Back to GetFilings.com

SECURITIES AND EXCHANGE COMMISSION

Form 10-K

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

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 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’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K:

     PG&E Corporation    o

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

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

      Common Stock outstanding as of February 17, 2004:

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.

TABLE OF CONTENTS

i

ii

iii

PART I

Item 1.     Business.

GENERAL

Corporate Structure and Business

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

      The Utility served approximately 4.9 million electricity distribution customers and approximately 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 Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.

      On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California. The factors that caused the Utility to take this action are discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations, or the MD&A, and in Note 2 of the Notes to the Consolidated Financial Statements in PG&E Corporation’s and the Utility’s Combined 2003 Annual Report to Shareholders, or the Annual Report, which is incorporated by reference into this report. The Utility has retained control of its assets and is authorized to operate its business as a debtor-in-possession during its Chapter 11 proceeding.

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

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

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

1

      The factors that caused NEGT and its subsidiaries to take this action are discussed in the MD&A and in Note 5 of the Notes to the Consolidated Financial Statements in the Annual Report. Pursuant to Chapter 11, NEGT and its subsidiaries that filed Chapter 11 petitions retain control of their assets and are authorized to operate their businesses as debtors-in-possession while they are subject to the jurisdiction of the bankruptcy court.

      NEGT’s proposed plan of reorganization, if implemented, would eliminate PG&E Corporation’s equity interest in NEGT and its subsidiaries. In anticipation of NEGT’s Chapter 11 filing, PG&E Corporation’s representatives, who previously served as directors of NEGT resigned on July 7, 2003, and were replaced with directors who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retains significant influence over NEGT. Accordingly, effective July 8, 2003, NEGT’s results of operations no longer are consolidated with those of PG&E Corporation. NEGT’s results of operations through July 7, 2003, and for prior years have been reclassified as discontinued operations and PG&E Corporation now accounts for its investment in NEGT using the cost method of accounting.

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

Employees

      At December 31, 2003, PG&E Corporation and its subsidiaries and affiliates (excluding NEGT) had approximately 20,600 employees, including approximately 20,300 employees of the Utility. Of the Utility’s employees, approximately 13,500 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, Local  24/7, or SEIU. The ESC and IBEW collective bargaining agreements expire on December 31, 2007. The SEIU collective bargaining agreement expires on February 28, 2008.

The Utility’s Plan of Reorganization and Settlement Agreement

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

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

2

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

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

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

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

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

3

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

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

Forward-Looking Statements and Risk Factors

      This combined Annual Report on Form 10-K, including the portions of the Annual Report incorporated by reference, 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” and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements.

      Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include:

Whether and on What Terms the Plan of Reorganization is Implemented

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

Operating Environment

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

4

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

Legislative and Regulatory Environment and Pending Litigation

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

Competition

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

5

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

Electric Utility Operations

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

      The Utility’s distribution network interconnects to the Utility’s electricity transmission system at 1,012 points. This interconnection between the Utility’s distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers. The distribution substations serve as the central hubs of the Utility’s electricity distribution network and consist of transformers, voltage regulation equipment, protective devices and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or facilities to entities, such as municipal and other utilities, that then resell the electricity.

2003 Electricity Deliveries

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

(80,156 GWhs)

6

     Electricity Distribution Operating Statistics

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

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

7

     Electricity Resources

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

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

     Generation Facilities

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

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

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

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 recovered by NEIL for these losses from reinsurance. Under the Terrorism Risk Insurance Act of 2002, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign terrorism. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.

      Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.9 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for the Diablo Canyon power plant. The balance of the $10.9 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of reactors 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $100.6 million per reactor, with payments in each year limited to a maximum of $10 million per incident until the Utility has fully paid its share of the liability. Since the Diablo Canyon power plant has two nuclear reactors over 100 MW, the Utility may be assessed up to

9

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

      Hydroelectric Generation Facilities. The Utility’s hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe and 5 miles of natural waterways. The system also includes water rights as specified in 83 permits and licenses and 163 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses, all of the Utility’s powerhouses are licensed by the FERC. Pursuant to the Federal Power Act, the term of a hydroelectric project license issued by the FERC is between 30 and 50 years. In the last three years, the Utility has received six renewed hydroelectric project licenses from the FERC. Licenses associated with approximately 928 MW expire within the next five years. Licenses associated with approximately 2959 MW expire between 2009 and 2043.

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

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

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

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

10

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

      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 any qualifying facilities refunds, which the Utility actually realizes in cash, claim offsets or other credits, would reduce the $2.21 billion after-tax regulatory asset. PG&E Corporation and the Utility are unable to estimate the outcome of this proceeding.

      The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts’ and water agencies’ debt service requirements, regardless if any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. The Utility’s irrigation district and water agency contracts accounted for approximately 5% of 2003 electricity sources, approximately 4% of 2002 electricity sources and approximately 3% of 2001 electricity sources.

11

      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:

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

Natural Gas Utility Operations

      The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 38 of California’s 58 counties and includes most of northern and central California. In 2003, the Utility served approximately 3.9 million natural gas distribution customers. The total volume of natural gas throughput during 2003 was approximately 804 Bcf.

      At December 31, 2003, the Utility’s natural gas system consisted of 39,510 miles of distribution pipelines, 6,350 miles of transportation pipelines and three storage facilities. The Utility’s distribution network connects to the Utility’s transportation and storage system at approximately 2,200 major interconnection points. The Utility’s Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation, a subsidiary of NEGT, at the California-Oregon border. This line has a receipt capacity at the border of 2.0 Bcf per day. The Utility’s Line 300, which interconnects with the U.S. southwest and California-Oregon pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity at the California-Arizona border of approximately 1.1 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada and the southwestern United States. The Utility also is supplied by natural gas fields in California.

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

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

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

13

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

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

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

      The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and natural gas utilities. The 2002 California Gas Report updated the Utility’s annual natural gas requirements forecast for the years 2002 through 2023, forecasting average annual growth in the Utility’s natural gas deliveries of approximately 1.8%. The natural gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, and the number and location of electricity generation facilities.

     2003 Natural Gas Deliveries

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

(804 Bcf)

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: