ITEM 1. Business.
GENERAL
Corporate Structure and Business
PG&E Corporation is an energy-based holding company headquartered in San Francisco, California which conducts its business through two principal subsidiaries: Pacific Gas and Electric Company, or the Utility, an operating public utility engaged principally in the business of providing electricity and natural gas distribution and transmission services throughout most of northern and central California, and PG&E National Energy Group, Inc., or PG&E NEG, a company engaged in power generation, wholesale energy marketing and trading, risk management, and natural gas transmission.
Pacific Gas and Electric Company was incorporated in California in 1905. Effective January 1, 1997, the Utility and its subsidiaries became subsidiaries of PG&E Corporation, which was incorporated in 1995. In the holding company reorganization, 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. The Utility filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court for the Northern District of California on April 6, 2001. Pursuant to Chapter 11, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. The Utility is regulated primarily by the California Public Utilities Commission, or CPUC, and the Federal Energy Regulatory Commission, or FERC.
PG&E NEG, headquartered in Bethesda, Maryland, was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. PG&E NEG and its subsidiaries are principally located in the United States and Canada. PG&E NEG's principal subsidiaries include: PG&E Generating Company, LLC, and its subsidiaries, or PG&E Gen; PG&E Energy Trading Holdings Corporation and its subsidiaries, or PG&E ET; and PG&E Gas Transmission Corporation and 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.
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 Pacific Gas and Electric Company 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, the Utility, and PG&E NEG each file various reports with the Securities and Exchange Commission, or the SEC. The reports that PG&E Corporation and the Utility file with the SEC are available free of charge on both PG&E Corporation's website, www.pge-corp.com, and the Utility's website, www.pge.com. PG&E NEG's reports also are available free of charge 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 information 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 is incorporated by reference into this report.
As result of the sustained downturn in the power industry during 2002, PG&E NEG and its affiliates have experienced a financial downtown which caused the major credit rating agencies to downgrade PG&E NEG's and
its 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 restructuring 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.
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 of 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, PG&E Corporation and its subsidiaries and affiliates had 21,814 employees (including 19,575 employees of the Utility). Of the Utility's employees, approximately 13,000 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 IUSO. The collective bargaining agreements with IBEW and ESC remain in effect until the earlier of December 31, 2003 or the date on which a new agreement is completed, and the agreement with the IUSO expires on February 28, 2003. The Utility currently is in negotiations for renewal of the collective bargaining agreements with IBEW and ESC and is beginning negotiations with IUSO.
Proposed Plans of Reorganization of the Utility
The Utility will not emerge from bankruptcy until a plan of reorganization has been confirmed 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 plan of reorganization, described below as the Utility Plan. The CPUC submitted a competing proposed plan of reorganization. During the summer of 2002, holders of claims against, and equity interests in, the Utility were requested to vote whether to accept or reject the competing plans. On September 9, 2002, an independent voting agent announced that nine of the ten voting classes under the Utility 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 CPUC 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 and 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 wholesale
regulators, 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% of the book value 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 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 LLCs after the effective date of the Utility Plan. For example
•the 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.
•The Utility would rely on ETrans for the Utility's electricity transmission needs because the transmission lines proposed to be transferred to ETrans are currently the only transmission lines directly connected to the Utility's electricity distribution system.
•The Utility 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 portion of the Utility's natural gas storage requirements for at least 10 years under a transportation 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 date 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 the
implementation 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 full rate of return on rate base.
The CPUC/OCC Plan also provides that it would not become effective until 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 redemption of, the securities to be issued under the CPUC/OCC Plan, and (2) certain recoverable costs (defined as the amounts that the Utility is authorized 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 includes 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 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:
Recovery of Undercollected Power Procurement and Transition Costs Previously Written Off. The extent to which the Utility is able to recover its undercollected power procurement and transition costs previously written off depends on many factors, including:
•what costs the CPUC determines are eligible 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 remitted to the DWR from existing retail rates;
•changes in the Utility's authorized revenue requirements;
•future regulatory or judicial decisions that determine whether the Utility is allowed under state law to recover undercollected power procurement and transition costs from its customers after the end of the rate freeze; and
•the outcome of the Utility's claims against the CPUC Commissioners for recovery of undercollected power procurement and transition costs based on the federal filed rate doctrine;
Refundability of Amounts Previously Collected. Whether the Utility is required to refund to ratepayers amounts previously collected depends on many factors, including:
•whether the CPUC determines that certain transition or procurement costs recovered in revenues collected by the Utility were not eligible transition costs or otherwise reduces the amount of revenues authorized to recover such transition or procurement costs due to an overcollection of such costs;
•whether the CPUC ultimately determines that certain past power procurement costs incurred by the Utility were not reasonably incurred and should be disallowed; and
•the purposes for which the CPUC ultimately determines that surcharges approved by the CPUC in January, March, and May 2001 may be used.
Outcome of the Utility's Bankruptcy Case. The pace and outcome of 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 implementation 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 be 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;
•the terms and conditions of the Utility's long-term generation procurement plan as approved by the CPUC;
•the ability of the Utility to timely recover in full its costs including its procurement costs;
•future sales levels, which can be affected by general economic and financial market conditions, changes in interest rates, weather, conservation efforts, outages, and the level of direct access customers (i.e., those customers who choose an alternative energy provider);
•the demand for and pricing of transportation and storage services which may be affected by weather, overall gas-fired generation, and price spreads between various natural gas delivery points;
•changes in the Utility's authorized revenue requirements; and
•acts of terrorism, storms, earthquakes, accidents, mechanical breakdowns, or other events or perils that result in power outages or damage to 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's and the Utility's business may be affected by:
•the outcome of the Utility's various regulatory proceedings pending at the CPUC and at the FERC, and
•the outcome 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 condition may be affected by the 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 outcome of the California Attorney General's petition requesting revocation of PG&E Corporation's exemption from the Public Utility Holding Company Act of 1935; and
•other pending litigation.
Competition. PG&E Corporation's and the Utility's future results of operations and financial condition may be affected by:
•the threat of municipalization which may result in stranded Utility investment, loss of customer growth, and additional barriers to cost recovery;
•changes in the level of direct access customer cost responsibility and other surcharges related to direct access, and competition from other service providers to 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, the cost of which could be significant;
•the outcome of pending environmental matters or proceedings;
•whether the Utility is able to fully recover in rates the costs of complying with existing and future environmental laws, regulations, and policies, the cost of which could be significant; and
•whether the Utility incurs costs in connection with its nuclear facilities that exceed the Utility's insurance coverage and other amounts set aside for decommissioning and other potential liabilities.
Accounting and Risk Management. PG&E Corporation's and the Utility's future results 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 certain of its subsidiaries seek protection under or be forced into a proceeding under the U.S. Bankruptcy Code will be affected by
•the 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 transferred to the project lenders as required by recent restructuring agreements.
PG&E NEG Operational Risks. PG&E Corporation's future results of operations and financial condition will be affected by:
•the extent to which PG&E NEG incurs further charges to earnings 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 charges to income that would result from the reduction 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,
embargoes, 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.
REGULATION
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 some of the more significant laws and regulations affecting PG&E Corporation's business at this time.
Regulation of PG&E Corporation
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 the Holding Company Act. At present, PG&E Corporation has no expectation of becoming a registered holding company under the Holding Company Act. On July 7, 2001, the California Attorney General, or the AG, filed a petition with the SEC requesting the SEC to review and revoke PG&E Corporation's exemption from the Holding Company Act 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's petition demonstrating that PG&E Corporation met the SEC's criteria for the intrastate exemption. On October 4, 2001, the AG filed a "supplement" to its petition requesting that the SEC consider additional issues 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's petition.
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 Pacific Gas and Electric Company to form a holding company was granted subject to various conditions 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 that
•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.
The CPUC also has adopted complex and detailed rules governing transactions between California's 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'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 utilities from engaging in certain practices that would discriminate against energy service providers that compete with the utility's non-regulated affiliates. 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 IOUs, including the Utility, have complied with past CPUC decisions, rules, or 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' transfer of money to their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties, (2) the failure of the holding companies to financially assist the utilities when needed, (3) the transfer by the holding companies of assets to unregulated subsidiaries, and (4) the holding companies' actions to "ringfence" their unregulated subsidiaries. The CPUC will also determine whether additional rules, conditions, or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the holding company structure. The CPUC will investigate whether it should modify, change, or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions, or recommend statutory changes to the California legislature. As a result of the investigation, the CPUC may impose remedies, prospective rules, or conditions, as appropriate. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders.
On January 9, 2002, the CPUC issued two decisions in its pending investigation. In one decision, the CPUC, for the first time, adopted a broad interpretation of the first priority condition and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies "infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve." The three major California IOUs and their parent holding companies had opposed this broader interpretation as being inconsistent with the prior 15 years' understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The CPUC also interpreted the first priority condition as prohibiting a holding company from (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's ability to fulfill its obligation to serve or to operate in a prudent and efficient manner.
In the other 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 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. The CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum; i.e., the state court action discussed below, could decide expeditiously whether adoption of the Utility's proposed plan of reorganization would violate the first priority condition.
On January 10, 2002, the AG 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 AG alleges that PG&E Corporation violated the various conditions established by the CPUC in decisions approving the holding company formation. After the AG'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. For more information, see "Item 3 - Legal Proceedings" below.
PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. Neither the Utility nor PG&E Corporation can predict what the outcomes of 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.
Regulation of Pacific Gas and Electric Company
Federal Regulation
The FERC. The FERC is an independent agency within the U.S. Department of Energy, or the DOE. The FERC 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 electric transmission rates and access, interconnections, operation of the California Independent System Operator, or ISO, and the terms and rates of wholesale electric power sales. The ISO has responsibility 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. In addition, the FERC has jurisdiction over the Utility's electric transmission revenue requirements and rates. The FERC also regulates the interstate 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.
In response to the unprecedented increase in wholesale electricity prices, the FERC issued a series of orders in the spring and summer of 2001 and July 2002 aimed at mitigating future extreme wholesale energy prices like those in 2000 and 2001. These orders established a cap on bids for real-time electricity and ancillary services of $250/MWh and established various automatic mitigation procedures. Recently, in the FERC's standard market design proposed rules, the FERC proposed to adopt a safety net bid cap as part of the mitigation plan for wholesale energy markets and has requested comments on the appropriate value for such a bid cap.
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 regarding
past 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, including the Utility and the State of California, which is 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, order from the U. S. Court of Appeals for the Ninth Circuit ordered the FERC to allow the California parties "to adduce additional evidence of market manipulation by various sellers...." 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 companies overcharged the utilities, the State of California and other buyers from October 2, 2000 to June 2001 by $1.8 billion, but that California buyers still owe the power companies $3 billion, leaving $1.2 billion in unpaid bills. The time period reviewed 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, the FERC commissioners must decide whether to uphold or change the initial decision. It is uncertain when the FERC will issue a decision.
The NRC. The NRC oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including the Diablo Canyon Nuclear Power Plant (Diablo Canyon) 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.
State Regulation
The CPUC. The CPUC has jurisdiction to set retail rates and conditions of service for the Utility's electric distribution, gas distribution, and gas transmission services in California. The CPUC also has jurisdiction over the Utility's sales of securities, dispositions of utility property, energy procurement on behalf of its electric and gas retail customers, rate of return, rates of depreciation, and certain aspects of the Utility's siting and operation of its electric and gas transmission and distribution systems. Ratemaking for retail sales from the Utility's remaining generation facilities is under the jurisdiction of the CPUC. To the extent such power is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. 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 six-year terms.
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's operations have been significantly affected by statutes passed by the California Legislature.
Assembly Bill 1890-California Electric Industry Restructuring. In 1998, California implemented Assembly Bill 1890, or AB 1890, which mandated the restructuring of the California electric industry 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. 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 reduced by a further 10% and frozen at that level. The rate freeze for each IOU was supposed to end when that IOU had recovered its eligible "transition" costs (costs 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 the 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 in 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.
In November 2002, the CPUC approved a decision modifying the restrictions on the use of revenues generated by the surcharges 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 predict the outcome of this case or whether 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 condition and results of operations would be materially adversely affected.
Direct Access -AB 1890 gave the Utility's customers the choice of continuing to buy electricity from the California IOUs 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 of 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 alternative 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. 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 ISO is responsible for ensuring the reliability of 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.
The 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.
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 the
proposal 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; and
•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, transmission lines, and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric facility and transmission line licenses, and NRC licenses are the most 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 eight hydroelectric projects and one transmission line project undergoing FERC license renewal.
The Utility has over 520 franchise agreements with various cities and counties that allow the Utility to install, operate and maintain its 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 according to statute depending on whether the particular franchise was granted under the Broughton Act or the Franchise Act of 1937; however, there are 38 "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 the permits, licenses, and franchises, the Utility has rights to occupy and/or use public property for the operation of its business and to conduct certain operations.
The Utility's operations and assets are also regulated by a variety of other federal, state, and local agencies.
Regulation of PG&E National Energy Group, Inc. Businesses
Federal Regulation
The rates, terms, and conditions of the wholesale sale of power by 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 jurisdiction under the Federal Power Act. Various PG&E NEG subsidiaries and affiliates have FERC-approved market-based rate schedules and accordingly have been granted waivers of
many of the accounting, record keeping, and reporting requirements imposed on entities with cost-based rate schedules. This market-based rate authority may be revoked or limited at any time by the FERC.
PG&E NEG-affiliated projects are also subject to other differing federal regulatory regimes. Those qualifying as qualifying facilities, or QFs, under the Public Utility Regulatory Policies Act of 1978, or PURPA, are exempt from the Holding Company Act, certain 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. As a result, power sales agreements, which PG&E NEG affiliates enter into with such utilities, are potentially subject to review by the public utility commissions, through the commissions' power to approve utilities' 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 and its subsidiaries are subject, see the section entitled "Environmental Matters" below.
COMPETITION
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, including timely recovery of their operating expenses and a reasonable return on their invested capital. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices. In recent years, energy utilities faced intensifying pressures to "unbundle," or price separately, those activities that are no longer considered natural monopoly services. The most significant 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 competition in the energy industry. Regulators and legislators required utilities to unbundle rates in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.
The Electric Industry
As discussed above, in 1998, California implemented AB 1890, which mandated the restructuring of the California electric industry 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 authorized 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 function 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 allow the Utility to fully recover its investment and procurement costs, the Utility's financial condition and results of operations could be materially adversely affected.
The Natural Gas Industry
FERC Order 636, issued in 1992, required interstate pipeline companies 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 whether the customer (often a local gas distribution company) buys the gas commodity from the pipeline.
In August 1997, the CPUC approved the Gas Accord settlement agreement, or Gas Accord, which restructured the Utility's gas services and its role in the gas market through 2002. Among other matters, the Gas Accord unbundled the rates for the 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 wholesale 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."
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.
UTILITY OPERATIONS
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 CPUC first determines the Utility's revenue requirements. The components of revenue requirements for electric and natural gas utility service include depreciation, expenses, taxes, and return on investment, as applicable, for distribution, transmission/
transportation, generation/procurement, and public purpose programs. The CPUC then allocates the revenue requirements among customer classes (mainly residential, commercial, industrial, and agricultural) and sets specific rates designed to produce the required revenue. The concept underpinning the determination of revenue requirements and rates is to allow a utility a fair opportunity to recover its reasonable costs of providing adequate utility service, including a reasonable rate of return of and on its investment in utility facilities.
The primary revenue requirement proceeding is the general rate case, or GRC. In the GRC, the CPUC authorizes the Utility to collect from ratepayers an amount known as "base revenues" to recover basic business and operational costs for its natural gas and electricity operations. The general rate case sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in general rate case proceedings generally every three years based on a forecast of costs for the first or "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, the CPUC allocates revenue requirements among customer classes and establishes specific rate levels in separate proceedings.
Another major CPUC proceeding for determining revenue requirements is the annual cost of capital proceeding. Each year, the CPUC determines the adopted rate of return that the Utility may earn on its electric and gas distribution assets and recover from ratepayers. On November 7, 2002, the CPUC issued a final decision that retained the Utility's return on common equity at the current authorized level of 11.22%. This final decision also increased the Utility's authorized cost of debt to 7.57% from 7.26%, and held 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 structure of the implementation and financing of a bankruptcy plan of reorganization.
The return on the Utility's electric transmission-related assets is determined by the FERC. See "Electric Ratemaking" below. The return on the Utility's natural gas transmission and storage business was incorporated in rates established in the Gas Accord. See "Gas Ratemaking" below.
Electric Ratemaking
As required by AB 1890, electric rates for all 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 authorized the Utility to begin collecting energy surcharges totaling $0.04 per kWh (composed of a $0.01 per kWh surcharge approved in 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 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 transition 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 electric 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 expects the CPUC to set rates to recover:
•the Utility's approved utility cost components,
•the cost of energy sold to customers, and
•the DWR'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 conditions the CPUC will determine that the Utility's rate freeze has ended and the Utility will begin bottoms-up billing or to which periods these rates would apply.
In April 2001, the California Public Utilities Code was amended to require that 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. 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, 2002, the CPUC issued a decision that required the Utility to increase baseline allowances 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 phase of the proceeding and ordered the Utility to track the undercollections associated with these baseline quantity changes in an interest-bearing balancing account. The Utility estimates the annual revenue shortfall to be approximately $96 million for electricity service, and $6 million for natural gas service. The total electricity revenue shortfall estimated 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 and 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 Transmission
Electric transmission revenues, and both wholesale and retail transmission rates, are subject to authorization by the FERC. The Utility has two sources of transmission revenues, those from charges under its transmission owner tariff, or TO Tariff, and those from charges under specific contracts with existing wholesale transmission customers that pre-date the Utility's participation in the ISO. Customers that receive transmission services under such 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 utilities 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 the
California aqueduct. The Utility's municipal utility ETC customers distribute electricity to municipal facilities and, in many cases to the homes and businesses of retail electricity customers located inside their municipality.
Under the FERC's regulatory regime, the Utility is able to file a new base transmission rate case under the Utility's TO Tariff whenever the Utility deems it necessary to increase its rates. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.
The Utility's TO Tariff includes two rate components: (1) base transmission rates (from which the Utility derives the majority of its transmission revenues) 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 (2) the rates the Utility charges its TO Tariff customers to recover various bills the Utility receives from the ISO for reliability service costs, and the ISO's transition charge associated with the 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 Utility 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, subject 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 remitted to the Utility as a transmission owner.
On January 13, 2003, the Utility filed 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.
The Utility recovers certain ISO costs described below in balancing accounts. In general, for each of these types of costs, the difference between the ISO's actual charges and revenues collected by the Utility and the forecasted costs will be used to either offset or increase 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.
•Reliability Services Costs-The ISO bills the Utility for reliability services based on payments that the ISO makes to generators under reliability must-run contracts and for locational out-of-market calls required to support reliability of the transmission system. 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. Costs and revenues related to reliability services are tracked in the reliability services balancing account.
•Transition Charges-Beginning on January 1, 2001, the Utility pays the ISO's high-voltage blended 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 attributable to the Utility's ETC 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 by the ISO 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 transmission with the ISO for its ETC customers. The ISO bills the Utility for providing certain services associated with these
contracts. 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 be
approximately $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.
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 contracts 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 on the Utility and its customers until it has complied with the law. No schedule has yet been set for consideration of the lawsuit.
In May 2002, the CPUC approved a servicing order between the Utility and the DWR which sets forth the 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 functions for the DWR's allocated contracts beginning on January 1, 2003. The operating order, which applies prospectively, includes the DWR's proposed method 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 2001 and 2002.
In December 2002, the CPUC adopted an operating order requiring the Utility to perform the operational, dispatch, 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 terms
and 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 assignment 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 Ratemaking
Natural 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.
Gas distribution costs and balancing account balances are allocated to customers in the Biennial Cost Allocation Proceeding, or BCAP. The BCAP normally occurs every two years and is updated in the interim year for
purposes of amortizing any accumulation 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, the Utility filed its 2000 BCAP application to cover the period January 1, 2000 through December 31, 2002, requesting a decrease in the annual base revenue requirement of $132 million compared to the authorized revenue requirement of $941 million at the time the application was filed. On November 8, 2001, the CPUC issued a decision approving the Utility's BCAP settlement filed 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 accounts and 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 in the CPUC reimbursement account fee, and the extension of the Gas Accord.
Natural Gas Transportation and Storage
The Utility's interstate and Canadian natural gas transportation agreements are governed by tariffs which detail rates, rules and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. These tariffs are approved by the FERC in a FERC ratemaking review process and by the Alberta Energy and Utilities Board and the National Energy Board for 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 portion 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.
The Utility sets the core natural gas procurement rate monthly based on the forecasted costs of natural gas and core pipeline capacity and storage costs. The Utility reflects the difference between actual 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. The CPUC has not acted on the Utility's request. In accordance with 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 gas commodity prices, many noncore customers switched to core service in order to receive procurement service from the Utility. In 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, 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 service 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 rules for the major California utilities to obtain El Paso turned-back capacity not subscribed to by other California replacement shippers. On July 17, 2002, the CPUC ordered utilities to obtain such capacity, and stated that if the utilities complied with this order that they would also receive full recovery for costs associated with existing capacity rights on interstate pipelines. The Utility obtained 204 MDth/day of capacity on El Paso in compliance with the CPUC decision. On December 19, 2002, the CPUC found that the Utility had met the objectives, terms and conditions set forth in the CPUC's July 17, 2002 order. The CPUC authorized the Utility to 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.
Public Purpose Programs
The Utility continues to administer and/or fund several state-mandated public purpose programs. In December 2002, the CPUC authorized 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 to
earn 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 mechanism 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 OPERATIONS
Electric 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.
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.
(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.
Electric 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:
(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.
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.
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 California
IOUs 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.
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.
The amount of electric power received and the total payments made under QF, irrigation district, water agency, and bilateral agreements are as follows:
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 further
implementation 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, 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.
Through the interconnection with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the 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 commercial natural gas customers. In 2002, core customers represented over 99% of 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.
Gas 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:
(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.
(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.
(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.
Natural 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 subject 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 its core customers. The Utility has been able to broker its unused capacity on PG&E GTN's system, when not needed 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 noncore 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 the
five-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:
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:
(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:
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 connects
with 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, contractually
committed 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 Pipelines
El 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.
Natural 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:
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 between 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.
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 certificating
construction 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.
ENVIRONMENTAL MATTERS
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, which 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's responsibility, and the availability of recoveries or contributions from third parties.
PG&E Corporation, the Utility, and various PG&E NEG affiliates (including USGen New England, Inc., or USGenNE), are subject to a number of federal, state, and local laws and regulations relating to the protection of the environment and human health and safety. 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 penalties for violation of these laws and requirements can be severe, and may include significant fines, damages, and criminal or civil sanctions. They also may require, under certain circumstances, the interruption or curtailment of operations. To comply with all applicable laws and requirements, the Utility or PG&E NEG may need to spend substantial amounts from time to time to construct or acquire new 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 their current or former facilities and at other third-party sites where they may have disposed of or recycled wastes. In the past the Utility generally has recovered the costs of complying with environmental laws and regulations in its rates. In 1994, the CPUC established a ratemaking mechanism for hazardous waste remediation costs under which the Utility is authorized to recover costs for environmental claims (e.g., for cleaning up facilities and sites to which the Utility has sent hazardous wastes) from ratepayers. That mechanism assigns 90% of the includable hazardous substance cleanup costs to Utility ratepayers and 10% to Utility shareholders without a review of the underlying costs. Expenditures to cover environmental costs in the future are likely to be significant; however, based on the Utility's past experience, PG&E Corporation and the Utility believe it will be able to recover most of these costs from ratepayers and its insurers. PG&E Corporation and the Utility cannot assure you, 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
The Utility's and PG&E NEG's generating plants 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, and particulate matter. Fossil fuel-fired electric utility plants are usually major sources of air pollutants and, therefore are subject to substantial regulation and enforcement oversight by the applicable governmental agencies.
Various multi-pollutant initiatives have been introduced in the U.S. Senate and House of Representatives, including Senate Bill 556 and House Resolutions 1256 and 1335. These initiatives include limits on the emissions of NOx, SO2, mercury, and carbon dioxide (CO2). Certain of these proposals would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules.
A multi-state memorandum of understanding dealing with the control of NOx air emissions from major emission sources was signed by the Ozone Transport Commission states 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 sources in the area in addition to those that are allocated to PG&E NEG facilities, instead 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.
As a result of the Utility's divestiture of most of its fossil-fuel fired power plants and its geothermal generation facilities, the Utility's NOx emission reduction compliance costs have been reduced significantly. Pursuant to the California Clean Air Act and the Federal Clean Air Act, two of the local air districts in which the Utility owns and operates fossil-fuel fired generating plants have adopted final rules that require a reduction in NOx emissions from the power plants of approximately 90% by 2004 (with numerous interim compliance deadlines).
The Utility's Gas Accord authorized $42 million to be included in rates through 2002 for gas NOx retrofit projects related to natural gas compressor stations on the Utility'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. Other air districts are considering NOx rules that would apply to the Utility's other natural gas compressor stations in California. Eventually the rules are likely to require NOx reductions of up to 80% at many of these natural gas compressor stations. Substantially all of these costs will be capital costs.
In addition, certain current regulatory initiatives, particularly at the federal level, could increase the Utility's and PG&E NEG's compliance costs and capital expenditures to comply with laws such as laws relating to emissions of carbon dioxide and other greenhouse gases, particulates, and various other pollutants. If enacted, these programs could require the Utility and PG&E NEG to install additional pollution controls, purchase emission allowances, or curtail operations. Although associated costs could be material, the Utility expects that it would be able to recover these costs from ratepayers. The Utility will be required to incur substantial 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.
The 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 take
effect 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 EPA. All of PG&E NEG's 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 water
discharge 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 plants comply in all material respects with the discharge constituents standards and the thermal standards. Additionally, pursuant to Section 316(b) of the Federal Clean Water Act, the Utility is required to demonstrate that the location, design, construction, and capacity of power plant 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's intake structure to various governmental agencies and each plant's existing intake structure was found to meet the BTA requirements.
The Diablo Canyon Power Plant employs a "once through" cooling water system that is regulated under a NPDES permit issued by the Central Coast Regional Water Quality Control Board, or the Central Coast Board. This permit allows Diablo Canyon to discharge the cooling water at a temperature no more than 22 degrees above 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, Diablo Canyon's discharge was not protective of beneficial uses. In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility's discharge of cooling water from the Diablo Canyon plant protects beneficial uses and that the intake technology meets the BTA requirements. As part of the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $6 million in environmental projects related to coastal resources. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment prior to final approval by 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 in the Utility's bankruptcy proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with Diablo Canyon's operation of its cooling water system.
In December 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, 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 power generation facilities using over 50 million gallons per day (mgd), typically including some form of "once-through" cooling. The Utility'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 plants nationwide that would be affected by this rulemaking. The proposed regulations call for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. Significant capital investment may be required to achieve the standards if the regulations are adopted as proposed. The final regulations are scheduled to be issued in February 2004.
PG&E Corporation and the Utility believe the ultimate outcome of these matters will not have a material impact on their consolidated financial position or results of operations.
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 Species
Many of the Utility'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's facilities or operations.
Hazardous Waste Compliance and Remediation
The Utility's and PG&E NEG'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 or CERCLA, along with 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's operations, the Utility has generated, and continues to generate, waste that falls within CERCLA's definition of a hazardous substance and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
The Utility and PG&E NEG assess, on an ongoing basis, measures that may need to be taken 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 have 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.
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 and disposes of potentially hazardous materials. The Utility may be responsible for remediation of hazardous substances even if the Utility did not deposit those substances on the site.
Operations at the Utility's current and former power plants may have resulted in contaminated soil or groundwater. Although the Utility has sold 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. 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 Utility's electric distribution system.
One part of the Utility's program 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 in the late 1800s and early 1900s, manufactured gas plants produced lampblack and tar residues. The lampblack and tar residues are byproducts of a process that the Utility, its predecessor companies, and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), the Utility's manufactured gas plants were removed from service. The residues that may remain at some sites contain chemical compounds that now are classified as hazardous. The Utility owns all or a portion of 28 manufactured gas plant sites. The Utility has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites that are owned by the Utility. The Utility spent approximately $4 million in 2002 and expects to spend approximately $11 million in 2003 on such projects. The Utility expects that expenses will increase as remedial actions related to these sites are approved by regulatory agencies. In addition, approximately 68 other manufactured gas plants in the Utility's service territory are now owned by numerous third parties, and it is possible that the Utility may incur cleanup costs related to these sites in the future.
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 wastes from the Utility's facilities, or to pay for associated cleanup costs or natural resource damages. The Utility is currently aware of 8 such sites where investigation or cleanup activities are currently underway. For example, at the Geothermal Incorporated site in Lake County, California, the Utility has been directed to perform site studies and any necessary remedial measures by regulatory agencies. At the Casmalia disposal facility near Santa Maria, California, the Utility and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and mitigation measures.
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 Utility no longer owns or never owned.
The cost of hazardous substance 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. 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. At December 31, 2002, the Utility expected to spend $331 million, undiscounted for the effect of future inflation, for hazardous waste remediation costs at identified sites, including divested fossil-fuel fired power plants, where such costs are probable and quantifiable. (Although the Utility has sold most of its fossil-fuel fired power plants, the Utility has retained pre-closing environmental liability with respect to these plants.) If other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated, the Utility's future cost could be as much as $469 million. The Utility estimated the upper limit of the range of costs using assumptions least favorable to the Utility based upon a range of reasonably possible
outcomes. Costs may be higher if the Utility is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change.
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).
The California Attorney General, on behalf of various state environmental agencies, filed claims in the Utility's bankruptcy case for environmental remediation at numerous sites totaling approximately $770 million. For most if not all these sites, the Utility is in the process of remediating the sites in cooperation with the relevant agencies and others responsible for contributing to the cleanup or would be doing so in the future, in the normal course of business. The Utility's proposed plan of reorganization provides that either the Utility or the LLCs will satisfy these types of claims in the regular course of businesses, and since the Utility has not argued that the bankruptcy proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the 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 of 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 reserve in the amount of $6 million relating to its estimate of the remaining environmental expenditures to fulfill its obligations under these agreements.
Potential Recovery of Hazardous Waste Compliance 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 rates 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 rate 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.
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.
Under the Nuclear Waste Policy Act of 1982, or Nuclear Waste Act, 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 signed a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities beginning not later than January 1998. However, due to delays in identifying a storage site, the DOE has been unable to meet its contract 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 by 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, Yucca Mountain, Nevada as the site for a permanent spent fuel repository. The State of Nevada vetoed this 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 licensing of the site. If Yucca Mountain 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 which the DOE will begin to accept spent fuel for storage or disposal. If Yucca Mountain is completed by 2010, the earliest Diablo Canyon's spent fuel would be accepted by Yucca Mountain for storage or disposal would be 2018.
In July 1988, the NRC gave final approval to the Utility to store radioactive waste from the retired nuclear generating unit Humboldt 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 is 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., a wet storage pool. The specially designed storage pool is constructed of steel-reinforced concrete and lined with stainless steel. The Utility currently is exploring licensing and permitting of an on-site dry cask storage 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, it would receive a 20-year initial license with the opportunity to receive a 20-year renewal term.
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) 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 Commission license and release of the property for unrestricted use.
The estimated total obligation for nuclear decommissioning costs, based on a February 2002 site study, is $1.9 billion in 2002 dollars (or $8.4 billion in future dollars). The Utility's future estimate is based upon its 2001 estimated obligation assuming an annual escalation rate of 5.5% for decommissioning costs. This estimate includes labor, materials, waste disposal charges, and other costs. A contingency of 40% to capture engineering, regulatory, and business environment changes is included in the total estimated obligation. The Utility plans to fund these costs from independent decommissioning trusts, which receive annual contributions 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'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. The estimated total obligation is being recognized proportionately over the license term of each facility. At December 31, 2002, the total nuclear decommissioning obligation accrued was $1.3 billion.
Since January 1, 1998, nuclear decommissioning costs, which are not transition costs, have been recovered from customers through a non-bypassable 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.
Decommissioning costs recovered in rates are placed in external trust funds. These funds, along with accumulated earnings, will be used exclusively for decommissioning and dismantling 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. Monies may not be released from the external trusts until authorized by the CPUC. At December 31, 2002, the Utility had accumulated external trust funds with an estimated liquidation value of $1.3 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.
Compressor 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
Electric 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.
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 and upgraded utility facilities. California energy utilities were required to fund an EMF education program and an EMF research program managed by the California Department of Health Services. As part of its effort to educate the public about EMFs, the Utility provides interested customers with information regarding the EMF exposure issue. The Utility also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.
In October 2002, the California Department of Health Services released its report, based primarily on its review of studies by others, evaluating the possible risks from electric and magnetic fields to the CPUC and the public. The report's conclusions contrast with other recent reports by authoritative health agencies in that the California Department of Health 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.
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 relocation of existing power lines ultimately is required.
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 EMF from power lines. The Court 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 defendant 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' 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 of
$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.
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.
The Utility's corporate headquarters consist of approximately 1.7 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 electric and natural gas distribution facilities, natural gas gathering facilities, and generation facilities, all which are described above under "Electric Utility Operations" and "Gas Utility Operations." The Utility occupies or uses real property that it does not own chiefly through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities. The Utility also owns or leases approximately 184 other facilities, including service centers, customer service offices, material distribution centers, training/conference centers, and office space, totaling 5.9 million square feet in the aggregate.
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.
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 Company are subject to routine litigation incidental to their business.
Pacific Gas and Electric Company Bankruptcy
On April 6, 2001, Pacific Gas and Electric Company 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. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. For more information about the Utility's financial condition and the factors leading up to the filing for bankruptcy protection, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 2 of the 2002 Annual Report to Shareholders, which portions are incorporated herein by reference and filed 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 interfere 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 the 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 regulatory
accounting order. First, the Court held that, assuming the Bankruptcy Code provision imposing an automatic stay on pre-petition proceedings might ordinarily apply (an issue that 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, 2001 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, and the CPUC and its Commissioners cross-appealed. The appeals have been deemed related to, and therefore have been assigned to the same district court judge as, the appeals discussed below in the Utility's complaint filed against the CPUC Commissioners.
The Utility and PG&E Corporation have jointly proposed a proposed plan of reorganization, the Utility Plan, that proposes to restructure 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 description of the Utility 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, the Utility and PG&E Corporation on behalf of its subsidiaries ETrans, GTrans, and Gen, filed various applications with the FERC seeking approval to implement the transactions proposed under the Utility's Plan. For additional information about the proposed Plan and the 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.
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 Proponents 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 rulings in connection with the plan confirmation process.
On March 22, 2002, PG&E Corporation and the Utility filed a notice of appeal from the Bankruptcy Court's March 18, 2002 order. PG&E Corporation and the Utility elected to have the appeal heard by the United States District Court for the Northern District of California, or the District Court. In addition, the CPUC, the City and
County 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, the District Court issued an order rejecting these contentions.
On August 30, 2002, 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 the Bankruptcy Code expressly preempts "nonbankruptcy laws that would otherwise apply to bar, among other things, transactions necessary to implement the reorganization plan." The CPUC, the California Attorney General, the City and County of San Francisco, and the California Hydropower Reform Coalition filed an appeal with the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, and also filed a request with the District Court to stay its August 30, 2002 decision pending their appeal to the Ninth Circuit. On November 14, 2002, the District Court issued an order denying the request for a stay and certifiying its August 30, 2002 decision for discretionary review by the Ninth Circuit. The CPUC and the other appellants proceeded with an appeal to the Ninth Circuit, and briefing in the appeal is now closed. All appellants except 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 on December 9, 2002. On January 17, 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 asking the Ninth Circuit to expedite the appeal, which was granted in part on November 18, 2002, along with a statement that the appeal would be calendared as soon as is practicable.
In addition, the United States Department of Justice has filed an amicus 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 of amici 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 as amici); 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 the amicus 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 Court on April 15, 2002. After the Bankruptcy Court approved the disclosure statements relating to the Utility Plan 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, PG&E Corporation and the Utility filed a motion with 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 response in the Bankruptcy Court requesting that the exclusivity period be modified 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.
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. In
January 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.
The 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.
Pacific Gas and Electric Company vs. California Public Utilities Commissioners
On November 8, 2000, Pacific Gas and Electric Company filed a lawsuit in the U.S. District Court for the Northern District of California against the CPUC Commissioners, asking the court to declare that the federally tariffed wholesale power costs that the Utility had incurred to serve its 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 management
conference 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.
The Utility's complaint alleges that the wholesale power costs that the Utility has prudently incurred are paid pursuant to filed tariffs that the FERC has authorized and approved, and that under the U.S. Constitution and numerous court decisions, such costs cannot be disallowed by state regulators. The Utility's complaint also alleges that to the extent that the Utility is denied recovery of these wholesale power costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of the Utility's property. The Utility argues that the CPUC's decisions are preempted by federal law under the filed rate doctrine, which requires the CPUC to allow the Utility to recover in full its reasonable procurement costs incurred under lawful rates and tariffs approved by the FERC, a federal governmental agency. The complaint also pleads claims under the Commerce Clause, Due Process Clause, and Equal Protection Clause of the U.S. Constitution.
On 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 March 2001, the CPUC had already allowed the Utility 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 district
courts 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 entitled Jack 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 Utility was subsequently dismissed, due to its Chapter 11 bankruptcy filing. By order entered on or about May 31, 2001, the case was transferred to the U.S. District Court for the Northern District of California.
On August 9, 2001, plaintiff filed a first amended complaint entitled Jack Gillam, et al. vs. PG&E Corporation, Robert D. Glynn, Jr., and Peter A. Darbee, in the U.S. District Court for the Northern District of California. The first amended complaint, purportedly brought on behalf of 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, 2001, 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 dismiss 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 amended complaint in the District Court entitled Jack Gillam, et al. vs. PG&E Corporation, and Robert D. Glynn, Jr. In addition to containing many of the same allegations as were contained in the prior complaint, the complaint contains allegations similar to the allegations made in the California Attorney General's complaint against PG&E Corporation discussed below. On March 11, 2002, the defendants filed a motion to dismiss the second amended complaint. After a hearing on June 24, 2002, the 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, plaintiffs filed an appeal of the District Court's order with the United States Court of Appeals for the Ninth Circuit, advancing substantially the same arguments that the District Court had rejected previously. The defendants filed an answering brief on January 2, 2003, and anticipate that oral argument may occur as early as the fall of 2003.
PG&E Corporation believes the case is without merit and intends to present a vigorous defense. PG&E Corporation believes that the ultimate outcome of this litigation will not have a material adverse effect on PG&E Corporation's financial condition or results of operations.
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. Gyrnberg (called a relator in the parlance 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. The cases were consolidated for pretrial purposes in the U.S. District Court, for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998.
Under procedures established by the False Claims Act, the United States (acting through the 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.
The complaints allege that the various defendants (most of which are pipeline companies or their affiliates) incorrectly measured the volume and heating content of natural gas produced from federal or Indian leases. As a result, the relator alleges that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases.
The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties 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 connection with the litigation. The relator has filed a claim in the Utility's bankruptcy case for $2.48 billion, $2 billion of which is based upon the relator's calculation of penalties against the Utility.
PG&E Corporation and the Utility believe the allegations to be without merit and intend to present a vigorous defense.
PG&E Corporation and the Utility believe that the ultimate outcome of the litigation will not have a material adverse effect on their financial condition or results of operations.
Moss Landing Power Plant
In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water and organic debris from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System, or 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 and the Central Coast Board requested additional information from the purchaser. The Utility initiated an investigation of these activities during the time it owned the plant. The Utility notified the Central Coast Board that it had undertaken an investigation and that it would present the results to the Central Coast Board when the investigation was completed. In March 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 indicated 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 that the temperature of the discharged water was higher than that of the receiving water.
In December 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 under which the Utility would pay a total of $5 million to be used for environmental projects. No civil penalties would be paid under the settlement. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment and final approval by the Central Coast Board, and, once signed by the parties, will be incorporated into a consent decree to be entered in California Superior Court.
The California Attorney General has filed a proof of claim in the Bankruptcy Court on behalf of the Central Coast Board seeking unspecified penalties for alleged discharges of heated cooling water at Moss Landing.
PG&E Corporation and the Utility believe that 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.
Diablo Canyon Power Plant
On June 13, 2002, the Utility received a draft Enforcement Order from the California Department of Toxic Substances Control, or DTSC, alleging that the Diablo Canyon Power Plant, or Diablo Canyon, 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 deteriorated 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 seeks $340,000 in civil penalties for the period during which the Utility was unable to comply with the DTSC's requirements. The draft order also directs the Utility to maintain appropriate financial assurance on a going-forward basis. On September 4, 2002, the Utility received a draft Enforcement Order from DTSC alleging a variety of hazardous waste violations at Diablo Canyon. The violations were identified in an April 2001 inspection. The draft order seeks $24,330 in civil penalties. A tentative settlement has been reached with DTSC under which the Utility will pay approximately $165,000 in civil penalties and approximately $30,000 in costs. The final agreement, once signed by the parties, will be incorporated into 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 pending in the Los Angeles Superior Court, except the Monice case, still pending in San Bernardino County, and the Lytle 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 and Kearney, also name PG&E Corporation as a defendant. The Utility has not yet been served with the complaints in the Gale or Lytle 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 the Aguayo, Acosta, and Aguilar 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, the Chapter 11 case automatically stayed all proceedings.
On March 27, 2002, the seven plaintiffs in the Fordyce case served their lawsuit on PG&E. The plaintiffs have all filed timely proofs of claim in the bankruptcy case.
In the Adams case, 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, and the Utility is attempting to gather information concerning the alleged type and duration 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 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 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. The Utility Plan provides 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.
California 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 as Pier 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 the Pier 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,
2002, 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 the Pier 23 and Millar 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 the outcome of these matters will not have a material adverse affect on PG&E Corporation's financial condition or results of operations.
California Attorney General Complaint
On January 10, 2002, the California AG 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, or B&P, Code Section 17200. Among other allegations, the AG 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 AG 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 capital requirements condition (which it terms the "first priority condition") and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies "infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve." The three major California investor-owned energy utilities and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years' understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The three major California investor-owned
utilities and their parent holding companies appealed the CPUC's interpretation of the capital requirements condition to various state appellate courts. The CPUC moved to consolidate all proceedings in the San Francisco state appellate court. The CPUC's request for consolidation was granted and all the petitions are now before the First Appellate District in San Francisco, California.)
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 B&P Code section 17200, that the total penalty not 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'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 Court to transfer the AG's complaint to the Bankruptcy Court.
After removing the California AG's complaint to the Bankruptcy Court, on February 15, 2002, PG&E Corporation filed a motion to dismiss, or in the alternative, to stay, the California AG's complaint with the Bankruptcy Court. Subsequently, the California AG 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. On 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 Court held that federal law preempted the California AG's allegations concerning PG&E Corporation's participation in the Utility's bankruptcy proceedings. The Bankruptcy Court directed the California AG 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's June 20, 2002 order.
The appeal and cross-appeal are pending in the United States District Court for the Northern District of California.
On August 9, 2002, the California AG filed its amended complaint in the San Francisco Superior Court, omitting the allegations concerning PG&E Corporation's participation in the Utility's bankruptcy proceedings. PG&E Corporation and the directors named in the complaint have filed motions to strike certain allegations of the amended complaint. These motions are pending.
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.
Complaint filed by the City and County of San Francisco, and the People of the State of California
On February 11, 2002, a complaint entitled, City 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 AG's complaint including allegations of unfair competition in violation of B&P Code Section 17200. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation "took at least $5.2 billion from PG&E," 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 complaint seeks injunctive relief, the appointment of a receiver, restitution, 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.
After removing the City's action to the Bankruptcy Court on 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. On June 20, 2002, the Bankruptcy Court issued an Amended Order on Motion to Remand. (An initial order was issued
on June 2, 2002.) In its remand order, the 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, but remanded the Section 17200 cause of action to the San Francisco Superior Court. Both parties have appealed the Bankruptcy Court's remand order. The appeal and cross-appeal are pending in the United States District Court for the Northern District of California.
Following remand, PG&E Corporation brought a motion to strike. This motion is pending. PG&E Corporation also moved to coordinate this 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.
Cynthia Behr v. PG&E Corporation, et al.
On February 14, 2002, this complaint was filed by a private plaintiff 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 allegations of the complaint are similar to the allegations contained in the Attorney General's complaint but also include allegations of fraudulent transfer and violation of the California bulk sales laws. Plaintiff requests the same remedies as the Attorney General's case and in addition requests damages, attachment, and restraints upon the transfer of defendants' property. On 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.
In its June 2002 ruling referred to above as to the Attorney General's case, the bankruptcy court retained jurisdiction over Behr's fraudulent transfer claim and bulk sales claim, finding them to belong to the Utility's estate. The bankruptcy court remanded Behr's Section 17200 claim to the Santa Clara Superior Court. Both parties have appealed the bankruptcy court's remand order. The appeal and cross-appeal are pending in the United States District Court for the Northern District of California.
Following remand, PG&E Corporation moved to have the Behr case coordinated with the City's case described above. That motion was granted, and the Behr case will now proceed in San Francisco Superior Court.
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.
William Ahern, et al. v. Pacific Gas and Electric Company
On February 27, 2002, a group of 25 ratepayers filed a complaint against the Utility at the CPUC demanding an immediate reduction of approximately 3.5 cents per kWh in allegedly excessive electric rates and a refund of alleged recent overcollections in electric revenue since June 1, 2001. The complaint claims that electric rate surcharges adopted in the first quarter of 2001 due to 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 assumed to be true, do not establish that currently authorized electric rates are not reasonable. On May 10, 2002 the Utility filed a motion to dismiss the complaint. The CPUC has not yet issued a decision.
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.
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 he
characterized 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.
ITEM 4.
ITEM 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANTS
"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 Corporation are as follows:
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.
"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 Company are as follows:
All officers of Pacific Gas and Electric Company serve at the pleasure of the Board of Directors. During the past five years, the executive officers of Pacific Gas and Electric Company had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.
PART II
ITEM 5.
ITEM 5. Market for the Registrant's Common Equity and Related Stockholder Matters.
Information responding to part of Item 5, for each of PG&E Corporation and Pacific Gas and Electric Company, is set forth on page 173 under the heading "Quarterly Consolidated Financial Data (Unaudited)" in the 2002 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, there were 117,812 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's common stock is hereby incorporated by reference from "Management's Discussion and Analysis of Financial Condition and Results of Operations-Dividends" on page 34 of the 2002 Annual Report to Shareholders.
On June 25, 2002, PG&E Corporation issued 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, including a warrant exercise price of $0.01 per share, are substantially identical to the warrants issued on June 25, 2002. The issuance of the warrants by PG&E Corporation was not registered under the Securities Act of 1933 in reliance on the exemption afforded by Section 4(2).
Also, on June 25, 2002, PG&E Corporation issued $280 million aggregate principal amount of 7.50% Convertible Subordinated Notes due June 30, 2007. On October 18, 2002, the notes and the related indenture were amended to delete certain cross-default provisions, to increase the interest rate on the notes to 9.50% from 7.50%, to extend 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 equal 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 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 shares 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 interest in the outstanding common stock of PG&E Corporation's subsidiary, the Utility, and all proceeds thereof. With respect 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.
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 to
approximately .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).
Pacific Gas and Electric Company did not make any sales of unregistered equity securities during 2002, the period covered by this report.
ITEM 6.
ITEM 6. Selected Financial Data.
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 on page 2 under the heading "Selected Financial Data" in the 2002 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.
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
A discussion of PG&E Corporation's and Pacific Gas and Electric Company's consolidated results of operations and financial condition is set forth on pages 3 through 70 under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the 2002 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.
Information responding to Item 7A appears in the 2002 Annual Report to Shareholders on pages 57-65 under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations-Risk Management Activities," and on pages 95-96 and 134 under Notes 1, 4, 9, and 11 of the "Notes to the Consolidated Financial Statements" of the 2002 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.
Information responding to Item 8 appears on pages 71 through 80 of the 2002 Annual Report to Shareholders under the following headings for PG&E Corporation: "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Common Stockholders' Equity;" under the following headings for Pacific Gas and Electric Company: "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Stockholders' Equity;" and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: "Notes to the Consolidated Financial Statements," "Quarterly Consolidated Financial Data (Unaudited)," "Independent Auditors' Report," and "Responsibility for the Consolidated Financial Statements," 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.
Not applicable.
PART III
ITEM 10.
ITEM 10. Directors and Executive Officers of the Registrant.
Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included in a separate item captioned "Executive Officers of the Registrants" contained on pages 72 through 75 in Part I of this report. Other information responding to Item 10 is included under the heading "Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company" and under the heading "Section 16 Beneficial Ownership Reporting Compliance" in the Joint Proxy Statement relating to the 2003 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 11.
ITEM 11. Executive Compensation.
Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Compensation 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 "Termination 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.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.
Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Security Ownership of Management" and under the heading "Principal Shareholders" in the Joint Proxy Statement relating to the 2003 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Equity Compensation Plan Information
The following table provides information as of December 31, 2002, concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation's existing equity compensation plans.
(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. ITEM 13.
ITEM 13. Certain Relationships and Related Transactions.
Information responding to Item 13, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Certain Relationships and Related Transactions" in the Joint Proxy Statement relating to the 2003 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
ITEM 14.
ITEM 14. Controls and Procedures.
Based on an evaluation of PG&E Corporation's and the Utility's disclosure controls and procedures conducted on February 7, 2003 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 required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.
There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.
ITEM 15.
ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a)The following documents are filed as a part of this report:
1.The following consolidated financial statements, supplemental information, and independent auditors' report are contained in the 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.
Consolidated Statements of Common Stockholders' Equity for the Years Ended December 31, 2002, 2001, and 2000, for PG&E Corporation.
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2002, 2001, and 2000 for Pacific Gas and Electric Company.
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-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:
3.1
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 19, 2003
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 19, 2003
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)
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
10.2
Second 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)
10.3.1
Utility 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)
10.3.2
Utility 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)
10.3.3
Utility 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)
10.3.4
Utility 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)
10.4
Amended 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 10.3
10.5
Second 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)
10.6
Credit 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 Agent
10.7
First 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 Agent
10.8
Guarantee 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 Agent
10.9
Amended 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 parties
10.10
Amended 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 Agent
10.11
Acknowledgement 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 thereto
10.12
Waiver 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.
10.13
Third 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.
10.14
Fourth 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)
10.15
Second 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)
10.16
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 (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)
10.17
Guarantee 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 Agent
10.18
Second 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)
10.19
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 (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)
10.20
Amendment, 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
10.21
Guarantee 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
*10.22
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)
*10.23
Agreement and Release between PG&E Corporation and Thomas G. Boren, dated December 18, 2002
*10.24
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)
*10.25
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)
*10.26
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)
*10.27
Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)
*10.28
Description of Relocation Arrangement Between PG&E Corporation and Lyn E. Maddox (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.9)
*10.29
PG&E Corporation Senior Executive Officer Retention Program approved December 20, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10)
*10.30.1
Letter regarding retention award to Robert D. Glynn, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.1)
*10.30.2
Letter regarding retention award to Gordon R. Smith dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.2)
*10.30.3
Letter regarding retention award to Peter A. Darbee dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.3)
*10.30.4
Letter regarding retention award to Bruce R. Worthington dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.4)
*10.30.5
Letter regarding retention award to G. Brent Stanley dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.5)
*10.30.6
Letter regarding retention award to Daniel D. Richard, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.6)
*10.30.7
Letter regarding retention award to James K. Randolph dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.7)
*10.30.8
Letter regarding retention award to Gregory M. Rueger dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.8)
*10.30.9
Letter regarding retention award to Kent M. Harvey dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.9)
*10.30.10
Letter regarding retention award to Roger J. Peters dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.10))
*10.30.11
Letter regarding retention award to Lyn E. Maddox dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.12)
*10.30.12
Letter regarding retention award to P. Chrisman Iribe dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.13)
*10.30.13
Letter regarding retention award to Thomas B. King dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.14)
*10.31
Pacific Gas and Electric Company Management Retention Program (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.1)
*10.32
PG&E Corporation Management Retention Program (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.2)
*10.33
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's Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
*10.34
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.25)
*10.35
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2003.
*10.36
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's Form 10-K for the year ended December 31, 2001 (File No. 1-2248), Exhibit 10.16)
*10.37.1
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002
*10.37.2
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002
*10.37.3
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002
*10.37.4
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002
*10.37.5
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated December 20, 2002
*10.37.6
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Thomas G. Boren dated December 20, 2002
*10.38
Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
*10.39
Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
*10.40
PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 1997 (File No. 1-12609), Exhibit 10.13)
*10.41
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's Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
*10.42
PG&E Corporation Executive Stock Ownership Program, amended as of September 19, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.20)
*10.43
PG&E Corporation Officer Severance Policy, amended as of December 19, 2001
*10.44
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)
*10.45
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)
*10.46
PG&E Corporation Form of Restricted Stock Award Agreement granted under the PG&E Corporation Long-Term Incentive Program
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
The 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)"
Subsidiaries of the Registrant
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
99.1
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
99.2
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 plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K. The 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)Reports on Form 8-K Reports on Form 8-K(1) during the quarter ended December 31, 2002, and through the date hereof:
8.
January 6, 2003
Item 5. Other Events
A.
Resumption of Power Procurement
B.
Pacific Gas and Electric Company bankruptcy: Monthly Operating Report
C.
General Rate Case 2003
D.
Pacific Gas and Electric Company bankruptcy: Monthly Operating Report
Item 7. Financial Statements, Pro Forma, Financial Information, and Exhibits
Exhibit 99.1-Pacific Gas and Electric Company Income Statement for the month ended November 30, 2002, and Balance Sheet dated November 30, 2002
9.
January 16, 2003
Item 5. Other Events
PG&E Corporation and PG&E National Energy Group, Inc.
Item 7. Financial Statements, Pro Forma, Financial Information, and Exhibits
Exhibit 99.1-Fourth 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.
Exhibit 99.2-Second 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.
Exhibit 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
Exhibit 99.4-Second 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.
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
(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).
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized, in the City and County of San Francisco, on the 27th day of February, 2003.
PG&E CORPORATION
(Registrant)
PACIFIC GAS AND ELECTRIC COMPANY
(Registrant)
By
GARY P. ENCINAS (Gary P. Encinas, Attorney-in-Fact)
By
GARY P. ENCINAS (Gary P. Encinas, Attorney-in-Fact)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.
Signature
Title
Date
A. Principal Executive Officers
*ROBERT D. GLYNN, JR.
Chairman of the Board, Chief Executive Officer, and President (PG&E Corporation)
February 27, 2003
*GORDON R. SMITH
President and Chief Executive Officer (Pacific Gas and Electric Company)
February 27, 2003
B. Principal Financial Officers
*PETER A. DARBEE
Senior Vice President and Chief Financial Officer (PG&E Corporation)
February 27, 2003
*KENT M. HARVEY
Senior Vice President, Chief Financial Officer, and Treasurer (Pacific Gas and Electric Company)
February 27, 2003
C. Principal Accounting Officers
*CHRISTOPHER P. JOHNS
Senior Vice President and Controller (PG&E Corporation)
February 27, 2003
*DINYAR B. MISTRY
Vice President-Controller (Pacific Gas and Electric Company)
February 27, 2003
D. Directors
*DAVID R. ANDREWS
*DAVID A. COULTER
*C. LEE COX
*WILLIAM S. DAVILA
*ROBERT D. GLYNN, JR.
*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, 2003
*By
GARY P. ENCINAS Gary P. Encinas, Attorney-in-Fact
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 President
PG&E Corporation
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
PETER A. DARBEE PETER A. DARBEE
Senior Vice President and Chief Financial Officer
PG&E Corporation
I, Gordon R. Smith, 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, 2003
GORDON R. SMITH GORDON R. SMITH
President and Chief Executive Officer
Pacific Gas and Electric Company
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, 2003
KENT M. HARVEY KENT M. HARVEY
Senior Vice President, Chief Financial Officer, and Treasurer
Pacific Gas and Electric Company
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Boards of Directors of
PG&E Corporation and Pacific Gas and Electric Company
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 as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002 and have issued our report thereon dated February 24, 2003, which report 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 method to the net method and retroactive reclassification of the consolidated 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. Such consolidated financial statements are included in the combined 2002 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 financial statements of PG&E Corporation and Pacific Gas and Electric Company taken as a whole, present fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
San Francisco, California
February 24, 2003
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF PARENT-(Continued)
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2002, 2001, and 2000
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2002, 2001, and 2000
PG&E CORPORATION
SCHEDULE II-CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2002, 2001, and 2000
(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."
PACIFIC GAS AND ELECTRIC COMPANY
A DEBTOR-IN-POSSESSION
SCHEDULE II-CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2002, 2001, and 2000
(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."
EXHIBIT INDEX
Exhibit
Number
Exhibit Description
3.1
Restated Articles of Incorporation of PG&E Corporation effective as of May 5, 2000 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 3.1)
3.2
Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3
Bylaws of PG&E Corporation amended as of February 19, 2003
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 19, 2003
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)
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
10.2
Second 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)
10.3.1
Utility 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)
10.3.2
Utility 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)
10.3.3
Utility 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)
10.3.4
Utility 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)
10.4
Amended 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 10.3
10.5
Second 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)
10.6
Credit 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 Agent
10.7
First 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 Agent
10.8
Guarantee 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 Agent
10.9
Amended 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 parties
10.10
Amended 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 Agent
10.11
Acknowledgement 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 thereto
10.12
Waiver 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.
10.13
Third 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.
10.14
Fourth 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)
10.15
Second 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)
10.16
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 (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)
10.17
Guarantee 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 Agent
10.18
Second 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)
10.19
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 (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)
10.20
Amendment, 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.
10.21
Guarantee 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
*10.22
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)
*10.23
Agreement and Release between PG&E Corporation and Thomas G. Boren, dated December 18, 2002
*10.24
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)
*10.25
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)
*10.26
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)
*10.27
Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)
*10.28
Description of Relocation Arrangement Between PG&E Corporation and Lyn E. Maddox (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.9)
*10.29
PG&E Corporation Senior Executive Officer Retention Program approved December 20, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10)
*10.30.1
Letter regarding retention award to Robert D. Glynn, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.1)
*10.30.2
Letter regarding retention award to Gordon R. Smith dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.2)
*10.30.3
Letter regarding retention award to Peter A. Darbee dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.3)
*10.30.4
Letter regarding retention award to Bruce R. Worthington dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.4)
*10.30.5
Letter regarding retention award to G. Brent Stanley dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.5)
*10.30.6
Letter regarding retention award to Daniel D. Richard, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.6)
*10.30.7
Letter regarding retention award to James K. Randolph dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.7)
*10.30.8
Letter regarding retention award to Gregory M. Rueger dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.8)
*10.30.9
Letter regarding retention award to Kent M. Harvey dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.9)
*10.30.10
Letter regarding retention award to Roger J. Peters dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.10))
*10.30.11
Letter regarding retention award to Lyn E. Maddox dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.12)
*10.30.12
Letter regarding retention award to P. Chrisman Iribe dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.13)
*10.30.13
Letter regarding retention award to Thomas B. King dated February 27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.14)
*10.31
Pacific Gas and Electric Company Management Retention Program (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.1)
*10.32
PG&E Corporation Management Retention Program (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.2)
*10.33
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's Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
*10.34
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.25)
*10.35
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2003.
*10.36
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's Form 10-K for the year ended December 31, 2001 (File No. 1-2248), Exhibit 10.16)
*10.37.1
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002
*10.37.2
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002
*10.37.3
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002
*10.37.4
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002
*10.37.5
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated December 20, 2002
*10.37.6
Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Thomas G. Boren dated December 20, 2002
*10.38
Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
*10.39
Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
*10.40
PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 1997 (File No. 1-12609), Exhibit 10.13)
*10.41
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's Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
*10.42
PG&E Corporation Executive Stock Ownership Program, amended as of September 19, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.20)
*10.43
PG&E Corporation Officer Severance Policy, amended as of December 19, 2001
*10.44
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)
*10.45
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)
*10.46
PG&E Corporation Form of Restricted Stock Award Agreement granted under the PG&E Corporation Long-Term Incentive Program
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
The 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)"
Subsidiaries of the Registrant
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
99.1
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
99.2
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
GLOSSARY OF TERMS
PART I
GENERAL
REGULATION
COMPETITION
UTILITY OPERATIONS
PG&E NATIONAL ENERGY GROUP, INC.
ENVIRONMENTAL MATTERS
EXECUTIVE OFFICERS OF THE REGISTRANTS
PART II
PART III
Equity Compensation Plan Information
SIGNATURES
INDEPENDENT AUDITORS' REPORT
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED BALANCE SHEETS
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF PARENT-(Continued) CONDENSED STATEMENTS OF INCOME For the Years Ended December 31, 2002, 2001, and 2000
CONDENSED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002, 2001, and 2000
PG&E CORPORATION SCHEDULE II-CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2002, 2001, and 2000
PACIFIC GAS AND ELECTRIC COMPANY A DEBTOR-IN-POSSESSION SCHEDULE II-CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2002, 2001, and 2000
EXHIBIT INDEX