownership interest in PG&E National Energy Group, LLC, or PG&E NEG LLC, which is a Delaware limited liability company and the owner of the shares of PG&E NEG and PG&E NEG LLC's equity interest in PG&E NEG.this report.PG&E Corporation has agreed to provide, following consummation of a plan of reorganization of the Utility, registration rights in connection with the shares issuable upon conversion of the notes and exercise of the warrants. Finally, in connection with the original credit agreement, the lenders had received an option to purchase up to 3% of the shares of PG&E NEG. Under the original credit agreement, PG&E Corporation's exercise of each of its one-year extensions of the loan was conditioned upon PG&E NEG granting affiliates of the lenders an additional option to purchase 1% of the common stock of PG&E NEG, determined on a fully-diluted basis, at an exercise price of $1.00. In connection with a new credit agreement entered into on June 25, 2002, the 1% was reduced to76approximately .87% of the common stock of PG&E NEG or up to 2.61%. On September 3, 2002, General Electric Capital Corporation, or GECC, gave PG&E Corporation notice that it would put its options to PG&E Corporation under the Option Agreement, and GECC and PG&E Corporation were engaged in a process of appraising the options as provided under the Option Agreement. On October 30, 2002, before the completion of the appraisal process, GECC gave notice of cancellation of its put notice, which was accepted by PG&E Corporation. GECC no longer has the right to put these options to PG&E Corporation. On February 25, 2003, GECC exercised the options, which otherwise would have expired on March 1, 2003. PG&E Corporation and PG&E NEG LLC have agreed with the other holders of options under the Option Agreement that they may exercise their put option any time before March 1, 2003. These options must in any event also be exercised before March 1, 2003. The issuance of the put option by PG&E Corporation was not registered under the Securities Act of 1933 in reliance on the exemption afforded by Section 4(2).2002,2003, the period covered by this report.Item 6. ITEM 6. Selected Financial Data.on page 2 under the heading "Selected“Selected Financial Data"Data” in the 20022003 Annual Report, to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. Pacific Gas and Electric Company's ratio of earnings to fixed charges for the year ended December 31, 2002, was 3.91. Pacific Gas and Electric Company's ratio of earnings to combined fixed charges and preferred stock dividends for the year ended December 31, 2002, was 3.78. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into Registration Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding.ITEM 7. Management'sItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Corporation'sCorporation’s and Pacific Gas and Electric Company'sCompany’s consolidated results of operations and financial condition is set forth on pages 3 through 70 under the heading "Management's“Management’s Discussion and AnalysisOperations"Operations” in the 20022003 Annual Report, to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.Item 7A. ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.20022003 Annual Report to Shareholders on pages 57-65 under the heading "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operations — Risk Management Activities,"” and on pages 95-96 and 134 under Notes 1 4, 9, and 118 of the "Notes“Notes to the Consolidated Financial Statements"Statements” of the 20022003 Annual Report, to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.Item 8. ITEM 8. Financial Statements and Supplementary Data.on pages 71 through 80 ofin the 20022003 Annual Report to Shareholders under the following headings for PG&E Corporation: "Consolidated“Consolidated Statements of Operations," "Consolidated” “Consolidated Balance Sheets," "Consolidated” “Consolidated Statements of Cash Flows,"” and "Consolidated“Consolidated Statements of Common Stockholders'Shareholders’ Equity;"” under the following headings for Pacific Gas and Electric Company: "Consolidated“Consolidated Statements of Operations," "Consolidated” “Consolidated Balance Sheets," "Consolidated” “Consolidated Statements of Cash Flows,"” and "Consolidated“Consolidated Statements of Stockholders'Shareholders’ Equity;"” and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: "Notes“Notes to the Consolidated Financial Statements," "Quarterly” “Quarterly Consolidated Financial Data (Unaudited)," "Independent Auditors'” “Independent Auditors’ Report,"” and "Responsibility“Responsibility for the Consolidated Financial Statements,"” which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.Item 9. ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.Item 9A. Controls and Procedures 77Item 10. ITEM 10. Directors and Executive Officers of the Registrant."Executive“Executive Officers of the Registrants"Registrants” contained on pages 7248 through 7550 in Part I of this report. Otherresponding to Itemis reported for individuals during periods in which they were not directors, officers, or 10 is included underpercent shareholders of the heading "Item No. 1: Electionrespective company.Company"Company’s website,www.pge.com: (1) the codes of conduct and under the heading "Section 16 Beneficial Ownership Reporting Compliance" in the Joint Proxy Statement relating to the 2003 Annual Meetings of Shareholders, which information is hereby incorporatedethics adopted by reference.ITEM 11. Executive Compensation. Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company is included underapplicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers, and other executive officers, (2) PG&E Corporation’s and Pacific Gas and Electric Company’s corporateheading "Compensationcompanies’ Audit Committees and the PG&E Corporation Nominating, Compensation, and Governance Committee. Shareholders also may obtain print copies of Directors" and under the headings "Summary Compensation Table," "Option/SAR Grants in 2002," "Aggregated Option/SAR Exercises in 2002 and Year-End Option/SAR Values," "Long-Term Incentive Plan—Awards in 2002," "Retirement Benefits," "Employment Contracts/Arrangements," and "Terminationthese documents by submitting a written request to Linda Y.H. Cheng, Corporate Secretary of Employment and Change In Control Provisions" in the Joint Proxy Statement relating to the 2003 Annual Meetings of Shareholders, which information is hereby incorporated by reference.ITEM 12. Security Ownership of Certain Beneficial Owners and Management. Information responding to Item 12, for each ofboth PG&E Corporation and Pacific Gas and Electric Company, One Market, Spear Tower, Suite 2400, San Francisco, California 94105.includedso affected will disclose the nature of such amendment or waiver on its respective website.Item 11. Executive Compensation. heading "Security OwnershipPlan were given a one-time option of Management"receiving at retirement the benefit accrued through 1997, or of converting the present value of their accrued benefit into a PG&E Corporation common stock equivalent investment held in the Deferred Compensation Plan for Non-Employee Directors. The payment of frozen accrued retirement benefits, or distributions from the Deferred Compensation Plan attributable to the conversion of retirement benefits, cannot be made until the later of age 65 or retirement from the Board.Summary Compensation Table Annual Compensation Long-Term Compensation Awards Payouts Other Annual Restricted Securities All Other Compen- Stock Underlying LTIP Compen- Salary Bonus sation Award(s) Options/SARs Payouts sation Name and Principal Position Year ($) ($)(1) ($)(2) ($)(3) (# of Shares) ($)(4) ($)(5) Robert D. Glynn, Jr. 2003 $ 1,050,000 $ 0 $ 3,154,268 $ 2,169,950 486,000 $ 9,879,911 $ 666,050 Chairman of the Board, Chief 2002 1,050,000 787,500 4,833,389 0 150,000 632,461 79,777 Executive Officer, and 2001 900,000 1,181,700 4,817 3,000,000 470,800 74,588 413,196 President of PG&E Corporation; Chairman of the Board of Pacific Gas and Electric Company Peter A. Darbee 2003 $ 490,000 $ 0 $ 2,368 $ 678,269 101,300 $ 4,023,098 $ 329,140 Senior Vice President and 2002 490,000 220,500 4,862 0 0 115,244 62,355 Chief Financial Officer 2001 455,000 328,578 4,817 1,125,000 183,800 26,105 613,596 of PG&E Corporation Bruce R. Worthington 2003 $ 425,000 $ 0 $ 836,295 $ 530,708 79,300 $ 2,310,713 $ 306,575 Senior Vice President and 2002 425,000 175,313 1,220,913 0 0 205,801 43,893 General Counsel of PG&E 2001 400,000 288,860 4,817 625,000 145,000 24,617 171,353 Corporation G. Brent Stanley 2003 $ 305,000 $ 0 $ 2,368 $ 353,927 52,900 $ 2,141,176 $ 204,782 Senior Vice President — 2002 305,000 114,375 4,862 0 0 84,311 18,010 Human Resources of PG&E 2001 285,000 187,103 4,817 625,000 102,800 15,385 110,691 Corporation P. Chrisman Iribe 2003 $ 450,000 $ 0 $ 0 $ 471,903 70,400 $ 3,017,831 $ 151,934 Senior Vice President of 2002 450,000 93,163 0 0 0 94,863 75,620 PG&E Corporation; Executive 2001 425,000 306,914 0 1,125,000 186,400 25,355 57,846 Vice President of National Energy & Gas Transmission, Inc. Gordon R. Smith 2003 $ 735,000 $ 0 $ 2,402,048 $ 943,441 140,900 $ 5,842,500 $ 453,723 Senior Vice President of 2002 735,000 519,278 4,310,520 0 0 182,009 37,173 PG&E Corporation; President 2001 630,000 664,808 937 1,750,000 272,000 40,282 241,302 and Chief Executive Officer of Pacific Gas and Electric Company Thomas B. King 2003 $ 500,000 $ 0 $ 23,780 $ 530,708 79,300 $ 2,938,351 $ 659,488 Senior Vice President and 2002 450,000 93,163 0 0 0 94,863 89,263 Chief of Utility Operations 2001 425,000 306,914 0 1,125,000 186,400 41,020 1,090,207 of Pacific Gas and Electric Company (November 1, 2003) Senior Vice President of PG&E Corporation (January 1, 1999 - October 31, 2003) Annual Compensation Long-Term Compensation Awards Payouts Other Annual Restricted Securities All Other Compen- Stock Underlying LTIP Compen- Salary Bonus sation Award(s) Options/SARs Payouts sation Name and Principal Position Year ($) ($)(1) ($)(2) ($)(3) (# of Shares) ($)(4) ($)(5) Gregory M. Rueger 2003 $ 358,000 $ 0 $ 642,860 $ 272,477 40,700 $ 1,563,204 $ 243,325 Senior Vice President — 2002 358,000 194,215 1,007,117 0 0 42,166 16,646 Generation and Chief Nuclear 2001 340,000 257,550 0 625,000 79,400 15,385 129,145 Officer of Pacific Gas and Electric Company Kent M. Harvey 2003 $ 302,000 $ 0 $ 0 $ 272,477 40,700 $ 1,557,466 $ 209,703 Senior Vice President, 2002 302,000 173,952 0 0 0 41,434 18,812 Chief Financial Officer, and 2001 285,000 213,465 0 625,000 76,000 15,385 113,462 Treasurer of Pacific Gas and Electric Company Roger J. Peters 2003 $ 302,000 $ 0 $ 0 $ 272,477 40,700 $ 1,557,466 $ 204,502 Senior Vice President and 2002 302,000 166,402 0 0 0 41,434 19,385 General Counsel of Pacific Gas 2001 285,000 212,753 0 625,000 76,000 15,385 112,619 and Electric Company James K. Randolph 2003 $ 337,000 $ 0 $ 669,741 $ 265,537 39,700 $ 1,557,466 $ 233.943 Senior Vice President and 2002 337,000 165,130 1,282,378 0 0 41,434 15,602 Chief of Utility Operations of 2001 325,000 218,725 0 625,000 72,600 15,385 123,028 Pacific Gas and Electric Company (retired October 31, 2003) (1) Represents payments received or deferred in 2003 and 2002 for achievement of corporate and organizational objectives in 2002 and 2001, respectively, under the Short-Term Incentive Plan. No decision has been made with respect to the 2003 Short-Term Incentive Plan. (2) Amounts reported consist of (i) reportable officer perquisite allowances and, for 2002 and 2003, amounts for non-business related travel (Mr. Glynn $35,000 and $62,998, respectively), (ii) payments of related taxes, and (iii) for 2002 and 2003, the cost of annuities to replace existing retirement benefits, at the time they are due under the Supplemental Executive Retirement Plan (SERP). The annuities will not change the after-tax benefits that would have been provided upon retirement under the existing arrangements. The cost of the annuity and associated tax restoration payments during 2003 for retirement obligations as of December 31, 2002, are: Mr. Glynn $3,048,972, Mr. Worthington $833,927, Mr. Smith $2,402,048, Mr. Rueger $642,860, and Mr. Randolph $669,741. (3) As of the end of the year, the aggregate number of shares or units of restricted stock held by each named executive officer, and the value using the year-end closing price of a share of PG&E Corporation common stock, were: Mr. Glynn 148,525 (with a value of $4,124,539), Mr. Darbee 46,425 (with a value of $1,289,222), Mr. Worthington 36,325 (with a value of $1,008,745), Mr. Stanley 24,225 (with a value of $672,728), Mr. Iribe 32,300 (with a value of $896,971), Mr. Smith 64,575 (with a value of $1,793,248), Mr. King 36,325 (with a value of $1,008,745), Mr. Rueger 18,650 (with a value of $517,911), Mr. Harvey 18,650 (with a value of $517,911), Mr. Peters 18,650 (with a value of $517,911), and Mr. Randolph 18,175 (with a value of $504,720). The restrictions lapse in annual increments of up to 25 percent on the first business day of 2004, 2005, 2006, and 2007, subject to the recipient’s continued employment. In general, 20 percent of each year’s increment is subject to forfeiture if PG&E Corporation fails to be in the top quartile of the comparator group as measured by relative annual total shareholder return at the end of the prior year. With respect to the Chairman, Chief Executive Officer, and President of PG&E Corporation, 25 percent of each year’s increment is subject to forfeiture if PG&E Corporation fails to be in the top quartile of the comparator group as measured by total shareholder return at the end of the prior year, and an additional 25 percent is subject to forfeiture if PG&E Corporation fails to be in the top half of the comparator group. The shares of restricted stock have the same dividend rights as unrestricted shares of PG&E Corporation common stock. (4) Represents (i) payments received or deferred in 2004, 2003, and 2002 for achievement of corporate performance objectives for the periods 2001 through 2003, 2000 through 2002, and 1999 through 2001, respectively, under the Performance Unit Plan (Mr. Glynn $1,292,837, Mr. Darbee $669,876, Mr. Worthington $522,915, Mr. Stanley $325,427, Mr. Iribe $533,063, Mr. Smith $799,143, Mr. King $533,063, Mr. Rueger $234,201, Mr. Harvey $228,463, Mr. Peters $228,463, and Mr. Randolph $228,463), (ii) common stock equivalents called Special Incentive Stock Ownership Premiums (SISOPs) earned by executive officers under the Executive Stock Ownership Program and vested during 2003, and additional common stock equivalents reflecting dividends accrued on those SISOPs as follows: Mr. Glynn 2,948 (with a value of $42,453), Mr. Darbee 10,346 (with a value of $148,981), Mr. Worthington 533 (with a value $7,672), Mr. Stanley 2,474 (with a value of $35,623), Mr. Iribe 6,430 (with a value of $92,591), Mr. Smith 4,096 (with a value of $58,989), and Mr. King 910 (with a value of $13,111), and (iii) amounts representing one-half of the phantom restricted stock units granted in 2001 under the Senior Executive Retention Program that were subject to a performance measure (Mr. Glynn 307,692.5 units with a value of $8,544,621, Mr. Darbee 115,385 units with a value of $3,204,241, Mr. Worthington 64,102.5 units with a value of $1,780,126, Mr. Stanley 64,102.5 units with a value of $1,780,126, Mr. Iribe 86,142.5 units with a value of $2,392,177, Mr. Smith 179,487.5 units with a value of $4,984,368, Mr. King 86,142.5 units with a value of $2,392,177, Mr. Rueger 47,857.5 units with a value of $1,329,003, Mr. Harvey 47,857.5 units with a value of $1,329,003, Mr. Peters 47,857.5 units with a value of $1,329,003, and Mr. Randolph 47,857.5 units with a value of $1,329,003). The value of all phantom restricted units granted under the Senior Executive Retention Program is based solely on the closing price of PG&E Corporation common stock on the date that the units vested, December 31, 2003. As previously reported, the total number of phantom restricted stock units granted under the Program and their value as of their vesting date of December 31, 2003, inclusive of the performance-based units described above, were: Mr. Glynn 615,385 units with a value of $17,089,241, Mr. Darbee 230,770 units with a value of $6,408,483, Mr. Worthington 128,205 units with a value of $3,560,253, Mr. Stanley 128,205 units with a value of $3,560,253, Mr. Iribe 172,285 units with a value of $4,784,354, Mr. Smith 358,975 units with a value of $9,968,736, Mr. King 172,285 units with a value of $4,784,354, Mr. Rueger 95,715 units with a value of $2,658,006, Mr. Harvey 95,715 units with a value of $2,658,006, Mr. Peters 95,715 units with a value of $2,658,006, and Mr. Randolph 95,715 units with a value of $2,658,006. (5) Amounts reported for 2003 consist of: (i) contributions to defined contribution retirement plans (Mr. Glynn $9,000, Mr. Darbee $16,125, Mr. Worthington $3,953, Mr. Stanley $3,853, Mr. Iribe $20,000, Mr. Smith $9,000, Mr. King $20,000, Mr. Rueger $9,000, Mr. Harvey $9,000, Mr. Peters $9,000, and Mr. Randolph $9,000), (ii) contributions received or deferred under excess benefit arrangements associated with defined contribution retirement plans (Mr. Glynn $38,250, Mr. Darbee $5,925, Mr. Worthington $15,172, Mr. Stanley $9,872, Mr. Iribe $25,000, Mr. Smith $24,075, Mr. King $2,500, Mr. Rueger $7,110, Mr. Harvey $4,590, Mr. Peters $4,590, and Mr. Randolph $6,165), (iii) above-market interest on deferred compensation (Mr. Glynn $18,800, Mr. Darbee $3,757, Mr. Worthington $350, Mr. Stanley $1,057, Mr. Iribe $203, Mr. Smith $648, Mr. King $1,285, Mr. Rueger $548, Mr. Harvey $306, Mr. Peters $331, and Mr. Randolph $167), (iv) relocation allowances and other one-time payments, Mr. King $374,645, (v) sale of vacation (Mr. Worthington $20,433, Mr. Iribe $69,231, Mr. King $36,058, Mr. Harvey $5,807, Mr. Peters $581, and Mr. Randolph $1,944), and (vi) amounts received pursuant to management retention programs (Mr. Glynn $600,000, Mr. Darbee $303,333, Mr. Worthington $266,667, Mr. Stanley $190,000, Mr. Iribe $37,500, Mr. Smith $420,000, Mr. King $225,000, Mr. Rueger $226,667, Mr. Harvey $190,000, Mr. Peters $190,000, and Mr. Randolph $216,667). Grant Individual Grants Date Value Number of % of Total Securities Options/SARs Underlying Granted to Exercise or Grant Date Options/SARs Employees in Base Price Expiration Present Name Granted (#)(1)(2) 2003(2) ($/Sh)(3) Date(4) Value ($)(5) Robert D. Glynn, Jr. 486,000 13.32 % 14.61 01-03-2013 $ 2,760,480 Peter A. Darbee 101,300 2.78 % 14.61 01-03-2013 575,384 Bruce R. Worthington 79,300 2.17 % 14.61 01-03-2013 450,424 G. Brent Stanley 52,900 1.45 % 14.61 01-03-2013 300,472 P. Chrisman Iribe 70,400 1.93 % 14.61 01-03-2013 399,872 Gordon R. Smith 140,900 3.86 % 14.61 01-03-2013 800,312 Thomas B. King 79,300 2.17 % 14.61 01-03-2013 450,424 Gregory M. Rueger 40,700 1.12 % 14.61 01-03-2013 231,176 Kent M. Harvey 40,700 1.12 % 14.61 01-03-2013 231,176 Roger J. Peters 40,700 1.12 % 14.61 01-03-2013 231,176 James K. Randolph 39,700 1.09 % 14.61 01-03-2013 225,496 (1) All options granted to executive officers in 2003 are exercisable as follows: 25 percent of the options may be exercised on or after the first anniversary of the date of grant, 50 percent on or after the second anniversary, 75 percent on or after the third anniversary, and 100 percent on or after the fourth anniversary, provided that options will vest immediately upon the occurrence of certain events. No options were accompanied by tandem dividend equivalents. (2) No stock appreciation rights (SARs) have been granted since 1991. (3) The exercise price is equal to the closing price of PG&E Corporation common stock on the date of grant. (4) All options granted to executive officers in 2003 expire ten years and one day from the date of grant, subject to earlier expiration in the event of the officer’s termination of employment with PG&E Corporation, the Utility, or one of their respective subsidiaries. (5) Estimated present values are based on the Black-Scholes Model, a mathematical formula used to value options traded on stock exchanges. The Black-Scholes Model considers a number of factors, including the expected volatility and dividend rate of the stock, interest rates, and time of exercise of the option. The following assumptions were used in applying the Black-Scholes Model to the 2003 option grant shown in the table above: volatility of 45.0 percent, risk-free rate of return of 3.94 percent, dividend yield of $0.00 (the annual dividend rate on the grant date), and an exercise date ten years after the date of grant. The ultimate value of the options will depend on the future market price of PG&E Corporation common stock, which cannot be forecast with reasonable accuracy. That value will depend on the future success achieved by employees for the benefit of all shareholders. The estimated grant date present value for the options shown in the table was $5.68 per share. Value of Number of Securities Unexercised Underlying Unexercised In-the-Money Options/SARs at Options/SARs at Shares Acquired End of 2003 (#) End of 2003 ($)(1) on Exercise Value Realized (Exercisable/ (Exercisable/ Name (#) ($) Unexercisable) Unexercisable) Robert D. Glynn, Jr. 0 0 1,363,492/1,057,232 $ 5,306,585/$12,720,407 Peter A. Darbee 0 0 309,402/272,898 $ 1,608,109/$3,371,912 Bruce R. Worthington 0 0 369,268/215,232 $ 1,633,980/$2,656,447 G. Brent Stanley 0 0 204,902/149,798 $ 1,069,201/$1,843,813 P. Chrisman Iribe 31,000 323,537 315,034/235,566 $ 1,203,811/$2,923,614 Gordon R. Smith 0 0 612,302/393,098 $ 2,824,560/$4,857,529 Thomas B. King 0 0 293,934/244,466 $ 1,486,781/$3,040,738 Gregory M. Rueger 82,402 210,363 135,132/113,598 $ 139,168/$1,406,559 Kent M. Harvey 31,334 378,715 151,734/111,332 $ 359,225/$1,376,076 Roger J. Peters(2) 2,000 $ (12,740 ) 183,568/111,332 $ 736,723/$1,376,076 James K. Randolph(2) 4,500 $ (30,375 ) 189,267/108,066 $ 773,373/$1,332,432 (1) Based on the difference between the option exercise price (without reduction for the amount of accrued dividend equivalents, if any) and a fair market value of $27.77, which was the closing price of PG&E Corporation common stock on December 31, 2003. (2) The options exercised would have expired on January 4, 2004. After accounting for accrued dividend equivalents, Mr. Peters realized $8,240 and Mr. Randolph realized $16,830. Awards Performance or Other Period Number of Shares, Until Maturation Name Units, or Other Rights or Payout Gregory M. Rueger 2,601(1) 3 years Kent M. Harvey 3,915(1) 3 years Roger J. Peters 631(1) 3 years James K. Randolph 177(1) 3 years (1) Represents common stock equivalents called Special Incentive Stock Ownership Premiums (SISOPs) earned under the Executive Stock Ownership Program. SISOPs are earned by eligible officers who achieve and maintain minimum PG&E Corporation common stock ownership levels as set by the Nominating, Compensation, and Governance Committee. All of the officers named in the Summary Compensation Table are eligible officers. Each SISOP represents a share of PG&E Corporation common stock that vests at the end of three years. Units can be forfeited prior to vesting if an eligible officer fails to maintain his or her minimum stock ownership level. Upon retirement or termination, vested SISOPs are distributed in the form of an equivalent number of shares of PG&E Corporation common stock. heading "Principal Shareholders"Retirement Plan due to tax code limits. The annuities will not change the amount or timing of the after-tax benefits that would have been provided upon retirement under the Supplemental Executive Retirement Plan (SERP) or similar arrangements. In connection with the annuities, tax restoration payments were made such that the annuitization was tax-neutral to the executive officer. Effective July 1, 2003, Mr. Darbee and Mr. King became participants in the Joint Proxy StatementSERP with five years of credited service. Mr. Darbee and Mr. King will each earn an additional five years of credited service provided that they are employed by PG&E Corporation or a subsidiary on July 1, 2008. As of December 31, 2003, the estimated pre-tax annual retirement benefits payable under the SERP or similar arrangements (assuming credited service to age 65), adjusted to reflect the effect of the annuities, for the most highly compensated executive officers were as follows: Mr. Glynn $309,602, Mr. Darbee $286,570, Mr. Worthington $285,740, Mr. Stanley $117,610, Mr. Smith $430,326, Mr. King $421,200, Mr. Rueger $287,450, Mr. Harvey $330,436, Mr. Peters $306,808, and Mr. Randolph $220,617. The estimated annual retirement benefits are single life annuity benefits and would not be subject to any Social Security offsets.2003 Annual Meetingsexercise or realization of any incentive (including common stock equivalents granted under the Executive Stock Ownership Program) will be accelerated so that such incentive may be exercised or realized in full immediately upon the change in control, (2) all shares of restricted stock will immediately cease to be forfeitable, and (3) all conditions relating to the realization of any stock-based incentive will terminate immediately. Under the LTIP, a “change in control”Item 12. Security Ownership of Certain Beneficial Owners and Management. Percent Common Beneficial Stock of Stock Name Ownership(1)(2)(3) Class(4) Equivalents(5) Total David R. Andrews(6) 4,054 * 767 4,821 Leslie S. Biller(6) 1,051 * 4,083 5,134 David A. Coulter(6) 5,681 * 22,897 28,578 C. Lee Cox(6) 47,207 * 3,609 50,816 William S. Davila(6) 21,517 * 12,949 34,466 Robert D. Glynn, Jr.(7) 1,901,961 * 99,181 2,001,142 David M. Lawrence, MD(6) 45,197 * 3,041 48,238 Mary S. Metz(6) 24,276 * 4,366 28,642 Carl E. Reichardt(6) 26,197 * 14,335 40,532 Gordon R. Smith(8) 804,073 * 20,059 824,132 Barry Lawson Williams(6) 22,109 * 5,689 27,798 Peter A. Darbee(9) 437,150 * 10,346 447,496 Bruce R. Worthington(9) 416,605 * 7,917 424,522 G. Brent Stanley(9) 289,592 * 4,262 293,854 P. Chrisman Iribe(9) 428,890 * 99,008 527,898 Thomas B. King(10) 435,614 * 49,366 484,980 Percent Common Beneficial Stock of Stock Name Ownership(1)(2)(3) Class(4) Equivalents(5) Total Gregory M. Rueger(10) 227,225 * 0 227,225 Kent M. Harvey(10) 138,918 * 0 138,918 Roger J. Peters(10) 262,930 * 86,144 349,074 James K. Randolph(11) 268,569 * 141 268,710 All PG&E Corporation directors and executive officers as a group (16 persons) 4,436,002 1.1 227,291 4,663,293 All Pacific Gas and Electric Company directors and executive officers as a group (16 persons) 4,192,772 1.1 328,184 4,520,956 * Less than 1 percent (1) Includes any shares held in the name of the spouse, minor children, or other relatives sharing the home of the director or executive officer and, in the case of executive officers, includes shares of PG&E Corporation common stock held in the defined contribution retirement plans maintained by PG&E Corporation, Pacific Gas and Electric Company, and their respective subsidiaries. Except as otherwise indicated below, the directors, nominees for director, and executive officers have sole voting and investment power over the shares shown. Voting power includes the power to direct the voting of the shares held, and investment power includes the power to direct the disposition of the shares held. Also includes the following shares of PG&E Corporation common stock in which the beneficial owners share voting and investment power: Mr. Andrews 2,076 shares, Mr. Biller 1,051 shares, Mr. Coulter 5,681 shares, Mr. Cox 24,192 shares, Mr. Davila 200 shares, Dr. Lawrence 15,676 shares, Dr. Metz 7,681 shares, Mr. Smith 3,884 shares, Mr. Darbee 69,818, Mr. Worthington 2,288 shares, Mr. Rueger 13,987 shares, Mr. Peters 184 shares, all PG&E Corporation directors and executive officers as a group 132,547 shares, and all Pacific Gas and Electric Company directors and executive officers as a group 74,612 shares. (2) Includes shares of PG&E Corporation common stock which the directors and executive officers have the right to acquire within 60 days of January 31, 2004, through the exercise of vested stock options granted under the PG&E Corporation Long-Term Incentive Program, as follows: Mr. Andrews 1,978 shares, Mr. Cox 23,015 shares, Mr. Glynn 1,713,325 shares, Dr. Lawrence 23,015 shares, Dr. Metz 14,368 shares, Mr. Reichardt 20,141 shares, Mr. Smith 702,392 shares, Mr. Williams 16,254 shares, Mr. Darbee 353,159 shares, Mr. Iribe 404,601 shares, Mr. Stanley 263,626 shares, Mr. Worthington 374,701 shares, Mr. King 385,726 shares, Mr. Rueger 178,506 shares, Mr. Harvey 97,300 shares, Mr. Peters 226,376 shares, Mr. Randolph 231,258 shares, all PG&E Corporation directors and executive officers as a group 3,845,092 shares, and all Pacific Gas and Electric Company directors and executive officers as a group 3,589,855 shares. The directors and executive officers have neither voting power nor investment power with respect to shares shown unless and until such shares are purchased through the exercise of the options, pursuant to the terms of the PG&E Corporation Long-Term Incentive Program. (3) Includes restricted shares of PG&E Corporation common stock awarded under the PG&E Corporation Long-Term Incentive Program. As of January 31, 2004, directors and executive officers of PG&E Corporation and Pacific Gas and Electric Company held the following numbers of restricted shares that may not be sold or otherwise transferred until certain vesting conditions are satisfied: Mr. Andrews 2,076 shares, Mr. Biller 1,051 shares, Mr. Coulter 3,703 shares, Mr. Cox 3,703 shares, Mr. Davila 4,056 shares, Mr. Glynn 163,393 shares, Dr. Lawrence 4,056 shares, Dr. Metz 4,056 shares, Mr. Reichardt 4,056 shares, Mr. Smith 70,321 shares, Mr. Williams 4,056 shares, Mr. Darbee 48,498 shares, Mr. Iribe 24,225 shares, Mr. Stanley 25,008 shares, Mr. Worthington 39,553 shares, Mr. King 39,553 shares, Mr. Rueger 18,777 shares, Mr. Harvey 19,797 shares, Mr. Peters 19,797 shares, Mr. Randolph 13,631 shares, all PG&E Corporation directors and executive officers as a group 417,498 shares, and all Pacific Gas and Electric Company directors and executive officers as a group 381,892 shares. (4) The percent of class calculation is based on the number of shares of PG&E Corporation common stock outstanding as of January 31, 2004, excluding shares held by a subsidiary. (5) Reflects the number of stock units purchased by directors and executive officers through salary and other compensation deferrals or awarded under equity compensation plans. The value of each stock unit is equal to the value of a share of PG&E Corporation common stock and fluctuates daily based on the market price of PG&E Corporation common stock. The directors and officers who own these stock units share the same market risk as PG&E Corporation shareholders, although they do not have voting rights with respect to these stock units. (6) Mr. Andrews, Mr. Biller, Mr. Coulter, Mr. Cox, Mr. Davila, Dr. Lawrence, Dr. Metz, Mr. Reichardt, and Mr. Williams are directors of both PG&E Corporation and Pacific Gas and Electric Company. (7) Mr. Glynn is a director and executive officer of PG&E Corporation, and also is a director of Pacific Gas and Electric Company. He is named in the Summary Compensation Table. (8) Mr. Smith is a director and an executive officer of Pacific Gas and Electric Company, and also is an executive officer of PG&E Corporation. He is named in the Summary Compensation Table. (9) Mr. Darbee, Mr. Iribe, Mr. Stanley, and Mr. Worthington are executive officers of PG&E Corporation named in the Summary Compensation Table. (10) Mr. Harvey, Mr. King, Mr. Peters, and Mr. Rueger are executive officers of Pacific Gas and Electric Company named in the Summary Compensation Table. (11) Mr. Randolph retired as an executive officer of Pacific Gas and Electric Company in 2003. He is named in the Summary Compensation Table. whichis hereby incorporated by reference.regarding shareholders that PG&E Corporation and the Utility know are the beneficial owners of more than 5 percent of any class of voting securities of PG&E Corporation or the Utility as of January 31, 2004: Amount and Nature of Beneficial Percent Class of Stock Name and Address of Beneficial Owner Ownership of Class Pacific Gas and PG&E Corporation(2) 321,314,760 94.90 % Electric Company stock(1) One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 PG&E Corporation State Street Bank and Trust Company(3) 31,626,606 8.01 % Common stock 225 Franklin Street Boston, MA 02110 (1) Pacific Gas and Electric Company’s common stock and preferred stock vote together as a single class. Each share is entitled to one vote. (2) As a result of the formation of the holding company on January 1, 1997, PG&E Corporation became the holder of all issued and outstanding shares of Pacific Gas and Electric Company common stock. As of January 31, 2004, PG&E Corporation and a subsidiary held 100 percent of the issued and outstanding shares of Pacific Gas and Electric Company common stock, and neither PG&E Corporation nor any of its subsidiaries held shares of Pacific Gas and Electric Company preferred stock. (3) The information relating to State Street Bank and Trust Company is based on beneficial ownership as of December 31, 2003, as reported in a Schedule 13G, dated February 5, 2004, filed with the Securities and Exchange Commission. The bank held 19,204,598 shares in its capacity as Trustee of the Pacific Gas and Electric Company Savings Fund Plan. The Trustee may not vote these shares in the absence of voting instructions from the Plan participants. The bank also held 12,422,008 shares of PG&E Corporation common stock in various other fiduciary capacities. The bank has sole voting power with respect to 11,500,089 of these shares, shared voting power with respect to 13,495 of these shares, sole investment power with respect to 12,386,522 of these shares, and shared investment power with respect to 31,486 of these shares.
Equity Compensation Plan Information2002,2003, concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation'sCorporation’s existing equity compensation plans. (c) Number of Securities (a) (b) Remaining Available for Number of Securities to Weighted Average Future Issuance Under be Issued Upon Exercise Exercise Price of Equity Compensation Plans of Outstanding Options, Outstanding Options, (Excluding Securities Plan Category Warrants and Rights Warrants and Rights Reflected in Column(a)) Equity compensation plans approved by shareholders 27,541,6291 $ 21.26 12,572,096 (1) Equity compensation plans not approved by shareholders — $ — — Total equity compensation plans 27,541,629 $ 21.26 12,572,096 (a) (b) (c) Plan Category Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted Average Exercise Price of Outstanding Options, Warrants and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) Equity compensation plans approved by shareholders 31,019,981 $ 22.22 18,337,728 (1) Equity compensation plans not approved by shareholders — $ — — Total equity compensation plans 31,019,981 $ 22.22 18,337,728 (1) Represents the total number of shares available for issuance under PG&E Corporation’s Long-Term Incentive Program (LTIP) as of December 31, 2003. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock, performance shares, and phantom stock payable in an equal number of shares upon termination of employment or service as a director. No more than 5,000,000 of the reserved shares under the LTIP may be awarded as restricted stock. For a description of the LTIP, see Note 14 to the Consolidated Financial Statements. (1)Represents the total number of shares available for issuance under PG&E Corporation's Long-Term Incentive Program (LTIP) as of December 31, 2002, as stock options, stock appreciation rights, dividend equivalents, performance units, restricted stock, common stock equivalents, or other stock-based awards, including Special Incentive Stock Ownership Premiums. Outstanding stock-based awards have been granted under various components of the LTIP as stock options, under the Non-Employee Director Stock Incentive Plan (as restricted stock), and under the Executive Stock Ownership Program (as stock equivalents paid out in stock upon retirement or termination). No more than 5,000,000 of the reserved shares may be awarded as restricted stock. For a description of the Corporation's Long-Term Incentive Program, see Note 14 to the Consolidated Financial Statements.ITEMItem 13. Certain Relationships and Related Transactions.Information respondingAudit-Related Fees.Aggregate fees billed for all audit-related services rendered by Deloitte & Touche LLP to Item 13,PG&E Corporation and its subsidiaries consisted of $0.9 million of fees in 2002 and $0.7 million of fees for 2003. These amounts include $206,000 of audit-related fees in 2002 and $351,000 of audit-related fees in 2003 for Pacific Gas and Electric Company and its subsidiaries. Specific services for both PG&E Corporation and its subsidiaries and Pacific Gas and Electric Company and its subsidiaries in both years include employee benefit plan audits, consultations on financial accounting and reporting standards, a required transition property procedures report, and nuclear decommissioning trust audits. Amounts in 2003 also include Sarbanes-Oxley Section 404 readiness work.offiscal year, the PG&E Corporation and Pacific Gas and Electric Company is includedAudit Committees approve the selection of the independent public accountants for that fiscal year, and approve obtaining from the auditors a detailed list of (1) audit services, (2) audit-related services, and (3) tax services, up to specified fee amounts.“Audit services”generally includes audit and review of annual and quarterly financial statements and services that only the external auditors reasonably can provide (e.g., comfort letters, statutory audits, attest services, consents, and assistance with and review of documents filed with the Securities and Exchange Commission).“Audit-related services”generally include assurance and related services that traditionally are performed by the independent public accountants (e.g., employee benefit plan audits, due diligence related to mergers and acquisitions, accounting consultations and audits in connection with acquisitions, internal control reviews, and attest services that are not required by statute or regulation).“Tax services”generally includes compliance, tax strategy, tax appeals, and specialized tax issues, all of which also must be permissible under the heading "Certain RelationshipsSarbanes-Oxley Act of 2002. In determining whether to pre-approve any services from the independent public accountants, the Audit Committees assess, among other things, the impact of that service on the auditor’s independence.Related Transactions" intax services that are not included on the Joint Proxy Statement relatinglist of pre-approved services, and must pre-approve any listed pre-approved services that would cause PG&E Corporation or Pacific and Electric Company to exceed the authorized fee amounts. Other services may be obtained from the independent public accountants only following review and approval from the applicable company’s management and review and pre-approval by the applicable Audit Committee.2003 Annual Meetings of Shareholders, which information is hereby incorporated by reference.ITEM 14. Controls and Procedures.full Audit Committee at the next regularly scheduled Committee meeting. No such pre-approvals were granted for 2003.Based on an evaluationAt each regular meeting of PG&E Corporation'sthe Audit Committees, management reports the specific non-audit services being performed by Deloitte & Touche LLP for the respective company and its subsidiaries, the Utility's disclosure controlsdollar amounts associated with these services, and procedures conducted on February 7,a comparison of fees paid to date to the pre-approved amounts.and February 5, 2003, respectively, PG&E Corporation's and the Utility's principal executive officers and principal financial officers have concluded that such controls and procedures effectively ensure that information requiredall services provided by Deloitte & Touche LLP to be disclosed by PG&E Corporation, Pacific Gas and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized,Electric Company, and reported within the time periods specified in the SEC rules and forms. Theretheir consolidated affiliates were no significant changes in internal controls or in other factors that could significantly affect these controls subsequentapproved pursuant to the date of their evaluation.applicable pre-approval procedures.ITEMItem 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.1.The following consolidated financial statements, supplemental information, and independent auditors' report are contained in the 2002 Annual Report to Shareholders, which have been incorporated by reference in this report:Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001, and 2000, for each of PG&E Corporation and Pacific Gas and Electric Company.Consolidated Balance Sheets at December 31, 2002, and 2001 for each of PG&E Corporation and Pacific Gas and Electric Company.1. The following consolidated financial statements, supplemental information, and independent auditors’ report are contained in the 2003 Annual Report, which have been incorporated by reference in this report: Consolidated Statements of Common Stockholders' EquityConsolidated Statements of Operations for the Years Ended December 31, 2003, 2002, and 2001, for each of PG&E Corporation and Pacific Gas and Electric Company. Consolidated Balance Sheets at December 31, 2003, and 2002 for each of PG&E Corporation and Pacific Gas and Electric Company. Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2003, 2002, and 2001, and 2000, for PG&E Corporation.Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2003, 2002, and 2001 for Pacific Gas and Electric Company. Notes to Consolidated Financial Statements. Quarterly Consolidated Financial Data (Unaudited). Independent Auditors’ Report (Deloitte & Touche LLP). Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2002, 2001, and 2000 for Pacific Gas and Electric Company.2. Independent Auditors’ Report (Deloitte & Touche LLP) included at page 77 of this Form 10-K. 3. Financial statement schedules: Notes to Consolidated Financial Statements.Quarterly Consolidated Financial Data (Unaudited).Independent Auditors' Report (Deloitte & Touche LLP).Independent Auditors' Report (Deloitte & Touche LLP) included at page 93 of this Form 10-K.2.Financial statement schedules:I—Condensed Financial Information of Parent for the Years Ended December 31, 2002, 2001, and 2000.II—I — Condensed Financial Information of Parent as of December 31, 2003 and 2002 and for the Years Ended December 31, 2003, 2002, and 2001. II — Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2002, 2001, and 2000. Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto.3.Exhibits required to be filed by Item 601 of Regulation S-K:3.1Restated Articles of Incorporation of PG&E Corporation effective as of May 5, 2000 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 3.1)3.2Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)3.3Bylaws of PG&E Corporation amended as of February 19, 20033.4Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the quarter ended MarchYears Ended December 31, 1998 (File No. 1-2348), Exhibit 3.1)2003, 2002, and 2001.3.5 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto. 4. Exhibits required to be filed by Item 601 of Regulation S-K: Exhibit Number Exhibit Description 3 .1 Restated Articles of Incorporation of PG&E Corporation effective as of May 5, 2000 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 3.1) 3 .2 Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2) 3 .3 Bylaws of PG&E Corporation amended as of February 18, 2004 3 .4 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit 3.1) 3 .5 Bylaws of Pacific Gas and Electric Company amended as of February 18, 2004 Exhibit Number Exhibit Description 4 .1 First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (incorporated by reference to Registration No. 2-1324, Exhibits B-1, B-2, and B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; and Pacific Gas and Electric Company’s Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2) 4 .2 Indenture related to PG&E Corporation’s 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1). 4 .3 Supplemental Indenture related to PG&E Corporation’s 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1) 4 .4 Warrant Agreement, dated as of June 25, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation’s Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.9). 4 .5 Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2) 4 .6 Form of Rights Agreement dated as of December 22, 2000, between PG&E Corporation and Mellon Investor Services LLC, including the Form of Rights Certificate as Exhibit A, the Summary of Rights to Purchase Preferred Stock as Exhibit B, and the Form of Certificate of Determination of Preferences for the Preferred Stock as Exhibit C (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 4.2) 4 .7 Amendment to Rights Agreement dated February 18, 2004, between PG&E Corporation and Mellon Investor Services LLC (incorporated by reference to PG&E Corporation’s Form 8-K filed February 19, 2004 (File No. 1-12609), Exhibit 99) 4 .8 Indenture dated as of July 2, 2003, by and between PG&E Corporation and Bank One, N.A. (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (File No. 1-12609), Exhibit 4.1) 4 .9 Utility Stock Base Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.2) 4 .10 Utility Stock Protective Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.3) 4 .11 Form of 6 7/8 percent Senior Secured Note due 2008 (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.4) Exhibit Number Exhibit Description 10 .1 The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2), as amended by Operational Flow Order (OFO) Settlement Agreement, approved by the California Public Utilities Commission on February 17, 2000, in Decision 00-02-050, as amended by Comprehensive Gas OII Settlement Agreement, approved by the California Public Utilities Commission on May 18, 2000, in Decision 00-05-049 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10); and the Gas Accord II Settlement Agreement, approved by the California Public Utilities Commission on August 22, 2002, in Decision 01-09-016 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1) 10 .2 Commitment Letter dated March 5, 2003, between PG&E Corporation and Lehman Brothers, Inc. (incorporated by reference to PG&E Corporation’s Form 8-K filed March 6, 2003 (File No. 1-12609), Exhibit 99.2) 10 .3 Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 8-K filed December 22, 2003 (File No. 1-12609 and File No. 1-2348) Exhibit 99) 10 .4 Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions 10 .5 Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996 10 .6 PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 10 .7 Electronic Commerce System User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation, effective as of September 28, 2001 10 .8 Operating Agreement effective as of April 1, 2003, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348) Exhibit 10.1) *10 .9 PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.4) *10 .10 Agreement and Release between PG&E Corporation and Thomas G. Boren dated December 18, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.23) *10 .11 Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3) *10 .12 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated November 4, 1998 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.6) Bylaws of Pacific Gas and Electric Company amended as of February 19, 2003794.1 First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (incorporated by reference to Registration No. 2-1324, Exhibits B-1, B-2, and B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; and Pacific Gas and Electric Company's Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2)4.2ExhibitNumber Exhibit Description Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).4.3*10Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)4.4Warrant 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).4.5Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)4.6Form of Rights Agreement dated as of December 22, 2000, between PG&E Corporation and Mellon Investor Services LLC, including the Form of Rights Certificate as Exhibit A, the Summary of Rights to Purchase Preferred Stock as Exhibit B, and the Form of Certificate of Determination of Preferences for the Preferred Stock as Exhibit C (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 4.2)10.1The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2), as amended by Operational Flow Order (OFO) Settlement Agreement, approved by the California Public Utilities Commission on February 17, 2000, in Decision 00-02-050, as amended by Comprehensive Gas OII Settlement Agreement, approved by the California Public Utilities Commission on May 18, 2000, in Decision 00-05-049 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10); and the Gas Accord II Settlement Agreement, approved by the California Public Utilities Commission on August 22, 2002, in Decision 01-09-01610.2Second Amended and Restated Credit Agreement, dated as of October 18, 2002, among PG&E Corporation, as Borrower, the Lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and other parties (incorporated by reference to PG&E Corporation's Form 8-K filed October 22, 2002 (File No. 1-12609), Exhibit 99.1)10.3.1Utility Stock Pledge Agreement (35 percent)—Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Form 8-K filed October 22, 2002 (File No. 1-12609), Exhibit 99.2)8010.3.2Utility Stock Pledge Agreement (35 percent)—New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Form 8-K filed October 22, 2002 (File No. 1-12609), Exhibit 99.3)10.3.3Utility Stock Pledge Agreement (65 percent)—Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Form 8-K filed October 22, 2002 (File No. 1-12609), Exhibit 99.4)10.3.4Utility Stock Pledge Agreement (65 percent)—New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Form 8-K filed October 22, 2002 (File No. 1-12609), Exhibit 99.5)10.4Amended and Restated Credit Agreement among PG&E National Energy Group, Inc. and Chase Manhattan Bank dated August 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.310.5Second Amendment, dated as of October 18, 2002, to the Amended and Restated Credit Agreement, dated as of August 22, 2001, among PG&E National Energy Group, Inc., JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank), as Issuing Bank, the several lenders from time to time parties thereto, the Documentation Agents thereunder, the Syndication Agents thereunder, and JPMorgan Chase Bank, as Administrative Agent. (incorporated by reference to PG&E National Energy Group, Inc.'s Form 8-K filed October 28, 2002) (File No. 333-66032), Exhibit 10.1)10.6Credit Agreement, dated as of May 29, 2001, among PG&E National Energy Group Construction Company, LLC, as Borrower, the lenders from time to time parties thereto, and Societe Generale, as Administrative Agent and Security Agent10.7First Amendment to Credit Agreement, dated as of June 5, 2002, among PG&E National Energy Group Construction Company, LLC, the lenders party thereto, and Societe Generale, as Administrative Agent and Security Agent10.8Guarantee and Agreement (Turbine Credit Agreement), dated as of May 29, 2001, made by PG&E National Energy Group, Inc. in favor of Societe Generale, as Security Agent10.9Amended and Restated Credit Agreement, dated as of March 15, 2002, among GenHoldings I, LLC, as Borrower, Societe Generale, as Administrative Agent and a Lead Arranger, Citibank, N.A., as Syndication Agent and a Lead Arranger, the other agents and arrangers thereunder, JP Morgan Chase Bank, as issuer of the Letters of Credit thereunder, the financial institutions party thereto from time to time, and various other parties10.10Amended and Restated Guarantee and Agreement dated as of March 15, 2002, by PG&E National Energy Group, Inc., in favor of Societe Generale, as Administrative Agent10.11Acknowledgement and Amendment Agreement, (GenHoldings I, LLC) dated as of April 5, 2002, by and among PG&E National Energy Group, Inc., GenHoldings I, LLC, as Borrower, Societe Generale, as Administrative Agent, and the banks and lenders party thereto10.12Waiver and Amendment Agreement, dated as of September 25, 2002, among GenHoldings I, LLC, as Borrower, Societe Generale, as Administrative Agent, Citibank N.A., as Depository Agent, and the banks and lender group agents party thereto.10.13Third Waiver and Amendment, dated as of November 14, 2002, among GenHoldings I, LLC, as Borrower, various lenders identified as the GenHoldings Lenders, Societe Generale, as Administrative Agent, Citibank, N.A., as Security Agent, and acknowledged and agreed to by PG&E National Energy Group, Inc.10.14Fourth Waiver and Amendment dated as of December 23, 2002, among GenHoldings I, LLC, various lenders identified as the GenHoldings Lenders, the Administrative Agent, and acknowledged and agreed to by PG&E National Energy Group, Inc. (incorporated by reference to PG&E Corporation's and PG&E National Energy Group, Inc.'s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and 333-66032), Exhibit 99.1)8110.15Second Omnibus Restructuring Agreement dated as of December 4, 2002 among La Paloma Generating Company, LLC, La Paloma Generating Trust, Ltd., and various other parties, including PG&E National Energy Group, Inc. (incorporated by reference to PG&E Corporation's and PG&E National Energy Group, Inc.'s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and 333-66032), Exhibit 99.2)10.16Priority Credit and Reimbursement Agreement among La Paloma Generating Company, LLC, La Paloma Generating Trust Ltd., Wilmington Trust Company, in its individual capacity and as Trustee, Citibank, N.A., as the Priority Working Capital L/C Issuer, the Several Priority Lenders from time to time parties hereto, Citibank, N.A., as administrative agent, and Citibank, N.A., as priority agent, dated as of December 4, 2002 (incorporated by reference to PG&E Corporation's and PG&E National Energy Group, Inc.'s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and 333-66032), Exhibit 99.3)10.17Guarantee and Agreement (La Paloma), dated as of April 6, 2001, by PG&E National Energy Group, Inc. in favor of Citibank, N.A., as Security Agent10.18Second Omnibus Restructuring Agreement dated as of December 4, 2002 among Lake Road Generating Company, LLC, Lake Road Generating Trust, Ltd., and various other parties, including PG&E National Energy Group, Inc. (incorporated by reference to PG&E Corporation's and PG&E National Energy Group, Inc.'s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and 333-66032), Exhibit 99.4)10.19Priority Credit and Reimbursement Agreement among Lake Road Generating Company, LLC, Lake Road Trust Ltd., Wilmington Trust Company, in its individual capacity and as Trustee, Citibank, N.A., as the Priority L/C Issuer, the Several Priority Lenders from time to time parties hereto, Citibank, N.A., as administrative agent, and Citibank, N.A., as priority agent, dated as of December 4, 2002 (incorporated by reference to PG&E Corporation's and PG&E National Energy Group, Inc.'s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and 333-66032), Exhibit 99.5)10.20Amendment, Waiver and Consent Agreement dated as of November 6, 2002, among La Paloma Generating Company, LLC, La Paloma Generating Trust, Ltd., Wilmington Trust Company as Trustee, Citibank, N.A., as administrative agent and security agent, and various other parties10.21Guarantee and Agreement (Lake Road), dated as of April 6, 2001, made by PG&E National Energy Group, Inc. in favor of Citibank, N.A., as Security Agent*10.22PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.4)*10.23Agreement and Release between PG&E Corporation and Thomas G. Boren, dated December 18, 2002*10.24Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)*10.25Letter 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)*10.26.13 Letter regarding Compensation Arrangement between PG&E Corporation and Lyn E. Maddox dated April 25, 1997 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.7)* 10.2710.14 Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)* 10.2810.15 Description of Relocation Arrangement Between PG&E Corporation and Lyn E. Maddox (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.9)82* 10.2910.16 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609) Exhibit 10.3) *10 .17 Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609) Exhibit 10.4) *10 .18 PG&E Corporation Senior Executive Officer Retention Program approved December 20, 2000 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10)* 10.30.110.19.1 Letter regarding retention award to Robert D. Glynn, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.1)* 10.30.210.19.2 Letter regarding retention award to Gordon R. Smith dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.2)* 10.30.310.19.3 Letter regarding retention award to Peter A. Darbee dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.3)* 10.30.410.19.4 Letter regarding retention award to Bruce R. Worthington dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.4)* 10.30.510.19.5 Letter regarding retention award to G. Brent Stanley dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.5)* 10.30.610.19.6 Letter regarding retention award to Daniel D. Richard, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.6)* 10.30.710.19.7 Letter regarding retention award to James K. Randolph dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.7)* 10.30.810.19.8 Letter regarding retention award to Gregory M. Rueger dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.8)* 10.30.910.19.9 Letter regarding retention award to Kent M. Harvey dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.9)Exhibit Number Exhibit Description * 10.30.1010.19.10 Letter regarding retention award to Roger J. Peters dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.10))* 10.30.1110.19.11 Letter regarding retention award to Lyn E. Maddox dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.12)* 10.30.1210.19.12 Letter regarding retention award to P. Chrisman Iribe dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.13)* 10.30.1310.19.13 Letter regarding retention award to Thomas B. King dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.14)* 10.3110.20 Pacific Gas and Electric Company Management Retention Program (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.1)* 10.3210.21 PG&E Corporation Management Retention Program (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.2)* 10.3310.22 PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)83* 10.3410.23 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 20022003 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 20012002 (File No. 1-12609), Exhibit 10.25)10.35)* 10.3510.24 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2003.2004* 10.3610.25 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended as of September 19, 2001 (incorporated by reference to Pacific Gas and Electric Company'sCompany’s Form 10-K for the year ended December 31, 2001 (File No. 1-2248), Exhibit 10.16)* 10.37.110.26.1 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) * 10.37.210.26.2 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) * 10.37.310.26.3 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) * 10.37.410.26.4 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) Exhibit Number Exhibit Description * 10.37.510.26.5 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated December 20, 2002 (incorporated by reference to PG&E Corporation’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) * 10.37.610.26.6 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Thomas G. Boren dated December 20, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.6) * 10.3810.27.1 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 Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609); Exhibit 10.2.1) *10 .27.2 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 Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348); Exhibit 10.2.2) *10 .27.3 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated April 18, 2003 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348); Exhibit 10.2.3) *10 .27.4 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 Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348); Exhibit 10.2.4) *10 .27.5 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 Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609); Exhibit 10.2.5) *10 .28 Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company'sCompany’s Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)* 10.3910.29 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company'sCompany’s Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)* 10.4010.30 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 1997 (File No. 1-12609), Exhibit 10.13)* 10.4110.31 PG&E Corporation Long-Term Incentive Program, as amended May 16, 2001, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)* 10.4210.32 PG&E Corporation Executive Stock Ownership Program amendedGuidelines dated as of SeptemberFebruary 19, 20002003 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K10-Q for the yearquarter ended DecemberMarch 31, 20002003 (File No. 1-12609), Exhibit 10.20)10.2)* 10.4310.33 PG&E Corporation Officer Severance Policy, amended as of December 19, 2001 *10.44PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q10-K for the quarteryear ended MarchDecember 31, 19982002 (File No. 1-12609), Exhibit 10.1)10.43) Exhibit Number Exhibit Description *10 .34 PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1) *10 .35 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2) *10 .36 PG&E Corporation Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46) *10 .37 Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program *10 .38 Form of Performance Share Award Agreement granted under the PG&E Corporation Long-Term Incentive Program *10 .39 PG&E National Energy Group, Inc. Management Retention/ Performance Award Program (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609) Exhibit 10.47) *10 .39.1 Letter regarding retention award to Thomas B. King dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609) Exhibit 10.47.1) *10 .39.2 Letter regarding retention award to P. Chrisman Iribe dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.47.2) *10 .39.3 Letter regarding retention award to Lyn E. Maddox dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609) Exhibit 10.47.3) 11 Computation of Earnings Per Common Share 12 .1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company 12 .2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company 13 The following portions of the 2003 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Independent Auditors’ Report,” “Responsibility for Consolidated Financial Statements,” financial statements of PG&E Corporation entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Common Shareholders’ Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” “Consolidated Statements of Shareholders’ Equity,” “Notes to Consolidated Financial Statements,” and “Quarterly Consolidated Financial Data (Unaudited)” 21 Subsidiaries of the Registrant 23 Independent Auditors’ Consent (Deloitte & Touche LLP) 24 .1 Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K 24 .2 Powers of Attorney Exhibit Number Exhibit Description 31 .1 Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002 31 .2 Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002 **32 .1 Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002 **32 .2 Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002 * Management contract or compensatory agreement. * 10.45* PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 (incorporated by referencePursuant to PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2)*10.46PG&E Corporation FormItem 601(b)(32) of Restricted Stock Award Agreement granted under the PG&E Corporation Long-Term Incentive Program11Computation of Earnings Per Common Share12.1Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company12.2Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric CompanySEC Regulation S-K, these exhibits are furnished rather than filed with this report.8413The following portions of the 2002 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Independent Auditors' Report," "Responsibility for Consolidated Financial Statements," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets, " "Consolidated Statements of Cash Flows," and "Consolidated Statements of Common Stockholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," "Consolidated Statements of Stockholders' Equity," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)"21Subsidiaries of the Registrant23Independent Auditors' Consent (Deloitte & Touche LLP)24.1Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K24.2Powers of Attorney99.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 200299.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002*Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.exhibits filed herewith are attached hereto (except as noted) and those indicated above which are not filed herewith were previously filed with the Commission and are hereby incorporated by reference. All exhibits filed herewith or incorporated by reference are filed with respect to both PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No. 1-2348), unless otherwise noted. Exhibits will be furnished to security holders of PG&E Corporation or Pacific Gas and Electric Company upon written request and payment of a fee of $0.30 per page, which fee covers only the registrants' reasonable expenses in furnishing such exhibits. The registrants agree to furnish to the Commission upon request a copy of any instrument defining the rights of long-term debt holders not otherwise required to be filed hereunder.(b)8-K Reports on Form 8-K(1)8-K(1) were filed, or furnished as indicated, during the quarter ended December 31, 2002,2003, and through the date hereof:1. October 3, 20022003 Item 5. Other Events
9.
A.PG&E Corporation-new waiver extensionB.Pacific Gas and Electric Company bankruptcy: Monthly Operating ReportItem 7. Financial Statements, Pro Forma, Financial Information, and ExhibitsExhibit 99.1—Amendment to Second Amended and Restated Waiver and Amendment Agreement, dated October 1, 2002, by and among PG&E Corporation, PG&E National Energy Group, LLC, Lehman Commercial Paper Inc. as administrative agent, and certain of the lenders partyRegulation FD Disclosure (furnished to the Amended and Restated Credit Agreement dated as of June 25, 2002SEC)
Exhibit 99.2—1 — Pacific Gas and Electric Company Income Statement for the month ended August 31, 2002,2003 and Balance Sheet dated August 31, 2002200385
2.
October 10, 2002—15, 2003
Item 5.Other Events
District Court ruling regarding California Business and Professions Code Section 17200 lawsuits
Item 9. Regulation FD Disclosure (furnished to the SEC) PG&E Corporation onlyExhibit 1 — Revised Financial Projections Relating to the Settlement PlanA.PG&E National Energy Group, Inc. credit ratings downgrades
3.
October 15, 200224, 2003
Item 5.Other Events
A. Credit Rating Change Pacific Gas and Electric Company's 2003 CostB. Department of CapitalWater Resources’ (DWR) 2001-2002 Revenue Requirement True-Up Proceeding
4.
November 12, 2003
Item 12.
B.Pacific GasResults of Operations and Electric Company bankruptcyFinancial Condition (furnished to the SEC)
Release of Third Quarter Earnings Results4.5.
October 21, 2002—November 20, 2003
Item 5.Other Events
A. Proposed Decisions Regarding Proposed Settlement Agreement
B. Conclusion of Confirmation Trial Testimony in Utility’s Chapter 11 Proceeding
C. Ninth Circuit Preemption Decision
6.
PG&E Corporation only
December 2, 2003
Item 9.
A.PG&E National Energy Group credit ratings downgrades5.October 22, 2002—Item 5. Other Events PG&E Corporation onlyItem 7. Financial Statements, Pro Forma Financial Information, and ExhibitsRegulation FD Disclosure (furnished to the SEC)
Exhibit 99.1—Second and Amended Restated Credit Agreement, dated as of October 18, 2002, among PG&E Corporation, the lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and other partiesExhibit 99.2—Utility Stock Pledge Agreement (35 percent)1 —Continued Tranche B Loan, dated as of October 18, 2002Exhibit 99.3—Utility Stock Pledge Agreement (35 percent)—New Tranche B Loan, dated as of October 18, 2002Exhibit 99.4—Utility Stock Pledge Agreement (65 percent)—Continued Tranche B Loan, dated as of October 18, 2002Exhibit 99.5—Utility Stock Pledge Agreement (65 percent)—New Tranche B Loan, dated as of October 18, 20026.November 18, 2002Item 5. Other Events PG&E Corporation onlyA.PG&E National Energy Group, Inc. defaultsB.PG&E National Energy Group, Inc. credit ratings7.December 4, 2002—Item 5. Other EventsA.Pacific Gas and Electric Company 2002 Attrition Revenue AdjustmentB.Pacific Gas and Electric Company bankruptcy: Monthly Operating ReportItem 7. Financial Statements, Pro Forma, Financial Information, and ExhibitsExhibit 99.1—Pacific Gas and Electric Company Income Statement for the month ended October 31, 2002,2003 and Balance Sheet dated October 31, 20022003
7.
December 9, 2003
Item 5.
Other Events A. Additional Proposed Decisions Regarding Proposed Settlement Agreement
B. Credit Rating Agency Announcement86748.
January 6, 2003
Item 5. Other Events
8.
December 12, 2003
Item 5.
Other Events A.ResumptionProposed Decision Issued in the California Department of Power ProcurementWater Resources” (DWR) 2001-2002 Revenue Requirement True-Up Proceeding and the DWR 2004 Revenue Requirement Proceeding
9.
December 15, 2003
Item 5.
Other Events B.Bankruptcy Court Decision Approving Proposed Chapter 11 Settlement Agreement and Plan of Reorganization10.
December 16, 2003 Item 5. Other Events
Comments Regarding Proposed Settlement Agreement Filed by the Utility and TURN11. December 22, 2003 Item 5. Other Events
A. California Public Utilities Commission Approves Proposed Settlement Agreement as Recommended to be Modified by Pacific Gas and Electric Company bankruptcy: Monthly Operating Reportand The Utility Reform Network
B. CPUC Approves Gas Accord II
C.General Rate Case 2003D.Pacific Gas and Electric Company bankruptcy: Monthly Operating Report
Item 7.Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99 — Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices
12.
December 23, 2003
Item 5.
Other Events
Bankruptcy Court Confirms Utility’s Plan of Reorganization13.
December 31, 2003Item 9. Regulation FD Disclosure (furnished to the SEC) Exhibit 99.1—1 — Pacific Gas and Electric Company Income Statement for the month ended November 30, 2002,2003 and Balance Sheet dated November 30, 200220039.14.
January 16, 200322, 2004
Item 5.Other Events
Applications Filed for Rehearing of CPUC Decision Approving Chapter 11 Settlement Agreement
PG&E Corporation and PG&E National Energy Group, Inc.
Item 7.Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99 — Notice to Directors and Executive Officers, dated January 22, 2004
Item 11.
Exhibit 99.1—Fourth Waiver and Amendment dated asTemporary Suspension of December 23, 2002, among GenHoldings I, LLC, various lenders identified as the GenHoldings Lenders, the Administrative Agent, and acknowledged and agreed to by PG&E National Energy Group, Inc.Trading Under Registrant’s Employee Benefits Plan
15.
February 3, 2004
Item 5.
Other Events
Implementation of Chapter 11 Settlement Rate Reduction16.
February 19, 2004Item 5. Other Events Item 7. Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99.2—Second Omnibus Restructuring99 — Amendment to Rights Agreement dated as of December 4, 2002 among La Paloma Generating Company, LLC, La Paloma Generating Trust, Ltd., and various other parties, includingFebruary 18, 2004, between PG&E National Energy Group, Inc.Corporation and Mellon Investor Services LLC
Item 12.
Results of Operations and Financial Condition (furnished to the SEC)
Release of Third Quarter Earnings ResultsExhibit 99.3—Priority Credit and Reimbursement Agreement among La Paloma Generating Company, LLC, La Paloma Generating Trust Ltd., Wilmington Trust Company, in its individual capacity and as Trustee, Citibank, N.A., as the Priority Working Capital L/C Issuer, the Several Priority Lenders from time to time parties hereto, Citibank, N.A., as administrative agent, and Citibank, N.A., as priority agent, dated as of December 4, 2002
(1) Exhibit 99.4—Second Omnibus Restructuring Agreement dated as of December 4, 2002 among Lake Road Generating Company, LLC, Lake Road Generating Trust, Ltd.,Unless otherwise noted, all reports were filed under Commission File Number 1-2348 (Pacific Gas and various other parties, including PGElectric Company) and Commission File Number 1-12609 (PG&E National Energy Group, Inc.Exhibit 99.5—Priority Credit and Reimbursement Agreement among Lake Road Generating Company, LLC, Lake Road Trust Ltd., Wilmington Trust Company, in its individual capacity and as Trustee, Citibank, N.A., as the Priority L/C Issuer, the Several Priority Lenders from time to time parties hereto, Citibank, N.A., as administrative agent, and Citibank, N.A., as priority agent, dated as of December 4, 2002
Corporation).(1)Unless otherwise noted, all reports were filed under Commission File Number 1-2348 (Pacific Gas and Electric Company) and Commission File Number 1-12609 (PG&E Corporation).87reportAnnual Report on Form 10-K for the year ended December 31, 2003 to be signed on their behalf by the undersigned, thereunto duly authorized, in the City and County of San Francisco, on the 27th19th day of February, 2003.2004.PG&E CORPORATION (Registrant) PACIFIC GAS AND ELECTRIC COMPANY (Registrant) (Registrant)
By
By GARY P. ENCINAS GARY P. ENCINAS (Gary P. Encinas, Attorney-in-Fact)
By
GARY P. ENCINAS
(Gary P. Encinas, Attorney-in-Fact)SignatureTitleDateA. Principal Executive Officers Signature Title Date A. Principal Executive Officers
*ROBERT D. GLYNN, JR.
Chairman of the Board, Chief Executive Officer, and President (PG&E Corporation)
February 27, 200319, 2004*GORDON *GORDON R. SMITH
President and Chief Executive Officer (Pacific Gas and Electric Company)
February 27, 200319, 2004B. Principal Financial Officers
*PETER A. DARBEE
Senior Vice President and Chief Financial Officer (PG&E Corporation)
February 27, 200319, 2004*KENT *KENT M. HARVEY
Senior Vice President, Chief Financial Officer, and Treasurer (Pacific Gas and Electric Company)
February 27, 200319, 2004C. Principal Accounting Officers
*CHRISTOPHER P. JOHNS
Senior Vice President and Controller (PG&E Corporation)
February 27, 200319, 2004*DINYAR *DINYAR B. MISTRY
Vice President-Controller (Pacific Gas and Electric Company)
February 27, 200319, 2004D. Directors
* DAVID R. ANDREWSLESLIE S. BILLER
*DAVID A. COULTER
*C. LEE COX
*WILLIAM S. DAVILA
*ROBERT D. GLYNN, JR.
*DAVID M. LAWRENCE, M.D.
*MARY S. METZ
*CARL E. REICHARDT
*GORDON R. SMITH
(Director of Pacific Gas and
Electric
Company only)
*BARRY LAWSON WILLIAMS
Directors of PG&E Corporation and Pacific Gas and Electric Company, except as noted
February 27, 200319, 2004*By GARY P. ENCINAS *ByGARY P. ENCINASGary P. Encinas, Attorney-in-Fact88 I, Robert D. Glynn, Jr., certify that: 1. I have reviewed this annual report on Form 10-K of PG&E Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:•designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;•evaluated the effectiveness of the registrant's disclosure controls and procedures within 90 days prior to the filing date of this annual report (the Evaluation Date); and•presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):•all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and•any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.Date: February 26, 2003 ROBERT D. GLYNN, JR.ROBERT D. GLYNN, JR.Chairman, Chief Executive Officer and PresidentPG&E Corporation89 I, Peter A. Darbee, certify that: 1. I have reviewed this annual report on Form 10-K of PG&E Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:•designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;•evaluated the effectiveness of the registrant's disclosure controls and procedures within 90 days prior to the filing date of this annual report (the Evaluation Date); and•presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):•all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and•any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.Date: February 26, 2003(Gary P. Encinas, Attorney-in-Fact) PETER A. DARBEEPETER A. DARBEESenior Vice President and Chief Financial OfficerPG&E Corporation90 I, Gordon R. Smith, certify that: 1. I have reviewed this annual report on Form 10-K of Pacific Gas and Electric Company;76 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:•designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;•evaluated the effectiveness of the registrant's disclosure controls and procedures within 90 days prior to the filing date of this annual report (the Evaluation Date); and•presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):•all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and•any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.Date: February 26, 2003GORDON R. SMITHGORDON R. SMITHPresident and Chief Executive OfficerPacific Gas and Electric Company91 I, Kent M. Harvey, certify that: 1. I have reviewed this annual report on Form 10-K of Pacific Gas and Electric Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:•designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;•evaluated the effectiveness of the registrant's disclosure controls and procedures within 90 days prior to the filing date of this annual report (the Evaluation Date); and•presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):•all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and•any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.Date: February 26, 2003KENT M. HARVEYKENT M. HARVEYSenior Vice President, Chief Financial Officer, and TreasurerPacific Gas and Electric Company9220022003 and 2001,2002, and for each of the three years in the period ended December 31, 20022003 and have issued our report thereon dated February 24, 2003, which18, 2004 (which report expresses an unqualified opinion and includes explanatory paragraphs relating to (i) PG&E Corporation's adoption of new accounting standards in 2002 relating to accounting for goodwill and intangible assets, impairment of long-lived assets, discontinued operations, gains and losses on debt extinguishment, certain derivative contracts and PG&E Corporation's change in method of reporting gains and losses associated with energy trading contracts from the gross methodchanges, a revision to the net method2002 and retroactive reclassification of the consolidated2001 financial statements of operations for 2001 and 2000, (ii) PG&E Corporation's and Pacific Gas and Electric Company's adoption of new accounting standards in 2001 relating to derivative contracts, and (iii) the ability of PG&E Corporation and Pacific Gas and Electric Company to continue as going concerns.concern uncertainties). Such consolidated financial statements of each of the Companies are included in the combined 20022003 Annual Report to Shareholders (of PG&E Corporation and Pacific Gas and Electric Company) and are incorporated herein by reference. Our audits also included the respective consolidated financial statement schedules of PG&E Corporation and Pacific Gas and Electric Company, listed in Item 15(a)2. These consolidated financial statement schedules are the responsibility of the respective managements of PG&E Corporation and Pacific Gas and Electric Company. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the respective basic consolidated financial statements of PG&E Corporation and Pacific Gas and Electric Company taken as a whole, present fairly in all material respects the information set forth therein.24, 200318, 200493
SCHEDULE I—I — CONDENSED FINANCIAL INFORMATION OF PARENT December 31, (in millions) 2002 2001 Assets: Cash and cash equivalents $ 182 $ 348 Restricted cash 377 — Advances to affiliates 479 404 Note receivable from subsidiary 208 308 Other current assets 1 1 Total current assets 1,247 1,061 Equipment 20 19 Accumulated depreciation (12 ) (9 ) Net equipment 8 10 Investments in subsidiaries 2,963 4,595 Other investments 33 61 Deferred income taxes 702 42 Other 34 57 Total Assets $ 4,987 $ 5,826 Liabilities and Stockholders' Equity: Current Liabilities: Accounts payable—related parties $ 31 $ 22 Accounts payable—other 38 17 Note payable to subsidiary — 75 Accrued taxes 133 309 Other 57 25 Total current liabilities 259 448 Noncurrent Liabilities: Long-term debt 976 904 Other 46 182 Total noncurrent liabilities 1,022 1,086 Stockholders' Equity: Common stock 6,274 5,986 Common stock held by subsidiary (690 ) (690 ) Reinvested earnings (1,878 ) (1,004 ) Total stockholders' equity 3,706 4,292 Total Liabilities and Stockholders' Equity $ 4,987 $ 5,826 94 Balance at December 31, 2003 2002 (In millions) ASSETS Cash and cash equivalents $ 673 $ 182 Restricted cash — 377 Advances to affiliates 398 479 Note receivable from subsidiary — 208 Other current assets 9 1 Total current assets 1,080 1,247 Equipment 20 20 Accumulated depreciation (15 ) (12 ) Net equipment 5 8 Restricted Cash 361 — Investments in subsidiaries 4,810 2,870 Other investments 24 33 Deferred income taxes 478 702 Other 32 34 Total Assets $ 6,790 $ 4,894 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Accounts payable — related parties $ 2 $ 31 Accounts payable — other 28 38 Income taxes payable 258 133 Other 158 57 Total current liabilities 446 259 Noncurrent Liabilities: Long-term debt 883 976 Net investment in NEGT 1,216 — Other 30 46 Total noncurrent liabilities 2,129 1,022 Preferred Stock — — Common Shareholders’ Equity Common stock 6,468 6,274 Common stock held by subsidiary (690 ) (690 ) Unearned compensation (20 ) — Accumulated deficit (1,458 ) (1,878 ) Accumulated other comprehensive income (85 ) (93 ) Total common shareholders’ equity 4,215 3,613 Total Liabilities and Shareholders’ Equity $ 6,790 $ 4,894 INCOME
OPERATIONS2001, and 2000
2001 2003 2002 2001 (In millions except per share amounts) Administrative service revenue $ 101 $ 96 $ 95 Equity in earnings of subsidiaries 917 1,842 1,087 Operating expenses (133 ) (141 ) (108 ) Interest income 20 30 35 Interest expense (200 ) (253 ) (132 ) Other income 2 81 4 Income before income taxes 707 1,655 981 Less: Income tax benefit (84 ) (68 ) (40 ) Income from continuing operations 791 1,723 1,021 Discontinued operations (365 ) (2,536 ) 69 Cumulative effect of changes in accounting principles (6 ) (61 ) 9 Net income (loss) before intercompany elimination $ 420 $ (874 ) $ 1,099 Weighted Average Common Shares Outstanding 385 371 363 Earnings (Loss) Per Common Share, Basic $ 1.09 $ (2.36 ) $ 3.03 Earnings (Loss) Per Common Share, Diluted $ 1.06 $ (2.26 ) $ 3.02 (in millions except per share amounts) 2002 2001 2000 Administrative service revenue $ 96 $ 95 $ 111 Equity in earnings (losses) of subsidiaries (434 ) 1,037 (3,415 ) Operating expenses (141 ) (108 ) (111 ) Interest income 30 35 20 Interest expense (253 ) (132 ) (27 ) Other income 81 4 2 Income (Loss) Before Income Taxes (621 ) 931 (3,420 ) Less: Income Taxes (564 ) (52 ) (4 ) Income (Loss) from continuing operations (57 ) 983 (3,416 ) Discontinued operations (756 ) 107 59 Cumulative effect of a change in an accounting principle (61 ) 9 — Net income (loss) before intercompany elimination (874 ) 1,099 (3,357 ) Eliminations of intercompany (profit) loss — — (7 ) Net income (loss) $ (874 ) $ 1,099 $ (3,364 ) Weighted Average Common Shares Outstanding 371 363 362 Earnings (Loss) Per Common Share, Basic $ (2.36 ) $ 3.03 $ (9.29 ) Earnings (Loss) Per Common Share, Diluted $ (2.36 ) $ 3.02 $ (9.29 )
CONDENSED STATEMENTS OF CASH FLOWS2001, and 2000
2001(in millions) 2002 2001 2000 Cash Flows from Operating Activities: Net income (loss) $ (874 ) $ 1,099 $ (3,364 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Equity in earnings of subsidiaries 1,623 (1,143 ) 3,316 Deferred taxes (525 ) (51 ) 20 Distributions from consolidated subsidiaries — — 475 Other-net (608 ) 218 232 Net cash provided by operating activities $ (382 ) $ 123 $ 679 Cash Flows From Investing Activities: Capital expenditures (1 ) (4 ) 1 Investment in subsidiaries — — (555 ) Loans to subsidiaries — — (308 ) Return of capital by Utility (share repurchases) — — 275 Other-net — — (9 ) Net cash provided (used) by investing activities $ (1 ) $ (4 ) $ (596 ) Cash Flows From Financing Activities: Common stock issued 217 15 65 Common stock repurchased — (1 ) (2 ) Loans from subsidiary — — 75 Long-term debt issued 908 904 — Long-term debt matured, redeemed, or repurchased (908 ) — — Short-term debt issued (redeemed) — (931 ) 405 Dividends paid — (109 ) (436 ) Other-net — — 6 Net cash provided (used) by financing activities $ 217 $ (122 ) $ 113 Net Change in Cash and Cash Equivalents (166 ) (3 ) 196 Cash and Cash Equivalents at January 1 348 351 155 Cash and Cash Equivalents at December 31 $ 182 $ 348 $ 351 95 2003 2002 2001 (In millions) Cash Flows from Operating Activities: Net income (loss) $ 420 $ (874 ) $ 1,099 Loss (income) from discontinued operations 365 2,536 (69 ) Cumulative effect of changes in accounting principles 6 61 (9 ) Net income from continuing operations 791 1,723 1,021 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Equity in earnings of subsidiaries (917 ) (1,842 ) (1,087 ) Deferred taxes 265 (660 ) (51 ) Other-net 391 458 237 Net cash provided (used) by operating activities 530 (321 ) 120 Cash Flows From Investing Activities: Capital expenditures — (1 ) (4 ) Net cash used by investing activities — (1 ) (4 ) Cash Flows From Financing Activities: Common stock issued 166 217 15 Common stock repurchased — — (1 ) Long-term debt issued 581 847 907 Long-term debt redeemed (787 ) (908 ) — Short-term debt issued redeemed — — (931 ) Dividends paid — — (109 ) Other-net 1 — — Net cash provided (used) by financing activities (39 ) 156 (119 ) Net Change in Cash & Cash Equivalents 491 (166 ) (3 ) Cash & Cash Equivalents at January 1 182 348 351 Cash & Cash Equivalents at December 31 $ 673 $ 182 $ 348 II—II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS2001, and 2000
2001Column A Column B Column C Column D Column E
Additions (in millions) Description Balance at
Beginning
of Period Charged to
Costs and
Expenses Charged
to Other
Accounts Deductions Balance at
End of
PeriodValuation and qualifying accounts deducted from assets: 2002: Allowance for uncollectible accounts(2) $ 89 58 (2 ) 32 (1) 113 2001: Allowance for uncollectible accounts(2) $ 71 $ 82 $ — $ 64 (1) $ 89 Provision for loss on generation-related regulatory assets and undercollected purchased power costs(3) $ 6,939 $ — $ — $ 6,939 $ — 2000: Allowance for uncollectible accounts(2) $ 65 $ 48 $ 2 $ 44 (1) $ 71 Provision for loss on generation-related regulatory assets and undercollected purchased power costs(3) $ — $ 6,939 $ — $ — $ 6,939 (1)Deductions consist principally of write-offs, net of collections of receivables previously written off.(2)Allowance for uncollectible accounts is deducted from "Accounts Receivable Customers, net" and "Accounts Receivable Energy Marketing."(3)Provision was deducted from "Regulatory Assets."96 Additions Balance at Charged to Charged Balance at Beginning Costs and to Other End of Description of Period Expenses Accounts Deductions Period (in millions) Valuation and qualifying accounts deducted from assets: 2003: $ 59 $ 42 $ — $ 33 (3) $ 68 2002: $ 48 $ 34 $ (2 ) $ 23 (3) $ 59 2001: $ 52 $ 24 $ — $ 28 (3) $ 48 $ 6,939 $ — $ — $ 6,939 $ — �� (1) Allowance for uncollectible accounts is deducted from “Accounts receivable Customers, net.” (2) Allowance for uncollectible accounts does not include NEGT. (3) Deductions consist principally of write-offs, net of collections of receivables previously written off. (4) Provision was deduction from “Regulatory Assets.”
PACIFIC GAS AND ELECTRIC COMPANY,
A DEBTOR-IN-POSSESSION
DEBTOR IN POSSESSIONII—II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS2001, and 2000
2001 Additions Balance at Charged to Charged Balance at Beginning Costs and to Other End of Description of Period Expenses Accounts Deductions Period (in millions) Valuation and qualifying accounts deducted from assets: 2003: $ 59 $ 42 $ — $ 33 (2) $ 68 2002: $ 48 $ 34 $ (2 ) $ 23 (2) $ 59 2001: $ 52 $ 24 $ — $ 28 (2) $ 48 $ 6,939 $ — $ — $ 6,939 $ — Column A Column B Column C Column D Column E Additions (in millions) Description Balance at
Beginning
of Period Charged to
Costs and
Expenses Charged
to Other
Accounts Deductions Balance at
End of
PeriodValuation and qualifying accounts deducted from assets: 2002: Allowance for uncollectible accounts(2) $ 48 $ 35 $ (2 ) $ 23 (1) $ 58 2001: Allowance for uncollectible accounts(2) $ 52 $ 24 $ — $ 28 (1) $ 48 Provision for loss on generation-related regulatory assets and undercollected purchased power costs(3) $ 6,939 $ — $ — $ 6,939 $ — 2000: Allowance for uncollectible accounts(2) $ 46 $ 19 $ 2 $ 15 (1) $ 52 Provision for loss on generation-related regulatory assets and undercollected purchased power costs(3) $ — $ 6,939 $ — $ — $ 6,939 (1) Allowance for uncollectible accounts is deducted from “Accounts receivable Customers, net.” (2) Deductions consist principally of write-offs, net of collections of receivables previously written off. (3) Provision was deduction from “Regulatory Assets.” (1)Deductions consist principally of write-offs, net of collections of receivables previously written off.(2)Allowance for uncollectible accounts is deducted from "Accounts Receivable Customers, net."(3)Provision was deducted from "Regulatory Assets."97 Exhibit Number Exhibit Description 3 .1 Restated Articles of Incorporation of PG&E Corporation effective as of May 5, 2000 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 3.1) 3 .2 Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2) 3 .3 Bylaws of PG&E Corporation amended as of February 18, 2004 3 .4 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit 3.1) 3 .5 Bylaws of Pacific Gas and Electric Company amended as of February 18, 2004 4 .1 First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (incorporated by reference to Registration No. 2-1324, Exhibits B-1, B-2, and B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; and Pacific Gas and Electric Company’s Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2) 4 .2 Indenture related to PG&E Corporation’s 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1). 4 .3 Supplemental Indenture related to PG&E Corporation’s 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1) 4 .4 Warrant Agreement, dated as of June 25, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation’s Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.9). 4 .5 Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2) 4 .6 Form of Rights Agreement dated as of December 22, 2000, between PG&E Corporation and Mellon Investor Services LLC, including the Form of Rights Certificate as Exhibit A, the Summary of Rights to Purchase Preferred Stock as Exhibit B, and the Form of Certificate of Determination of Preferences for the Preferred Stock as Exhibit C (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 4.2) 4 .7 Amendment to Rights Agreement dated February 18, 2004, between PG&E Corporation and Mellon Investor Services LLC (incorporated by reference to PG&E Corporation’s Form 8-K filed February 19, 2004 (file No. 1-12609), Exhibit 99) 4 .8 Indenture dated as of July 2, 2003, by and between PG&E Corporation and Bank One, N.A. (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.1) 4 .9 Utility Stock Base Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.2) Exhibit Number Exhibit Description 4 .10 Utility Stock Protective Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.3) 4 .11 Form of 6 7/8 percent Senior Secured Note due 2008 (incorporated by reference to PG&E Corporation’s Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.4) 10 .1 The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2), as amended by Operational Flow Order (OFO) Settlement Agreement, approved by the California Public Utilities Commission on February 17, 2000, in Decision 00-02-050, as amended by Comprehensive Gas OII Settlement Agreement, approved by the California Public Utilities Commission on May 18, 2000, in Decision 00-05-049 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10); and the Gas Accord II Settlement Agreement, approved by the California Public Utilities Commission on August 22, 2002, in Decision 01-09-016 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1) 10 .2 Commitment Letter dated March 5, 2003, between PG&E Corporation and Lehman Brothers, Inc. (incorporated by reference to PG&E Corporation’s Form 8-K filed March 6, 2003) (File No. 1-12609), Exhibit 99.2) 10 .3 Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348); Exhibit 99) 10 .4 Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions 10 .5 Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996 10 .6 PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 10 .7 Electronic Commerce System User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation, effective as of September 28, 2001 10 .8 Operating Agreement effective as of April 1, 2003, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348); Exhibit 10.1) *10 .9 PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.4) *10 .10 Agreement and Release between PG&E Corporation and Thomas G. Boren, dated December 18, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.23) *10 .11 Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3) *10 .12 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated November 4, 1998 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.6) *10 .13 Letter regarding Compensation Arrangement between PG&E Corporation and Lyn E. Maddox dated April 25, 1997 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.7) Exhibit Exhibit
NumberExhibit Description 3.1 Restated Articles of Incorporation of PG&E Corporation effective as of May 5, 2000 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 3.1)3.2*10Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)3.3Bylaws of PG&E Corporation amended as of February 19, 20033.4Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit 3.1)3.5Bylaws of Pacific Gas and Electric Company amended as of February 19, 20034.1First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (incorporated by reference to Registration No. 2-1324, Exhibits B-1, B-2, and B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; and Pacific Gas and Electric Company's Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2)4.2Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).4.3Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)4.4Warrant 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).4.5Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)4.6Form of Rights Agreement dated as of December 22, 2000, between PG&E Corporation and Mellon Investor Services LLC, including the Form of Rights Certificate as Exhibit A, the Summary of Rights to Purchase Preferred Stock as Exhibit B, and the Form of Certificate of Determination of Preferences for the Preferred Stock as Exhibit C (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 4.2)10.1The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2), as amended by Operational Flow Order (OFO) Settlement Agreement, approved by the California Public Utilities Commission on February 17, 2000, in Decision 00-02-050, as amended by Comprehensive Gas OII Settlement Agreement, approved by the California Public Utilities Commission on May 18, 2000, in Decision 00-05-049 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10); and the Gas Accord II Settlement Agreement, approved by the California Public Utilities Commission on August 22, 2002, in Decision 01-09-01610.2Second Amended and Restated Credit Agreement, dated as of October 18, 2002, among PG&E Corporation, as Borrower, the Lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and other parties (incorporated by reference to PG&E Corporation's Form 8-K filed October 22, 2002 (File No. 1-12609), Exhibit 99.1)10.3.1Utility Stock Pledge Agreement (35 percent)—Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Form 8-K filed October 22, 2002 (File No. 1-12609), Exhibit 99.2)10.3.2Utility Stock Pledge Agreement (35 percent)—New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Form 8-K filed October 22, 2002 (File No. 1-12609), Exhibit 99.3)10.3.3Utility Stock Pledge Agreement (65 percent)—Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Form 8-K filed October 22, 2002 (File No. 1-12609), Exhibit 99.4)10.3.4Utility Stock Pledge Agreement (65 percent)—New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Form 8-K filed October 22, 2002 (File No. 1-12609), Exhibit 99.5)10.4Amended and Restated Credit Agreement among PG&E National Energy Group, Inc. and Chase Manhattan Bank dated August 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.310.5Second Amendment, dated as of October 18, 2002, to the Amended and Restated Credit Agreement, dated as of August 22, 2001, among PG&E National Energy Group, Inc., JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank), as Issuing Bank, the several lenders from time to time parties thereto, the Documentation Agents thereunder, the Syndication Agents thereunder, and JPMorgan Chase Bank, as Administrative Agent. (incorporated by reference to PG&E National Energy Group, Inc.'s Form 8-K filed October 28, 2002) (File No. 333-66032), Exhibit 10.1)10.6Credit Agreement, dated as of May 29, 2001, among PG&E National Energy Group Construction Company, LLC, as Borrower, the lenders from time to time parties thereto, and Societe Generale, as Administrative Agent and Security Agent10.7First Amendment to Credit Agreement, dated as of June 5, 2002, among PG&E National Energy Group Construction Company, LLC, the lenders party thereto, and Societe Generale, as Administrative Agent and Security Agent10.8Guarantee and Agreement (Turbine Credit Agreement), dated as of May 29, 2001, made by PG&E National Energy Group, Inc. in favor of Societe Generale, as Security Agent10.9Amended and Restated Credit Agreement, dated as of March 15, 2002, among GenHoldings I, LLC, as Borrower, Societe Generale, as Administrative Agent and a Lead Arranger, Citibank, N.A., as Syndication Agent and a Lead Arranger, the other agents and arrangers thereunder, JP Morgan Chase Bank, as issuer of the Letters of Credit thereunder, the financial institutions party thereto from time to time, and various other parties10.10Amended and Restated Guarantee and Agreement (GenHoldings I, LLC) dated as of March 15, 2002, by PG&E National Energy Group, Inc., in favor of Societe Generale, as Administrative Agent10.11Acknowledgement and Amendment Agreement, dated as of April 5, 2002, by and among PG&E National Energy Group, Inc., GenHoldings I, LLC, as Borrower, Societe Generale, as Administrative Agent, and the banks and lenders party thereto10.12Waiver and Amendment Agreement, dated as of September 25, 2002, among GenHoldings I, LLC, as Borrower, Societe Generale, as Administrative Agent, Citibank N.A., as Depository Agent, and the banks and lender group agents party thereto.10.13Third Waiver and Amendment, dated as of November 14, 2002, among GenHoldings I, LLC, as Borrower, various lenders identified as the GenHoldings Lenders, Societe Generale, as the Administrative Agent, Citibank, N.A., as Security Agent, and acknowledged and agreed to by PG&E National Energy Group, Inc.10.14Fourth Waiver and Amendment dated as of December 23, 2002, among GenHoldings I, LLC, various lenders identified as the GenHoldings Lenders, the Administrative Agent, and acknowledged and agreed to by PG&E National Energy Group, Inc. (incorporated by reference to PG&E Corporation's and PG&E National Energy Group, Inc.'s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and 333-66032), Exhibit 99.1)10.15Second Omnibus Restructuring Agreement dated as of December 4, 2002 among La Paloma Generating Company, LLC, La Paloma Generating Trust, Ltd., and various other parties, including PG&E National Energy Group, Inc. (incorporated by reference to PG&E Corporation's and PG&E National Energy Group, Inc.'s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and 333-66032), Exhibit 99.2)10.16Priority Credit and Reimbursement Agreement among La Paloma Generating Company, LLC, La Paloma Generating Trust Ltd., Wilmington Trust Company, in its individual capacity and as Trustee, Citibank, N.A., as the Priority Working Capital L/C Issuer, the Several Priority Lenders from time to time parties hereto, Citibank, N.A., as administrative agent, and Citibank, N.A., as priority agent, dated as of December 4, 2002 (incorporated by reference to PG&E Corporation's and PG&E National Energy Group, Inc.'s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and 333-66032), Exhibit 99.3)10.17Guarantee and Agreement (La Paloma), dated as of April 6, 2001, by PG&E National Energy Group, Inc. in favor of Citibank, N.A., as Security Agent10.18Second Omnibus Restructuring Agreement dated as of December 4, 2002 among Lake Road Generating Company, LLC, Lake Road Generating Trust, Ltd., and various other parties, including PG&E National Energy Group, Inc. (incorporated by reference to PG&E Corporation's and PG&E National Energy Group, Inc.'s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and 333-66032), Exhibit 99.4)10.19Priority Credit and Reimbursement Agreement among Lake Road Generating Company, LLC, Lake Road Trust Ltd., Wilmington Trust Company, in its individual capacity and as Trustee, Citibank, N.A., as the Priority L/C Issuer, the Several Priority Lenders from time to time parties hereto, Citibank, N.A., as administrative agent, and Citibank, N.A., as priority agent, dated as of December 4, 2002 (incorporated by reference to PG&E Corporation's and PG&E National Energy Group, Inc.'s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and 333-66032), Exhibit 99.5)10.20Amendment, Waiver and Consent Agreement dated as of November 6, 2002, among La Paloma Generating Company, LLC, La Paloma Generating Trust, Ltd., Wilmington Trust Company as Trustee, Citibank, N.A., as administrative agent and security agent, and various other parties, and acknowledged and agreed to by PG&E National Energy Group, Inc.10.21Guarantee and Agreement (Lake Road), dated as of April 6, 2001, made by PG&E National Energy Group, Inc. in favor of Citibank, N.A., as Security Agent*10.22PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.4)*10.23Agreement and Release between PG&E Corporation and Thomas G. Boren, dated December 18, 2002*10.24Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)*10.25Letter 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)*10.26Letter regarding Compensation Arrangement between PG&E Corporation and Lyn E. Maddox dated April 25, 1997 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.7)*10.27.14 Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)* 10.2810.15 Description of Relocation Arrangement Between PG&E Corporation and Lyn E. Maddox (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.9)* 10.2910.16 Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609); Exhibit 10.3) *10 .17 Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609); Exhibit 10.4) *10 .18 PG&E Corporation Senior Executive Officer Retention Program approved December 20, 2000 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10)]* 10.30.110.19.1 Letter regarding retention award to Robert D. Glynn, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.1)* 10.30.210.19.2 Letter regarding retention award to Gordon R. Smith dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.2)* 10.30.310.19.3 Letter regarding retention award to Peter A. Darbee dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.3)* 10.30.410.19.4 Letter regarding retention award to Bruce R. Worthington dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.4)* 10.30.510.19.5 Letter regarding retention award to G. Brent Stanley dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.5)* 10.30.610.19.6 Letter regarding retention award to Daniel D. Richard, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.6)* 10.30.710.19.7 Letter regarding retention award to James K. Randolph dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.7)* 10.30.810.19.8 Letter regarding retention award to Gregory M. Rueger dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.8)* 10.30.910.19.9 Letter regarding retention award to Kent M. Harvey dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.9)* 10.30.1010.19.10 Letter regarding retention award to Roger J. Peters dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.10.10))* 10.30.1110.19.11 Letter regarding retention award to Lyn E. Maddox dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.12)* 10.30.1210.19.12 Letter regarding retention award to P. Chrisman Iribe dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.13)Exhibit Number Exhibit Description * 10.30.1310.19.13 Letter regarding retention award to Thomas B. King dated February 27, 2001 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.14)* 10.3110.20 Pacific Gas and Electric Company Management Retention Program (incorporated by reference to PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609)1-12609 and File No. 1-2348), Exhibit 10.1)* 10.3210.21 PG&E Corporation Management Retention Program (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.2)* 10.3310.22 PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)* 10.3410.23 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 20022003 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 20012002 (File No. 1-12609), Exhibit 10.25)10.35)* 10.3510.24 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2003.2004* 10.3610.25 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended as of September 19, 2001 (incorporated by reference to Pacific Gas and Electric Company'sCompany’s Form 10-K for the year ended December 31, 2001 (File No. 1-2248), Exhibit 10.16)* 10.37.110.26.1 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) * 10.37.210.26.2 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) * 10.37.310.26.3 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) * 10.37.410.26.4 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) * 10.37.510.26.5 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated December 20, 2002 (incorporated by reference to PG&E Corporation’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) * 10.37.610.26.6 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Thomas G. Boren dated December 20, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.6) * 10.3810.27.1 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 Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609); Exhibit 10.2.1) *10 .27.2 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 Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348); Exhibit 10.2.2) Exhibit Number Exhibit Description *10 .27.3 Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated April 18, 2003 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348); Exhibit 10.2.3) *10 .27.4 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 Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348); Exhibit 10.2.4) *10 .27.5 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 Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609); Exhibit 10.2.5) *10 .28 Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company'sCompany’s Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)* 10.3910.29 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company'sCompany’s Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)* 10.4010.30 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K for the year ended December 31, 1997 (File No. 1-12609), Exhibit 10.13)* 10.4110.31 PG&E Corporation Long-Term Incentive Program, as amended May 16, 2001, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)* 10.4210.32 PG&E Corporation Executive Stock Ownership Program amendedGuidelines dated as of SeptemberFebruary 19, 20002003 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-K10-Q for the yearquarter ended DecemberMarch 31, 20002003 (File No. 1-12609),; Exhibit 10.20)10.2)* 10.4310.33 PG&E Corporation Officer Severance Policy, amended as of December 19, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.43) * 10.4410.34 PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)* 10.4510.35 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation'sCorporation’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2)* 10.4610.36 PG&E Corporation Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46) *10 .37 Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program *10 .38 Form of Performance Share Award Agreement granted under the PG&E Corporation Long-Term Incentive Program 11*10 .39 Computation of Earnings Per Common SharePG&E National Energy Group, Inc. Management Retention/ Performance Award Program (incorporated by reference to PG&E Corporation’s Form 10-K/A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609); Exhibit 10.47)12.1*10 .39.1 Computation of Ratios of EarningsLetter regarding retention award to Fixed ChargesThomas B. King dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for Pacific Gas and Electric Companythe year ended December 31, 2002 (File No. 1-12609); Exhibit 10.47.1) Exhibit Number Exhibit Description *10 .39.2 Letter regarding retention award to P. Chrisman Iribe dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609); Exhibit 10.47.2) *10 .39.3 Letter regarding retention award Lyn E. Maddox dated September 9, 2002 (incorporated by reference to PG&E Corporation’s Form 10-K/ A Amendment No. 2 for the year ended December 31, 2002 (File No. 1-12609); Exhibit 10.47.3) 11 Computation of Earnings Per Common Share 12 .1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company 12 .2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company 13 The following portions of the 2003 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Independent Auditors’ Report,” “Responsibility for Consolidated Financial Statements,” financial statements of PG&E Corporation entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Common Shareholders’ Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” “Consolidated Statements of Shareholders’ Equity,” “Notes to Consolidated Financial Statements,” and “Quarterly Consolidated Financial Data (Unaudited)” 21 Subsidiaries of the Registrant 23 Independent Auditors’ Consent (Deloitte & Touche LLP) 24 .1 Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K 24 .2 Powers of Attorney 31 .1 Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002 31 .2 Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002 **32 .1 Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002 **32 .2 Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002 12.2* Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric CompanyManagement contract or compensatory agreement.13** The following portionsPursuant to Item 601(b)(32) of the 2002 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric CompanySEC Regulation S-K, these exhibits are included: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Independent Auditors' Report," "Responsibility for Consolidated Financial Statements," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets, " "Consolidated Statements of Cash Flows," and "Consolidated Statements of Common Stockholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," "Consolidated Statements of Stockholders' Equity," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)"21Subsidiaries of the Registrant23Independent Auditors' Consent (Deloitte & Touche LLP)24.1Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K24.2Powers of Attorney99.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 200299.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002furnished rather than filed with this report.TABLE OF CONTENTSGLOSSARY OF TERMSPART IGENERALREGULATIONCOMPETITIONUTILITY OPERATIONSPG&E NATIONAL ENERGY GROUP, INC.ENVIRONMENTAL MATTERSEXECUTIVE OFFICERS OF THE REGISTRANTSPART IIPART IIIEquity Compensation Plan InformationSIGNATURESINDEPENDENT AUDITORS' REPORTSCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED BALANCE SHEETSSCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT—(Continued) CONDENSED STATEMENTS OF INCOME For the Years Ended December 31, 2002, 2001, and 2000CONDENSED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002, 2001, and 2000PG&E CORPORATION SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2002, 2001, and 2000PACIFIC GAS AND ELECTRIC COMPANY A DEBTOR-IN-POSSESSION SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2002, 2001, and 2000EXHIBIT INDEX