-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Gz67b6y64Dnv8g8twAdPGvjuox/WeMBPSQoqD3GltsvflNPKe3Jrnvy3pro7W5zd Q/h7hAzAlu+eh9+iMeIBnA== 0000929624-99-000404.txt : 19990310 0000929624-99-000404.hdr.sgml : 19990310 ACCESSION NUMBER: 0000929624-99-000404 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 20 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990309 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PG&E CORP CENTRAL INDEX KEY: 0001004980 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 943234914 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-12609 FILM NUMBER: 99561106 BUSINESS ADDRESS: STREET 1: ONE MARKET SPEAR TOWER STREET 2: SUITE 2400 CITY: SAN FRANCISCO STATE: CA ZIP: 94105 BUSINESS PHONE: 4152677000 MAIL ADDRESS: STREET 1: ONE MARKET SPEAR TOWER STREET 2: SUITE 2400 CITY: SAN FRANCISCO STATE: CA ZIP: 94105 FORMER COMPANY: FORMER CONFORMED NAME: PG&E PARENT CO INC DATE OF NAME CHANGE: 19951214 10-K405 1 FORM 10-K -- PG&E CORPORATION SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 1998 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to
Commission Exact Name of Registrant IRS Employer File as specified in its State of Identification Number charter Incorporation Number ---------- ------------------------ ------------- -------------- 1-12609 PG&E CORPORATION California 94-3234914 1-2348 PACIFIC GAS AND ELECTRIC California 94-0742640 COMPANY
Pacific Gas and Electric Company PG&E Corporation 77 Beale Street One Market, Spear Tower P.O. Box 770000 Suite 2400 San Francisco, California San Francisco, California (Address of principal executive (Address of principal executive offices) offices) 94105 (Zip Code) 94177 (Zip Code) (415) 267-7000 (Registrant's telephone number, (415) 973-7000 including area code) (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on Title of Each Class Which Registered - ------------------- --------------------------- PG&E Corporation Common Stock, no par value New York Stock Exchange and Pacific Exchange Pacific Gas and Electric Company First Preferred Stock, cumulative, American Stock Exchange and par value $25 per share: Pacific Exchange
Redeemable: 7.04%, 5% Series A, 5%, 4.80%, 4.50%, 4.36%. Mandatorily Redeemable: 6.57%, 6.30% Nonredeemable: 6%, 5.50%, 5% 7.90% Cumulative Quarterly Income Preferred American Stock Exchange and Securities, Series A (liquidation preference Pacific Exchange $25), issued by PG&E Capital I and guaranteed by Pacific Gas and Electric Company
Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Aggregate market value of the voting stock held by non-affiliates of the registrant as of February 22, 1999: PG&E Corporation Common Stock $11,810 million Pacific Gas and Electric Company First Preferred Stock $422 million Common Stock outstanding as of February 22, 1999: PG&E Corporation: 382,964,605 Pacific Gas and Electric Company: Wholly owned by PG&E Corporation The market values of certain series of First Preferred Stock, for which market prices as of a date within 60 days prior to the date of filing were not available, were derived by dividing the annual dividend rate of each such series of stock by the average yield of all of Pacific Gas and Electric Company's Preferred Stock outstanding for which market prices were available. DOCUMENTS INCORPORATED BY REFERENCE Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved. (1) Designated portions of the combined Annual Report to Shareholders for the year ended December 31, 1998................... Part II (Items 5, 6, 7.7A and 8) Part IV (Item 14) (2) Designated portions of the Joint Proxy Statement relating to the 1999 Annual Meetings of Shareholders.................. Part III (Items 10, 11, 12 and 13)
TABLE OF CONTENTS
Page ---- Glossary of Terms PART I Item 1. Business......................................................... 1 GENERAL.......................................................... 1 Corporate Structure and Business................................. 1 Competition and the Changing Regulatory Environment.............. 3 Electric Industry................................................ 3 Gas Industry..................................................... 4 Regulation of Pacific Gas and Electric Company................... 5 State Regulation................................................. 5 Federal Regulation............................................... 6 Licenses and Permits............................................. 6 Regulation of PG&E Corporation and Other Subsidiaries............ 6 PG&E Corporation................................................. 6 Wholesale Operations of Affiliates............................... 7 Capital Requirements and Financing Programs...................... 9 Price Risk Management Programs................................... 10 Year 2000 Matters................................................ 10 UTILITY OPERATIONS............................................... 11 California Ratemaking Mechanisms................................. 11 Electric Ratemaking.............................................. 12 Gas Ratemaking................................................... 13 Electric Utility Operations...................................... 14 Implementation of Electric Industry Restructuring................ 14 Independent System Operator and Power Exchange................... 14 Voluntary Generation Asset Divestiture........................... 15 Direct Access.................................................... 16 Electric Base Revenue Increase................................... 16 Rate Levels and Rate Reduction Bonds............................. 17 Recovery of Transition Costs..................................... 17 Public Purpose Programs.......................................... 18 Electric Operating Statistics.................................... 19 Electric Generating Capacity..................................... 20 Diablo Canyon.................................................... 21 Diablo Canyon Operations......................................... 21 Diablo Canyon Ratemaking......................................... 21 Nuclear Fuel Supply and Disposal................................. 22 Insurance........................................................ 23 Decommissioning.................................................. 23 Other Electric Resources......................................... 24 QF Generation and Other Power-Purchase Contracts................. 24 Geothermal Generation............................................ 25 Electric Transmission and Distribution........................... 25 Gas Utility Operations........................................... 26 Gas Operating Statistics......................................... 27 Natural Gas Supplies............................................. 28 Gas Regulatory Framework......................................... 28
i TABLE OF CONTENTS--(Continued)
Page ---- Transportation Commitments.................................... 29 Core Procurement Incentive Mechanism.......................... 30 PGT/Pacific Gas and Electric Company Pipeline Expansion....... 30 WHOLESALE OPERATIONS OF AFFILIATES............................ 31 Gas Transmission Operations................................... 31 Independent Power Generation.................................. 31 Portfolio of Operating Generating Plants...................... 34 Energy Trading................................................ 35 RETAIL OPERATIONS OF AFFILIATES............................... 35 Energy Services............................................... 35 ENVIRONMENTAL MATTERS......................................... 36 Environmental Matters......................................... 36 Environmental Protection Measures............................. 36 Air Quality................................................... 36 Water Quality................................................. 37 Hazardous Waste Compliance and Remediation.................... 38 Potential Recovery of Hazardous Waste Compliance and Remediation Costs............................................. 39 Compressor Station Litigation................................. 40 Electric and Magnetic Fields.................................. 40 Low Emission Vehicle Programs................................. 41 Item 2. Properties.................................................... 41 Item 3. Legal Proceedings............................................. 41 Compressor Station Chromium Litigation........................ 41 Texas Franchise Fee Litigation................................ 42 Item 4. Submission of Matters to a Vote of Security Holders........... 44 EXECUTIVE OFFICERS OF THE REGISTRANTS......................... 45 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters........................................... 48 Item 6. Selected Financial Data....................................... 48 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations..................................... 48 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.... 48 Item 8. Financial Statements and Supplementary Data................... 49 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...................................... 49 PART III Item 10. Directors and Executive Officers of the Registrant............ 49 Item 11. Executive Compensation........................................ 49 Item 12. Security Ownership of Certain Beneficial Owners and Management.................................................... 49 Item 13. Certain Relationships and Related Transactions................ 49 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................................................... 50 Signatures.................................................... 54 Report of Independent Public Accountants...................... 55
ii GLOSSARY OF TERMS AB 1890........... Assembly Bill 1890, the California electric industry restructuring legislation AEAP.............. Annual Earnings Assessment Proceeding AER............... Annual Energy Rate AFUDC............. allowance for funds used during construction ALJ............... Administrative Law Judge ATCP.............. Annual Transition Cost Proceeding Betz.............. Betz Laboratories, Inc. and affiliated entities BCAP.............. Biennial Cost Allocation Proceeding bcf............... billion cubic feet BRPU.............. Biennial Resource Plan Update BTA............... best technology available Btu............... British thermal unit CARE.............. California Alternate Rates for Energy CCAA.............. California Clean Air Act CEC............... California Energy Commission CEMA.............. Catastrophic Emergency Memorandum Account Central Coast Board............ Central Coast Regional Water Quality Control Board CERCLA............ Comprehensive Environmental Response, Compensation, and Liability Act Company........... Pacific Gas and Electric Company and its subsidiaries core customers.... residential and smaller commercial gas customers core subscription customers........ noncore customers who choose bundled service CPIM.............. core procurement incentive mechanism CPUC.............. California Public Utilities Commission CTC............... competition transition charge Diablo Canyon..... Diablo Canyon Nuclear Power Plant DOE............... United States Department of Energy DSM............... demand side management EDRA.............. Electric Deferred Refund Account El Paso........... El Paso Natural Gas Company EMF............... electric and magnetic fields EPA............... United States Environmental Protection Agency FERC.............. Federal Energy Regulatory Commission Gas Accord........ Gas Accord Settlement Geysers........... The Geysers Power Plant GRC............... General Rate Case HCP............... Habitat Conservation Plan Helms............. Helms hydroelectric pumped storage plant Holding Company Act.............. Public Utility Holding Company Act of 1935 Humboldt.......... Humboldt Bay Power Plant HWRC.............. hazardous waste remediation costs ICIP.............. Incremental Cost Incentive Price IPP............... Independent power producer ISO............... Independent System Operator ITCBA............. Interim Transition Cost Balancing Account ITCS.............. Interstate Transition Cost Surcharge kV................ kilovolts kVa............... kilovolt-amperes
kW................ kilowatts kWh............... kilowatt-hour LEV............... low emission vehicle Mcf............... thousand cubic feet MMcf.............. million cubic feet MMcf/d............ million cubic feet per day MW................ megawatts MWh............... megawatt-hour NEES.............. New England Electric System NEIL.............. Nuclear Electric Insurance Limited NGL............... natural gas liquids noncore customers........ industrial and larger commercial gas customers NOx............... oxides of nitrogen NRC............... Nuclear Regulatory Commission Nuclear Waste Act.............. Nuclear Waste Policy Act of 1982 ORA............... Office of Ratepayer Advocates, a division of the California Public Utilities Commission PBR............... performance-based ratemaking PG&E Expansion.... the Pacific Gas and Electric Company portion of the Pipeline Expansion PG&E ES........... PG&E Corporation's energy services operations, PG&E Energy Services or PG&E ES PG&E GT........... PG&E Corporation's gas transmission operations, PG&E Gas Transmission or PG&E GT PG&E GTT.......... PG&E Gas Transmission, Texas Corporation PG&E ET........... PG&E Corporation's energy commodities activities, PG&E Energy Trading or PG&E ET PGT Expansion..... Pacific Gas Transmission Company (now known as PG&E Gas Transmission, Northwest Corporation) portion of the Pipeline Expansion Pipeline Expansion........ PGT/Pacific Gas and Electric Company Pipeline Expansion PPPs.............. public purpose programs PRP............... potentially responsible party PX................ California Power Exchange QF................ qualifying facility RAP............... Revenue Adjustment Proceeding RRC............... The Railroad Commission of Texas SEC............... Securities and Exchange Commission SOS............... Standard Offer Service Teco.............. Teco Pipeline Company TRA............... Transition Revenue Account transition the period during which electric rates are frozen at 1996 period........... levels, which extends until the earlier of March 31, 2002 or the point in time when Pacific Gas and Electric Company has recovered its transition costs Transwestern...... Transwestern Pipeline Company USGen............. U.S. Generating Company, LLC and its affiliates USGenNE........... USGen New England, Inc. USOSC............. U.S. Operating Services Company Valero............ Valero Energy Corporation
PART I ITEM 1. Business. GENERAL Corporate Structure and Business PG&E Corporation is a holding company based in San Francisco, California, which provides energy services throughout North America. Effective January 1, 1997, Pacific Gas and Electric Company (sometimes referred to herein as the "Company") and its subsidiaries became subsidiaries of PG&E Corporation, which was incorporated in 1995. Pacific Gas and Electric Company, incorporated in California in 1905, is an operating public utility primarily regulated by the California Public Utilities Commission (CPUC) and engaged principally in the business of providing electric and natural gas services throughout most of Northern and Central California. In the holding company reorganization, Pacific Gas and Electric Company's outstanding common stock was converted on a share-for-share basis into PG&E Corporation common stock. Pacific Gas and Electric Company's debt securities and preferred stock were unaffected and remain securities of Pacific Gas and Electric Company. The consolidated financial statements of PG&E Corporation incorporated herein include the accounts of PG&E Corporation and its wholly owned and controlled subsidiaries (collectively, PG&E Corporation). The consolidated financial statements of Pacific Gas and Electric Company incorporated herein include the accounts of Pacific Gas and Electric Company and its wholly owned and controlled subsidiaries. Because PG&E Corporation did not become the holding company for Pacific Gas and Electric Company until January 1, 1997, the 1996 consolidated financial statements represent the accounts of Pacific Gas and Electric Company on a consolidated basis as predecessor of PG&E Corporation. The principal executive offices of PG&E Corporation are located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive offices of Pacific Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. As of December 31, 1998, PG&E Corporation had $33.2 billion in assets. PG&E Corporation generated $19.9 billion in operating revenues for 1998. As of December 31, 1998, PG&E Corporation and its subsidiaries and affiliates had approximately 23,300 employees. As of December 31, 1998, Pacific Gas and Electric Company had $23 billion in assets. The Company generated $8.9 billion in operating revenues for 1998. As of December 31, 1998, Pacific Gas and Electric Company had approximately 19,800 employees. In addition to the regulated utility business of Pacific Gas and Electric Company, PG&E Corporation's other affiliated businesses include the ownership and operation of natural gas pipelines, natural gas storage facilities, and natural gas processing plants, primarily in the Pacific Northwest and Texas, through various subsidiaries of PG&E Corporation (PG&E Gas Transmission or PG&E GT); the development, construction, operation, ownership, and management of independent power generation facilities through U.S. Generating Company, LLC and its affiliates (USGen); the purchase and sale of energy commodities and financial instruments to PG&E Corporation's other businesses, unaffiliated utilities, marketers, municipalities, cooperatives, independent power producers, and large end-use customers through PG&E Energy Trading Corporation and its affiliates (PG&E Energy Trading or PG&E ET); and the provision to customers nationwide with competitively priced natural gas and electricity and services to manage and make more efficient their energy consumption through PG&E Energy Services Corporation (PG&E Energy Services or PG&E ES). On September 1, 1998, PG&E Corporation, through its indirect subsidiary, USGen New England, Inc. (USGenNE), completed the acquisition of a portfolio of electric generating assets and power supply contracts from the New England Electric System (NEES) for approximately $1.59 billion plus $85 million for certain employee-related costs. See "Wholesale Operations of Affiliates-- Independent Power Generation" below. 1 The gas and electric utility operations of Pacific Gas and Electric Company represent the principal component of PG&E Corporation's business, contributing 45% of PG&E Corporation's total revenues in 1998. Pacific Gas and Electric Company's utility operations contributed $1.82 of PG&E Corporation's total 1998 earnings per share of $1.88. Pacific Gas and Electric Company's utility service territory covers 70,000 square miles with an estimated population of approximately 13 million and includes all or portions of 48 of California's 58 counties. The area's diverse economy includes aerospace, electronics, financial services, food processing, petroleum refining, agriculture, and tourism. At December 31, 1998, Pacific Gas and Electric Company served approximately 4.6 million electric customers. In 1998, Pacific Gas and Electric Company served its electric customers with power generated by seven primarily natural gas-fueled steam power plants with 21 units, ten combustion turbines, two nuclear power reactor units at Diablo Canyon Nuclear Power Plant (Diablo Canyon), 68 hydroelectric powerhouses with 109 units, the Helms hydroelectric pumped storage plant (Helms) with three units, and a geothermal energy complex of 14 units. (In connection with the ongoing California electric industry restructuring, on July 1, 1998, the Company sold three fossil-fueled power plants which included six steam units and three combustion turbines. In late 1998 and in January 1999, the Company entered into agreements to sell three of its five remaining fossil-fueled power plants, which include 10 steam units and three combustion turbines, and its geothermal facilities. The sales are expected to be completed in 1999. See "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring" below.) The Company also purchases power produced by other generating entities that use a wide array of resources and technologies, including hydroelectric, wind, solar, biomass, geothermal, and cogeneration. In addition, the Company is interconnected with electric power systems in 14 western states and British Columbia, Canada, for the purposes of buying, selling, and transmitting power. Pacific Gas and Electric Company served approximately 3.8 million gas customers at December 31, 1998. Most of these customers continue to obtain gas supplies from the Company under regulated tariff rates. To ensure a diverse and competitive mix of natural gas supplies to serve customers that choose the Company as its supplier, the Company directly purchases gas from producers and marketers in both Canada and the United States. In 1998, about 68% of the Company's gas supply was purchased in Canada, about 4% was purchased in California, and about 28% was purchased in the U.S. Southwest. In 1998, California became one of the first states in the nation to implement an electric industry restructuring plan. (The framework of this plan was established by Assembly Bill 1890 (AB 1890) passed by the California Legislature and signed by the Governor in 1996.) In California, electric customers may choose to purchase their electricity from investor-owned utilities (such as Pacific Gas and Electric Company), unregulated retail electricity providers (such as marketers, including PG&E Energy Services, brokers, and aggregators), or unregulated power generators, on a competitive basis (i.e., "direct access"). The California restructuring plan contemplates that the investor-owned utilities (such as Pacific Gas and Electric Company) will continue to provide distribution services to substantially all customers within their service territories. In November 1998, the California voters defeated Proposition 9, a voter initiative which would have overturned major portions of AB 1890 if it had been approved. See "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring" below. The following information includes forward-looking statements about the future that involve a number of risks and uncertainties. Words such as "estimates," "expects," "intends," "anticipates," and "plans," and similar expressions identify those statements which are forward-looking. These forward-looking statements are based on management's beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. Some of the factors that could cause actual results to differ materially from those contemplated in the forward-looking statements include, but are not limited to, the pace and extent of the ongoing restructuring of the electric and gas industries across the United States; the outcome of regulatory and legislative proceedings and operational changes related to industry restructuring; any changes in the amount Pacific Gas and Electric Company is allowed to collect 2 (recover) from its customers for certain costs which prove to be uneconomic under the new competitive market (called transition costs) in accordance with the Company's plan for recovering those costs; the successful integration and performance of recently acquired assets; the Corporation's ability to successfully compete outside of the traditional regulated markets; the ability to lessen the risk of the impact of the Year 2000 on internal and external computer and software systems; the outcome of ongoing regulatory proceedings, including Pacific Gas and Electric Company's pending General Rate Case which will determine whether the Company will have the opportunity to earn its authorized rate of return, the Cost of Capital proceeding, which will determine the amount of return the Company will be authorized to earn on its assets and recover from ratepayers, the Company's proposal to adopt performance-based ratemaking, the Company's electric transmission rate case applications, and the CPUC's proceeding relating to the Company's affiliate transactions; fluctuations in commodity gas and electric prices and the ability to successfully manage such price fluctuations; and the pace and extent of competition in the California generation market and its impact on the Company's costs and resulting collection of transition costs. As the ultimate impacts of these and other factors is uncertain, these and other factors may cause future results to differ materially from results or outcomes currently expected or sought by PG&E Corporation. Competition and the Changing Regulatory Environment The electric and gas industries are undergoing significant change. Under traditional regulation, utilities were provided the opportunity to earn a fair return on their invested capital in exchange for a commitment to serve all customers within a designated service territory. 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. Today, competitive pressures and emerging market forces are exerting an increasing influence over the structure of the gas and electric industries. Other companies have challenged the utilities' exclusive relationship with their customers and have sought to replace certain utility functions with their own. Customers, too, have asked for choice in their energy provider. These pressures have caused a move from the traditional regulatory framework to one in which competition is allowed in certain segments of the gas and electric industries. In 1998, a significant portion of Pacific Gas and Electric Company's business was transformed from the traditional monopoly structure to a competitive operation. The return on Diablo Canyon and certain other generation assets continued to be significantly lower in 1998 than historical levels and will remain at this lower level throughout the transition period. See "Utility Operations--Electric Utility Operations--Diablo Canyon--Diablo Canyon Ratemaking" below. The new competitive environment and the regulatory decisions made in the context of electric and gas industry restructuring will continue to affect PG&E Corporation's financial results and may result in greater earnings volatility. The changes in both the electric and gas industries, as described below, require the Company to develop and implement changes to its business processes and systems, including customer information and billing systems, to accommodate electric and gas industry restructuring. To the extent the Company is unable to successfully and timely develop and implement such changes, there could be an adverse impact on the Company's future results of operations. Electric Industry In 1998, California became one of the first states in the nation to implement an electric industry restructuring plan, the framework of which was established by AB 1890. Pursuant to AB 1890, on January 1, 1997, electric rates were frozen, at the levels in effect on June 10, 1996, until the earlier of March 31, 2002, or when the particular utility has recovered its generation-related transition costs (the transition period). The following key features of AB 1890 have been implemented: --Mandatory unbundling of transmission, distribution, and generation services, although the utilities must continue to offer bundled electric service to customers who wish to continue receiving it from the utility. --Commencement of operations of the California Power Exchange (PX) which provides a competitive auction process to establish a transparent market clearing price for electricity in California. 3 --Relinquishment of control (but not ownership or maintenance) of the utilities' transmission facilities to the California Independent System Operator (ISO). --Commencement of operations of the ISO which ensures system reliability and provides electric market participants with open and comparable access to transmission services. --A 10% reduction in the previously frozen rates, effective January 1, 1998, through the end of the transition period, for residential and small commercial customers. --The issuance of rate reduction bonds in December 1997 to finance the 10% rate reduction. --Collection of a nonbypassable charge (the competition transition charge or CTC) to provide the opportunity for utilities to recover their transition costs. --Accelerated recovery of transition costs associated with utility-owned generation facilities. --Commencement of direct access to competitive generation resources for all retail electric customers on March 31, 1998. --Commencement of the market valuation process for utility-owned non- nuclear generation assets, to be completed by 2001. For more information about California electric industry restructuring, see "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring" below. Other states also have moved forward with their electric industry restructuring plans to increase competition. PG&E Corporation's national energy strategy includes active pursuit of opportunities created by the gradual deregulation of the electric industry across the nation. PG&E Corporation's ability to anticipate and capture profitable business opportunities created by deregulation will have a significant impact on the Corporation's future operating results. Additional information concerning electric industry restructuring and the financial impact of these changes on PG&E Corporation is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 49 of the 1998 Annual Report to Shareholders. Gas Industry Restructuring of the natural gas industry on both the national and state levels has given customers greater options in meeting their gas supply needs. Regulators and legislators are using "unbundling" (separating the various services and the pricing of those services) to increase competition for non- monopoly energy services and to increase choices for customers. In the gas industry, Federal Energy Regulatory Commission (FERC) Order 636 required interstate pipeline companies to divide their services into separate sales, transportation, and storage services. Under Order 636, interstate pipelines must provide transportation service regardless of whether the customer (typically a local gas distribution company) buys the gas commodity from the pipeline. During 1998, the California gas industry continued to be restructured pursuant to the Gas Accord Settlement, a multi-party agreement approved by the CPUC in 1997 (Gas Accord). The Gas Accord separates, or "unbundles," Pacific Gas and Electric Company's gas transmission services from its distribution services and changes the terms of service and rate structure for gas transportation. Unbundling gives noncore customers the opportunity to select from a menu of services offered by Pacific Gas and Electric Company and enables them to pay only for the services they use. Unbundling also makes access to the transmission system possible for all gas marketers and shippers, as well as noncore end-users. As a result, the transmission system is now more accessible to a greater number of customers. Pacific Gas and Electric Company's customers may buy gas directly from competing suppliers and purchase transmission-only and distribution-only services from Pacific Gas and Electric Company. The Company's 4 transmission and distribution services historically have been "bundled," or sold together at a combined rate, within California. Most of Pacific Gas and Electric Company's industrial and larger commercial (noncore) customers now purchase their gas from marketers and brokers. Substantially all residential and smaller commercial (core) customers buy gas as well as transmission and distribution services from Pacific Gas and Electric Company as a bundled service. Customer rates for gas are updated on a monthly basis in order to reflect changes in Pacific Gas and Electric Company's gas procurement costs. The Gas Accord increases opportunities for Pacific Gas and Electric Company's core customers to purchase gas from competing suppliers and, therefore, may reduce the Company's role in procuring gas for such customers. However, Pacific Gas and Electric Company will continue to procure gas as a regulated utility supplier for those customers who do not obtain gas supplies from an alternative provider. Under the Gas Accord, Pacific Gas and Electric Company's core gas procurement costs for the period 1994 to 2002 are recoverable under a core procurement incentive mechanism (CPIM), a form of incentive regulation. The CPIM provides the Company with a direct financial incentive to procure gas and transportation services at the lowest reasonable costs by comparing all procurement costs to an aggregate market-based benchmark. If costs fall within a range (tolerance band) around the benchmark, costs are deemed reasonable and fully recoverable from ratepayers. If the Company's actual core procurement costs fall outside the tolerance band, the Company's ratepayers and shareholders share savings or costs, respectively. The Gas Accord also established gas transmission and storage rates for the period from March 1, 1998, through December 31, 2002. During this period, Pacific Gas and Electric Company is at risk for revenue fluctuations resulting from variances in demand for noncore gas transmission throughput. Rates for distribution service continue to be set by the CPUC, and are designed to provide the Company an opportunity to recover its costs of service and include a return on investment. In January 1998, the CPUC opened a rulemaking proceeding to expand market- oriented policies in the natural gas industry, including the further unbundling of services to promote competition, streamlining regulation for noncompetitive services, mitigating the potential for anti-competitive behavior, and establishing appropriate consumer protections. In August 1998, the Governor of California signed Senate Bill 1602, allowing the CPUC to investigate issues associated with the further restructuring of natural gas services. If the CPUC determines that further changes are in the public interest, it is required to submit its findings to the Legislature. Senate Bill 1602 prohibits the CPUC from adopting any decisions regarding gas industry restructuring until January 1, 2000. The CPUC has completed hearings dealing with market conditions and has indicated that it will issue a decision identfiying the most promising structural changes for further study. The CPUC will hold hearings in the future on safety issues associated with gas revenue cycle service unbundling and the costs and benefits associated with the most promising options. The CPUC then intends to conduct open public comment meetings, develop consumer protection rules, and submit a report to the Legislature setting forth its recommendations. Additional information concerning gas industry restructuring, and the financial impact of these changes on PG&E Corporation, is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18. Regulation of Pacific Gas and Electric Company State Regulation The CPUC consists of five members appointed by the Governor (although there are currently two vacancies) and confirmed by the State Senate for six-year terms. The CPUC regulates Pacific Gas and Electric Company's rates and conditions of service, sales of securities, dispositions of utility property, rate of return, rates of depreciation, uniform systems of accounts, long-term resource procurement, and transactions between Pacific Gas and Electric Company and its subsidiaries and affiliates. 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. 5 The California Energy Commission (CEC) has the responsibility to make electric-demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines the need for additional energy sources and for conservation programs. 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. The funding will be collected from ratepayers through a nonbypassable public benefits charge. See "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring--Public Purpose Programs" below. Federal Regulation The Federal Energy Regulatory Commission (FERC) regulates electric transmission rates and access, operation of the California Independent System Operator and the California Power Exchange, compliance with the uniform systems of accounts, and electric contracts involving sales of electricity for resale. The FERC also has jurisdiction over Pacific Gas and Electric Company's electric transmission revenue requirements and rates. The FERC also regulates the interstate transportation of natural gas. Further, most of Pacific Gas and Electric Company's hydroelectric facilities are subject to licenses issued by the FERC. The Nuclear Regulatory Commission (NRC) oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including Diablo Canyon and the nuclear generating unit at Humboldt Bay Power Plant (Unit 3). NRC regulations require extensive monitoring and review of the safety, radiological, and environmental aspects of these facilities. 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 and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, FERC hydroelectric facility 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. Regulation of PG&E Corporation and Other Subsidiaries PG&E Corporation PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the federal Public Utility Holding Company Act of 1935 (Holding Company Act) on the basis that PG&E Corporation and Pacific Gas and Electric Company are incorporated in the same state and their business is predominantly intrastate in character and carried on substantially in the state of incorporation. At present, PG&E Corporation has no expectation of becoming a registered holding company under the Holding Company Act. 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. The financial conditions provide that Pacific Gas and Electric Company is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC, Pacific Gas and Electric Company's dividend policy shall continue to be established by Pacific Gas and Electric Company's Board of Directors as though Pacific Gas and Electric Company were a comparable stand-alone utility company, and the capital requirements of Pacific Gas and Electric Company, as 6 determined to be necessary to meet Pacific Gas and Electric Company's service obligations, shall be given first priority by the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company. The conditions also provide that Pacific Gas and Electric Company shall 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. A further condition of the CPUC's approval of the holding company formation was that an audit of affiliate transactions from 1994 to 1996 be conducted and supervised by the CPUC's Office of Ratepayer Advocates (ORA). The audit report, completed in November 1997, was critical of Pacific Gas and Electric Company's affiliate transaction internal controls and compliance. The report contained numerous recommendations for additional conditions to be imposed on the holding company. Pacific Gas and Electric Company has responded to the audit report, and the CPUC held hearings in 1998 to determine if the additional recommended conditions should be imposed on the holding company. On February 23, 1999, a CPUC administrative law judge (ALJ) issued a proposed decision which declines to adopt most of the recommended conditions, including all of the financial conditions contested by the Company. Instead, the ALJ's proposed decision directs the CPUC staff to prepare for the CPUC's consideration a draft CPUC order to institute a generic proceeding to determine whether the recommended financial conditions, or other appropriate financial conditions, should be imposed on all California electric and gas utilities within the CPUC's jurisdiction with respect to their holding company operations. The ALJ's proposed decision also proposes to require Pacific Gas and Electric Company to establish and maintain various accounting and internal control practices and systems with respect to affiliate transactions. A final CPUC decision is expected in early 1999. On December 16, 1997, the CPUC issued a decision that adopted rules governing transactions between California's natural gas local distribution and electric utility companies and their non-regulated affiliates. This decision permits non-regulated affiliates of regulated utilities (such as PG&E Energy Services, the non-regulated energy marketing subsidiary of PG&E Corporation) 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 decision adopts complex and detailed rules requiring the separation of regulated utilities and their non-regulated affiliates, and also contains rules regarding information exchange among the affiliates and prohibits the utility from engaging in certain practices which would discriminate against energy service providers which compete with the utility's non-regulated affiliates. As required by the decision, Pacific Gas and Electric Company filed a comprehensive plan to comply with the affiliate transaction rules and on September 17, 1998, the CPUC approved parts of the plan and ordered that other parts be resubmitted. The Company has resubmitted its plan and expects the CPUC to act on the plan in early 1999. On December 17, 1998, the CPUC issued a decision establishing specific penalties and enforcement procedures for affiliate rules violations. The decision included a new requirement that utilities self-report for affiliate rules violations, provided for an experimental advisory ruling process to be established, and established an informal inquiry and a formal complaint process. Wholesale Operations of Affiliates In addition to Pacific Gas and Electric Company, certain of PG&E Corporation's other subsidiaries which conduct interstate gas transmission and electric wholesale power marketing operations, are subject to FERC jurisdiction. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. The FERC also regulates certain transportation transactions on the intrastate pipelines pursuant to Section 311 of the Natural Gas Policy Act of 1978. The Railroad Commission of Texas (RRC) regulates gas utilities, including those owned by PG&E Corporation through PG&E Gas Transmission, Texas Corporation, (PG&E GTT), PG&E Gas Transmission Teco, Inc., and other affiliates operating in Texas. The RRC's gas proration rules govern the wellhead production and purchase of gas. Intrastate pipelines can provide intrastate gas transportation at negotiated rates which are 7 presumed just and reasonable. If the criteria for negotiated rates cannot be met, the RRC may assess a cost-of-service-based rate. The RRC also may regulate certain sales of gas. Currently, the price of natural gas sold under a majority of PG&E GTT's gas sales contracts is not regulated by the RRC. All transportation and gathering of gas is subject to the RRC Code of Conduct which prohibits undue discrimination among similarly situated shippers. Further, all transportation of gas, processing of gas, and transportation of natural gas liquids are subject to safety regulations enforced by the RRC and the Texas Natural Resource Conservation Commission. In addition, the power generation projects that USGen develop, manage, or own are subject to differing types of federal regulation depending on the regulatory status of the particular project. Some of these projects are exempt wholesale generators (EWG) under the National Energy Policy Act of 1992, which status exempts the project from the Holding Company Act. EWG status is granted by the FERC upon application by the project. Some projects have received authority from the FERC to charge market-based rates for the power they sell, rather than traditional cost-based rates. Many of USGen's affiliated projects are qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978. QF status exempts the project from regulation under various federal and state laws concerning the electric industry. USGen's projects are also subject to various federal, state, and local regulations concerning siting and environmental matters. PG&E Corporation's indirect subsidiary, USGen New England, Inc. (USGenNE), acquired the electric generating facilities of the New England Electric System (NEES) in September 1998. USGenNE also is subject to numerous federal, state, and local statutes and regulations. USGenNE sells at wholesale all of the electricity it generates, as well as electricity it purchases from third parties under existing power sales agreements. Under the Federal Power Act ("FPA"), the FERC regulates these wholesale sales. The FERC has approved USGenNE's rate schedule as a market-based schedule and, accordingly, the FERC granted USGenNE waivers of certain other requirements that otherwise are imposed on utilities with cost-based rate schedules. In addition, USGenNE owns and operates a number of hydroelectric and pumped-storage projects that are licensed by the FERC. These licenses expire periodically and the projects must be relicensed at that time. USGenNE's licenses for these hydroelectric projects expire over a period from 2001 to 2020. Prior to the expiration of any one of the hydroelectric licenses, there is an opportunity for the existing licensee (as well as others interested in owning and operating the project) to apply for, and obtain, a new license. USGenNE also is subject to limited regulation by certain state public utility commissions located in states where USGenNE owns and operates electric generating facilities. This regulation does not extend to its rates, which are regulated exclusively by the FERC, and the scope of this regulation has been substantially limited by various legislative initiatives. Other regulatory matters are described throughout this report. 8 Capital Requirements and Financing Programs PG&E Corporation and Pacific Gas and Electric Company continue to require capital for improvements to facilities to enhance their efficiency and reliability, to extend their useful lives, and to comply with environmental laws and regulations. PG&E Corporation's expenditures for these purposes, including the allowance for funds used during construction (AFUDC), were approximately $1,633 million for 1998. New investments totaled $1,779 million in 1998. The following table sets forth estimated capital expenditures, as well as amounts for maturing debt and sinking funds, for PG&E Corporation subsidiaries for the years 1999 through 2001. The amount of capital expenditures for Pacific Gas and Electric Company (other than estimated capital expenditures for Diablo Canyon) include estimates prepared for the Company's GRC application now pending at the CPUC, excluding capital expenditures for divested fossil and geothermal power plants. The amount of capital expenditures for Pacific Gas and Electric Company shown in the table will be reduced if the CPUC authorizes base revenues significantly lower than those requested by the Company in its GRC filing.
1999 2000 2001 ------ ------ ------ (in millions) Utility Capital Expenditures(1)........................ $1,598 $1,666 $1,681 Other Capital Expenditures(2).......................... 364 205 157 Maturing Debt and Sinking Funds........................ 628 988 771 ------ ------ ------ Total Capital Requirements........................... $2,590 $2,859 $2,609 ====== ====== ======
- -------- (1) Utility capital expenditures include the estimates prepared for Pacific Gas and Electric Company's GRC but exclude capital expenditures for divested fossil and geothermal power plants. These numbers are shown net of reimbursed capital and include AFUDC. (2) Other expenditures include those of PG&E GT, PG&E ES, PG&E ET, and USGen. Most of the estimated capital expenditures for Pacific Gas and Electric Company for 1999 through 2001 are associated with short lead time capital expenditure projects aimed at the replacement and enhancement of existing facilities, and compliance with environmental laws and regulations. Also included are proposed expenditures to maintain and improve safety and reliability of Pacific Gas and Electric Company's electric transmission and distribution system, as well as proposed expenditures for major projects associated with customer service improvements. PG&E Corporation estimates that its total capital requirements for the years 1999 through 2001 will include approximately $2.4 billion for payment at maturity of outstanding long-term debt and for meeting sinking fund requirements for debt, as indicated above. The funds necessary for 1999-2001 capital requirements of PG&E Corporation and its subsidiaries will be obtained from (i) internal sources, principally net income before noncash charges for depreciation and deferred income taxes, and (ii) external sources, including short-term financing, such as bank loans and the sale of short-term notes, and long-term financing, such as sales of equity and long-term debt securities, when and as required. PG&E Corporation and its subsidiaries and affiliates conduct a continuing review of their capital expenditures and financing programs. The amounts shown in the table above are forward-looking statements based on a number of assumptions and which are subject to various uncertainties. Actual amounts may differ materially based upon a number of factors, including the outcome of Pacific Gas and Electric Company's GRC filing, changes in assumptions about system load growth, rates of inflation, receipt of adequate and timely rate relief, availability and timing of regulatory approvals, total cost of major projects, availability and cost of suitable nonregulated investments, and availability and cost of external sources of capital, as well as the outcome of the ongoing restructuring in both the electric and gas industries. 9 Price Risk Management Programs PG&E Corporation has an officer-level Price Risk Management Committee and has adopted a Risk Management Policy, approved by the Board of Directors of PG&E Corporation, for trading and risk management activities. The Price Risk Management Committee oversees implementation of the policy, approves the trading and price risk management policies of subsidiaries, and monitors compliance with the policy. The Risk Management Policy allows derivatives to be used for both hedging and non-hedging purposes. (A derivative is a contract whose value is dependent on or derived from the value of some underlying asset.) PG&E Corporation uses derivatives for hedging purposes primarily to offset underlying commodity price risks. PG&E Corporation also participates in markets using derivatives to create liquidity and maintain a market presence. Such derivatives include forward contracts, futures, swaps, and options. The Risk Management Policy and the trading and risk management policies of PG&E Corporation's subsidiaries prohibit the use of derivatives whose payment formula includes a multiple of some underlying asset. PG&E Corporation also monitors the trading and risk management of PG&E ET, consistent with PG&E Corporation's Risk Management Policy. See "Wholesale Operations of Affiliates--Energy Trading." In 1998, the CPUC granted authority to Pacific Gas and Electric Company to trade natural gas-based financial instruments to manage the influence of natural gas prices on the cost of electricity purchased under existing power- purchase contracts and to manage price and revenue risks associated with its natural gas transmission and storage assets, subject to certain conditions. The CPUC had previously granted authority to Pacific Gas and Electric Company to trade natural gas-based financial instruments to hedge the gas commodity price swings in serving core gas customers. Additional information concerning price risk management activities and the financial impact of price risk management activities on PG&E Corporation and Pacific Gas and Electric Company is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18 and in Notes 1, 3, and 4 of the "Notes to Consolidated Financial Statements" beginning on page 46 of the 1998 Annual Report to Shareholders. Year 2000 Matters PG&E Corporation's Year 2000 compliance program generally is proceeding on schedule. However, if PG&E Corporation or third parties with whom PG&E Corporation or Pacific Gas and Electric Company have significant business relationships fail to achieve Year 2000 readiness with respect to mission- critical systems, there could be a material adverse impact on PG&E Corporation and Pacific Gas and Electric Company's financial position, results of operations, and cash flow. Additional information concerning Year 2000 matters and the financial impact of Year 2000 matters on PG&E Corporation and Pacific Gas and Electric Company is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18. 10 UTILITY OPERATIONS California Ratemaking Mechanisms The CPUC authorizes an amount, known as "base revenues," to be collected from ratepayers to recover Pacific Gas and Electric Company's basic business and operational costs for its gas and electric operations. Base revenues, which include non-fuel-related operating and maintenance costs, depreciation, taxes, and a return on invested capital, are currently authorized by the CPUC in General Rate Case (GRC) proceedings before the CPUC. During the GRC, which occurs every three years, the CPUC examines Pacific Gas and Electric Company's costs and operations to determine the amount of base revenue requirement the Company is authorized to collect from customers through base revenues. The revenue requirement is forecasted on the basis of a specified test year. (The return component of Pacific Gas and Electric Company's revenue requirement is computed using the overall cost of capital authorized in other proceedings.) Following the revenue requirement phase of a GRC, the CPUC conducts a rate design phase, which allocates revenue requirements and establishes rate levels for the different classes of customers. The Company's current GRC application pending at the CPUC is discussed below. In December 1997, the CPUC adopted a cost-of-service-based ratemaking mechanism for determining Pacific Gas and Electric Company's revenue requirement for its hydroelectric and geothermal generation facilities. Under this mechanism, the revenue requirements for these facilities will be calculated as the sum of the capital-related revenue requirement (based on recorded capital costs), the expense revenue requirement (based on the current GRC-adopted expenses), and actual fuel expenses. A reduced rate of return on common equity of 6.77% applies to these facilities. This alternative revenue requirement mechanism will be in place through 2001, unless the CPUC determines otherwise. Each year, Pacific Gas and Electric Company files an application with the CPUC to determine the authorized rate of return that the Company may earn on its assets (subject to the rates of return established for Diablo Canyon and non-nuclear generation-related assets discussed in the previous paragraph) and recover from ratepayers. On May 8, 1998, the Company filed its 1999 Cost of Capital application. Since (i) the CPUC separately reduced the rate of return on the Company's generation-related assets including Diablo Canyon, (ii) the FERC will authorize the rate of return for electric transmission assets at a later date (see discussion below), and (iii) gas transmission and storage rates have been set in the Gas Accord, the rate of return adopted in the 1999 Cost of Capital Proceeding only applies to the Company's electric and gas distribution assets. The Company has requested an increase in the rate of return on common equity to 12.10% and an overall utility return on rate base of 9.53% compared to the 1998 authorized returns of 11.20% and 9.17%, respectively. No request was made to change the capital structure for the Company, which continues to be composed of 48.00% common equity, 5.80% preferred stock, and 46.20% long-term debt. Other parties have recommended lower rates of return than the amounts requested. If the Company's requested increase is approved, the authorized cost of capital will increase 1999 authorized electric and gas revenue by $49.7 million and $15.5 million, respectively. In November 1998, Pacific Gas and Electric Company filed an application with the CPUC to establish performance-based ratemaking (PBR) for electric and gas distribution services. If approved, the distribution PBR will establish electric and gas distribution revenue requirements for the years 2000 to 2004. The Company has proposed that the revenue requirement for the year 2000 be determined by applying a formula, based principally on inflation and productivity factors, to the 1999 GRC authorized revenue requirement. In subsequent years, the formula would be applied to the previous year's authorized revenue requirement. The proposed PBR also includes a sharing mechanism for earnings that are significantly above or below the authorized cost of capital, and a framework for rewards and penalties based upon the achievement of various performance measures. As the CPUC has indicated that a decision will not be issued until as late as May 2000, in February 1999, the Company requested interim relief to be effective starting January 2000. The 1998 Annual Earnings Assessment Proceeding (AEAP), which determines shareholder incentives earned for Pacific Gas and Electric Company's 1996 and 1997 demand side management (DSM) programs, was submitted in May 1998. In the 1998 AEAP, the Company has requested an incentive payment of approximately 11 $39.8 million for the Company's 1997 DSM programs, to be trued-up and collected in installments over a 10-year period. After consolidating the adjusted incentive payment installments from prior years, the net revenue change in 1999 from DSM shareholder incentives should be an electric decrease of approximately $14.3 million and a gas decrease of approximately $2.5 million. A final CPUC decision is expected during the first quarter of 1999. On January 7, 1999, Pacific Gas and Electric Company filed an application with the CPUC in its first Catastrophic Event Memorandum Account (CEMA) requesting increases in electric and gas revenue requirements of $60.1 million and $15.8 million, respectively, for costs incurred for several emergencies, including the 1997 storms. The Company has requested that these costs be included in rates effective January 1, 2000. Electric Ratemaking During 1998, the CPUC issued many decisions to implement electric industry restructuring and the new market structure, including decisions related to unbundling of rates, the recovery of transition costs, performance-based ratemaking (PBR), and other activities that affect rates and revenue requirements. Because electric rates are frozen, any change in Pacific Gas and Electric Company's electric revenue requirements (the amount of revenue required to pay certain costs) resulting from the items discussed below will not change electric customer rates. Under the electric rate freeze, the portion of total actual revenue that exceeds authorized base revenues and certain other authorized revenue requirements is available to recover transition costs. Therefore, increases in base revenues would reduce the amount of revenue available to recover transition costs. Conversely, decreases in base revenues would increase revenue available from frozen rates for recovery of transition costs. General Rate Case. In Pacific Gas and Electric Company's GRC now pending before the CPUC, the Company is requesting increases in electric base revenues of $445 million over electric base revenues authorized in 1998 to reflect increasing levels of electric demand as well as customer growth in the service territory, the costs of continued and enhanced maintenance activities, and increased capital expenditures. The GRC electric revenue request includes proposed funding for distribution services, including system reliability and safety projects, increased distribution capacity (poles, wires, substations, etc.), equipment inspection and maintenance, a continuation of tree-trimming programs, and enhanced customer service and information technology systems. Since the FERC authorizes the rates collected from customers for electric transmission services, the GRC application does not seek approval of base revenues to recover the cost of transmission services. In December 1998, the CPUC issued a decision granting the requested increases on an interim basis effective January 1, 1999. This interim decision will be in effect until the CPUC issues its final decision, expected in June 1999. The interim decision allows the Company to reflect the increased revenue requirements in its balancing accounts to permit the Company to track the differences between actual revenue requirements in effect on January 1, 1999, and the requested revenue requirements. The interim decision did not increase electric rates. Recovery of Transition Costs. On January 1, 1998, the Transition Revenue Account (TRA) was established. Within the TRA, revenue from frozen rates collected from ratepayers are allocated to transmission costs, distribution costs, the costs of public purpose programs, nuclear decommissioning costs, and energy procurement costs. Remaining revenues, if any, are transferred to the Transition Cost Balancing Account (TCBA) to offset transition costs. The CPUC established a separate annual proceeding, the Revenue Adjustment Proceeding (RAP), to review, track, and compare each electric utility's authorized revenue requirements with the actual recorded revenues, and to make any necessary adjustments to reflect the authorized revenues that are approved in other proceedings. The RAP is a consolidation proceeding to verify that the outcomes from other proceedings are properly reflected and that the utilities accurately calculate the amount of revenues available to transfer to the TCBA to offset transition costs. On July 1, 1998, Pacific Gas and Electric Company filed an application with the CPUC in its first RAP requesting CPUC approval of entries made into the TRA from January 1 through May 31, 1998, and requesting approval of the Company's accounting, revenue allocation, and rate design proposals. On September 1, 1998, Pacific Gas and Electric Company also filed an application in its first Annual Transition Cost Proceeding (ATCP) requesting recovery of transition costs recorded in the TCBA from January 1 through June 30, 1998. This 1998 ATCP will verify the accounting and recording of costs and revenues in the TCBA and ensure that only eligible transition costs have been entered. Transition costs will receive a limited "reasonableness" review. 12 Electric Industry Restructuring Implementation Costs. Under AB 1890, certain electric industry restructuring implementation costs, that are found reasonable by the CPUC may be recovered from ratepayers. Eligible costs include FERC-authorized start-up and development costs of the ISO and PX, CPUC approved consumer education programs, and the costs of implementing direct access and demand PX billing and settlement systems. A multiparty settlement agreement filed with the CPUC on November 13, 1998, proposes that Pacific Gas and Electric Company would recover $40 million in 1997 and 1998 restructuring implementation costs during the rate freeze (on a revenue requirements basis). If recovery of these restructuring implementation costs during the rate freeze displaces recovery of transition costs, the settlement agreement proposes that Pacific Gas and Electric Company may recover up to $95 million of such displaced transition costs after the rate freeze. A proposed CPUC decision is expected in June 1999. Revenues from Must-Run Contracts. The ISO has designated certain units at electric generation facilities as necessary to remain available and operational to maintain the reliability of the electric transmission system. These units are called "must-run" units. In general, the ISO dispatches these units under cost-based rate schedules that allow the owners to recover sunk costs and ongoing operating costs of the must-run units. Although still subject to FERC approval, the owners of must-run units choose among three forms of must-run rate schedules, all of which are premised upon a different mix of cost-based payments and revenues earned in the market. Electric Transmission Revenues. Beginning in 1998, the FERC obtained jurisdiction to determine the annual amount of Pacific Gas and Electric Company's authorized revenue for transmission services that it may collect from customers. The Company expects to file an application with the FERC in March 1999 requesting 1999 electric transmission revenues of approximately $425 million, an increase of approximately 8% over transmission revenues sought by the Company and accepted, subject to refund, by the FERC in 1998. Electric Deferred Refund Account (EDRA). In December 1996, the CPUC issued a decision establishing an EDRA. The CPUC ordered Pacific Gas and Electric Company to place into the EDRA credits for CPUC-ordered electric disallowances, the utility electric generation share of gas disallowances ordered by the CPUC or the FERC, and amounts resulting from reasonableness disputes or fuel-related cost refunds made to Pacific Gas and Electric Company based on regulatory agency decisions, plus interest charges. The Company requested, and the CPUC approved, an early refund of amounts accrued in EDRA in 1998. In 1998, the Company refunded approximately $36.4 million of EDRA refunds to customers. Post-Rate Freeze Ratemaking Mechanisms. On January 15, 1999, Pacific Gas and Electric Company filed an application with the CPUC to determine the ratemaking mechanisms to be in effect after the end of the electric rate freeze period. Additional information concerning Pacific Gas and Electric Company's transition cost recovery plan, and the financial impact of electric industry restructuring, is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 49 of the 1998 Annual Report to Shareholders. Gas Ratemaking Gas Accord. As noted above (see "General--Competition and the Changing Regulatory Environment--Gas Industry"), the CPUC approved the Gas Accord in 1997. As part of the Gas Accord, the CPUC's traditional reasonableness reviews of Pacific Gas and Electric Company's core gas costs have been replaced with a CPIM (which also is discussed below in "Utility Operations--Gas Utility Operations--Core Procurement Incentive Mechanism") for the period from June 1, 1994, through 2002. Additional information concerning the potential financial impact of the Gas Accord is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18. 13 General Rate Case. The Company is requesting an increase in gas base revenues of $377 million, over base revenues authorized in 1998. The requested increase in base revenues reflects increasing levels of gas demand as well as customer growth in the service territory, the costs of continued and enhanced maintenance activities, and increased capital expenditures. The GRC gas base revenue request includes proposed funding for distribution system safety and reliability improvements, increased depreciation costs of the gas pipeline system, expanded customer service, and expanded customer and other information systems. In December 1998, the CPUC issued a decision granting the requested increase on an interim basis effective January 1, 1999. This interim decision will be in effect until the CPUC issues its final decision, expected in June 1999. The interim decision allows the Company to reflect the increased revenue requirements in its balancing accounts to permit the Company to track the differences between actual revenue requirements in effect on January 1, 1999, and the requested revenue requirements. The interim decision did not increase gas rates. However, gas customers would experience an increase in gas distribution rates if the CPUC approves the requested gas base revenue increase. The requested increase in gas base revenues will not result in an increase in customer gas transmission and storage rates, since the Gas Accord has set gas transmission and storage rates for the period from implementation of the Gas Accord through December 2002. The Biennial Cost Allocation Proceeding (BCAP). The BCAP remains the proceeding in which distribution costs and balancing account balances are allocated to customers. 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 natural gas costs accumulate differences between the actual recovery of gas costs and the revenues designed for recovery of such costs. Balancing accounts for sales volumes accumulate differences between authorized and actual base revenues. In 1997, Pacific Gas and Electric Company filed its 1998 BCAP application. In June 1998, the CPUC adopted a decision in the 1998 BCAP granting an annual $97.8 million revenue requirement decrease effective September 1, 1998, compared to revenues established by the Gas Accord on March 1, 1998. The overall annual revenue requirement for the two-year BCAP period (September 1, 1998, through August 31, 2000) is approximately $1.5 billion, of which an annual average of approximately $102 million is allocated for the collection of balancing accounts. The previous annual revenue requirement was approximately $1.8 billion, of which approximately $303 million was allocated for the collection of balancing accounts. Electric Utility Operations Implementation of Electric Industry Restructuring In 1998, electric industry restructuring in California became effective with the commencement of operations of the California Independent System Operator (ISO) and the California Power Exchange (PX) on March 31, 1998. Independent System Operator and Power Exchange The ISO operates and controls most of the state's electric transmission facilities (which continue to be owned and maintained by the California utilities) and provides comparable open access to electric transmission service. The ISO accepts balanced supply and load schedules from market participants and manages the availability of electric transmission on a statewide basis for these transactions. The ISO also purchases necessary generation and ancillary services to maintain grid reliability. In 1998, California's three largest investor-owned utilities relinquished operational control, but not ownership, of their transmission facilities to the ISO. The ISO is required to ensure reliable transmission services consistent with planning and operating reserve criteria no less stringent than those established by the Western Systems Coordinating Council and the North American Electric Reliability Council. Oversight responsibility for reliability of utility distribution systems remains with the CPUC. The PX provides a competitive auction process to establish transparent market clearing prices for electricity in the markets operated by the PX. The three largest investor-owned utilities in California are required to sell into the PX all of their generated electric power. "Must-take" generation resources, such as nuclear generation, 14 electric power generated by QFs which the utilities are required to purchase under existing contractual commitments, are also scheduled through the PX. The utilities must then purchase all electric power for their retail customers through the PX. Customers who buy power directly from non-regulated suppliers pay for that generation based upon negotiated contracts. The PX sets a market clearing price for electricity by matching all demand load bids with supply bids ranked from lowest to highest. The highest-accepted generation supply bid used to serve load sets the PX market clearing price for electricity. The FERC has jurisdiction over both the ISO and the PX. In October 1997, the FERC granted authority for the ISO and the PX to commence operations and approved the initial structure, rates, terms and conditions applicable to the new market structure. The ISO and PX both have made numerous tariff amendment filings with the FERC to address issues which arose after the commencement of ISO and PX operations. The FERC has acted on several of these filings and several remain pending. The ISO and PX, California public benefit non-profit corporations, each has a Governing Board that includes representatives of investor-owned utility transmission systems, publicly-owned utility transmission systems, non-utility electricity sellers, public buyers and sellers, private buyers and sellers, industrial end-users, commercial end-users, residential end-users, agricultural end-users, public interest groups, and non-market participant representatives. The ISO and PX currently are overseen by a five-member Electricity Oversight Board which appoints the members of the ISO and PX Governing Boards. However, this appointment power has been rejected by the FERC and new bylaws for the ISO and the PX have been filed with the FERC which, if approved by the FERC, would eliminate this role of the Electricity Oversight Board. Voluntary Generation Asset Divestiture As part of the electric industry restructuring plan to promote a competitive electric generation market, California utilities, including Pacific Gas and Electric Company, have voluntarily begun divestiture of some of their generation assets. On July 1, 1998, Pacific Gas and Electric Company sold three electric generating plants with a combined capacity of 2,645 megawatts (MW): the Morro Bay Power Plant located in San Luis Obispo County, the Moss Landing Power Plant located in Monterey County, and the Oakland Power Plant located in Alameda County. The aggregate sale price for these three fossil- fueled plants was $501 million and the combined book value for these three plants was approximately $346 million as of July 1, 1998. Pacific Gas and Electric Company has retained liability for required environmental remediation of any preclosing soil or groundwater contamination at these plants. In late 1998 and in January 1999, Pacific Gas and Electric Company agreed to sell three fossil-fueled generating facilities (the Pittsburg and Contra Costa power plants located in Contra Costa County, and the Potrero power plant in San Francisco) and its geothermal generating facilities (The Geysers Power Plant located in Lake and Sonoma Counties) for a combined sale price of $1.014 billion compared to their combined book value of approximately $523 million (as of December 31, 1998). The aggregate purchase price of the fossil-fueled power plants is $801 million. The purchase price for the Geysers geothermal facilities is $213 million. The sales are subject to approval by various regulatory agencies, including the CPUC, and are conditioned upon the transfer of various permits and licenses. The transactions are expected to close by the first half of 1999. Together, the seven power plants represent 91% of Pacific Gas and Electric Company's fossil-fueled generating capacity and all of its geothermal generating capacity. The facilities generated approximately 31% of Pacific Gas and Electric Company's total electric energy production. The gain from the sale of these power plants will be used to offset Pacific Gas and Electric Company's transition costs. As required by the California electric industry restructuring legislation, Pacific Gas and Electric Company employees, under two-year operations and maintenance agreements with the new owners, will continue to operate and maintain the power plants that are sold. To the extent that payments to the Company under these agreements exceed the Company's cost of operating the plants, the Company would offset other transition costs. Conversely, to the extent the Company's operating costs exceed the revenues from these agreements, the Company would have lower earnings. 15 In May 1998, Pacific Gas and Electric Company notified the CPUC that its non-nuclear generating facilities, including the hydroelectric facilities, will not be retained by the Company. In July 1998, the Company reached an agreement with the City and County of San Francisco regarding the Hunters Point fossil-fueled power plant, which the ISO has designated as a "must run" facility. The agreement expresses the Company's intention to retire the plant when it is no longer needed by the ISO. In December 1998, the Company asked the CPUC to allow it to hire appraisers to determine the market value of the hydroelectric system. Under the Company's proposal, the Company would have the option of accepting the appraised value and transferring the assets to another unit of PG&E Corporation or rejecting the appraised value and auctioning the assets. The Company expects the CPUC to issue a decision on the appraisal process in 1999. Direct Access Although the restructuring legislation contemplated that direct access would begin on January 1, 1998, the ISO and PX delayed the commencement of operations until March 31, 1998. Customers participating in direct access may purchase their electric power directly either through (1) competing non- utility retail electric providers such as brokers, marketers, aggregators, or other retailers, or (2) direct negotiated contracts with electric generators. All customers (with limited exceptions), whether they choose direct access or not, must pay the nonbypassable CTC, which will be collected by their distribution utility in connection with recovery of the utilities' transition costs. Utilities began accepting requests for direct access in November 1997 to become effective after direct access began. As of February 24, 1999, Pacific Gas and Electric Company had transferred 53,990 customers to direct access. The CPUC requires that electric customers with an electricity demand, or load, of 50 kilowatts (kW) or more must have meters that are capable of providing hourly data in order to participate in direct access. Those customers with a load less than 50 kW may participate in direct access either through "load profiling" or by installing an hourly meter. (Load profiling approximates the pattern of electricity usage for a given customer class and provides the equivalent of hourly meter reads.) The customer is responsible for the cost of the meter and the meter installation. Energy service providers supplying the direct access market may choose one of three billing options: (1) consolidated energy supplier billing, under which the utility bills the energy supplier for the services provided directly by the utility to the customer, and the supplier, in turn, provides a consolidated bill to the customer, (2) consolidated distribution company billing, under which the utility places the supplier's energy charge on a distribution bill, or (3) dual billing, under which the energy supplier and the utility bill separately for their own services. Since January 1, 1998, energy service providers have been allowed to provide metering services to their customers with a demand greater than 20 kW, and beginning January 1, 1999, energy service providers may provide metering to all of their customers. During 1998, Pacific Gas and Electric Company continued its efforts to develop and implement changes to its business processes and systems, including customer information and billing systems, to accommodate direct access. To the extent the Company is unable to successfully and timely develop and implement such changes, there could be an adverse impact on the Company's future results of operations. Electric Base Revenue Increase AB 1890 provides for an increase in Pacific Gas and Electric Company's electric base revenues for 1997 and 1998, for enhancement of transmission and distribution system safety and reliability. The CPUC authorized a 1997 base revenue increase of $164 million. For 1998, the CPUC authorized an additional base revenue increase of $77 million, for a total authorized base revenue increase for 1997 and 1998 of $406 million. The recovery of these amounts from ratepayers is subject to a reasonableness review by the CPUC. In May 1998, the Company filed its report on 1997 expenditures with the CPUC seeking review of approximately $183 million for costs incurred in 1997 for safety and system reliability enhancements, which exceeded the 1997 authorized revenue requirement by approximately $19 million. On January 29, 1999, the ORA issued its report on the claimed expenditures and recommended that a total of approximately $50 million, including the $19 million amount overspent, be disallowed, for a net recommended disallowance of $31 million. Under AB 1890, the 16 disallowance or underspending of the 1997 revenue requirement, if adopted by the CPUC, would be credited as an expense against the 1998 authorized revenue requirement. To the extent that 1998 expenditures (including any amounts carried over from 1997) exceed the 1998 authorized revenue requirement, the amount overspent would not be recoverable from ratepayers. The Company plans to file its report on 1998 expenditures seeking review of its 1997 and 1998 costs for safety and system reliability enhancements in March 1999. Rate Levels and Rate Reduction Bonds To achieve the 10% rate reduction for residential and eligible small commercial customers, effective January 1, 1998, AB 1890 authorized utilities to finance a portion of their transition costs with "rate reduction bonds." On December 8, 1997, a special purpose entity established by the California Infrastructure and Economic Development Bank issued $2.9 billion of rate reduction bonds on behalf of a wholly owned subsidiary of Pacific Gas and Electric Company. The bonds were issued in eight classes with maturities ranging from 10 months to 10 years, and bearing interest at rates ranging from 5.94% to 6.48%. Pacific Gas and Electric Company is collecting a separate nonbypassable charge on behalf of the bondholders to recover principal, interest, and related costs over the life of the bonds from residential and small commercial customers. The bond proceeds were used by the wholly owned subsidiary to purchase from Pacific Gas and Electric Company the right to be paid the revenues from this separate charge. The bonds are secured by the future revenue from the separate charge and not by Pacific Gas and Electric Company's assets. While the bonds are reflected as long-term debt on Pacific Gas and Electric Company's balance sheet, creditors of Pacific Gas and Electric Company do not have any recourse to the revenues from the separate charge. In November 1998, the California voters defeated a voter initiative known as Proposition 9. If it had passed, Proposition 9 would have, among other things, (i) required investor-owned California utilities to provide an additional 10% rate reduction to residential and small commercial customers, (ii) eliminated transition cost recovery for nuclear investments by utilities (other than reasonable decommissioning costs), (iii) restricted transition cost recovery for non-nuclear investments (other than costs associated with QFs), unless the CPUC found that the utility would be deprived of the opportunity to earn a fair rate of return, and (iv) prohibited the collection of any customer charges for rate reduction bonds, or alternatively, required the utility to offset such charges with an equal credit to customers. Recovery of Transition Costs Under electric industry restructuring, utilities are authorized to recover their transition costs--the utilities' costs of their generation-related assets and obligations which prove to be uneconomic in the new competitive framework. Costs eligible for recovery as transition costs, as determined by the CPUC, include (1) above-market sunk costs (sunk costs are costs associated with utility generating facilities that are fixed and unavoidable and currently included in customer rates), and future sunk costs, such as costs related to plant removal; (2) costs associated with long-term contracts to purchase power at above-market prices from QFs and other power suppliers; and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods to be included in rates in subsequent periods.) Transition costs are eligible for recovery from all customers (with certain exceptions) through a nonbypassable competition transition charge, or CTC, included as part of rates. Transition costs that are disallowed by the CPUC for collection from customers will be written off. As a prerequisite to any consumer obtaining direct access services, the consumer must agree to pay its applicable nonbypassable CTC. Further, nuclear decommissioning costs are being recovered through a separate CPUC-authorized charge. Most transition costs must be recovered by December 31, 2001, although certain transition costs may be recovered after December 31, 2001. These costs include certain employee-related transition costs, costs that are unrecovered as result of the implementation of direct access and creation of the PX and ISO, and above-market costs associated with power-purchase agreements. In addition, costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds. 17 The total amount of sunk costs to be included as transition costs will be based on the aggregate of above-market and below-market values of utility- owned generation assets and obligations. Under AB 1890, valuation of generation-related assets through appraisal or sale must be completed by December 31, 2001. In 1997, the value of three of Pacific Gas and Electric Company's electric facilities was established through the auction process. In 1998, the value of four of the Company's remaining power plants and its geothermal facilities also has been established by the auction process, subject to CPUC approval. In October 1998, the CPUC ruled that the market value of the Hunters Point power plant is zero. In December 1998, the Company filed an application with the CPUC requesting approval for the Company to hire appraisers to establish a market value for the Company's hydroelectric facilities. In September 1997, the CPUC adopted a decision addressing transition cost recovery for capital additions to Pacific Gas and Electric Company's non- nuclear generating facilities. The decision allows Pacific Gas and Electric Company to recover costs of capital additions made in 1996 and 1997 (and in 1998 for fossil-fueled plants completely divested by March 31, 1998) based upon an after-the-fact reasonableness review. All capital additions found reasonable by the CPUC through this process will be recoverable as transition costs. Capital additions made in 1998 and thereafter to non-nuclear generation-related assets, and capital additions made to fossil-fueled generating assets which are not completely divested by March 31, 1998, must be recovered either through revenues from the ISO agreements for "must-run" plants or from sales of electricity to the PX. The CPUC decision allows Pacific Gas and Electric Company to seek an after-the-fact reasonableness review of post-1997 capital addition expenditures for collection as transition costs in certain limited circumstances. In May 1998, the CPUC approved $53 million in 1996 non-nuclear generation capital additions as eligible for recovery as transition costs. Further, a multiparty settlement agreement filed with the CPUC on January 8, 1999, proposes that Pacific Gas and Electric Company would recover approximately $128.5 million of its $133 million request for recovery of 1997 and first quarter 1998 capital additions. A CPUC decision on the 1997 and first quarter 1998 capital additions is expected in 1999. In 1997, to reflect the accelerated recovery of transition costs related to non-nuclear generation-related assets, including hydroelectric and geothermal facilities, and for Diablo Canyon, the CPUC reduced the authorized rate of return on common equity for these assets to 6.77%. The reduced rate of return will be effective for the duration of the transition period. During 1998, proceedings commenced at the CPUC to review, track, and compare each electric utility's authorized revenue requirements with the actual recorded revenues, and to make any necessary adjustments to reflect the authorized revenues that are approved in other proceedings. An annual proceeding also was established to verify the accounting and recording of transition costs and revenues available for recovery of transition costs and to ensure that only eligible transition costs have been entered. In this proceeding, transition costs will receive a limited "reasonableness" review. Public Purpose Programs On January 1, 1998, and continuing through December 31, 2001, energy efficiency, research and development, and low-income programs are being funded through a separate nonbypassable charge included in frozen electric rates, in compliance with AB 1890. Low-income programs are funded at the level of need, but are not to be funded at less than the 1996 level of expenditures. Under this provision of AB 1890, Pacific Gas and Electric Company is obligated to fund through electric rates energy efficiency and conservation programs in an amount not less than $106 million per year, public interest research and development programs at not less than $30 million per year, renewable technologies at not less than $48 million per year, and low-income energy efficiency programs at not less than $14 million per year. The California Alternative Rates for Energy (CARE) low-income discount rate, a rate subsidy paid for by the Company's other customers, is currently about $31 million per year. The California Energy Commission (CEC) administers the public interest research and development program and the renewable program. The CPUC has set up public member boards to advise the CPUC on public purpose programs related to energy efficiency and low-income programs. Initially, these boards also were 18 assigned to solicit competitive bids to determine who will administer the programs in place of the utility's interim administration. However, the CPUC appointed Pacific Gas and Electric Company as interim administrator of energy efficiency and low-income programs for 1999. The CPUC recently has issued a draft decision which, if adopted, would continue the Company's interim administration of these programs through the end of the transition period. Additional information concerning AB 1890 and its financial impact on PG&E Corporation is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 49 of the 1998 Annual Report to Shareholders. Electric Operating Statistics The following table shows Pacific Gas and Electric Company's operating statistics (excluding subsidiaries except where indicated) for electric energy, including the classification of sales and revenues by type of service.
Years Ended December 31 ---------------------------------------------------------- 1998 1997 1996 1995 1994 ---------- ---------- ---------- ---------- ---------- Customers (average for the year): Residential............ 3,962,318 3,915,370 3,874,223 3,825,413 3,788,044 Commercial............. 469,136 465,461 459,001 454,718 452,049 Industrial............. 1,093 1,121 1,248 1,253 1,260 Agricultural........... 85,429 86,359 87,250 88,546 90,520 Public street and highway lighting...... 18,351 17,955 17,583 17,089 16,709 Other electric utilities............. 14 47 28 35 29 ---------- ---------- ---------- ---------- ---------- Total............... 4,536,341 4,486,313 4,439,333 4,387,054 4,348,611 ========== ========== ========== ========== ========== Sales-kWh (in millions): Residential............ 26,846 25,946 25,458 24,391 24,326 Commercial............. 28,839 28,887 27,868 27,014 26,195 Industrial............. 16,327 16,876 15,786 16,879 16,010 Agricultural........... 3,069 3,932 3,631 3,478 4,426 Public street and highway lighting...... 445 446 438 425 418 Other electric utilities............. 2,358 3,291 1,213 3,172 4,246 ---------- ---------- ---------- ---------- ---------- Total energy delivered.......... 77,884 79,378 74,394 75,359 75,621 ========== ========== ========== ========== ========== Revenues (in thousands): Residential............ $2,891,424 $3,082,013 $3,033,613 $2,979,590 $2,980,966 Commercial............. 2,793,336 2,932,560 2,840,101 2,964,568 2,892,302 Industrial............. 933,316 1,028,378 1,005,694 1,160,938 1,128,561 Agricultural........... 350,445 413,711 396,469 395,531 477,330 Public street and highway lighting...... 51,195 53,183 55,372 56,154 55,545 Other electric utilities............. 50,166 118,781 81,855 133,566 201,133 ---------- ---------- ---------- ---------- ---------- Revenues from energy deliveries......... 7,069,882 7,628,626 7,413,104 7,690,347 7,735,837 Miscellaneous.......... 161,156 (9,439) 112,303 92,538 142,771 Regulatory balancing accounts.............. (40,408) 71,441 (365,192) (396,578) 142,939 ---------- ---------- ---------- ---------- ---------- Operating revenues.. $7,190,630 $7,690,628 $7,160,215 $7,386,307 $8,021,547 ========== ========== ========== ========== ==========
19 The following table shows certain customer information: Selected Statistics: Total customers (at year- end)....................... 4,565,000 4,500,000 4,500,000 4,400,000 4,400,000 Average annual residential usage (kWh)................ 6,776 6,627 6,571 6,377 6,422 Average billed revenues per kWh (cents per kWh): Residential............... 10.77 11.88 11.92 12.22 12.25 Commercial................ 9.69 10.15 10.19 10.97 11.04 Industrial................ 5.72 6.09 6.37 6.88 7.05 Agricultural................ 11.42 10.52 10.92 11.37 10.78 Net plant investment per customer ($)............... 2,705 3,027 3,198 3,228 3,362
Electric Generating Capacity As described above in "Implementation of Electric Industry Restructuring-- Voluntary Generation Asset Divestiture," in 1998, Pacific Gas and Electric Company sold three fossil-fueled power plants and entered into agreements for the sale of an additional four fossil-fueled power plants and its geothermal facilities. Except as otherwise noted below, as of December 31, 1998, Pacific Gas and Electric Company owned and operated the following generating plants, all located in California, listed by energy source:
Net Number Operating of Capacity Generation Type County Location Units kW --------------- --------------- ------ ---------- Hydroelectric: Conventional Plants.............. 16 counties in Northern and Central California 109 2,698,100 Helms Pumped Storage Plant....... Fresno 3 1,212,000 --- ---------- Hydroelectric Subtotal......... 112 3,910,100 --- ---------- Steam Plants: Contra Costa(1).................. Contra Costa 2 680,000 Humboldt Bay..................... Humboldt 2 105,000 Hunters Point.................... San Francisco 3 377,000 Pittsburg(1)..................... Contra Costa 7 2,022,000 Potrero(1)....................... San Francisco 1 207,000 --- ---------- Steam Subtotal................... 15 3,391,000 --- ---------- Combustion Turbines: Hunters Point.................... San Francisco 1 52,000 Potrero(1)....................... San Francisco 3 156,000 Mobile Turbines(2)............... Humboldt and Mendocino 3 45,000 --- ---------- Combustion Turbines Subtotal..... 7 253,000 --- ---------- Geothermal: The Geysers Power Plant(1)(3).... Sonoma and Lake 14 1,224,000 Nuclear: Diablo Canyon.................... San Luis Obispo 2 2,160,000 --- ---------- Thermal Subtotal............... 38 7,028,000 --- ---------- Total......................... 150 10,938,100 === ==========
- -------- (1) In 1998, Pacific Gas and Electric Company entered into agreements to sell these power plants and its geothermal facilities in connection with electric industry restructuring. (2) Listed to show capability; subject to relocation within the system as required. (3) The Geysers Power Plant net operating capacity is based on adequate geothermal steam supply conditions. (Present steam conditions prevent the units from operating at full operating capacity.) 20 Diablo Canyon Diablo Canyon Operations Diablo Canyon consists of two nuclear power reactor units, each capable of generating up to approximately 26 million kilowatt-hours (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, 1998, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 81.4% and 82.9%, 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. Pacific Gas and Electric Company has been seeking NRC licensing authority to schedule such outages once every 24 months. Though nominal 20- month cycles are firm, achieving a 24-month cycle is uncertain and its implementation could be delayed. The schedule below assumes that a refueling outage for a unit will last approximately five weeks, 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 or changes in the length of the fuel cycle.
1999 2000 2001 2002 2003 -------- -------- ---- ---- -------- Unit 1 Refueling............................ February October May Startup.............................. March November June Unit 2 Refueling............................ October May February Startup.............................. November June March
Diablo Canyon Ratemaking Effective January 1, 1997, Pacific Gas and Electric Company's sunk costs in Diablo Canyon are recovered from ratepayers through a sunk cost revenue requirement, at a reduced return on common equity equal to 6.77% that will remain in effect through the end of the transition period. (Sunk costs are costs associated with the facility that are fixed and unavoidable and currently included in customers' electric rates.) Also effective January 1, 1997, a performance-based Incremental Cost Incentive Price (ICIP) mechanism was established to recover Diablo Canyon's variable and other operating costs and capital addition costs. The ICIP mechanism establishes a rate per kWh generated by the facility. This rate is based upon a fixed forecast of ongoing costs, capital additions, and capacity factors for the period 1997 through 2001. The fixed forecast of ICIP for 1999-2001 is shown below. The revenues are based on an assumed capacity factor of 83.6%. Incremental Cost Incentive Prices and Estimated Total CPUC Revenue Requirement
Estimated Total Revenue Requirement -------------------- 1999 2000 2001 ------ ------ ------ ICIP (cents per kWh)................................. 3.37 3.43 3.49 Sunk Cost Recovery ($ in millions)................... $1,259 $1,197 $1,135 ICIP Revenues ($ in millions)........................ 532 542 552 ------ ------ ------ Total Revenue Requirement ($ in millions)............ $1,791 $1,739 $1,687
The CPUC decision adopting the ratemaking mechanism excluded several items totaling $160 million from the sunk cost revenue requirement, including out- of-core fuel inventory, materials and supplies inventory, and prepaid insurance expenses. The CPUC decision requires that the costs of materials, supplies, and nuclear fuel be recovered through the ICIP mechanism as these items are used. The CPUC also disallowed about $70 million in plant costs from the sunk cost revenue requirement. 21 The CPUC decision also ordered that a financial verification audit of Diablo Canyon plant accounts be performed by an independent accounting firm, and that the CPUC hold a proceeding to review the results of the audit, including any proposed adjustments to Diablo Canyon accounts, following the completion of the audit. On August 31, 1998, an independent accounting firm retained by the CPUC completed its financial verification audit of Diablo Canyon plant accounts at December 31, 1996. The audit resulted in the issuance of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. The independent accounting firm also issued an agreed-upon special procedures report, requested by the CPUC, which questioned $200 million of the $3.3 billion sunk costs. The CPUC will review the results of the audit and may seek to make adjustments to Diablo Canyon sunk costs subject to transition cost recovery. At this time, the amount of transition cost disallowances, if any, cannot be predicted. Additional information concerning the financial impact of Diablo Canyon ratemaking is included in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 49 of the 1998 Annual Report to Shareholders. Nuclear Fuel Supply and Disposal Pacific Gas and Electric Company has purchase contracts for, and inventories of, uranium concentrates, uranium hexaflouride, and enriched uranium, as well as one contract for fuel fabrication. Based on current operations forecasts, Diablo Canyon's requirements for uranium supply, the conversion of uranium to uranium hexaflouride, and the enrichment of the uranium hexaflouride to enriched uranium will be satisfied by a combination of existing contracts and inventories through 2002, 2000, and 2002, respectively. The fuel fabrication contract for the two units will supply their requirements for the next seven operating cycles of each unit. These contracts are intended to ensure long- term fuel supply, but permit Pacific Gas and Electric Company the flexibility to take advantage of short-term supply opportunities. In most cases, Pacific Gas and Electric Company's nuclear fuel contracts are requirements-based, with the Company's obligations linked to the continued operation of Diablo Canyon. Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the U.S. Department of Energy (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, Pacific Gas and Electric Company signed a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Company'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, Pacific Gas and Electric Company's facilities are sufficient to store on-site all spent fuel produced through approximately 2006 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 2006. Pacific Gas and Electric Company is examining options for providing additional temporary spent fuel storage at Diablo Canyon or other facilities, pending disposal or storage at a DOE facility. In July 1988, the NRC gave final approval to Pacific Gas and Electric Company's plan to store radioactive waste from the nuclear generating unit (Unit 3) at Humboldt Bay Power Plant (Humboldt) at Humboldt prior to ultimately decommissioning the unit. The Company has agreed to remove all spent fuel when the federal disposal site is available. 22 Insurance Pacific Gas and Electric Company has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). NEIL, which is owned by utilities with nuclear generating facilities, provides insurance coverage against property damage, decontamination, decommissioning, and business interruption and/or extra expenses during prolonged accidental outages for reactor units in commercial operation. Under these insurance policies, if the nuclear generating facility of a member utility suffers a loss due to a prolonged accidental outage, the Company may be subject to maximum retrospective premium assessments of $17 million (property damage) and $5 million (business interruption), in each case per one-year policy period, if losses exceed the resources of NEIL. Pacific Gas and Electric Company has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. An additional $9.6 billion of coverage is provided by secondary financial protection required by federal law and 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 $200 million, Pacific Gas and Electric Company may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident. Decommissioning Pacific Gas and Electric Company's estimated total obligation to decommission and dismantle its nuclear power facilities is $1.5 billion in 1998 dollars ($5.1 billion in future dollars). This estimate, which includes labor, materials, waste disposal charges, and other costs, is based on a 1997 decommissioning cost study. A contingency to capture engineering, regulatory, and business environment changes is included in the total estimated obligation. Actual decommissioning costs are expected to vary from this estimate because of changes in the assumed dates of decommissioning, regulatory requirements, and technology, as well as differences in the amount of labor, materials, and equipment needed to complete decommissioning. The estimated total obligation needed to complete decommissioning is recognized proportionately over the license term of each facility. Nuclear 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 the nuclear facilities. The trust funds maintain substantially all of their investments in debt and equity securities. All earnings on the trust fund, net of authorized disbursements from the trusts and management and administrative fees, are reinvested. Monies may not be released from the external trust funds until authorized by the CPUC. In December 1997, the CPUC granted Pacific Gas and Electric Company's request for authority to disburse up to $15.7 million from the Humboldt Bay Power Plant decommissioning trust funds to finance three partial nuclear decommissioning projects at Humboldt Bay Power Plant Unit 3. Accordingly, as of December 31, 1998, $7.2 million (net of taxes) was disbursed from the Humboldt Bay Power Plant Unit 3 non-tax-qualified trust to reimburse the Company for nuclear decommissioning expenses associated with the partial decommissioning projects. In its 1999 GRC, Pacific Gas and Electric Company is seeking approval from the CPUC to use the tax savings resulting from the payment of tax-deductible nuclear decommissioning expenses from the Humboldt Bay Power Plant Unit 3 non- tax-qualified trust to fund nuclear decommissioning work. If the CPUC rejects the Company's request, an additional $4.9 million will be disbursed from the trust to reimburse the Company for the full amount of the 1998 nuclear decommissioning expenses of $12.1 million. A mechanism to flow the realized tax savings of $4.9 million associated with $12.1 million tax-deductible nuclear decommissioning expenses to ratepayers will be established. As of December 31, 1998, Pacific Gas and Electric Company had accumulated external trust funds with an estimated fair value of $1.2 billion, based on quoted market prices and net of deferred taxes on unrealized gains, to be used for the decommissioning of the Company's nuclear facilities. The amount recovered in rates for nuclear decommissioning costs is authorized by the CPUC as part of the GRC. The CPUC considers the trusts' asset levels, together with revised earnings and decommissioning cost 23 assumptions, to determine the amount of decommissioning costs it will authorize in rates for contribution to the trusts. The monies contributed to the decommissioning trusts, together with existing trust fund balances and projected earnings, are intended to satisfy the estimated future obligation for decommissioning costs. For the year ended December 31, 1998, nuclear decommissioning costs recovered in rates were $33 million. Beginning January 1, 1998, nuclear decommissioning costs, which are not transition costs, were being recovered through a nonbypassable charge which will continue until those costs are fully recovered. Recovery of decommissioning costs may be accelerated to the extent possible under the rate freeze. 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 when and if GRCs are discontinued. Other Electric Resources QF Generation and Other Power-Purchase Contracts By federal law, Pacific Gas and Electric Company is required to purchase electric energy and capacity provided by independent power producers. The CPUC established a series of power-purchase contracts and set the applicable terms, conditions, price options, and eligibility requirements. Under these contracts, Pacific Gas and Electric Company is required to make payments only when energy is supplied or when capacity commitments are met. The total cost of these payments is recoverable in rates. Pacific Gas and Electric Company's contracts with these power producers expire on various dates through 2028. Total energy payments are expected to decline in the years 1999 through 2001. Total capacity payments are expected to remain at current levels during this period. Deliveries from these power producers account for approximately 23% of Pacific Gas and Electric Company's 1998 electric energy requirements and no single contract accounted for more than 5% of the Company's energy needs. Pacific Gas and Electric Company has negotiated early termination or suspension of certain power-purchase contracts. These amounts are expected to be recovered in rates and as such are reflected as deferred charges on the Company's balance sheet. At December 31, 1998, the total discounted future payments remaining under early termination or suspension contracts is $48 million. Pacific Gas and Electric Company also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Company must make specified semi-annual minimum payments whether or not any energy is supplied (subject to the provider'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. The total cost of these payments is recoverable in rates. At December 31, 1998, the undiscounted future minimum payments under these contracts are $32 million for each of the years 1999 through 2003 and a total of $280 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 7.5% of Pacific Gas and Electric Company's 1998 electric energy requirements. The amount of energy received and the total payments made under all these power-purchase contracts were:
1998 1997 1996 ------ ------ ------ (in millions) Kilowatt-hours received.............................. 25,994 24,389 26,056 Energy payments...................................... $ 943 $1,157 $1,136 Capacity payments.................................... $ 529 $ 538 $ 521 Irrigation district and water agency payments........ $ 53 $ 56 $ 52
As of December 31, 1998, Pacific Gas and Electric Company had commitments to purchase approximately 5,200 MW of capacity under CPUC-mandated power-purchase agreements. Of the 5,200 MW, approximately 24 4,400 MW were operational. Development of the majority of the balance is uncertain and it is estimated that very few of the remaining contracts will become operational. The 4,400 MW of operational capacity consists of 2,800 MW from cogeneration projects, 600 MW from wind projects, and 1,000 MW from other projects, including biomass, waste-to-energy, geothermal, solar, and hydroelectric. Geothermal Generation In late 1998 and January 1999, Pacific Gas and Electric Company entered into agreements to sell its geothermal units at The Geysers Power Plant located in Lake and Sonoma counties (Geysers) for a total of $213 million. The sale is subject to final approval by the CPUC and other regulatory agencies, and the transaction is expected to close by the first half of 1999. See "Electric Utility Operations--Implementation of Electric Industry Restructuring-- Voluntary Generation Asset Divestiture" above. The Geysers are forecast to operate at reduced capacities because of declining geothermal steam supplies and curtailment of the Geysers due to the existence of more economic sources of electric generation. The Company's agreements with several of its steam suppliers permit the Company to curtail generation at the Geysers at the Company's discretion. The 1999 consolidated Geysers capacity factor through the expected close of sale is forecast to be approximately 38% of installed capacity in 1999, which includes economic curtailments, forced outages, scheduled overhauls, and projected steam shortage curtailments, as compared to the actual Geysers capacity factor of 44% in 1998. Electric Transmission and Distribution To transport energy to load centers, Pacific Gas and Electric Company as of December 31, 1998, owned and operated approximately 18,624 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations having a capacity of approximately 39,565,906 kilovolt-amperes (kVa), including spares, excluding power plant interconnection facilities. Energy is distributed to customers through approximately 112,080 circuit miles of distribution system and distribution substations having a capacity of approximately 23,575,800 kVa. In 1998, the utilities relinquished control, but not ownership, of their transmission facilities to the ISO. 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. In 1998, the FERC approved the various forms of agreements for must-run facilities that have been entered into between the utilities and the ISO to ensure grid reliability. The FERC has also approved a proposal from Pacific Gas and Electric Company and the other California utilities that distinguishes between local distribution facilities and transmission facilities. The order defines jurisdiction for the CPUC over local distribution and retail power customers. The FERC will have jurisdiction over the transmission facilities as defined in the order and over the transmission aspects of retail direct access. Most of Pacific Gas and Electric Company's distribution services will remain subject to CPUC jurisdiction. On December 17, 1998, the CPUC opened a rulemaking proceeding to consider whether it should pursue further reforms in the structure and regulatory framework governing electricity distribution service. The CPUC will solicit comments and proposals regarding the scope and substance of issues, possible policy options, and procedural steps the CPUC could pursue in considering distributed generation and competition in electric distribution service. The rulemaking was opened, in part, in response to a request from Pacific Gas and Electric Company for a comprehensive review of distribution competition. Initial comments are due to the CPUC on March 17, 1999. On December 8, 1998, Pacific Gas and Electric Company lost power on all its 115 kV transmission lines from the San Mateo Substation to San Francisco, and the two San Francisco power plants tripped off line, leaving more than 456,000 customers without power. The Company immediately notified the ISO of the outage. Only the approximately 13,000 customers served from the 230 kV transmission line maintained power. Six hours later, the Company had restored service to all but 27,000 customers. Within the next two hours, all customers had power. 25 Pacific Gas and Electric Company immediately began an internal investigation of the outage. On December 17, 1998, the CPUC issued an Order Instituting Investigation concerning the power outage. The order required Pacific Gas and Electric Company to file a report by January 25, 1999 to address various issues arising from the outage, including chronology, cause, response, mitigation, prevention, and handling of claims. On January 25, 1999, the Company completed its internal investigation and filed a report with the CPUC detailing the results of its investigation. The Company's internal investigation confirmed that the outage resulted when a construction crew working on an equipment upgrade project at the San Mateo Substation failed to follow established procedures and practices, and failed to remove temporary protective grounds. Separately, a transmission operator at the substation then energized the substation bus, but failed to engage the protective relays associated with the bus. (A "bus" refers to a collection point for connecting transmission lines and flowing power out from a substation.) Without the local protective system in place, the electric current was sent to ground, and the system took a half second to isolate the fault instead of the one-tenth of a second that would normally be required. This delay resulted in a sharp drop in transmission line voltages, and the transmission system into San Francisco then experienced large power fluctuations. As they are designed to do, protective systems at other substations and at the Hunters Point and Potrero power plants separated from the transmission system to make sure that the fluctuations did not extend to other parts of the Company's system, and that no damage occurred to equipment in San Francisco's electric facilities that could have delayed restoration of operations. Pacific Gas and Electric Company is taking actions to strengthen and adjust its grounding and switching procedures as preventative measures to minimize the risk that such an initiating event could occur in the future. The Company's internal investigation found that the transmission system design is consistent with the requirements of the North American Electric Reliability Council and the Western Systems Coordinating Council, and performed as designed given the initiating event that occurred. As a result of this finding, the Company is not proposing modifications to the system design. Finally, the Company and the ISO are using the lessons learned in this event to strengthen their communications. Gas Utility Operations Pacific Gas and Electric Company owns and operates an integrated gas transmission, storage, and distribution system in California. At December 31, 1998, Pacific Gas and Electric Company's system, including the PG&E Expansion (Line 401), consisted of approximately 5,706 miles of transmission pipelines, three gas storage facilities, and approximately 37,023 miles of gas distribution lines. Pacific Gas and Electric Company's peak day send-out of gas on its integrated system in California during the year ended December 31, 1998, was 4,300 million cubic feet (MMcf). The total volume of gas throughput during 1998 was approximately 850,000 MMcf, of which 295,000 MMcf was sold to direct end-use or resale customers, 158,000 MMcf was used by Pacific Gas and Electric Company primarily for its fossil-fueled electric generating plants, and 397,000 MMcf was transported as customer-owned 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 as a result of a CPUC order. A comprehensive biennial report is prepared in even-numbered years with a supplemental report in intervening odd-numbered years. The 1998 California Gas Report updates Pacific Gas and Electric Company's annual gas requirements forecast (excluding bypass volumes) for the years 1998 through 2015, forecasting average annual growth in gas throughput served by the Company of approximately 1%. 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 utility electric generation, fuel switching, and new technology. In addition, some large customers, mostly in the industrial and enhanced oil recovery sectors, may have the ability to use unregulated private pipelines or interstate pipelines, bypassing the Company's system entirely. The 1998 California Gas Report forecasts a total bypass volume of 133,600 MMcf for 1999. 26 Gas Operating Statistics The following table shows Pacific Gas and Electric Company's operating statistics (excluding subsidiaries except where indicated) for gas, including the classification of sales and revenues by type of service.
Years Ended December 31 ---------------------------------------------------------- 1998 1997 1996 1995 1994 ---------- ---------- ---------- ---------- ---------- Customers (average for the year): Residential............ 3,536,089 3,491,963 3,455,086 3,417,556 3,372,768 Commercial............. 200,620 198,453 198,071 197,939 196,509 Industrial............. 1,610 1,650 1,500 1,500 1,400 Other gas utilities.... 5 3 2 2 2 ---------- ---------- ---------- ---------- ---------- Total.............. 3,738,324 3,692,069 3,654,659 3,616,997 3,570,679 ========== ========== ========== ========== ========== Gas supply--thousand cubic feet (Mcf) (in thousands): Purchased from suppliers in: Canada............... 298,125 280,084 253,209 261,800 319,453 California........... 17,724 10,655 28,130 31,158 31,757 Other states......... 122,342 131,074 110,604 117,538 249,733 ---------- ---------- ---------- ---------- ---------- Total purchased.... 438,191 421,813 391,943 410,496 600,943 Net from storage (to storage).............. 14,468 14,160 6,871 (10,921) 3,591 ---------- ---------- ---------- ---------- ---------- Total.............. 452,659 435,973 398,814 399,575 604,534 Pacific Gas and Electric Company use, losses, etc.(1)....... 158,241 173,789 134,375 129,671 297,604 ---------- ---------- ---------- ---------- ---------- Net gas for sales.. 294,418 262,184 264,439 269,904 306,930 ========== ========== ========== ========== ========== Bundled gas sales and transportation service--Mcf (in thousands): Residential............ 223,706 191,327 190,246 191,724 214,358 Commercial............. 66,082 60,803 62,178 64,135 72,183 Industrial............. 4,616 10,054 12,015 14,045 19,495 Other gas utilities.... 14 0 0 0 894 ---------- ---------- ---------- ---------- ---------- Total.............. 294,418 262,184 264,439 269,904 306,930 ========== ========== ========== ========== ========== Transportation service only--Mcf (in thousands): Vintage system (Substantially all Industrial)(2)........ 319,099 218,660 189,695 143,921 142,393 PG&E Expansion (Line 401).................. 77,773 233,269 237,776 240,506 200,755 ---------- ---------- ---------- ---------- ---------- Total.............. 396,872 451,929 427,471 384,427 343,148 ========== ========== ========== ========== ========== Revenues (in thousands): Bundled gas sales and transportation service: Residential.......... $1,414,313 $1,170,135 $1,109,463 $1,205,223 $1,268,966 Commercial........... 426,299 374,084 362,819 421,397 444,805 Industrial........... 24,634 46,592 42,520 42,106 57,297 Other gas utilities.. 1,072 3,701 510 0 2,371 ---------- ---------- ---------- ---------- ---------- Bundled gas revenues.......... 1,866,318 1,594,512 1,515,312 1,668,726 1,773,439 Transportation only revenue: Vintage system (Substantially all Industrial)......... 232,038 207,160 180,197 167,325 132,509 PG&E Expansion (Line 401)................ 42,194 90,180 85,144 82,904 58,442 ---------- ---------- ---------- ---------- ---------- Transportation service only revenue.......... 274,232 297,340 265,341 250,229 190,951 Miscellaneous.......... 41,364 50,295 (9,271) (18,018) 40,427 Regulatory balancing accounts.............. (448,351) (137,787) 57,864 (43,771) (101,443) Subsidiaries(3)........ 0 0 210,556 201,951 177,688 ---------- ---------- ---------- ---------- ---------- Operating revenues.......... $1,733,563 $1,804,360 $2,039,802 $2,059,117 $2,081,062 ========== ========== ========== ========== ==========
- -------- (1) Primarily includes fuel for Pacific Gas and Electric Company's fossil- fueled generating plants. (2) Does not include on-system transportation volumes transported on the PG&E Expansion of 34,169 MMcf, 72,958 MMcf, 78,552 MMcf, 100,207 MMcf, and 79,749 MMcf, for 1998, 1997, 1996, 1995, and 1994, respectively. (3) In January 1997, a Pacific Gas and Electric Company subsidiary--Pacific Gas Transmission Company (PGT)--became a subsidiary of PG&E Corporation and is now known as PG&E Gas Transmission, Northwest Corporation. 27
Years Ended December 31 ------------------------------------------------- 1998 1997 1996 1995 1994 --------- --------- --------- --------- --------- Selected Statistics: Total customers (at year- end)....................... 3,766,000 3,700,000 3,700,000 3,600,000 3,500,000 Average annual residential usage (Mcf)................ 63 55 55 56 64 Heating temperature--% of normal(1).................. 93.0 71.7 75.7 75.3 104.4 Average billed bundled gas sales revenues per Mcf: Residential................. $6.32 $6.12 $5.83 $6.29 $5.92 Commercial.................. 6.45 6.15 5.84 6.57 6.16 Industrial.................. 5.36 4.63 3.54 3.00 2.94 Average billed transportation only revenue per Mcf: Vintage system.............. 0.66 0.71 0.67 0.69 0.60 PG&E Expansion (Line 401)... 0.54 0.39 0.36 0.34 0.29 Net plant investment per customer (2)............... $1,040 $1,031 $1,378 $1,315 $1,340
- -------- (1) Over 100% indicates colder than normal. (2) The net plant investment per customer figures for 1997 and 1998 are lower than in previous years because they exclude subsidiaries. Natural Gas Supplies The objective of Pacific Gas and Electric Company's gas supply planning is to maintain a balanced supply portfolio which provides supply reliability and contract flexibility, minimizes costs, and fosters competition among suppliers. Under current CPUC regulations, Pacific Gas and Electric Company purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual, and operational constraints. During the year ended December 31, 1998, approximately 68% of the Company's total purchases of natural gas consisted of Canadian gas purchased from various Canadian producers and transported by Canadian pipeline companies and PG&E Gas Transmission, Northwest Corporation; approximately 4% was purchased in California; and approximately 28% was purchased in the U.S. Southwest and transported by the El Paso Natural Gas Company or Transwestern Pipeline Company pipelines. California purchases include both purchases from various California producers and purchases of gas transported to California by others. The following table shows the total volume and average price of gas in dollars per thousand cubic feet (Mcf) purchased by Pacific Gas and Electric Company from these sources during each of the last five years.
Years Ended December 31 ---------------------------------------------------------------------------------------------- 1998 1997 1996 1995 1994 ------------------ ------------------ ------------------ ------------------ ------------------ Thousands Avg. Thousands Avg. Thousands Avg. Thousands Avg. Thousands Avg. of Mcf Price(1) of Mcf Price(1) of Mcf Price(1) of Mcf Price(1) of Mcf Price(1) --------- -------- --------- -------- --------- -------- --------- -------- --------- -------- Canada................. 298,125 $2.00 280,084 $1.77 253,209 $1.57 261,800 $1.34 319,453 $1.94 California............. 17,724 2.44 10,655 2.12 28,130 1.90 31,158 1.32 31,757 1.55 Other states........... (substantially all U.S Southwest)....... 122,342 2.62 131,074 3.75 110,604 3.72 117,538 2.64 249,733 2.41 ------- ----- ------- ----- ------- ----- ------- ----- ------- ----- Total/Weighted Average............... 438,191 $2.19 421,813 $2.39 391,943 $2.21 410,496 $1.71 600,943 $2.12 ======= ===== ======= ===== ======= ===== ======= ===== ======= =====
- -------- (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 were previously bundled in gas rates. Gas Regulatory Framework In August 1997, the CPUC approved the Gas Accord which restructures Pacific Gas and Electric Company's gas services and its role in the gas market. As discussed above (see "General--Competition and the Changing Regulatory Environment--Gas Industry"), the Gas Accord separates, or "unbundles," the rates for Pacific Gas 28 and Electric Company's gas transmission services from its distribution services, increases the opportunities for core customers to purchase gas from competing suppliers, establishes a form of incentive regulation to measure the reasonableness of core procurement costs, and establishes gas transmission and storage rates from March 1998 through December 2002. The Gas Accord also settled various issues pending in certain regulatory proceedings. The CPUC is considering further changes in California's natural gas industry. See "General--Competition and the Changing Regulatory Environment-- Gas Industry" above. Transportation Commitments Pacific Gas and Electric Company has gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for payment of fixed demand charges for reserving firm capacity on the pipelines. The total demand charges that Pacific Gas and Electric Company will pay each year may change due to changes in tariff rates. The total demand and volumetric transportation charges paid by Pacific Gas and Electric Company under these agreements were approximately $113 million in 1998. This amount includes payments made to PG&E Gas Transmission, Northwest Corporation (PG&E GT-Northwest) of approximately $49 million in 1998, but which are eliminated in the consolidated financial statements of PG&E Corporation. As a result of regulatory changes, Pacific Gas and Electric Company no longer procures gas for most of its noncore customers, resulting in a decrease in the Company's need for firm transportation capacity for its gas purchases. Pacific Gas and Electric Company continues to procure gas for almost all of its core customers and those noncore customers who choose bundled service (core subscription customers). Pacific Gas and Electric Company is continuing its efforts to broker or assign any of its remaining contracted-for but unused interstate transportation capacity, including unused capacity held for its core and core subscription customers. Under a firm transportation agreement with PG&E GT-Northwest that runs through October 31, 2005, Pacific Gas and Electric Company currently retains approximately 600 million cubic feet per day (MMcf/d) on the PG&E GT-Northwest system to support its core and core subscription customers. The Company has been able to broker its unused capacity on PG&E GT-Northwest's system, when not needed for core and core subscription customers. In general, any shortfall resulting from the difference between the fixed demand charges Pacific Gas and Electric Company pays under gas transportation contracts with interstate pipeline companies for the reservation of interstate pipeline capacity that the Company no longer uses to serve noncore customers, and the revenues Pacific Gas and Electric Company obtains from brokering that capacity, is eligible for rate recovery through the Interstate Transition Cost Surcharge (ITCS), subject to a reasonableness review. Various groups had challenged Pacific Gas and Electric Company's recovery of these amounts, including amounts which arose in connection with firm transportation commitments that the Company had entered into with PG&E GT-Northwest and El Paso Natural Gas Company (El Paso). (The agreement with El Paso terminated as of December 31, 1997.) Under the Gas Accord, these challenges were resolved through Pacific Gas and Electric Company's agreement to forgo recovery of 100 percent and 50 percent of the ITCS amounts allocated for collection from its core and noncore customers, respectively. In 1992, Pacific Gas and Electric Company entered into a firm transportation agreement with Transwestern Pipeline Company (Transwestern), which expires in 2007, to meet core gas sales demands and electric generation needs. The demand charges associated with the entire Transwestern capacity are currently approximately $26 million per year. Pacific Gas and Electric Company was not permitted to include any Transwestern firm capacity demand charges in rates or in the ITCS account, although the Company was authorized to record costs associated with its Transwestern capacity in a balancing account, with recovery of such costs subject to reasonableness review proceedings. In 1995, the CPUC determined that it was unreasonable for Pacific Gas and Electric Company to commit to transportation capacity with Transwestern and disallowed recovery of the costs 29 of capacity for 1992. It indicated that it would disallow costs through the term of the contract unless Pacific Gas and Electric Company could demonstrate on an annual basis that the benefit of the commitment outweighed the costs in a particular year. As part of the Gas Accord, Pacific Gas and Electric Company agreed to resolve this issue by forgoing the recovery of costs associated with capacity originally subscribed to in order to serve core customers through 1997 and to limit its recovery of demand charges through the CPIM during the period 1998 through 2002. Core Procurement Incentive Mechanism Pacific Gas and Electric Company's core gas procurement costs for the period June 1994 to 2002 are recoverable under a core procurement incentive mechanism (CPIM), a form of incentive regulation established by the Gas Accord. The CPIM provides the Company with a direct financial incentive to procure gas and transportation services at the lowest reasonable costs by comparing all procurement costs to an aggregate market-based benchmark. If costs fall within a range (tolerance band) around the benchmark, costs are deemed reasonable and fully recoverable from ratepayers. If procurement costs fall outside the tolerance band, the Company's ratepayers and shareholders share savings or costs, respectively. In January 1999, the Company filed a performance report with the ORA of the CPUC, recommending a shareholder award of $190,766, for the period January 1, 1998 through October 31, 1998. During 1998, the Company submitted a similar report to the ORA for its January 1997 through December 1997 performance, recommending a shareholder award of approximately $1.8 million. After ORA comments on the Company's performance reports, the Company will seek CPUC approval for all gas procurement costs for both periods, including the Company's shareholder awards. PGT/Pacific Gas and Electric Company Pipeline Expansion In November 1993, PG&E GT-Northwest (then known as Pacific Gas Transmission Company or PGT) and Pacific Gas and Electric Company placed in service the Pipeline Expansion, an expansion of their interconnected natural gas transmission systems from the Canadian border into California. The 840-mile combined Pipeline Expansion provides an additional 148 MMcf/d of firm capacity to the Pacific Northwest and an additional 851 MMcf/d of capacity to Northern and Southern California. The conditions of the CPUC's approval of the construction of Pacific Gas and Electric Company's portion of the Pipeline Expansion (PG&E Expansion or Line 401) placed the Company at risk for its decision to construct based on its assessment of market demand and for undersubscription and underutilization of the facility. The CPUC required the application of a "cross-over" ban under which volumes delivered from the incremental portion owned by PG&E GT- Northwest (PGT Expansion) of the Pipeline Expansion must be transported at an incremental PG&E Expansion rate. The costs of PG&E Expansion operations were recovered only from PG&E Expansion customers, through rates established in separate PG&E Expansion rate proceedings. Under the Gas Accord, Pacific Gas and Electric Company is at risk for recovery of all gas transmission costs, including costs of the PG&E Expansion, through rates; however, a portion of the PG&E Expansion will be combined with other transmission assets (specifically, a portion of the Company's Line 400) for ratemaking purposes. This new ratemaking treatment for gas transmission assets allows all shippers supplying noncore customers to transport Canadian gas in California at a single rate, and obviates the need for the "cross-over" ban, which was eliminated under the Gas Accord. Further, in the Gas Accord, the CPUC adopted a rule under which Pacific Gas and Electric Company is required, whenever it discounts service for a shipper on its Line 400/401 delivering primarily Canadian gas within the Company's service territory, to contemporaneously offer a commensurate discount to all shippers delivering Southwest or California source gas on Line 300 within the Company's service territory. 30 WHOLESALE OPERATIONS OF AFFILIATES Gas Transmission Operations PG&E Corporation participates in the "midstream" portion of the gas business through PG&E GTT, PG&E Gas Transmission Teco, Inc. and PG&E GT-Northwest. The "midstream" gas business includes (1) gas gathering, processing, and storage, and transportation of natural gas and natural gas liquids (NGLs); (2) the marketing of natural gas to gas distribution companies, electric utilities, municipalities, marketers, independent power producers, and end-use customers; (3) the transportation of natural gas for these customers, producers, and other pipelines; and (4) the marketing and transportation of NGLs to various customers, including end-use customers. PG&E GTT and PG&E Gas Transmission Teco, Inc. own and operate gas gathering, transportation, and processing facilities, and NGL pipelines. The NGL business includes the gathering of natural gas, the extraction of NGLs from natural gas, the fractionation of mixed NGLs into component products (e.g., ethane, propane, butane, and natural gasoline), and the transportation and marketing of NGLs. The Texas operations include approximately 6,600 miles of natural gas pipelines and joint ownership or leasehold interests in approximately 1,900 miles of pipelines, including pipelines from Waha in west Texas to the Katy area near Houston, Texas. These pipeline systems have the capacity to transport more than 3 billion cubic feet (bcf) of gas per day. Other Texas assets include a long-term lease of 7.2 bcf of storage capacity, approximately 536 miles of NGL pipelines and nine natural gas processing plants with a combined capacity of approximately 1.6 bcf per day of gas throughput, capable of producing approximately over 100,000 barrels per day of NGLs. PG&E GT-Northwest owns and operates gas transmission pipelines and associated facilities which extend over 612 miles from the Canada-U.S. border to the Oregon-California border and are capable of transporting 2.4 bcf per day of natural gas. It also owns two smaller diameter pipeline extensions within Oregon, totaling 106 miles. In July 1998, PG&E Corporation sold its natural gas pipeline in Australia as part of its strategy to focus on the domestic market. In September 1996, the FERC approved a settlement of PG&E GT-Northwest's 1994 rate case. The major issue in this proceeding was whether PG&E GT- Northwest's mainline transportation rates should be equalized through the use of rolled-in cost allocations or whether they should continue to reflect the use of incremental cost allocation to determine the rates to be paid by firm shippers. (Under incremental rates, a pipeline would generally charge higher rates to shippers contracting for capacity on newly-added expansion facilities, as compared to shippers using depreciated pre-expansion facilities.) The settlement provides for rolled-in rates effective November 1996. To mitigate the impact of the higher rolled-in rates on shippers who were paying lower rates under contracts executed prior to construction of the PGT Expansion, most of the firm shippers who took service prior to such time receive a reduction from the rolled-in rate for a six-year period, while PGT Expansion firm shippers pay a surcharge in addition to the rolled-in rates to offset the effect of the mitigation. See "Utility Operations--Gas Utility Operations--PGT/Pacific Gas and Electric Company Pipeline Expansion" above. The settlement also provides for rates based on a return on equity of 12.2%. In 1998, petitions filed by various parties for rehearing of the FERC order approving the settlement were denied. Some parties have appealed the FERC's denial of these rehearing petitions to the U.S. Court of Appeals for the District of Columbia Circuit, but PG&E GT-Northwest currently expects the settlement to be upheld. Independent Power Generation Through USGen and its affiliates, PG&E Corporation participates in the development, construction, operation, ownership, and management of non-utility electric generating facilities that compete in the United States power generation market. USGen is headquartered in Bethesda, Maryland. In 1998, PG&E Corporation, through its indirect subsidiary, USGen New England, Inc. (USGenNE), completed the acquisition of a portfolio of electric generating assets and power supply contracts from NEES for 31 $1.59 billion, plus $85 million for early retirement and severance costs previously committed to by NEES. Including fuel and other inventories and transaction costs, PG&E Corporation's financing requirements were approximately $1.8 billion, funded through $1.3 billion of debt, a $425 million equity contribution, and $70 million from cash on hand and other sources. The debt was raised through revolving credit facilities established at both the USGen and the USGenNE levels. Specifically, a $1.1 billion credit facility was established at the USGen level, and $575 million credit facility was established at the USGenNE level. In December 1998, USGenNE canceled $475 million of this $575 million facility through a sale-leaseback transaction involving the pumped storage facility acquired from NEES. The acquired NEES facilities consist of two conventional hydroelectric systems with 14 stations, three fossil-fuel stations (coal, oil, and natural gas) with 11 units, and a pumped storage facility, with a combined generating capacity of approximately 4,000 MW. In addition, USGenNE assumed the purchase obligations under 27 multi-year power-purchase agreements between NEES's subsidiary, New England Power, and other utility and non-utility wholesale suppliers representing an additional 1,100 MW of production capacity. Subsequently, several of the power-purchase agreements expired and/or were transferred, thereby reducing the total capacity to the current level of approximately 800 MW. USGenNE entered into agreements with NEES as part of the acquisition, which (1) provide that NEES shall make annual support payments through early 2008 to offset the cost of power associated with these above- market contracts, and (2) require that USGenNE provide electricity to NEES under supply agreements that expire over the next six to 11 years. Three of the four states in which the acquired assets are located (Massachusetts, Rhode Island, and New Hampshire) were also among the first states in the country to introduce retail competition. (A referendum in Massachusetts reaffirming electric industry restructuring was approved by the voters in November 1998.) Connecticut also has passed retail competition legislation. The acquired assets are located within the New England Power Pool (NEPOOL). The wholesale electricity market in New England features a bid-based, real- time pricing structure. Traditionally, NEPOOL has operated as a "tight power pool," one in which the utilities within the pool dedicate their generation resources to be centrally dispatched. Dispatch starts with the lowest-cost generation and ends with the highest-cost generation. In 1998, an independent system operator for the New England states (ISO-NE) began to provide central dispatch service and to operate the power pool as a competitive wholesale marketplace. As a result, the NEPOOL market is in the midst of transitioning to a competitive market. The duties of the ISO-NE include scheduling the operations of the regional transmission systems and, importantly, operating a power exchange for seven generation products (the "Interchange"). These products are energy, installed (monthly) capacity and operable (hourly) capacity, three types of reserves and automatic generation control (adjustment of generators to meet the second-to-second changes in electric load). The installed capacity market began operations on April 1, 1998. The balance of the Interchange is anticipated to begin operations on April 1, 1999, although this date is subject to final implementation by the ISO-NE. In these New England states, the utility companies providing service to retail customers are required to provide Standard Offer Service (SOS) to those customers. The SOS is intended to provide consumers with a price benefit (the commodity electric price offered to the retail customer is expected to be less than the market price) for the first several years, followed by a price disincentive that is intended to stimulate the retail market. Retail customers may continue to receive SOS through June 30, 2002, in New Hampshire (subject to early termination on December 31, 2000, at the discretion of the New Hampshire Public Service Commission); through December 31, 2004, in Massachusetts; and through December 31, 2009, in Rhode Island. However, if any customer elects to have their electricity provided by an alternate supplier, they are precluded from returning to the SOS. In connection with the purchase of the NEES generation assets, PG&E Corporation, through USGenNE, entered into agreements to supply the electric capacity and energy requirements necessary for NEES to meet its SOS obligations. In December 1998, NEES's New Hampshire utility subsidiary, Granite State Electric Co., reached an agreement with Constellation Power Source, Inc. under which Constellation Power Source, Inc. will 32 provide the SOS for Granite State Electric Co.'s customers. USGenNE retains its supply obligations for Massachusetts Electric Company and Narrangansett Electric Company, two utility subsidiaries of NEES located in Massachusetts and Rhode Island, respectively. NEES is responsible for passing on to PG&E Corporation the revenues generated from the SOS. Initially, approximately 90% of the operating capacity acquired from NEES, including capacity and energy generated by independent power producers (IPPs) under the assumed power-purchase agreements, has been dedicated to providing SOS. To the extent that customers eligible to receive SOS choose alternate suppliers this percentage will decrease. Like California utilities, the New England utilities have entered into agreements with IPPs to provide energy and capacity at prices which are anticipated to be in excess of market prices. As described above, USGenNE assumed NEES's contractual rights and duties under certain power-purchase agreements with IPPs, which in the aggregate provide for approximately 800 MW of capacity. In connection with the acquisition of NEES's generating assets, USGenNE is required to pay NEES amounts due from NEES to the IPPs in accordance with their power-purchase agreements. These payment obligations are reduced by monthly support payments that NEES pays USGenNE. Finally, in connection with the NEES acquisition, USGenNE obtained the right to purchase NEES's nuclear generated electric energy, capacity, and associated products at market prices up to the entire amount available. This right terminates automatically with respect to any nuclear facility that is sold or ceases operation for any reason, and if not terminated earlier, expires at termination of the SOS. The financial impact of the acquisition of the NEES assets on PG&E Corporation is subject to a number of risks and uncertainties, including future market prices of power in the region where the NEES assets are located, future fuel prices, the development of a competitive market in the states in which the NEES assets are located, the extent to which operating efficiencies at the NEES plants can be attained, changes in legislation affecting electric industry restructuring and in the regulatory environment in the states where the NEES assets are located, the extent of the obligation to provide electricity under the SOS at prices below cost or market, the extent to which a liquid, well-structured trading market develops for wholesale electric power in the states in which the NEES assets are located, and generating capacity expansion and retirements by others. As of December 31, 1998, USGen affiliates had ownership interests in 30 operating plants (including the assets acquired from NEES) in 10 states. The total generating capacity of these 30 plants is approximately 6,560 MW. PG&E Corporation's combined net equity ownership and leased interest in these plants as of December 31, 1998, represented approximately 5,300 MW. The plants were financed largely with a combination of equity or equity commitments from the project sponsors and non-recourse debt. (For a description of the financing of the NEES acquisition, see above.) USGen, through its affiliate, U.S. Operating Services Company (USOSC), provides contract operations and maintenance services to many of these facilities. Nationwide, USGen's power plant development activities exceed 8,600 MW in 8 states. USGen and its affiliated or managed facilities sold 22,242,949 million megawatt-hours (MWh) of electricity in 1998, including sales of electricity from the generating facilities acquired from NEES on September 1, 1998. 33 The following table sets forth information regarding the operating generating plants in which USGen affiliates have ownership or leasehold interests. The table also notes the operating plants which USGen affiliates manage or operate, or both manage and operate, power plant operations. Portfolio of Operating Generating Plants
Date Placed in Commercial Plant MWs Fuel Location Service ----- --- ---- -------- -------------- Bear Swamp Facility(1),(2) Pumped Storage 2 Units........... 588 Water Massachusetts 1974 Fife Brook....................... 10 Water 1974 Brayton Point Station (2) Unit Nos. 1, 2 and 3............. 1,130 Coal Massachusetts 1963, '64, '69 Unit No. 4....................... 446 Oil/Gas 1974 Diesel Generators................ 10 Diesel Oil N/A Carneys Point....................... 260 Coal New Jersey 1994 Cedar Bay........................... 250 Coal Florida 1994 Connecticut River (2) Hydroelectric 26 Units........... 484 Water New Hampshire/Vermont 1909-1957 Deerfield River (2) Hydroelectric 15 Units........... 84 Water Massachusetts/Vermont 1912-1927 Hermiston........................... 474 Natural Gas Oregon 1996 Indiantown.......................... 330 Coal Florida 1995 Logan............................... 225 Coal New Jersey 1995 Manchester St. Station (2) 3 Combined Cycle Units........... 495 Natural Gas Rhode Island 1995 MASSPOWER........................... 240 Natural Gas Massachusetts 1993 Northampton......................... 110 Waste Coal Pennsylvania 1995 Pittsfield.......................... 165 Natural Gas Massachusetts 1990 Salem Harbor Station (2) Unit Nos. 1, 2 and 3............. 314 Coal Massachusetts 1952, '52, '58 Unit No. 4....................... 400 Oil 1972 Scrubgrass.......................... 83 Waste Coal Pennsylvania 1993 Selkirk............................. 345 Natural Gas New York 1994 ----- Total MWs/Operating Plants... 6,443 USGen Affiliate Investments Colstrip (3)........................ 37 Waste Coal Montana 1990 Panther Creek (3)................... 83 Waste Coal Pennsylvania 1992 ----- Total MWs from Investments... 120 ===== Total MWs in Operation (4)... 6,563
- -------- (1) Unlike other operating facilities in which USGen affiliates have ownership and management interests, the Bear Swamp Facility is owned by a third party through a single-investor lease arrangement. USGen maintains full management and operating responsibility for the facility. (2) Acquired from NEES on September 1, 1998. (3) USGen affiliates have an ownership or leasehold interest in these plants, but do not manage power plant operations. (4) Of the total of 6,563 megawatts, USGen's net equity ownership and leased percentage is 5,282 megawatts. 34 Energy Trading PG&E Energy Trading-Gas Corporation and PG&E Energy Trading-Power, L.P. (collectively referred to as PG&E Energy Trading), headquartered in Houston, Texas, purchase bulk volumes of power and natural gas from PG&E Corporation affiliates and the wholesale market. PG&E Energy Trading then schedules, transports, and resells these commodities, either directly to third parties or to other PG&E Corporation affiliates. PG&E Energy Trading also provides price risk management services to PG&E Corporation's other businesses (except Pacific Gas and Electric Company) and to wholesale customers. Additionally, PG&E Energy Trading provides PG&E Energy Services Corporation with a broad portfolio of energy products and services for the retail market. For more information, see "General--Price Risk Management Programs" above. Additional information concerning the wholesale operations of PG&E Corporation's affiliates is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 16 of the "Notes to Consolidated Financial Statements" beginning on page 67 of the 1998 Annual Report to Shareholders. RETAIL OPERATIONS OF AFFILIATES Energy Services PG&E Energy Services (PG&E ES), headquartered in San Francisco, California, provides retail gas and electric commodities nationwide, where permitted under applicable laws, and provides energy related value-added services, including billing and information management services, energy efficiency and other energy management services, regulatory and rate analysis, and power quality solutions. PG&E ES targets primarily industrial, commercial, and institutional customers, offering comprehensive energy management solutions to reduce their energy costs and improve their productivity. PG&E ES has 20 offices nationwide to support its sales activities. PG&E ES currently competes with other non- utility electric retailers in California for direct access customers. See "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring" above. Additional information concerning the retail operations of PG&E ES is provided in "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note 16 of the "Notes to Consolidated Financial Statements" beginning on page 67 of the 1998 Annual Report to Shareholders. 35 ENVIRONMENTAL MATTERS Environmental Matters The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection and the possible future impact of environmental compliance. This information below reflects current estimates, which are periodically evaluated and revised. 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. Future estimates and actual results may differ materially from those indicated below. PG&E Corporation, Pacific Gas and Electric Company, U.S. Generating Company and its affiliates (including USGen New England, Inc. (USGenNE) which holds the electric generating facilities acquired from NEES in September 1998), and other PG&E Corporation subsidiaries and affiliates, are subject to a number of federal, state, and local laws and regulations designed to protect human health and the environment by imposing stringent controls with regard to planning and construction activities, land use, and air and water pollution, and, in recent years, by governing the use, treatment, storage, and disposal of hazardous or toxic materials. These laws and regulations affect future planning and existing operations, including environmental protection and remediation activities. Pacific Gas and Electric Company has undertaken major compliance efforts with specific emphasis on its purchase, use, and disposal of hazardous materials, the cleanup or mitigation of historic waste spill and disposal activities, and the upgrading or replacement of the Company's bulk waste handling and storage facilities. The costs of compliance with environmental laws and regulations generally have been recovered in rates. 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. With Pacific Gas and Electric Company's 1998 sale of its Morro Bay, Moss Landing, and Oakland power plants, and the upcoming sale of the Company's Contra Costa, Pittsburg, Potrero, and Geysers power plants (expected to close in 1999), the Company's oxides of nitrogen (NOx) emission reduction compliance costs will be reduced significantly. See "Utility Operations--Electric Utility Operations--Implementation of Electric Industry Restructuring--Voluntary Generation Asset Divestiture" above. Air Quality Pacific Gas and Electric Company's thermal electric generating plants are subject to numerous air pollution control laws, including the California Clean Air Act (CCAA) with respect to emissions. Pursuant to the CCAA and the Federal Clean Air Act, three of the local air districts in which Pacific Gas and Electric Company operates fossil-fueled 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). Following divestiture of the Company's fossil-fueled generating plants in connection with electric industry restructuring, the new owners will bear NOx retrofit costs. Under AB 1890, NOx retrofit costs would be eligible for recovery as transition costs but only to the extent that those costs are found by the CPUC to be both reasonable and necessary to maintain the unit in operation through 2001. The Gas Accord authorizes $42 million to be included in rates through 2002, for gas NOx retrofit projects related to natural gas compressor stations on Pacific Gas and Electric Company's Line 300, which delivers Southwest gas. Other air districts are considering NOx rules which would apply to Pacific Gas and Electric 36 Company'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. Pacific Gas and Electric Company currently estimates that the total cost of complying with these various NOx rules will be up to $51.9 million over four years. USGen's compliance with certain future regulatory requirements limiting the total amount of NOx emissions from its fossil-fueled power plants is expected to be achieved by installing additional controls, fuel switching and purchasing of NOx allowances. USGenNE has agreed to be bound by a number of state and regional initiatives that will require it to achieve significant reductions of sulfur dioxide (SO/2/) and NOx emissions by the time its older fossil-fueled power plants have been in operation for 40 years or by 2010, whichever comes first. It is expected that USGenNE can meet these requirements through the utilization of allowances it currently owns, installation of additional controls or through the purchase of additional allowances. (SO/2/ allowances are emission credits that are traded in a national market under the United States Environmental Protection Agency's (EPA) Acid Rain Program. NOx allowances are emission credits that are traded in a regional market consisting of seven Northeast states known as the Ozone Transport Region.) It is estimated that USGenNE's total cost of complying with these requirements will be up to $6 million through the year 2000. Water Quality Pacific Gas and Electric Company's existing power plants, including Diablo Canyon, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Pacific Gas and Electric Company's fossil-fueled power plants comply in all material respects with the discharge constituents standards and either comply in all material respects with or are exempt from the thermal standards. A thermal effects study at Diablo Canyon was completed in May 1988, and was reviewed by the Central Coast Regional Water Quality Control Board (Central Coast Board). The Central Coast Board did not make a final decision on the report and requested that Pacific Gas and Electric Company continue its thermal effects monitoring program. In 1995, the Central Coast Board requested that Pacific Gas and Electric Company prepare an updated comprehensive assessment of Diablo Canyon's thermal effects and approved a reduced environmental monitoring program. A comprehensive statistical analysis of Diablo Canyon's thermal effects was submitted to the Central Coast Board in December 1997 and a regulatory assessment was submitted in November 1998. In the unlikely event that the Central Coast Board finds that Diablo Canyon's existing thermal limits are not protective of beneficial uses of the marine waters and that major modifications are required (e.g., cooling towers), significant additional construction expenses could be required. Pursuant to the federal Clean Water Act, Pacific Gas and Electric Company is required to demonstrate that the location, design, construction, and capacity of power plant cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts at all existing water-cooled thermal plants. The Company has submitted detailed studies of each power plant's intake structure to various governmental agencies. Each plant's existing water intake structure was found to meet the BTA requirements. The Company is currently preparing a new study for Diablo Canyon. The study is scheduled to be submitted to the Central Coast Board for review in 1999. In the event that the Central Coast Board finds that Diablo Canyon's cooling water intake structure does not meet the BTA requirements, significant additional expenses for construction or mitigation could be required. In addition, the promulgation 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 Pacific Gas and Electric Company power plants in the future. Costs to comply with renewed permit conditions required to meet any more stringent requirements that might be imposed cannot be estimated at the present time. Several fish species listed or proposed for listing as endangered species may be found in the waters near Pacific Gas and Electric Company's Delta power plants (the Contra Costa and Pittsburgh fossil-fueled power plants). To address the impacts of operation and maintenance activities at the Delta plants on sensitive species, the Company has developed a Habitat Conservation Plan (HCP) pursuant to the requirements of Section 10(a) of the federal Endangered Species Act. The HCP is designed to minimize and mitigate any incidental "take" 37 (e.g., harassing, wounding, or killing) of listed species that may occur from the operation, maintenance, and repair of the power plants, in order to support the issuance of a Section 10(a) incidental take permit necessary for continued operation of the plants. USGen's existing power plants, including USGenNE facilities, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Two of the fossil-fueled plants owned and operated by USGenNE are operating in compliance with National Pollutant Discharge Elimination System (NPDES) permits that have expired and the NPDES permit for a third facility is scheduled to expire in 1999. As to the facilities for which the NPDES permit has expired, new permit applications are pending and it is anticipated that all three facilities should be able to continue to operate under existing terms and conditions until new permits are issued. USGenNE has submitted a permit renewal application and is negotiating with EPA on ongoing studies and permit conditions. It is estimated that USGenNE's cost to comply with these conditions could be as much as $4 million through the year 2000. Hazardous Waste Compliance and Remediation PG&E Corporation subsidiaries assess, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. Pacific Gas and Electric Company has a comprehensive program to comply with many hazardous waste storage, handling, and disposal requirements promulgated by the EPA under the Resource Conservation and Recovery Act (RCRA) and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), along with other state hazardous waste laws and other environmental requirements. One part of this 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, manufactured gas plants produced lampblack and tar residues, byproducts of a process that Pacific Gas and Electric Company, 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), Pacific Gas and Electric Company's manufactured gas plants were removed from service. The residues which may remain at some sites contain chemical compounds which now are classified as hazardous. The Company has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites which operated in the Company's service territory. The Company owns all or a portion of 30 of these manufactured gas plant sites. The Company has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites which the Company owns. It is estimated that the Company's program may result in expenditures of approximately $8 million in 1999. The full long-term costs of the program cannot be determined accurately until a closer study of each site has been completed. It is expected that expenses will increase as remedial actions related to these sites are approved by regulatory agencies or if Pacific Gas and Electric Company is found to be responsible for cleanup at sites it does not currently own. In addition to the manufactured gas plant sites, Pacific Gas and Electric Company may be required to take remedial action at certain other disposal sites if they are determined to present a significant threat to human health and the environment because of an actual or potential release of hazardous substances. Pacific Gas and Electric Company has been designated as a potentially responsible party (PRP) under CERCLA (the federal Superfund law) with respect to the Purity Oil Sales site in Malaga, California, the Industrial Waste Processing site near Fresno, California, and the Lorentz Barrel and Drum site in San Jose, California. With respect to the Casmalia site near Santa Maria, California, the Company and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires these generators to perform certain site investigation and mitigation measures, and provides a release from liability for certain other site cleanup obligations. Although the Company has not been formally designated a PRP with respect to the Geothermal Incorporated site in Lake County, California, the Central Valley Regional Water Quality Control Board and the California Attorney General's office have directed the Company and other parties to initiate measures with respect to the study and remediation of that site. 38 In addition, Pacific Gas and Electric Company has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Company is responsible for performing or paying for remedial action at sites the Company no longer owns or never owned. The cost of hazardous substance remediation ultimately undertaken by Pacific Gas and Electric Company is difficult to estimate. It is reasonably possible that a change in the estimate will occur in the near term due to uncertainty concerning the Company's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. Pacific Gas and Electric Company had an accrued liability at December 31, 1998, of $296 million for hazardous waste remediation costs at those sites, including fossil-fueled power plants, where such costs are probable and quantifiable. Environmental remediation at identified sites may be as much as $487 million if, among other things, other PRPs 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 at sites for which the Company is responsible. This upper limit of the range of costs was estimated using assumptions least favorable to the Company based upon a range of reasonably possible outcomes. Costs may be higher if the Company is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change. USGen acquired the onsite environmental liability associated with USGenNE's acquisition of electric generating facilities from NEES, but did not acquire any offsite pollution liability associated with the past disposal practices at the acquired facilities. USGen has obtained pollution liability and environmental remediation insurance coverage to limit the financial risk associated with the onsite pollution liability at all of its facilities. Potential Recovery of Hazardous Waste Compliance and Remediation Costs In 1994, the CPUC established a ratemaking mechanism for hazardous waste remediation costs (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. However, utilities will have the opportunity to recover the shareholder portion of the cleanup costs from insurance carriers. Under the HWRC, 70% of the ratepayer portion of Pacific Gas and Electric Company's cleanup costs is attributed to its gas department and 30% is attributed to its electric department. The Company can seek to recover hazardous substance cleanup costs under the HWRC in the rate proceeding it deems most appropriate. In connection with electric industry restructuring, the HWRC mechanism may no longer be used to recover electric generation-related clean-up costs for contamination caused by events occurring after January 1, 1998. Pacific Gas and Electric Company retains liability for certain required environmental remediation of pre-closing soil or groundwater contamination for fossil and geothermal generation facilities which are sold in connection with electric industry restructuring. As each generation facility is divested, the Company is required to prepare a forecast of environmental remediation costs for that plant and to use the forecast to adjust the current plant decommissioning cost estimate, eventually to be recovered through the Transition Cost Balancing Account (TCBA). (For ratemaking purposes, estimates of environmental remediation costs are discounted to present value, whereas for accounting purposes the nominal value of estimated remediation costs is used.) The discounted environmental liability associated with the Morro Bay, Moss Landing, and Oakland power plants (which were sold on July 1, 1998) and approved by the CPUC is $31.6 million. (The buyer of these plants has assumed the decommissioning liability for the purchased plants.) As of July 1, 1998, the Company had recovered $66 million from ratepayers for both the environmental and non-environmental decommissioning accrual related to the Morro Bay, Moss Landing, and Oakland power plants. The excess recovery related to these plants in the amount of $34.5 million ($66 million minus $31.6 million) resulted in a net credit to the sunk cost of the remaining plants (the Contra Costa, Pittsburgh, and Potrero power plants, and the Geysers geothermal facilities) reducing the amount of sunk costs to be amortized over the transition period, offsetting other transition costs. On October 23, 1998, Pacific Gas and Electric Company requested that the CPUC approve a total of $88.6 million of estimated costs of environmental remediation liability that the Company will retain for the Contra Costa, Pittsburg, and Potrero power plants, and the Geysers geothermal facilities. (The buyers will assume 39 the decommissioning liability.) The Company also requested that the CPUC approve similar accounting and ratemaking treatment of environmental remediation and non-environmental decommissioning for these plants as the CPUC approved for the first group of plants sold. As of December 31, 1998, Pacific Gas and Electric Company has recovered from ratepayers approximately $141 million for environmental and non-environmental decommissioning accrual related to these plants. After the plant sales are completed, the excess recovery of approximately $48.5 million (as adjusted for decommissioning costs that will continue to be accrued) would reduce the amount of generation- related sunk costs to be amortized over the transition period, offsetting other transition costs. Pacific Gas and Electric Company expects to recover $160 million of the $296 million accrued liability, discussed above, in future rates. The liability also includes $76 million related to power plant decommissioning for environmental clean-up, which is recovered through depreciation. Additionally, the Company is seeking recovery of costs from insurance carriers and from other third parties. In 1992, Pacific Gas and Electric Company filed a complaint in San Francisco County Superior Court against more than 100 of its domestic and foreign insurers, seeking damages and declaratory relief for remediation and other costs associated with hazardous waste mitigation. The Company previously had notified its insurance carriers that it seeks coverage under its comprehensive general liability policies to recover costs incurred at certain specified sites. In general, the Company's carriers neither admitted nor denied coverage, but requested additional information from the Company. Although the Company has received some amounts in settlements with certain of its insurers (approximately $49.6 million through December 31, 1998), 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. Compressor Station Litigation Several cases have been brought against Pacific Gas and Electric Company seeking damages from alleged chromium contamination at the Company'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 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 which may be associated with electric and magnetic fields (EMF) 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 EMF, but went on to state that a body of evidence has been compiled which raises the question of whether adverse health impacts might exist. In November 1993, the CPUC adopted an interim EMF policy for California energy utilities which, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMF from new and upgraded utility facilities. California energy utilities are required to fund a $1.5 million EMF education program and a $5.6 million EMF research program managed by the California Department of Health Services. As part of its effort to educate the public about EMF, Pacific Gas and Electric Company provides interested customers with information regarding the EMF exposure issue. The Company also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings. Pacific Gas and Electric Company is not currently involved in third party litigation concerning EMF. 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 40 property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMF are similarly barred. Pacific Gas and Electric Company was a defendant in civil litigation in which plaintiffs alleged personal injuries resulting from exposure to EMF. 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 EMF 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. In the event that the scientific community reaches a consensus that EMF presents a health hazard and further determines that the impact of utility- related EMF exposures can be isolated from other exposures, Pacific Gas and Electric Company may be required to take mitigation measures at its facilities. The costs of such mitigation measures cannot be estimated 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 is ultimately required. 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 Pacific Gas and Electric Company's LEV program for the six-year period beginning in 1996. The CPUC's decision on electric industry restructuring finds that the costs of utility LEV programs should continue to be collected by the utility for the duration of the six-year period. Pacific Gas and Electric Company continues to run its LEV program as funded. ITEM 2. Properties. Information concerning Pacific Gas and Electric Company's electric generation units, gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1. All real properties and substantially all personal properties of Pacific Gas and Electric Company are subject to the lien of an indenture which provides security to the holders of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds. Information concerning properties and facilities owned by other PG&E Corporation subsidiaries is included in the discussion under the heading of this report entitled "Wholesale Operations of Affiliates." 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. Compressor Station Chromium Litigation Pacific Gas and Electric Company is a defendant in five civil actions pending in California courts on behalf of approximately 2,300 plaintiffs. These cases are (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 Superior Court; (4) Little and Mustafa v. Pacific Gas and Electric Company and PG&E Corporation, filed September 10, 1997, in San Bernardino Superior Court; and (5) Whipple, et al. v. Pacific Gas and Electric Company and PG&E Corporation, et al., filed September 10, 1997, in San Bernardino Superior Court. (Plaintiffs have agreed to dismiss PG&E Corporation in these last two suits.) These cases are collectively referred to as the "Aguayo Litigation." Each of the complaints in the Aguayo Litigation, except the Little case described below, alleges personal injuries and seeks compensatory and punitive damages in an unspecified amount arising out of alleged exposure to chromium contamination in the vicinity of Pacific Gas and Electric Company's gas compressor stations at 41 Kettleman, Hinkley, and Topock, California. The plaintiffs in the Aguayo Litigation include current and former Pacific Gas and Electric Company employees, relatives of current and former Company employees, residents in the vicinity of the compressor stations, and persons who visited the gas compressor stations. The plaintiffs also include spouses or children of these plaintiffs who claim only loss of consortium or injury through the alleged exposure of their spouses or parents. In the Whipple case, pending in San Bernardino Superior Court, the plaintiffs (four members of one family) allege personal injuries, injury to a business enterprise, and injury to real property based upon causes of action for (1) actual fraud and deceit, (2) negligence, (3) negligence per se, (4) strict liability, (5) battery, (6) intentional misrepresentation, (7) negligent misrepresentation, (8) fraudulent concealment, and (9) intentional spoliation of evidence. In the Little case, also pending in San Bernardino Superior Court, two plaintiffs allege injury to real property based upon causes of action for (1) actual fraud and deceit, (2) negligence, and (3) negligence per se. Plaintiffs in each action are seeking unspecified compensatory and punitive damages, as well as civil penalties pursuant to Proposition 65. In June 1998, a Los Angeles Superior Court judge found that preconception claims are not recognizable under California law and ordered the dismissal of 235 plaintiffs with such claims from the Aguayo Litigation. Judgment was entered against these plaintiffs in December 1998. During September and October 1998, the court made similar rulings in the Acosta and Aguilar cases. The Company expects that plaintiffs may appeal these rulings. All discovery and discovery motion practice in three of the cases brought in Los Angeles Superior Court (Acosta v. Betz, Aguilar v. Pacific Gas and Electric Company, and Aguayo v. Pacific Gas and Electric Company) has been referred by the judge to a discovery referee. The court ordered that those plaintiffs who did not respond to written discovery requests served by Pacific Gas and Electric Company by November 15, 1998, would be dismissed. The Company has submitted stipulations to dismiss approximately 630 plaintiffs who failed to respond to discovery requests. It is not anticipated that these plaintiffs will appeal. After the entry of the dismissal of plaintiffs with preconception claims and those plaintiffs who failed to respond to discovery requests, there will be approximately 1,650 plaintiffs remaining in the Aguayo Litigation. On September 16, 1998, a discovery referee set the procedures for selecting 20 trial test plaintiffs and two alternates in the Aguayo, Acosta, and Aguilar cases. Ten of these trial test plaintiffs and one alternate were selected by plaintiffs, six plaintiffs and one alternate were selected by defendants, and four plaintiffs were selected at random (by selecting seven plaintiffs at random and allowing each party -- plaintiffs, Pacific Gas and Electric Company, and Betz to strike one). A trial date has been set for November 16, 1999. The Company has filed a motion to transfer venue to Fresno County Superior Court which is scheduled to be heard on March 22, 1999. Pacific Gas and Electric Company is responding to the complaints and asserting affirmative defenses. The Company will pursue appropriate legal defenses including statute of limitations, inability of certain plaintiffs to state a claim for alleged preconception exposure, or 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. At this stage of the proceedings, there is substantial uncertainty concerning the claims alleged. The Company 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, in order to better evaluate and defend this litigation. PG&E Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or Pacific Gas and Electric Company's financial position or results of operations. Texas Franchise Fee Litigation On July 31, 1997, PG&E Corporation acquired Valero Energy Corporation (Valero), now known as PG&E Gas Transmission, Texas Corporation or PG&E GTT. PG&E GTT succeeded to the eight cases described below 42 which were pending at the time of the acquisition against Valero and its affiliates (collectively referred to as the "Texas Franchise Fees Litigation"). These actions were brought by various cities in Texas arising out of several Texas statutes and city ordinances involving the following: (a) what rights, if any, Texas cities may have to require companies engaged in the gathering, production, distribution, transmission, and/or sale of natural gas (gas business) to obtain consent from, and pay fees to, the cities within which such activities are being conducted, (b) what form any such consent, if required, must take, (c) what constitutes "use" of city property, and (d) what types of charges, if any, a Texas city properly can assess against gas pipeline and marketing companies for use of that city's property. These seven cases pending against Valero entities at the time of the acquisition are: (1) City of Edinburg v. Rio Grande Valley Gas Co. (RGVG), Valero Energy Corporation (now known as PG&E GTT), Valero Transmission Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation), Valero Transmission, L.P. (now known as PG&E Texas Pipeline, L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.), Southern Union Gas Co., and Mercado Gas Services, Inc., filed August 31, 1995, in the 92nd State District Court, Hidalgo County, Texas; (2) Cities of San Benito, Primera, and Port Isabel v. RGVG, Valero Energy Corporation (now known as PG&E GTT), Southern Union Company, et al., filed December 31, 1996, in the 107th State District Court, Cameron County, Texas; (3) City of Mercedes v. Reata Industrial Gas L.P. (now known as PG&E Reata Energy, L.P.), and Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation), filed April 16, 1997, in the 92nd State District Court in Hidalgo County, Texas; (4) Cities of Alton and Dana v. Rio Grande Valley Gas Co., Valero Energy Corporation (now known as PG&E GTT), Valero Transmission Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation), Valero Transmission, L.P. (now known as PG&E Texas Pipeline, L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.), Southern Union Gas Co., and Mercado Gas Services, Inc., filed July 18, 1996, in the 92nd State District Court, Hidalgo County, Texas; (5) City of La Joya v. Rio Grande Valley Gas Company, Valero Energy Corporation (now known as PG&E GTT), Southern Union Company, et al., filed December 27, 1996, in the 92nd State District Court, Hidalgo County, Texas; (6) City of San Juan, City of La Villa, City of Penitas, City of Edcouch, and City of Palmview v. Rio Grande Valley Gas Company, Valero Energy Corporation (now known as PG&E GTT), Southern Union Company, et al., filed December 27, 1996, in the 93rd State District Court, Hidalgo County, Texas; and (7) City of Weslaco v. Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation) and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy L.P.) filed April 17, 1997, in the 92nd State District Court, Hidalgo County, Texas. The trial in the City of Edinburg case began on June 15, 1998. On August 14, 1998, a jury returned a verdict in favor of the City of Edinburg, and awarded damages in the approximate aggregate amount of $9.8 million, plus attorneys' fees of approximately $3.5 million, against PG&E GTT, Southern Union Gas Company and various affiliates of PG&E GTT. The jury refused to award punitive damages against the PG&E GTT defendants. On December 1, 1998, based on the jury verdict, the court entered a judgment in the City's favor, and awarded damages of $5.3 million, attorneys' fees of up to $3.5 million (to the extent that the City is successful on appeal), prejudgment interest of $1.6 million and post-judgment interest at the rate of 10 percent per year, compounded annually, from December 1, 1998. The court found that various PG&E GTT and Southern Union defendants were jointly and severally liable for $3.3 million of the damages, prejudgment interest in the amount of $1.1 million, and all the attorneys' fees. Certain PG&E GTT subsidiaries were found solely liable for $1.4 million of the damages and prejudgment interest of $440,000. The court did not clearly indicate the extent to which the PG&E GTT defendants could be found liable for the remaining damages. The judgment also decreed that (1) certain pipelines owned by PG&E GTT subsidiaries encroached on the City's property without the City's consent and (2) based on certain jury findings, PG&E GTT was vicariously liable for certain conduct of the local distribution company, RGVG, from October 1, 1985, to September 30, 1993 (the date Valero, PG&E GTT's predecessor, sold RGVG to Southern Union). The PG&E GTT defendants are appealing the judgment. 43 On November 4, 1997, the lawsuit filed in Cameron County, Texas, by the cities of San Benito, Primera, and Port Isabel was amended to name as defendants PG&E GTT and all of its subsidiaries (excluding its Canadian gas trading and power trading company), PG&E Gas Transmission Teco, Inc. and its subsidiaries, and PG&E Energy Trading Corporation (now known as PG&E Energy Trading--Gas Corporation), and to dismiss the Southern Union defendants. In connection with the certification of a class in this case, the court ordered notice to be sent to all potential class members and setting an opt-out deadline of December 31, 1997. Notices were mailed to approximately 159 Texas cities. Fewer than 20 cities opted out by the deadline. Some of the cities opting out include Austin, Brownsville, Houston, Pharr, and San Antonio. Defendants' motion to transfer venue of this case to Bexar County, Texas, is currently pending. The factual allegations and claims asserted in the lawsuit filed by the city of La Joya, and in the lawsuit filed by the cities of San Juan, Lavilla, Penitas, Edcouch, and Palmview, are similar to the claims made in the lawsuit filed by the cities of San Benito, Primera, and Port Isabel. Defendants' motion to transfer venue of both cases to Bexar County, Texas, also is currently pending. In July 1996, the lawsuits brought by the cities of Alton and Dana were originally brought as intervening actions in the City of Edinburg case, but were severed from the Edinburg lawsuit. The claims asserted by the cities of Alton and Dana are substantially similar to the Edinburg litigation claims. Damages are not quantified. Defendants' motion to transfer venue of both cases to Bexar County, Texas, also is currently pending. On September 4, 1997, the City of Mercedes amended its petition to include class action claims and requested to be named as class representative for a statewide class consisting of all Texas municipal corporations, municipalities, towns, and villages, excluding the cities of Edinburg and Weslaco (both of which filed separate actions), in which any of the defendants have sold or supplied gas, or used public rights-of-way to transport gas. The City of Mercedes has requested a damage award, but has not specified an amount. On November 26, 1997, defendants' motion to recuse the presiding judge was granted. Plaintiffs' request for class certification is still pending. If a class is certified, defendants anticipate that they will challenge such certification. Defendants' motion to transfer venue to Bexar County, Texas, also is still pending. The causes of action alleged in the case brought by the city of Weslaco are identical to those alleged in the City of Mercedes case. Defendants' motion to transfer venue to Bexar County, Texas, is currently pending. Defendants also have filed a motion to disqualify or recuse the presiding judge (the same judge that was recused in the Mercedes case) which is also pending. In addition to the seven cases described above, a lawsuit was filed on April 3, 1996, in the 92nd State District Court, Hidalgo County, Texas, by the City of Pharr against Southern Union Company, et al., and RGVG. On June 24, 1996, the court certified the case as a class action and named Pharr as the class representative for the class consisting of those Texas cities, excluding Edinburg and McAllen, that have, or had natural gas franchises with RGVG. The Pharr class was certified as to two claims: breach of contract and declaratory relief dealing with the rights, status, and legal relationship between plaintiff, the class members, and the local distribution company regarding payment of franchise fees and use of granted easements. Plaintiffs' original petition also sought injunctive relief, but the class order does not include injunctive relief. Plaintiffs seek actual damages, exemplary damages, attorneys' fees, costs, and pre- and post-judgment interest, but have not specified any amounts. The court records show that a pleading was allegedly filed on December 12, 1997, but not docketed until mid-February 1998, that purports to add as defendants the same 29 PG&E Corporation entities that are parties in the San Benito class action. These PG&E Corporation entities have not been served in this litigation. On December 30, 1997, in affirming the Pharr class certification, the appellate court specifically found that the PG&E Corporation-related entities were not parties to the class action. PG&E Corporation believes that the ultimate outcome of the Texas franchise fee cases described above could have a material adverse impact on its financial position or results of operation. ITEM 4. Submission of Matters to a Vote of Security Holders. Not applicable. 44 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:
Age at December 31, Name 1998 Position ---- ------------ -------- R. D. Glynn, Jr. ....... 56 Chairman of the Board, Chief Executive Officer, and President S. W. Gebhardt.......... 47 Senior Vice President; President and Chief Executive Officer, PG&E Energy Services Corporation T. W. High.............. 51 Senior Vice President, Administration and External Relations P. C. Iribe............. 48 Senior Vice President; President and Chief Operating Officer, U.S. Generating Company T. B. King.............. 37 Senior Vice President; President and Chief Operating Officer, PG&E Gas Transmission Corporation L. E. Maddox............ 43 Senior Vice President, President and Chief Executive Officer, PG&E Energy Trading Corporation M. E. Rescoe............ 46 Senior Vice President, Chief Financial Officer, and Treasurer G. R. Smith............. 50 Senior Vice President; President and Chief Executive Officer, Pacific Gas and Electric Company G. B. Stanley........... 52 Senior Vice President, Human Resources B. R. Worthington....... 49 Senior Vice President and General Counsel
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.
Name Position Period Held Office ---- -------- ------------------ R. D. Glynn, Jr. .... Chairman of the Board, January 1, 1998, to current Chief Executive Officer, and President Chairman of the Board of January 1, 1998, to current Directors, Pacific Gas and Electric Company President and Chief June 1, 1997, to current Executive Officer President and Chief December 18, 1996, to May 31, 1997 Operating Officer President and Chief June 1, 1995, to May 31, 1997 Operating Officer, Pacific Gas and Electric Company Executive Vice July 1, 1994, to May 31, 1995 President, Pacific Gas and Electric Company Senior Vice President January 1, 1994, to June 30, 1994 and General Manager, Customer Energy Services Business Unit, Pacific Gas and Electric Company Senior Vice President November 1, 1991, to December 31, 1993 and General Manager, Electric Supply Business Unit, Pacific Gas and Electric Company S. W. Gebhardt....... Senior Vice President April 1, 1997, to current President and Chief April 1, 1997, to current Executive Officer, PG&E Energy Services Corporation Executive Vice April 1, 1996, to March 28, 1997 President, PennUnion Energy Services Vice President, Enron January 1, 1993, to December 31, 1995 Capital & Trade Resources T. W. High........... Senior Vice President, June 1, 1997, to current Administration and External Relations Senior Vice President, June 1, 1995, to May 31, 1997 Corporate Services, Pacific Gas and Electric Company Vice President and July 1, 1994, to May 31, 1995 Assistant to the Chief Executive Officer, Pacific Gas and Electric Company Vice President and November 1, 1991, to June 30, 1994 Assistant to the Chairman of the Board, Pacific Gas and Electric Company
45
Name Position Period Held Office ---- -------- ------------------ P. C. Iribe.......... Senior Vice President January 1, 1999, to current President and Chief November 1, 1998, to current Operating Officer, U.S. Generating Company Executive Vice President September 1, 1997, to October 31, 1998 and Chief Operating Officer, U.S. Generating Company Executive Vice May 1994 to September 1, 1997 President, Marketing, Development, and Asset Management, U.S. Generating Company Senior Vice President, September 1990 to May 1994 U.S. Generating Company T. B. King........... Senior Vice President January 1, 1999, to current President and Chief November 23, 1998, to current Operating Officer, PG&E Gas Transmission Corporation President and Chief February 14, 1997, to November 22, 1998 Operating Officer, Kinder Morgan Energy Partners, L.P. Vice President, July 1, 1995, to February 14, 1997 Commercial Operations-- Midwest Region, Enron Liquid Services Corporation Vice President, July 1994 to July 1, 1995 Gathering Services, Northern Natural Gas Company and Transwestern Pipeline Company Vice President, September 1993 to July 1994 Transportation Marketing Northern Natural Gas Company L. E. Maddox......... Senior Vice President June 1, 1997, to current President and Chief June 1, 1997, to current Executive Officer, PG&E Energy Trading Corporation President, PennUnion May 1995 to May 1997 Energy Services, L.L.C. President, Brooklyn January 1993 to May 1995 Interstate Natural Gas Corp. M. E. Rescoe......... Senior Vice President, January 1, 1998, to current Chief Financial Officer, and Treasurer Senior Vice President September 1, 1997, to December 31, 1997 and Chief Financial Officer Executive Vice August 11, 1997, to August 31, 1997 President, Strategic Planning and Corporate Development, Texas Utilities Company Senior Vice President, July 1995 to August 10, 1997 Chief Financial Officer, Enserch Corp. (gas and power) Senior Managing July 1992 to July 1995 Director, Bear, Stearns & Co., Inc. (investment bankers) G. R. Smith.......... Senior Vice President January 1, 1999, to current (Please refer to description of business experience for executive officers of Pacific Gas and Electric Company below.) G. B. Stanley........ Senior Vice President, January 1, 1998, to current Human Resources Vice President, Human June 1, 1997, to December 31, 1997 Resources Vice President, Human July 1, 1996, to May 31, 1997 Resources, Pacific Gas and Electric Company Self-employed (human January 1995 to June 1996 resources consultant) Senior Vice President, January 1992 to December 1994 Human Resources, The Gap, Inc. (retail clothing) B. R. Worthington.... Senior Vice President June 1, 1997, to current and General Counsel General Counsel December 18, 1996, to May 31, 1997 Senior Vice President June 1, 1995, to June 30, 1997 and General Counsel, Pacific Gas and Electric Company Vice President and December 21, 1994, to May 31, 1996 General Counsel, Pacific Gas and Electric Company Chief Counsel-Corporate, January 10, 1991, to December 20, 1994 Pacific Gas and Electric Company
46 "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:
Age at December 31, Name 1998 Position ---- ------------ -------- G. R. Smith............. 50 President and Chief Executive Officer K. M. Harvey............ 40 Senior Vice President, Treasurer and Chief Financial Officer E. J. Macias............ 44 Senior Vice President and General Manager, Generation, Transmission, and Supply Business Unit R. J. Peters............ 48 Senior Vice President and General Counsel J. K. Randolph.......... 54 Senior Vice President and General Manager, Distribution and Customer Service Business Unit D. D. Richard, Jr. ..... 48 Senior Vice President, Governmental and Regulatory Relations G. M. Rueger............ 48 Senior Vice President and General Manager, Nuclear Power Generation Business Unit
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.
Name Position Period Held Office ---- -------- ------------------ G. R. Smith.......... President and Chief June 1, 1997 to current Executive Officer Chief Financial Officer, December 18, 1996 to May 31, 1997 PG&E Corporation Senior Vice President June 1, 1995 to May 31, 1997 and Chief Financial Officer Vice President and Chief November 1, 1991 to May 31, 1995 Financial Officer K. M. Harvey......... Senior Vice President, July 1, 1997 to current Chief Financial Officer, and Treasurer Vice President and June 1, 1995 to June 30, 1997 Treasurer Treasurer August 1, 1993 to May 31, 1995 Corporate Secretary November 1, 1991 to July 31, 1993 E. J. Macias......... Senior Vice President July 1, 1997 to current and General Manager, Generation, Transmission and Supply Business Unit Vice President and November 15, 1995 to June 30, 1997 General Manager, Electric Transmission Vice President, Power December 21, 1994 to November 14, 1995 System Manager, Power Control March 1993 to December 20, 1994 and System Operation R. J. Peters......... Vice President and July 1, 1997 to current General Counsel Chief Counsel, January 1, 1993 to June 30, 1997 Regulatory J. K. Randolph....... Senior Vice President July 1, 1997 to current and General Manager, Distribution and Customer Service Business Unit Vice President and January 1, 1997 to June 30, 1997 General Manager, Power Generation Vice President, Power November 1, 1991 to December 31, 1996 Generation D. D. Richard, Jr. .. Senior Vice President, July 1, 1997 to current Governmental and Regulatory Relations Vice President, July 1, 1997 to current Governmental Relations, PG&E Corporation Vice President, January 1, 1997 to June 30, 1997 Governmental Relations Executive Vice President January 1993 to December 1996 and Principal, Morse, Richard, Weisenmiller & Assoc., Inc. (energy, project finance, and environmental consulting) G. M. Rueger......... Senior Vice President November 1, 1991 to current and General Manager, Nuclear Power Generation Business Unit
47 PART II 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 69 under the heading "Quarterly Consolidated Financial Data (Unaudited)" in the 1998 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. As of February 22, 1999, there were 162,261 holders of record of PG&E Corporation common stock. Pacific Gas and Electric Company has made no sales of unregistered equity securities in the last three years. PG&E Corporation has made the following sales of unregistered equity securities during such period: On January 27, 1997, PG&E Corporation issued 14,607,143 shares of common stock. The shares were issued to nine former shareholders of Teco Pipeline Company (Teco) in connection with the acquisition of Teco by PG&E Corporation. PG&E Corporation owns all the outstanding shares of Teco as a result of the acquisition. The shares were issued in reliance upon the exemption from registration under the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof and Rule 506 of Regulation D thereunder. All of the former shareholders of Teco represented that they were "accredited investors" as defined in Rule 501(a) under the Securities Act of 1933 and made other representations establishing the basis for the exemption. A legend as provided for by Rule 501(d)(3) was placed on each of the stock certificates representing the shares of PG&E Corporation common stock received by the former shareholders of Teco. 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 17 under the heading "Selected Financial Data" in the 1998 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 earnings to fixed charges ratio for the year ended December 31, 1998, was 3.02. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the year ended December 31, 1998, was 2.85. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into Registration Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding. ITEM 7. Management'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 18 through 35 under the heading "Management's Discussion and Analysis" in the 1998 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk. Information responding to Item 7A appears in the 1998 Annual Report to Shareholders on page 32 under the heading "Management's Discussion and Analysis--Debt Obligations and Rate Reduction Bonds," on pages 34 and 35 under the heading "Management's Discussion and Analysis--Price Risk Management Activities," and on pages 47, 48, 53, and 54 under Notes 1, 3, and 4 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. 48 ITEM 8. Financial Statements and Supplementary Data. Information responding to Item 8 appears on pages 36 through 70 of the 1998 Annual Report to Shareholders under the following headings for PG&E Corporation: "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," and "Statement of Consolidated Common Stock Equity;" under the following headings for Pacific Gas and Electric Company: "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," and "Statement of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities;" and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: "Notes to Consolidated Financial Statements," "Quarterly Consolidated Financial Data (Unaudited)," and "Report of Independent Public Accountants," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. Information responding to Item 9 has been previously reported by PG&E Corporation and Pacific Gas and Electric Company in a current report on Form 8-K dated February 17, 1999 and filed on February 23, 1999. PART III 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 Registrant" contained on pages 45 through 47 in Part I of this report. Other information responding to Item 10 is included on pages 3 through 6 under the heading "Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company" and page 43 under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the 1999 Joint Proxy Statement relating to the 1999 Annual Meetings of Shareholders, which information is hereby incorporated by reference. ITEM 11. Executive Compensation. Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included on pages 9 and 10 under the heading "Compensation of Directors" and on pages 36 through 41 under the headings "Summary Compensation Table," "Option/SAR Grants in 1998," "Aggregated Option/SAR Exercises in 1998 and Year-End Option/SAR Values," "Long-Term Incentive Plan--Awards in 1998," "Retirement Benefits," and "Termination of Employment and Change In Control Provisions" in the 1999 Joint Proxy Statement relating to the 1999 Annual Meetings of Shareholders, which information is hereby incorporated by reference. ITEM 12. Security Ownership of Certain Beneficial Owners and Management. Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included on pages 11 and 12 under the heading "Security Ownership of Management" and on pages 42 and 43 under the heading "Principal Shareholders" in the 1999 Joint Proxy Statement relating to the 1999 Annual Meetings of Shareholders, which information is hereby incorporated by reference. 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 on page 10 under the heading "Certain Relationships and Related Transactions" in the 1999 Joint Proxy Statement relating to the 1999 Annual Meetings of Shareholders, which information is hereby incorporated by reference. 49 PART IV ITEM 14. 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 report of independent public accountants contained in the 1998 Annual Report to Shareholders, which have been incorporated by reference in this report: Statements of Consolidated Income for the Years Ended December 31, 1998, 1997, and 1996, for each of PG&E Corporation and Pacific Gas and Electric Company. Statements of Consolidated Cash Flows for the Years Ended December 31, 1998, 1997, and 1996, for each of PG&E Corporation and Pacific Gas and Electric Company. Consolidated Balance Sheets at December 31, 1998, and 1997, for each of PG&E Corporation and Pacific Gas and Electric Company. Statement of Consolidated Common Stock Equity for the Years Ended December 31, 1998, 1997, and 1996, for PG&E Corporation. Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities for the Years Ended December 31, 1998, 1997, and 1996, for Pacific Gas and Electric Company. Notes to Consolidated Financial Statements. Quarterly Consolidated Financial Data (Unaudited). Report of Independent Public Accountants. 2. Report of Independent Public Accountants included at page 55 of this Form 10-K. 3. Consolidated financial statement schedules: I --Condensed Financial Information of Parent for the Years Ended December 31, 1998 and 1997. II--Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 1998, 1997 and 1996. Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto. 4.Exhibits required to be filed by Item 601 of Regulation S-K: 3.1 Restated Articles of Incorporation of PG&E Corporation effective as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1- 12609), Exhibit 3.1). 3.2 By-Laws of PG&E Corporation amended as of January 27, 1999. 3.3 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 (Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit 3.1). 3.4 By-Laws of Pacific Gas and Electric Company amended as of January 27, 1999. 4. 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 (Registration No. 2-1324, Exhibits B-1, B-2, 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
50 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; Pacific Gas and Electric Company's Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2). 10.1 Asset Purchase Agreement by and among New England Power Company, The Narragansett Electric Company, and USGen Acquisition Corporation, dated as of August 5, 1997 (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1997 (File No. 1-12609, Exhibit No. 10.1). Filed only as an exhibit to the Annual Report on Form 10-K filed by PG&E Corporation under Commission File Number 1-12609. 10.2 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. (PG&E Corporation 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 No. 10.2.) *10.3 PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998. (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2). *10.4 PG&E Corporation Deferred Compensation Plan for Officers, as amended and restated effective as of October 21, 1998. *10.5 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 1998. *10.6 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 1999. *10.7 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company, effective January 1, 1998. *10.8 PG&E Corporation Supplemental Executive Retirement Savings Plan, effective January 1, 1998. *10.9 Pacific Gas and Electric Company Relocation Assistance Program for Officers (Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16). *10.10 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16). *10.11 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998. (PG&E Corporation Form 10-K for the year ended December 31, 1997, (File No. 1-12609), Exhibit No. 10.13.) *10.12 PG&E Corporation Long-Term Incentive Program, as amended and restated effective as of October 21, 1998, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non- Employee Director Stock Incentive Plan. *10.13 PG&E Corporation Executive Stock Ownership Program, effective January 1, 1998, as amended October 21, 1998. *10.14 PG&E Corporation Officer Severance Policy, effective as of December 16, 1998. *10.15 PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1). *10.16 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 (PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2).
51 11. Computation of Earnings Per Common Share. 12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company. 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company. 13. 1998 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company--portions of the 1998 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis," "Report of Independent Public Accountants," financial statements of PG&E Corporation entitled "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity," financial statements of Pacific Gas and Electric Company entitled "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities," "Notes to Consolidated Financial Statements" and "Quarterly Consolidated Financial Data (Unaudited)" are included only. (Except for those portions which are expressly incorporated herein by reference, such 1998 Annual Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein.) 21. Subsidiaries of the Registrant (incorporated by reference from PG&E Corporation's Statement by Holding Company Claiming Exemption from the Public Utility Holding Company Act of 1935 under Rule 2 by filing Form U-3A-2 dated March 1, 1999, pages 1 through 34). 23. Consent of Arthur Andersen 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. 27.1 Financial Data Schedule for the year ended December 31, 1998, for PG&E Corporation. 27.2 Financial Data Schedule for the year ended December 31, 1998, for Pacific Gas and Electric Company.
- -------- * 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. 52 (b) Reports on Form 8-K Reports on Form 8-K(/1/) during the quarter ended December 31, 1998, and through the date hereof: 1. October 21, 1998 Item 5. Other Events -- Year-to-Date Financial Results 2. November 4, 1998 Item 5. Other Events A. Electric Industry Restructuring 3. November 25, 1998 Item 5. Other Events A. Electric Industry Restructuring 4. January 20, 1999 Item 5. Other Events A. 1998 Consolidated Earnings (unaudited) B.1999 Outlook C.Share Repurchase Program 5. February 17, 1999 Item 4. Changes in Registrant's Certifying Accountant Item 5. Other Events -- Share Repurchase Program - -------- (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) 53 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 5th day of March, 1999. PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY (Registrant) (Registrant) By /s/ Gary P. Encinas By /s/ Gary P. Encinas --------------------------------- --------------------------------- (Gary P. Encinas, Attorney-in-Fact) (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 March 5, 1999 Executive Officer, and President (PG&E Corporation) *GORDON R. SMITH President and Chief Executive Officer (Pacific Gas and Electric Company) B. Principal Financial Officers *MICHAEL E. RESCOE Senior Vice President, Chief March 5, 1999 Financial Officer, and Treasurer (PG&E Corporation) *KENT M. HARVEY Senior Vice President, Treasurer, and Chief Financial Officer (Pacific Gas and Electric Company) C. Principal Accounting Officer *CHRISTOPHER P. JOHNS Vice President and Controller March 5, 1999 (PG&E Corporation) Vice President and Controller (Pacific Gas and Electric Company) D. Directors *RICHARD A. CLARKE *DAVID A. COULTER *C. LEE COX *WILLIAM S. DAVILA *ROBERT D. GLYNN, JR. *DAVID M. LAWRENCE Directors of PG&E Corporation and March 5, 1999 *RICHARD B. MADDEN Pacific Gas and Electric Company, *MARY S. METZ except as noted *REBECCA Q. MORGAN *JOHN C. SAWHILL *GORDON R. SMITH (Director of Pacific Gas and Electric Company, only) *BARRY LAWSON WILLIAMS
*By /s/ Gary P. Encinas ---------------------------- (Gary P. Encinas, Attorney-in-Fact) 54 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and the Board of Directors of PG&E Corporation and Pacific Gas and Electric Company: We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in the PG&E Corporation and Pacific Gas and Electric Company Annual Report to Shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated February 8, 1999. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in Part IV, Item 14. (a)(3) in this Form 10-K are the responsibility of the management of PG&E Corporation and of Pacific Gas and Electric Company and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the consolidated financial statements taken as a whole. /s/ ARTHUR ANDERSEN LLP San Francisco, California February 8, 1999 55 SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED BALANCE SHEET
December 31, -------------- 1998 1997 ------ ------ (in millions) Assets: Cash and cash equivalents.................................... $ 9 $ 1 Accounts Receivable Related parties............................................ 448 149 Other current assets......................................... 2 -- ------ ------ Total current assets..................................... 459 150 Property, plant, and equipment............................... 6 -- Construction work in progress................................ 2 -- ------ ------ Total property, plant, and equipment......................... 8 -- Accumulated depreciation and decommissioning................. (1) -- ------ ------ Net property, plant, and equipment........................... 7 -- Investments in subsidiaries.................................. 8,780 9,556 Other noncurrent assets...................................... 41 -- Other deferred charges....................................... 1 1 ------ ------ Total Assets............................................. $9,288 $9,707 ====== ====== Liabilities and Stockholders' Equity: Current Liabilities Short-term borrowings...................................... $ 683 $ -- Accounts payable Related parties........................................... 221 635 Other..................................................... 9 10 Accrued taxes.............................................. 155 46 Dividends payable.......................................... 115 118 Other...................................................... 16 -- ------ ------ Total current liabilities.................................. 1,199 809 Noncurrent Liabilities Deferred income taxes...................................... 19 -- Other...................................................... 4 1 ------ ------ Total noncurrent liabilities............................... 23 1 Stockholder's Equity Common stock............................................... 5,862 6,366 Reinvested earnings........................................ 2,204 2,531 ------ ------ Total stockholders' equity................................. 8,066 8,897 ------ ------ Total Liabilities and Stockholders' Equity............... $9,288 $9,707 ====== ======
SCHEDULE I--CONDENSED FINANCIAL INFORMATION FOR PARENT--(Continued) CONDENSED STATEMENTS OF INCOME For the years ended December 31, 1998 and 1997
1998 1997 ------- ------- (in millions, except per share amounts) Equity in earnings of subsidiaries......................... $ 684 $ 743 Operating expenses......................................... 1 (21) Interest expense........................................... (52) (23) Other income............................................... 5 -- ------- ------- Income Before Income Taxes................................. 638 699 Less: Income taxes......................................... (83) (17) ------- ------- Net Income................................................. $ 721 $ 716 Elimination of intercompany profit......................... (2) -- ------- ------- Income Available for Common Stock.......................... $ 719 $ 716 ======= ======= Weighted Average Common Shares Outstanding................. 382 410 Earnings Per Common Share.................................. $ 1.88 $ 1.75 ======= =======
CONDENSED STATEMENTS OF CASH FLOWS For the years ended December 31, 1998 and 1997
1998 1997 ------- ------- (in millions) Cash Flows From Operating Activities Net income............................................... $ 721 $ 716 Adjustments to reconcile net income to net cash provided by operating activities: Dividends received from consolidated subsidiaries...... 445 763 Other--net............................................. (1,291) (167) ------- ------- Net cash provided by operating activities................ $ (125) $ 1,312 Cash Flows From Investing Activities Capital expenditures................................... (8) -- Investments in unregulated projects.................... (575) (150) Repurchase of Utility stock holdings by parent......... 1,600 -- ------- ------- Net cash provided by investing activities................ $ 1,017 $ (150) Cash Flows From Financing Activities Common stock repurchased............................... (1,158) (804) Short-term debt issued--net............................ 683 -- Dividends paid......................................... (470) (367) Other--net............................................. 61 10 ------- ------- Net cash used by financing activities.................... (884) (1,161) Net Change in Cash and Cash Equivalents.................. 8 1 Cash and Cash Equivalents at January 1................... 1 -- ------- ------- Cash and Cash Equivalents at December 31................. $ 9 $ 1 ======= =======
PG&E CORPORATION SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the years ended December 31, 1998, 1997, and 1996
Column A Column B Column C Column D Column E Additions --------------------- Balance Balance at Charged Charged at end beginning to costs to other of Description of period and expenses accounts Deductions period ----------- ---------- ------------ -------- ---------- -------- (in thousands) Valuation and qualifying accounts deducted from assets: 1998: Allowance for uncollectible accounts............. $72,912 $10,978 $(2,893) $22,420(2) $58,577 ======= ======= ======= ======= ======= 1997: Allowance for uncollectible accounts............. $57,904 $42,500 $ -- $27,492(2) $72,912 ======= ======= ======= ======= ======= 1996: Reserve for deferred project costs........ $ 5,710 $ -- $ -- $ 5,710(1) $ -- ======= ======= ======= ======= ======= Allowance for uncollectible accounts............. $35,520 $55,566 $ 1,836 $35,018(2) $57,904 ======= ======= ======= ======= ======= Reserve for land costs................ $ 4,444 $ -- $ -- $ 4,444(1) $ -- ======= ======= ======= ======= =======
- -------- (1) Deductions consist principally of write-offs. Reserve for deferred project costs and reserve for land costs are classified on the balance sheet in other noncurrent assets. (2) Deductions consist principally of write-offs, net of collections of receivables previously written off. PACIFIC GAS AND ELECTRIC COMPANY SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the years ended December 31, 1998, 1997, and 1996
Column A Column B Column C Column D Column E Additions --------------------- Balance Balance at Charged Charged at end beginning to costs to other of Description of period and expenses accounts Deductions period ----------- ---------- ------------ -------- ---------- -------- (in thousands) Valuation and qualifying accounts deducted from assets: 1998: Allowance for uncollectible accounts............. $59,608 $10,007 $ 152 $22,420(2) $47,347 ======= ======= ======= ======= ======= 1997: Allowance for uncollectible accounts............. $57,904 $30,718 $(1,836) $27,178(2) $59,608 ======= ======= ======= ======= ======= 1996: Reserve for deferred project costs........ $ 5,710 $ -- $ -- $ 5,710(1) $ -- ======= ======= ======= ======= ======= Allowance for uncollectible accounts............. $35,520 $55,566 $ 1,836 $35,018(2) $57,904 ======= ======= ======= ======= ======= Reserve for land costs................ $ 4,444 $ -- $ -- $ 4,444(1) $ -- ======= ======= ======= ======= =======
- -------- (1) Deductions consist principally of write-offs. Reserve for deferred project costs and reserve for land costs are classified on the balance sheet in other noncurrent assets. (2) Deductions consist principally of write-offs, net of collections of receivables previously written off. EXHIBIT INDEX
Exhibit No. Description ------- ----------- 3.1 Restated Articles of Incorporation of PG&E Corporation effective as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 3.1). 3.2 By-Laws of PG&E Corporation amended as of January 27, 1999. 3.3 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 (Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit 3.1). 3.4 By-Laws of Pacific Gas and Electric Company amended as of January 27, 1999. 4. 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 (Registration No. 2-1324, Exhibits B-1, B-2, 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; Pacific Gas and Electric Company's Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2). 10.1 Asset Purchase Agreement by and among New England Power Company, The Narragansett Electric Company, and USGen Acquisition Corporation, dated as of August 5, 1997 (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1997 (File No. 1-12609, Exhibit No. 10.1). Filed only as an exhibit to the Annual Report on Form 10-K filed by PG&E Corporation under Commission File Number 1-12609. 10.2 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. (PG&E Corporation 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 No. 10.2.) *10.3 PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998. (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2). *10.4 PG&E Corporation Deferred Compensation Plan for Officers, as amended and restated effective as of October 21, 1998. *10.5 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 1998. *10.6 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 1999. *10.7 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company, effective January 1, 1998. *10.8 PG&E Corporation Supplemental Executive Retirement Savings Plan, effective January 1, 1998. *10.9 Pacific Gas and Electric Company Relocation Assistance Program for Officers (Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16). *10.10 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16). *10.11 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998. (PG&E Corporation Form 10-K for the year ended December 31, 1997, (File No. 1-12609), Exhibit No. 10.13.)
56
EXHIBIT NO. DESCRIPTION ------- ----------- *10.12 PG&E Corporation Long-Term Incentive Program, as amended and restated effective as of October 21, 1998, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan. *10.13 PG&E Corporation Executive Stock Ownership Program, effective January 1, 1998, as amended October 21, 1998. *10.14 PG&E Corporation Officer Severance Policy, effective as of December 16, 1998. *10.15 PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1). *10.16 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 (PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2). 11. Computation of Earnings Per Common Share. 12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company. 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company. 13. 1998 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company--portions of the 1998 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis," "Report of Independent Public Accountants," financial statements of PG&E Corporation entitled "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity," financial statements of Pacific Gas and Electric Company entitled "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities," "Notes to Consolidated Financial Statements" and "Quarterly Consolidated Financial Data (Unaudited)" are included only. (Except for those portions which are expressly incorporated herein by reference, such 1998 Annual Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein.) 21. Subsidiaries of the Registrant (incorporated by reference from PG&E Corporation's Statement by Holding Company Claiming Exemption from the Public Utility Holding Company Act of 1935 under Rule 2 by filing Form U-3A-2 dated March 1, 1999, pages 1 through 34). 23. Consent of Arthur Andersen 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. 27.1 Financial Data Schedule for the year ended December 31, 1998, for PG&E Corporation. 27.2 Financial Data Schedule for the year ended December 31, 1998, for Pacific Gas and Electric Company.
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. - -------- * 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. 57 EX-3.2 2 BYLAWS OF PG&E CORPORATION EXHIBIT 3.2 Bylaws of PG&E Corporation amended as of January 27, 1999 ------------------------------ Article I. SHAREHOLDERS. 1. Place of Meeting. All meetings of the shareholders shall be held at the office of the Corporation in the City and County of San Francisco, State of California, or at such other place within the State of California as may be designated by the Board of Directors. 2. Annual Meetings. The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors. Written notice of the annual meeting shall be given not less than ten (or, if sent by third-class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat. The notice shall state the place, day, and hour of such meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders. Notice of any meeting of the shareholders shall be given by mail or telegraphic or other written communication, postage prepaid, to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Corporation. 3. Special Meetings. Special meetings of the shareholders shall be called by the Corporate Secretary or an Assistant Corporate Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, or the President. Special meetings of the shareholders shall also be called by the Corporate Secretary or an Assistant Corporate Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting. Such request shall state the purposes of the meeting, and shall be delivered to the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or the Corporate Secretary. A special meeting so requested shall be held on the date requested, but not less than thirty-five nor more than sixty days after the date of the original request. Written notice of each special meeting of shareholders, stating the place, day, and hour of such meeting and the business proposed to be transacted thereat, shall be given in the manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within twenty days after receipt of the written request. 4. Attendance at Meetings. At any meeting of the shareholders, each holder of record of stock entitled to vote thereat may attend in person or may designate an agent or a reasonable number of agents, not to exceed three to attend the meeting and cast votes for his or her shares. The authority of agents must be evidenced by a written proxy signed by the shareholder designating the agents authorized to attend the meeting and be delivered to the Corporate Secretary of the Corporation prior to the commencement of the meeting. Article II. DIRECTORS. 1. Number. As stated in Section I of Article Third of this Corporation's Articles of Incorporation, the authorized number of directors of this Corporation can be no less than nine (9) nor more than seventeen (17), with the exact number within the range determined by this Corporation's Board of Directors. The exact number of directors within the range shall be thirteen (13), unless and until the Board of Directors fixes a different number within the range through amendment of these Bylaws which amendment may be adopted solely by the Board of Directors. 2. Powers. The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders. 3. Executive Committee. There shall be an Executive Committee of the Board of Directors consisting of the Chairman of the Committee, the Chairman of the Board, if these offices be filled, the President, and four Directors who are not officers of the Corporation. The members of the Committee shall be elected, and may at any time be removed, by a two-thirds vote of the whole Board. The Executive Committee, subject to the provisions of law, may exercise any of the powers and perform any of the duties of the Board of Directors; but the Board may by an affirmative vote of a majority of its members withdraw or limit any of the powers of the Executive Committee. The Executive Committee, by a vote of a majority of its members, shall fix its own time and place of meeting, and shall prescribe its own rules of procedure. A quorum of the Committee for the transaction of business shall consist of three members. 2 4. Time and Place of Directors' Meetings. Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance. 5. Special Meetings. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Corporate Secretary. Such notice shall be delivered personally or by telephone to each Director at least four hours in advance of such meeting, or sent by first-class mail or telegram, postage prepaid, at least two days in advance of such meeting. 6. Quorum. A quorum for the transaction of business at any meeting of the Board of Directors shall consist of six members. 7. Action by Consent. Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all Directors individually or collectively consent in writing to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors. 8. Meetings by Conference Telephone. Any meeting, regular or special, of the Board of Directors or of any committee of the Board of Directors, may be held by conference telephone or similar communication equipment, provided that all Directors participating in the meeting can hear one another. Article III. OFFICERS. 1. Officers. The officers of the Corporation shall be a Chairman of the Board, a Vice Chairman of the Board, a Chairman of the Executive Committee (whenever the Board of Directors in its discretion fills these offices), a President, a Chief Financial Officer, a General Counsel, one or more Vice Presidents, a Corporate Secretary and one or more Assistant Corporate Secretaries, a Treasurer and one or more Assistant Treasurers, and a Controller, all of whom shall be elected by the Board of Directors. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, and the President shall be members of the Board of Directors. 3 2. Chairman of the Board. The Chairman of the Board, if that office be filled, shall preside at all meetings of the shareholders and of the Directors, and shall preside at all meetings of the Executive Committee in the absence of the Chairman of that Committee. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. He shall have such duties and responsibilities as may be prescribed by the Board of Directors or the Bylaws. The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and, in the absence or disability of the President, shall exercise the President's duties and responsibilities. 3. Vice Chairman of the Board. The Vice Chairman of the Board, if that office be filled, shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. In the absence of the Chairman of the Board, he shall preside at all meetings of the Board of Directors and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, he shall preside at all meetings of the Executive Committee. The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 4. Chairman of the Executive Committee. The Chairman of the Executive Committee, if that office be filled, shall preside at all meetings of the Executive Committee. He shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board of Directors or the Bylaws. 5. President. The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. If there be no Chairman of the Board, the President shall also exercise the duties and responsibilities of that office. The President shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 6. Chief Financial Officer. The Chief Financial Officer shall be responsible for the overall management of the financial affairs of the Corporation. He shall render a statement of the Corporation's financial condition and an account of all transactions whenever requested by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, or the President. The Chief Financial Officer shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. 4 7. General Counsel. The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature. He shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business. He shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation. The General Counsel shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. 8. Vice Presidents. Each Vice President, if those offices are filled, shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. Each Vice President's authority to sign agreements and instruments on behalf of the Corporation shall be as prescribed by the Board of Directors. The Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, or the President may confer a special title upon any Vice President. 9. Corporate Secretary. The Corporate Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and he shall record the minutes of all proceedings in books to be kept for that purpose. He shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Corporation. He shall give, or cause to be given, all notices required either by law or the Bylaws. He shall keep the seal of the Corporation in safe custody, and shall affix the seal of the Corporation to any instrument requiring it and shall attest the same by his signature. The Corporate Secretary shall have such other duties as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Corporate Secretaries shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Corporate Secretary. In the absence or disability of the Corporate Secretary, his duties shall be performed by an Assistant Corporate Secretary. 10. Treasurer. The Treasurer shall have custody of all moneys and funds of the Corporation, and shall cause to be kept full and accurate records of receipts and disbursements of the Corporation. He shall deposit all moneys and other valuables of the Corporation in the name and to the credit of the Corporation in such depositaries as may be designated by the Board of Directors or any employee of the Corporation 5 designated by the Board of Directors. He shall disburse such funds of the Corporation as have been duly approved for disbursement. The Treasurer shall perform such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, the Chief Financial Officer, or the Bylaws. The Assistant Treasurers shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, the Chief Financial Officer, or the Treasurer. In the absence or disability of the Treasurer, his duties shall be performed by an Assistant Treasurer. 11. Controller. The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and he shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation. He shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them. The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, the Chief Financial Officer, or the Bylaws. He shall be the principal accounting officer of the Corporation, unless another individual shall be so designated by the Board of Directors. Article IV. MISCELLANEOUS. 1. Record Date. The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares. The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed. When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be. 2. Transfers of Stock. Upon surrender to the Corporate Secretary or Transfer Agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment, or authority to transfer, 6 and payment of transfer taxes, the Corporation shall issue a new certificate to the person entitled thereto, cancel the old certificate, and record the transaction upon its books. Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of certificates for shares of stock of the Corporation, and to appoint and remove Transfer Agents and Registrars of transfers. 3. Lost Certificates. Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board of Directors so requires, give the Corporation, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Corporate Secretary of the Corporation, before a new certificate may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed. Article V. AMENDMENTS. 1. Amendment by Shareholders. Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders. 2. Amendment by Directors. To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors. 7 EX-3.4 3 BYLAWS OF PACIFIC GAS AND ELECTRIC EXHIBIT 3.4 Bylaws of Pacific Gas and Electric Company amended as of January 27, 1999 ------------------------------- Article I. SHAREHOLDERS. 1. Place of Meeting. All meetings of the shareholders shall be held at the office of the Corporation in the City and County of San Francisco, State of California, or at such other place within the State of California as may be designated by the Board of Directors. 2. Annual Meetings. The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors. Written notice of the annual meeting shall be given not less than ten (or, if sent by third-class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat. The notice shall state the place, day, and hour of such meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders. Notice of any meeting of the shareholders shall be given by mail or telegraphic or other written communication, postage prepaid, to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Corporation. 3. Special Meetings. Special meetings of the shareholders shall be called by the Secretary or an Assistant Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, or the President. Special meetings of the shareholders shall also be called by the Secretary or an Assistant Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting. Such request shall state the purposes of the meeting, and shall be delivered to the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President or the Secretary. [1] A special meeting so requested shall be held on the date requested, but not less than thirty-five nor more than sixty days after the date of the original request. Written notice of each special meeting of shareholders, stating the place, day, and hour of such meeting and the business proposed to be transacted thereat, shall be given in the manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within twenty days after receipt of the written request. 4. Attendance at Meetings. At any meeting of the shareholders, each holder of record of stock entitled to vote thereat may attend in person or may designate an agent or a reasonable number of agents, not to exceed three to attend the meeting and cast votes for his shares. The authority of agents must be evidenced by a written proxy signed by the shareholder designating the agents authorized to attend the meeting and be delivered to the Secretary of the Corporation prior to the commencement of the meeting. 5. No Cumulative Voting. No shareholder of the Corporation shall be entitled to cumulate his or her voting power. Article II. DIRECTORS. 1. Number. The Board of Directors of this corporation shall consist of such number of directors, not less than nine (9) nor more than seventeen (17), and the exact number of directors shall be fourteen (14) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders. 2. Powers. The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders. 3. Executive Committee. There shall be an Executive Committee of the Board of Directors consisting of the Chairman of the Committee, the Chairman of the Board, if these offices be filled, the President, and four Directors who are not officers of the Corporation. The members of the Committee shall be elected, and may at any time be removed, by a two-thirds vote of the whole Board. The Executive Committee, subject to the provisions of law, may exercise any of the powers and perform any of the duties of the Board of Directors; but the Board may by an affirmative vote of a majority of its members withdraw or limit any of the powers of the Executive Committee. The Executive Committee, by a vote of a majority of its members, shall fix its own time and place of meeting, and shall prescribe its own rules of procedure. A quorum of the Committee for the transaction of business shall consist of three members. 4. Time and Place of Directors' Meetings. Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance. 5. Special Meetings. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Secretary. Such notice shall be delivered personally or by telephone to each Director at least four hours in advance of such meeting, or sent by first- class mail or telegram, postage prepaid, at least two days in advance of such meeting. 6. Quorum. A quorum for the transaction of business at any meeting of the Board of Directors shall consist of six members. 7. Action by Consent. Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all Directors individually or collectively consent in writing to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors. 8. Meetings by Conference Telephone. Any meeting, regular or special, of the Board of Directors or of any committee of the Board of Directors, may be held by conference telephone or similar communication equipment, provided that all Directors participating in the meeting can hear one another. Article III. OFFICERS. 1. Officers. The officers of the Corporation shall be a Chairman of the Board, a Vice Chairman of the Board, a Chairman of the Executive Committee (whenever the Board of Directors in its discretion fills these offices), a President, one or more Vice Presidents, a Secretary and one or more Assistant Secretaries, a Treasurer and one or more Assistant Treasurers, a General Counsel, a General Attorney (whenever the Board of Directors in its discretion fills this office), and a Controller, all of whom shall be elected by the Board of Directors. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, and the President shall be members of the Board of Directors. 2. Chairman of the Board. The Chairman of the Board, if that office be filled, shall preside at all meetings of the shareholders, of the Directors, and of the Executive Committee in the absence of the Chairman of that Committee. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. He shall have such duties and responsibilities as may be prescribed by the Board of Directors or the Bylaws. The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and in the absence or disability of the President, shall exercise his duties and responsibilities. 3. Vice Chairman of the Board. The Vice Chairman of the Board, if that office be filled, shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. In the absence of the Chairman of the Board, he shall preside at all meetings of the Board of Directors and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, he shall preside at all meetings of the Executive Committee. The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 4. Chairman of the Executive Committee. The Chairman of the Executive Committee, if that office be filled, shall preside at all meetings of the Executive Committee. He shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board of Directors or the Bylaws. 5. President. The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. If there be no Chairman of the Board, the President shall also exercise the duties and responsibilities of that office. The President shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 6. Vice Presidents. Each Vice President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. Each Vice President's authority to sign agreements and instruments on behalf of the Corporation shall be as prescribed by the Board of Directors. The Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, or the President may confer a special title upon any Vice President. 7. Secretary. The Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and he shall record the minutes of all proceedings in books to be kept for that purpose. He shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Corporation. He shall give, or cause to be given, all notices required either by law or the Bylaws. He shall keep the seal of the Corporation in safe custody, and shall affix the seal of the Corporation to any instrument requiring it and shall attest the same by his signature. The Secretary shall have such other duties as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Secretaries shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Secretary. In the absence or disability of the Secretary, his duties shall be performed by an Assistant Secretary. 8. Treasurer. The Treasurer shall have custody of all moneys and funds of the Corporation, and shall cause to be kept full and accurate records of receipts and disbursements of the Corporation. He shall deposit all moneys and other valuables of the Corporation in the name and to the credit of the Corporation in such depositaries as may be designated by the Board of Directors or any employee of the Corporation designated by the Board of Directors. He shall disburse such funds of the Corporation as have been duly approved for disbursement. The Treasurer shall perform such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Treasurer shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Treasurer. In the absence or disability of the Treasurer, his duties shall be performed by an Assistant Treasurer. 9. General Counsel. The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature. He shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business. He shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation. The General Counsel shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. 10. Controller. The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and he shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation. He shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them. The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. He shall be the principal accounting officer of the Corporation, unless another individual shall be so designated by the Board of Directors. Article IV. MISCELLANEOUS. 1. Record Date. The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares. The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed. When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be. 2. Transfers of Stock. Upon surrender to the Secretary or Transfer Agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment, or authority to transfer, and payment of transfer taxes, the Corporation shall issue a new certificate to the person entitled thereto, cancel the old certificate, and record the transaction upon its books. Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of certificates for shares of stock of the Corporation, and to appoint and remove Transfer Agents and Registrars of transfers. 3. Lost Certificates. Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board of Directors so requires, give the Corporation, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Secretary of the Corporation, before a new certificate may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed. Article V. AMENDMENTS. 1. Amendment by Shareholders. Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders. 2. Amendment by Directors. To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors. EX-10.4 4 PG&E CORPORATION DEFFERED COMPENSATION PLAN EXHIBIT 10.4 PG&E CORPORATION DEFERRED COMPENSATION PLAN FOR OFFICERS (As amended and restated effective as of October 21, 1998) 1. Purpose ------- This is the controlling and definitive statement of the PG&E Corporation Deferred Compensation Plan for Officers ("PLAN")./1/ The PLAN which became effective on November 5, 1997, takes the place of and assumes the existing benefits accrued under the Deferred Compensation Plan of the Pacific Gas and Electric Company. The PLAN provides an opportunity for OFFICERS and other designated key employees of the CORPORATION and its subsidiaries and affiliates to defer payment of (1) part of their salaries, (2) all or part of their INCENTIVE PLAN AWARDS, (3) all of their SAVINGS FUND PLAN EXCESS BENEFITS, (4) PERQUISITE ALLOWANCES under the Executive Flexible Perquisites Program, (5) all or a portion of their PERFORMANCE UNITS under the Performance Unit Plan, and (6) such other payments, awards, allowances, or benefits as the COMMITTEE may in the future determine appropriate. SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS are automatically credited to participant accounts maintained by the PLAN. 2. Definitions ----------- (a) "BENEFICIARY" means the person, persons, or entity designated by the PLAN participant on the DEFERRAL ELECTION FORM to receive payment of the participant's DEFERRED COMPENSATION ACCOUNT in the event of the death of the participant. (b) "BOARD" and "BOARD OF DIRECTORS" means the BOARD OF DIRECTORS of the CORPORATION or, when appropriate, any committee of the BOARD which has been delegated authority to take action with respect to the PLAN. (c) "COMMITTEE" means the Nominating and Compensation Committee of the BOARD. (d) "CORPORATION" means PG&E Corporation, a California corporation. (e) "DEFERRAL ELECTION FORM" means a participation form to be supplied by the Human Resources Department of the CORPORATION. (f) "DEFERRED COMPENSATION ACCOUNT" means the bookkeeping account established pursuant to Section 6 on behalf of each ELIGIBLE EMPLOYEE who elects to participate in the PLAN. - ------------------------ /1/ Words in all capitals are defined in Section 2. (g) "ELIGIBLE EMPLOYEE" means an OFFICER and such other key employees as may be designated by the PLAN ADMINISTRATOR as eligible to participate in the PLAN. (h) "INCENTIVE PLAN AWARD" means a monetary award payable under the annual short-term performance incentive plan maintained by the CORPORATION, or any of its subsidiaries or affiliates. (i) "OFFICER" means all OFFICERS of the CORPORATION and its subsidiaries and affiliates in Officer Band 6 and above. (j) "PERFORMANCE UNITS" means the amounts which are payable as a result of units earned under the CORPORATION'S Performance Unit Plan, as may be revised thereafter from time to time. (k) "PERQUISITE ALLOWANCE" means the amounts which an OFFICER can use for the reimbursement of certain designated expenses under the CORPORATION'S Executive Flexible Perquisites Program. (l) "PLAN" means the PG&E Corporation Deferred Compensation Plan for Officers. (m) "PLAN ADMINISTRATOR" shall mean the senior Human Resources officer of the CORPORATION. (n) "SALARY" means the amount of compensation payable by the CORPORATION or by any of its subsidiaries or affiliates to an ELIGIBLE EMPLOYEE for his or her duties. It does not include any amount payable with respect to services rendered prior to an ELIGIBLE EMPLOYEE'S election to defer according to Section 5 of this PLAN. (o) "SAVINGS FUND PLAN EXCESS BENEFITS" means amounts payable to OFFICERS under the SAVINGS FUND PLAN EXCESS BENEFITS arrangement as originally adopted on December 20, 1989, and as may be revised thereafter from time to time. (p) "SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS" means the special premiums awarded to eligible OFFICERS under the Executive Stock Ownership Guidelines approved by the COMMITTEE on October 15, 1997, as amended on July 22, 1998, and as may hereafter be amended from time to time. (q) "TERMINATION DATE" means the last day on which the PLAN participant is an employee of the CORPORATION, one of its subsidiaries, or of an association affiliated with the CORPORATION. (r) "YEAR" means the calendar YEAR. 3. Eligibility ----------- Each OFFICER who receives a SALARY for service as an OFFICER of the CORPORATION shall be eligible to participate in the PLAN. Any other -2- ELIGIBLE EMPLOYEE shall be eligible to participate in the PLAN consistent with the terms set by the PLAN ADMINISTRATOR in its designation of such key employee as an ELIGIBLE EMPLOYEE. 4. Participation ------------- In order to commence participation in the PLAN, a participant must file a DEFERRAL ELECTION FORM with the PLAN ADMINISTRATOR. An election to defer (i) an INCENTIVE PLAN AWARD, (ii) PERFORMANCE UNITS or (iii) SALARY must be filed prior to the beginning of the YEAR in which said amounts are paid. An election to defer SAVINGS FUND PLAN EXCESS BENEFITS must be filed prior to the beginning of the Savings Fund Plan YEAR to which the Excess Benefits are attributable. An election to defer PERQUISITE ALLOWANCES must be filed prior to the beginning of the YEAR in which said amounts are granted. SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS are automatically deferred into the PLAN immediately upon grant. Notwithstanding the foregoing, upon first becoming an ELIGIBLE EMPLOYEE, an election to participate shall be effective for the month following the filing of a DEFERRAL ELECTION FORM, provided said Form is filed within 60 days following the date when the employee first becomes an ELIGIBLE EMPLOYEE. (a) Deferral of SALARY ------------------ A participant may defer from 5 percent to 30 percent of his or her monthly SALARY. (b) Deferral of INCENTIVE PLAN AWARDS --------------------------------- A participant may defer all or part of his or her INCENTIVE PLAN AWARDS. (c) Deferral of SAVINGS FUND PLAN EXCESS BENEFITS --------------------------------------------- A participant may defer all amounts which would otherwise be paid in cash under the SAVINGS FUND PLAN EXCESS BENEFITS arrangement. Partial deferrals of SAVINGS FUND PLAN EXCESS BENEFITS are not permitted. (d) Deferral of PERQUISITE ALLOWANCES --------------------------------- A participant may elect to defer any portion of his or her flexible PERQUISITE ALLOWANCE. (e) Deferral of PERFORMANCE UNITS ----------------------------- A participant may elect to defer all or part of his or her PERFORMANCE UNITS. (f) Deferral of SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS. ------------------------------------------------------ All of an OFFICER'S SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS are automatically deferred to the PLAN immediately upon -3- grant and converted into units representing shares of PG&E Corporation common stock. The units attributable to SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS and any additional units resulting from the conversion of dividend equivalents thereon remain unvested until the earlier of the third anniversary of the date on which the SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS are credited to an OFFICER'S DEFERRED COMPENSATION ACCOUNT (provided the OFFICER continues to be employed on such date), death, disability, or retirement of the participant, or upon a Change in Control as defined in the PG&E Corporation Long-Term Incentive Program (LTIP). (The term "disability" shall, for purposes of the PLAN, have the same meaning as in Section 22(e)(3) of the Internal Revenue Code.) Unvested units attributable to SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS and any additional units resulting from the conversion of dividend equivalents thereon shall be forfeited upon termination of the OFFICER'S employment unless otherwise provided in the PG&E Corporation Officer Severance Policy, or if an OFFICER'S stock ownership falls below the levels set forth in the Executive Stock Ownership Program. The phantom stock units attributable to the award of SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS under the Executive Stock Ownership Guidelines, and additional units acquired upon the conversion of dividend equivalents thereon, constitute Incentive Awards under the LTIP. An such units are credited to a participant's account, an equal number of shares of PG&E Corporation common stock shall be reserved from the pool of shares authorized for issuance under the LTIP. Upon forfeiture of such units, a number of shares equal to the number of forfeited units shall again become available for issuance under the LTIP. 5. Deferral Election ----------------- An ELIGIBLE EMPLOYEE who elects to participate in the PLAN shall file an executed DEFERRAL ELECTION FORM with the PLAN ADMINISTRATOR which (i) indicates the percentage of SALARY and applicable pay periods, and the amount of any INCENTIVE PLAN AWARD, PERFORMANCE UNITS, SAVINGS FUND PLAN EXCESS BENEFITS, PERQUISITE ALLOWANCES, and such other eligible payments, awards, allowances, or benefits to be deferred under the PLAN; and (ii) specifies the time and form of distribution and designates a BENEFICIARY. A participant may not elect to defer the receipt of SALARY, any INCENTIVE PLAN AWARD, PERFORMANCE UNITS, or SAVINGS FUND PLAN EXCESS BENEFITS, for less than three years, subject to earlier distribution following termination of employment in accordance with Section 9. The participant's deferral election of SALARY shall continue from YEAR to YEAR until terminated or modified by written notice to the PLAN ADMINISTRATOR. Notice of termination of SALARY deferrals shall not become effective until the first day of the month following the month in which such written notice is received by the PLAN ADMINISTRATOR. A participant who terminates SALARY deferrals shall not be permitted to elect future SALARY deferrals earlier than the first day of the following YEAR. A participant may modify a prior deferral election of SALARY only by delivering a -4- new DEFERRAL ELECTION FORM to the PLAN ADMINISTRATOR to be effective as of the first day of the following YEAR. In no event shall any termination or modification of deferrals affect amounts deferred prior to the effective date of such termination or modification. Deferral elections of INCENTIVE PLAN AWARDS, PERFORMANCE UNITS, SAVINGS FUND PLAN EXCESS BENEFITS, and PERQUISITE ALLOWANCES, only are effective for the YEAR following the YEAR in which the executed DEFERRAL ELECTION FORM is filed with the PLAN ADMINISTRATOR. Thereafter, a new DEFERRAL ELECTION FORM must be filed with the PLAN ADMINISTRATOR in order to maintain deferrals in subsequent years. All deferral elections of INCENTIVE PLAN AWARDS, PERFORMANCE UNITS, SAVINGS FUND PLAN EXCESS BENEFITS, and PERQUISITE ALLOWANCES may be revoked prior to the beginning of the YEAR in which INCENTIVE PLAN AWARDS, PERFORMANCE UNITS, and PERQUISITE ALLOWANCES would otherwise be paid, and thereafter shall be irrevocable. All deferral elections of SAVINGS FUND PLAN EXCESS BENEFITS may be revoked prior to the beginning of the Savings Fund Plan YEAR to which the Excess Benefits are attributable. Notwithstanding the foregoing, the participant's designation as to time and form of distribution to the participant may not be revoked or modified by the participant as to amounts already deferred, except as permitted by the PLAN ADMINISTRATOR pursuant to Section 10 in the case of hardship withdrawals. 6. Credits to DEFERRED COMPENSATION ACCOUNT ---------------------------------------- Upon receipt of a completed DEFERRAL ELECTION FORM, the CORPORATION shall establish a DEFERRED COMPENSATION ACCOUNT to which shall be credited such amounts as the participant has elected to defer under the terms of the PLAN. SALARY which is deferred shall be credited to the participant's DEFERRED COMPENSATION ACCOUNT as of each payroll period. SAVINGS FUND PLAN EXCESS BENEFITS which are deferred shall be credited to the participant's DEFERRED COMPENSATION ACCOUNT as of the first business day following the end of the YEAR to which such Excess Benefits are attributable. PERQUISITE ALLOWANCES which are deferred shall be credited to the participant's DEFERRED COMPENSATION ACCOUNT on the date of grant. PERFORMANCE UNITS and INCENTIVE PLAN AWARDS which are deferred shall be credited to the participant's DEFERRED COMPENSATION ACCOUNT as of the date such amounts would otherwise have been paid. SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall be credited to the participant's DEFERRED COMPENSATION ACCOUNT immediately upon the date of grant and converted into units (including fractions computed to three decimal places) representing shares of PG&E Corporation common stock. The initial value of a SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM unit shall be the average of the daily high and low price of a share of PG&E Corporation common stock as traded on the New York Stock Exchange for the 30 trading days preceding the date that the SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM is credited to a participant's DEFERRED COMPENSATION ACCOUNT. Thereafter, the value of a SPECIAL -5- INCENTIVE STOCK OWNERSHIP PREMIUM unit shall fluctuate with the closing price of a share of PG&E Corporation common stock. Whenever dividends are declared with respect to the Corporation's common stock, additional SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM units (including fractions computed to three decimal places) shall be credited to a participant's account on the dividend payment date in an amount determined by dividing (i) the aggregate amount of dividends, i.e., the dividend multiplied by the number of SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM units credited to the participant's account as of the dividend record date, by (ii) the closing price of PG&E Corporation common stock on the New York Stock Exchange on the dividend payment date. 7. Earnings During Deferral Period ------------------------------- At such time as participant elects to participate in the PLAN, he shall also elect to have his account balances allocated to the Utility Bond Fund or to the PG&E Corporation Phantom Stock Fund. Participant shall make such elections and in such percentages as the PLAN ADMINISTRATOR shall prescribe. Participant shall be able to reallocate account balances between the funds and reallocate new deferrals at such time and in such manner as the PLAN ADMINISTRATOR shall prescribe; provided, however, that units attributable to SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS and additional units resulting from the conversion of dividend equivalents thereon may not be reallocated. Anything to the contrary herein notwithstanding, a participant may not reallocate account balances between funds if such reallocation would result in a non-exempt Discretionary Transaction as defined in Rule 16b-3 of the Securities Exchange Act of 1934, as amended, or any successor to Rule 16b-3, as in effect when the reallocation is requested. (a) Utility Bond Fund ----------------- On the first business day of each calendar quarter, interest shall be credited on the balance in each participant's DEFERRED COMPENSATION ACCOUNT as of the last day of the immediately preceding calendar quarter and prorated based on the number of days in the quarter that the balance was allocated to the Utility Bond Fund. Such interest shall be at a rate equal to the AA Utility Bond Yield reported in Moody's Public Utility, ---------------------- published in the issue of Moody's Investors Service immediately preceding ------------------------- the first day of the calendar quarter in which the interest is to be credited. Such interest shall become a part of the DEFERRED COMPENSATION ACCOUNT and shall be paid at the same time or times as the balance of the DEFERRED COMPENSATION ACCOUNT. Notwithstanding the above, if a participant has requested that his account balance be reallocated to the PG&E Corporation Phantom Stock Fund before the end of the quarter, prorated interest on the participant's account balance shall be calculated at a rate equal to the AA Utility Bond Yield reported in Moody's Public Utility, ---------------------- published in the issue of Moody's Investors Service immediately preceding ------------------------- the date of reallocation, shall be credited to the participant's account on the date of reallocation, and shall be subject to the reallocation request. (b) PG&E Corporation Phantom Stock Fund ----------------------------------- Deferrals credited to the PG&E Corporation Phantom Stock Fund shall be converted into units (including fractions computed to three decimal places) each -6- representing share of PG&E Corporation common stock. The value of a unit for purposes of determining the number of units to credit upon initial deferral or reallocation from the Utility Bond Fund, and for determining the dollar value of the aggregate number of units to be reallocated from the PG&E Corporation Phantom Stock Fund to the Utility Bond Fund, shall be the average of the daily high and low price of a share of PG&E Corporation common stock as traded on the New York Stock Exchange for the 30 trading days preceding (i) the date that deferrals and reallocations are credited to a participant's account in the PG&E Corporation Phantom Stock Fund in the case of new deferrals and reallocations from the Utility Bond Fund, and (ii) the date the PLAN ADMINISTRATOR receives a reallocation request, in the case of reallocations. Thereafter, the value of a unit shall fluctuate in accordance with the closing price of PG&E Corporation common stock on the New York Stock Exchange. Whenever dividends are paid with respect to the Corporation's common stock, additional units (including fractions computed to three decimal places) shall be credited to a participant's account on the dividend payment date in an amount determined by dividing (i) the aggregate amount of dividends, i.e,. the dividend multiplied by the number of units credited to the participant's account as of the dividend record date, by (ii) the closing price of PG&E Corporation common stock on the New York Stock Exchange on the dividend payment date. If, after the record date but before the dividend payment date, a participant's balance in the PG&E Corporation Phantom Stock Fund has been reallocated to the Utility Bond Fund, or has been paid to the participant or the participant's beneficiary, then an amount equal to the aggregate dividend shall be credited to the participant's account in the Utility Bond Fund, or paid directly to the participant or the participant's beneficiary, whichever is applicable. 8. Effect of Deferral on Qualified Benefit PLANS --------------------------------------------- A participant who participates in this PLAN shall continue to be eligible to participate in all CORPORATION benefit PLANS. However, no amount deferred under this PLAN shall be deemed to be covered compensation or SALARY for the purposes of computing percentage of participation and benefits to which the OFFICER may be entitled under the CORPORATION Retirement and Savings Fund Plans and any other CORPORATION benefit plans which are qualified under Section 401(a) of the Internal Revenue Code of 1986, as amended. 9. Form and Time of Payment to a Participant of DEFERRED COMPENSATION ACCOUNT -------------------------------------------------------------------------- Payment to the participant of deferred compensation allocated to the Utility Bond Fund or the PG&E Corporation Phantom Stock Fund shall be made in the form of cash. At the election of the participant, the cash may be paid in a lump sum or in a series of ten or less approximately equal annual installments. Payment to the participant shall be made at such time and in such form as the participant has specified on the DEFERRAL ELECTION FORM(s) previously filed with the PLAN ADMINISTRATOR; provided however, that payments shall commence (either as a lump sum or as the first of a series of ten or less approximately equal annual installments) no later than January of the YEAR following the YEAR in which the participant's employment terminated. Payment to a participant of his or her DEFERRED COMPENSATION ACCOUNT shall be made in January of -7- each YEAR in which payment is to be made in accordance with the participant's DEFERAL ELECTION FORM. All payments from the DEFERRED COMPENSATION ACCOUNT shall be subject to all tax withholdings or other reductions which may be required by law. In accordance with Section 11 of the LTIP with respect to Incentive Awards, a participant may elect (unless the Committee determines otherwise) to have PG&E Corporation withhold a sufficient number of shares of PG&E Corporation common stock from the shares otherwise due upon settlement of the phantom stock units attributable to SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS (and dividend equivalents with respect thereto), to satisfy applicable withholding taxes. The value of the shares withheld shall be calculated in the same manner as the value of the shares distributed to the participant for tax reporting purposes. For purposes of this Section 9 and Sections 10 and 11 below, the amount of cash to be distributed upon settlement of units credited to a participant's account in the PG&E Corporation Phantom Stock Fund shall be equal to the number of credited units, or fraction thereof, multiplied by the average of the high and low price of a share of PG&E Corporation common stock as traded on the New York Stock Exchange for the 30 trading days preceding the date of distribution. Notwithstanding the foregoing, following a participant's termination of employment, deferrals attributable to SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall only be distributed in January of the YEAR following termination in the form of one or more certificates for a number of shares of PG&E Corporation common stock equal to the number of vested SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM units, rounded down to the nearest whole share. 10. Distribution Due to Unforeseeable Emergency ------------------------------------------- A participant may request a distribution due to an Unforeseeable Emergency by submitting a written request to the Plan Administrator accompanied by evidence to demonstrate that the circumstances being experienced qualify as an Unforeseeable Emergency. The Plan Administrator shall have the authority to require such evidence as it deems necessary to determine if a distribution is warranted. If an application for a hardship distribution due to an Unforeseeable Emergency is approved, the distribution is limited to the amount sufficient to meet the emergency. The allowed distribution shall be payable in a method determined by the Plan Administrator as soon as possible after approval of such distribution. A participant who has commenced receiving installment payments under the Plan may request acceleration of such payments in the event of an Unforeseeable Emergency. The Administrator may permit accelerated payments to the extent such accelerated payment does not exceed the amount necessary to meet the emergency. For purposes of this Section 10, an "Unforeseeable Emergency " means a severe financial hardship to the participant resulting from a sudden and unexpected illness or accident of the participant or of a dependent of the participant, loss of the participant's property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant. The circumstances that will constitute an "Unforeseeable Emergency" would depend upon the facts in each case, but, in any case, payment may not be made in the event that such hardship is or may be relieved (i) through prompt -8- reimbursement or compensation by insurance or otherwise, (ii) by liquidation of the participant's assets, to the extent that liquidation of such assets would not itself cause severe financial hardship, or (iii) by cessation of deferrals under the Plan. The need to send a participant's child to college or the desire to purchase a home shall not be an Unforeseeable Emergency. 11. Effect of Death of Participant ------------------------------ Upon the death of a participant who participated in the PLAN, all amounts, if any, remaining in his or her DEFERRED COMPENSATION ACCOUNT shall be distributed to the BENEFICIARY designated by the participant. Payment to the beneficiary shall be made at such time and in such form as the participant has previously specified in a form previously filed with the PLAN ADMINISTRATOR; provided however, that payments shall commence (either as a lump sum or as the first of a series of ten or less approximately equal annual installments) no later than January of the YEAR following the YEAR in which the participant's death occurred. Earnings, as determined under Section 7 of the PLAN, shall be credited to the date of distribution. Any shares of PG&E Corporation common stock to be issued in settlement of the deceased participant's SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM units shall be issued in the name of the participant's designated beneficiary. If the designated BENEFICIARY does not survive the participant or dies before receiving payment in full of the participant's DEFERRED COMPENSATION ACCOUNT, a lump sum payment of the remaining balance (and a distribution of the shares of PG&E Corporation common stock issuable in settlement of the deceased participant's SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM units) shall be made as soon as practicable to the estate of whoever dies last, the participant or the designated BENEFICIARY. All BENEFICIARY designations may be changed by the participant at any time without the consent of a BENEFICIARY. The participant shall notify the PLAN ADMINISTRATOR in writing of any such change of BENEFICIARY. 12. Participant's Rights Unsecured ------------------------------ The interest under the PLAN of any participant and such participant's right to receive a distribution of his or her DEFERRED COMPENSATION ACCOUNT shall be an unsecured claim against the general assets of the CORPORATION. The DEFERRED COMPENSATION ACCOUNT shall consist of bookkeeping entries only, and this PLAN does not create an interest in, nor permit a claim against, any specific asset of the CORPORATION pursuant to the PLAN. 13. Annual Statement of DEFERRED COMPENSATION ACCOUNT ------------------------------------------------- As soon as practicable after the close of each YEAR, each participant shall be provided with a statement describing the status of his or her DEFERRED COMPENSATION ACCOUNT as of the end of the preceding YEAR. The statement shall reflect the totals of amounts deferred during the YEAR, the amount of interest credited, the amount of PG&E Corporation Phantom Stock Fund units, the amount of SPECIAL INCENTIVE STOCK OWNERSHIP -9- PREMIUMS (if any), the amount of payments made during the YEAR, if any, and the net balance remaining in the account at the end of the YEAR. 14. Nonassignability of Interests ----------------------------- The interest and property rights of any participant under the PLAN shall not be assignable either by voluntary or involuntary assignment or by operation of law, including (without limitation) bankruptcy, garnishment, attachment or other creditor's process, and any act in violation of this Section 14 shall be void. 15. Administration of the PLAN -------------------------- The PLAN shall be administered by the PLAN ADMINISTRATOR. The PLAN ADMINISTRATOR shall have full power and authority to administer and interpret the PLAN, to establish procedures for administering the PLAN, and to take any and all necessary action in connection therewith. The PLAN ADMINISTRATOR's interpretation and construction of the PLAN shall be conclusive and binding on all persons. 16. Amendment or Termination of the PLAN ------------------------------------ The CORPORATION may amend, suspend, or terminate the PLAN at any time. In the event of such termination, the DEFERRED COMPENSATION ACCOUNTS of participants shall be paid in accordance with the participant's deferral election. -10- EX-10.5 5 SHORT-TERM INCENTIVE PLAN - 1/1/1998 Exhibit 10.5 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 1998. Executive Summary ----------------- Background - ---------- In October of this year, the Nominating and Compensation Committee reviewed and approved a general short-term incentive plan (STIP) structure for officers of the Corporation and each subsidiary. Recommendation - -------------- It is recommended that the Nominating and Compensation Committee approve a STIP structure for officers which ties a significant portion (a minimum of 75%) of all officers'(1) short-term incentives to earnings per share (EPS) objective as measured by earnings from operations. The remainder of each officers' STIP will be linked to either additional financial measures or operational measures as defined by the respective head of each subsidiary. The EPS performance scale will be constructed and presented to the Committee for its approval in January 1998, based on actual 1997 earnings from operations. (1) Excludes PG&E Energy Services officers (see page 3). 1 Background ---------- Short-Term Incentive Plan Structure - ----------------------------------- In October of this year, the Nominating and Compensation Committee reviewed and approved the following general STIP structure for officers of the Corporation and each subsidiary:
Officer Group Award Components Weight - ------------- ---------------- ------- PG&E Corporation Corporate Financial Performance 75% Subsidiary Performance (1) 25% Subsidiary CEO's Corporate Financial Performance 25% Subsidiary Performance (2) 75% PG&E Company Subsidiary Financial Performance 25-100% Subsidiary Operational Performance Remainder of weighting PG&E Energy Services Subsidiary Financial Performance 25-100% Subsidiary Operational Performance Remainder of weighting PG&E US Generating Subsidiary Financial Performance 25-100% Subsidiary Operational Performance Remainder of weighting PG&E Energy Trading Subsidiary Financial Performance 25-100% Subsidiary Operational Performance Remainder of weighting PG&E Gas Transmissions Subsidiary Financial Performance 25-100% Subsidiary Operational Performance Remainder of weighting
(1) Simple average of the STIP performance ratings of the five subsidiaries. (2) STIP performance rating of respective subsidiary. 2 Recommendation -------------- It is recommended that the Nominating and Compensation Committee approve the following officer STIP structures and associated Corporate financial performance measure.
Short-Term Incentive Plan Structures - ------------------------------------ Officer Group Award Component Weight Performance Measure - ------------- --------------- ------ ------------------- PG&E Corporation Corporate Financial Performance 75% Corporate EPS from operations Subsidiary Performance 25% Average STIP rating of five subsidiary officer groups Subsidiary CEO's Corporate Financial Performance 25% Corporate EPS from operations Subsidiary Performance 75% Average STIP rating of respective subsidiary PG&E Company Subsidiary Financial Performance 75% Subsidiary contribution to PG&E Gas Transmission corporate EPS from operations PG&E Energy Trading Subsidiary Operational 25% Financial, operating, and PG&E US Generating Performance service measures determined by subsidiary CEO PG&E Energy Services Subsidiary Financial Performance 40% Financial measures (12%) are net income and gross margin. Non-financial measures (28%) are sales momentum, product development, staffing, regulatory relations, and effective relationships with other PG&E subsidiaries Individual Officer Performance 60% Subjective evaluation of each individual's contribution to company performance approved by Corporation CEO
3 Recommendation (continued) -------------- Corporate Financial Performance Measure - --------------------------------------- The Corporate financial measure will be earnings per share (EPS). The 1998 EPS performance scale will be presented to the Committee for approval in January 1998. The scale will be designed so that (1) there will be no payout unless 1998 EPS exceeds inflation-adjusted 1997 EPS from operations, and (2) target payout will occur only if 1998 EPS exceeds the 1998 budget (in the past, target has been pegged to the budget). EPS Performance Level STIP Payout Level --------------------- ----------------- 9.0% Above 1997 EPS Maximum 2.00 1998 EPS Budget 0.75 Inflation-Adjusted 1997 EPS Threshold 0.50 See Appendix A for an example of the EPS Scale. The 1997 EPS used to calculate the performance scale will be the EPS from operations used to determine the 1997 STIP payout. The 1998 EPS used to measure the achievement of the 1998 STIP will be EPS from operations resulting from implementing the 1998 business plan and budget. As with past STIPs, unbudgeted one-time charges for items such as changes in accounting methods, workforce restructuring, and similar one-time occurrences will be excluded, and the Committee will continue to retain full discretion to determine final awards to officers. 4 EX-10.6 6 SHORT-TERM INCENTIVE PLAN - 1/1/1999 EXHIBIT 10.6 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 1999. Recommendation -------------- It is recommended that the Nominating and Compensation Committee approve the following methodology for establishing the scale for the corporate EPS performance measure. TARGET (1.0) payout will occur at budgeted financial performance of $2.15 per share. This is estimated to represent a 13% increase over 1998 EPS from operations. THRESHOLD (0.5) payout will occur at 1999 EPS from operations of 5% over actual 1998 EPS from operations(1). MAXIMUM (2.0) payout will occur at 1999 EPS from operations of 17.5% over actual 1998 EPS from operations(1). Each of these payout targets represents a significant stretch from 1998 and prior years as illustrated in the table below. Appendix B shows an example of this scale based on a current forecast of 1998 EPS from operations performance.
EPS Performance Level STIP Payout Level --------------------- ----------------- 1999 1998 ---- ---- 17.50 Above 1998 EPS 11.65% Above 1997 EPS Maximum 2.00 13.16% Above 1998 EPS 7.51% Above 1997 EPS Target 1.00 5.00% Above 1998 EPS 0.00% Above 1997 EPS Threshold 0.50
The 1998 EPS used to calculate the performance scale will be the EPS from operations used to determine the 1998 STIP payout. The 1999 EPS used to measure the achievement of the 1999 STIP will be EPS from operations resulting from implementing the 1999 business plan and budget. As with past STIPs, unbudgeted one-time charges for items such as changes in accounting methods, workforce restructuring, and similar one-time occurrences will be excluded, and the Committee will continue to retain full discretion to determine final awards to officers. (1) This actual value will be presented to the Committee in January 1999 when actual 1998 EPS from operations are available. 1 Background ---------- Short-Term Incentive Plan Structure - ----------------------------------- At its meeting on October 21, 1998, the Nominating and Compensation Committee reviewed and approved the 1999 Short-Term Incentive Plan (STIP) structure for officers of the Corporation and each subsidiary. The structure (see Appendix A) established the weighting of corporate earnings per share (EPS), subsidiary EPS, and other performance factors for officers. The structure requires an implementing methodology to link the EPS performance levels to threshold, minimum, and maximum incentive payout levels, which is contained in this document. 2 EX-10.7 7 SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN EXHIBIT 10.7 SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN OF THE PACIFIC GAS AND ELECTRIC COMPANY ---------------------------------------------- This is the controlling and definitive statement of the Supplemental Executive Retirement Plan ("PLAN"/1/) for ELIGIBLE EMPLOYEES of Pacific Gas and Electric Company ("COMPANY") and such other companies, affiliates, subsidiaries, or associations as the BOARD OF DIRECTORS may designate from time to time. The PLAN was first adopted by the BOARD OF DIRECTORS in 1984 and was effective January 1, 1985. It has since been amended from time to time. Except as expressly stated by any amendment to this PLAN, benefits of ELIGIBLE EMPLOYEES who retire, terminate from employment, or cease to be ELIGIBLE EMPLOYEES prior to the effective date of any amendment shall not be affected by any such amendment. The amended PLAN as contained herein is effective January 1, 1998. ARTICLE I DEFINITIONS ----------- 1.01 Basic SERP Benefit shall mean the benefit described in Section 2.01. ------------------ 1.02 Beneficiary shall mean the person, persons, or entity designated by ----------- the ELIGIBLE EMPLOYEE to receive payments under any optional form of benefit elected pursuant to Section 2.03 c. or Section 2.03 d., payable or owed but unpaid at the time of the ELIGIBLE EMPLOYEE's death. An ELIGIBLE EMPLOYEE shall designate a BENEFICIARY on a form provided by the PLAN ADMINISTRATOR and kept on file in the PLAN ADMINISTRATOR's office. An ELIGIBLE EMPLOYEE may change a BENEFICIARY at any time by filing a new beneficiary form with the PLAN ADMINISTRATOR. 1.03 Board or Board of Directors shall mean the BOARD OF DIRECTORS of the ----- ------------------ COMPANY or, when appropriate, any committee of the BOARD which has been delegated the authority to take action with respect to the PLAN. 1.04 Company shall mean the Pacific Gas and Electric Company, a California ------- corporation. - ----------------------------- /1/ Words in all capitals are defined in Article I. 1.05 Eligible Employee shall mean (1) employees of the COMPANY, or (2) ----------------- with respect to PG&E Corporation and PG&E Corporation Support Services, Inc., employees who were transferred to PG&E Corporation or PG&E Corporation Support Services, Inc., from the COMPANY before January 1, 2000, (3) who are officers at the vice presidential level or above, the corporate secretary, the controller, and the treasurer of the COMPANY, and (4) such other employees of the COMPANY, or such other companies, affiliates, subsidiaries, or associations as may be designated by the Nominating and Compensation Committee. 1.06 STIP Payment shall mean amounts received by an ELIGIBLE EMPLOYEE ------------ under the Short-Term Incentive Plan maintained by PG&E Corporation. 1.07 Plan shall mean the Supplemental Executive Retirement Plan ("SERP") ---- as set forth herein and as may be amended from time to time. 1.08 Plan Administrator shall mean the Employee Benefit Administrative ------------------ Committee or such individual or individuals as that Committee may appoint to handle the day-to-day affairs of the PLAN. 1.09 Retirement Plan shall mean the Pacific Gas and Electric Company --------------- Retirement Plan for Management Employees. 1.10 Salary shall mean the base salary received by an ELIGIBLE EMPLOYEE. ------ SALARY shall not include amounts received by an employee after such employee ceases to be an ELIGIBLE EMPLOYEE. For purposes of calculating benefits under the PLAN, SALARY shall not be reduced to reflect amounts which have been deferred under the Pacific Gas and Electric Company Deferred Compensation Plan or under the PG&E Corporation Deferred Compensation Plan which became effective November 5, 1997. 1.11 Service shall mean "credited service" as that term is defined in the ------- RETIREMENT PLAN or, if the Nominating and Compensation Committee of the BOARD OF DIRECTORS has granted an adjusted service date for an ELIGIBLE EMPLOYEE, "credited service" as calculated from such adjusted service date. In no event, however, shall SERVICE include periods of time after which an officer has ceased to be an ELIGIBLE EMPLOYEE. ARTICLE II SERP BENEFITS ------------- 2.01 The BASIC SERP BENEFIT payable from the PLAN shall be a monthly annuity commencing on the first of the month following the month in which the ELIGIBLE 2 EMPLOYEE (i) attains his 65th birthday or (ii) ceases to be an employee of the COMPANY, whichever is later. The monthly amount of the BASIC SERP BENEFIT shall be equal to the product of: 1.6% x [average of three highest calendar years' combination of SALARY and STIP PAYMENT for the last ten years of SERVICE] x SERVICE x 1/12. In computing a year's combination of SALARY and STIP PAYMENT, the year's amount shall be the sum of the SALARY and STIP PAYMENT, if any, paid or payable in the same calendar year. If an ELIGIBLE EMPLOYEE has fewer than three years' SALARY, the average shall be the combination of SALARY and STIP PAYMENT for such shorter time, divided by the number of years and partial years during which such employee was an ELIGIBLE EMPLOYEE. The BASIC SERP BENEFIT is further reduced by any amounts paid or payable from the RETIREMENT PLAN, calculated before adjustments for marital or joint pension option elections. 2.02 For ELIGIBLE EMPLOYEES of the COMPANY, PG&E Corporation, or PG&E Corporation Support Services, Inc., who transfer from any of said companies to another subsidiary or affiliate, the principles of Section 10 of the RETIREMENT PLAN shall govern the calculation of benefits under this PLAN. An ELIGIBLE EMPLOYEE who ceases to be an employee of the COMPANY and who is also not employed by any of its subsidiaries, affiliates, or related associations shall be entitled to receive a benefit payable from the PLAN at any time after his 55th birthday. The amount of the benefit payable shall be reduced by the appropriate age and service factors contained in the RETIREMENT PLAN applicable to such employee. For such calculations, the service factor shall be SERVICE as defined in the PLAN. In computing amounts payable from the RETIREMENT PLAN as an offset to the benefit payable from this PLAN, the RETIREMENT PLAN benefit shall be calculated as though the ELIGIBLE EMPLOYEE elected to receive a pension from the RETIREMENT PLAN commencing on the same date as benefits from this PLAN. 2.03 An ELIGIBLE EMPLOYEE may elect to have his BASIC SERP BENEFIT paid in any one of the following forms: a. BASIC SERP BENEFIT, or a reduced BASIC SERP BENEFIT as calculated under Section 2.02, paid as a monthly annuity for the life of the ELIGIBLE EMPLOYEE with no survivor's benefit. b. A monthly annuity payable for the life of the ELIGIBLE EMPLOYEE with a survivor's option payable to the ELIGIBLE EMPLOYEE's joint annuitant beginning on the first of the month following the ELIGIBLE EMPLOYEE'S 3 death. The factors to be applied to reduce the BASIC SERP BENEFIT to provide for a survivor's benefit shall be the factors which are contained in the RETIREMENT PLAN and which are appropriate given the type of joint pension elected and the ages and marital status of the joint annuitants. c. A five-year or ten-year certain annuity, with equal annual installment payments beginning on January 1 of the year following the year in which payments of the BASIC SERP BENEFIT would otherwise have commenced and continuing every January 1 thereafter until all payments are made. In determining the amount of the annuity payments, the present value of the BASIC SERP BENEFIT shall be computed using the appropriate mortality factors contained in the RETIREMENT PLAN for single life annuities and the interest rate set by the Pension Benefit Guaranty Corporation as of the first day of the year in which annuity payments begin. d. A lump sum payment of the actuarial present value of the BASIC SERP BENEFIT which would have been payable to the ELIGIBLE EMPLOYEE under Section 2.03 a. In determining the actuarial present value of the BASIC SERP BENEFIT, the PLAN ADMINISTRATOR shall apply the appropriate mortality factors used in calculating lump sum payments under the RETIREMENT PLAN for single life annuities and the interest rate set by the Pension Benefit Guaranty Corporation as of the first day of the year in which the lump sum payment is made. 2.04 Annuities payable to an ELIGIBLE EMPLOYEE who is receiving a (i) BASIC SERP BENEFIT, (ii) a BASIC SERP BENEFIT reduced to provide a survivor's benefit to a joint annuitant, or (iii) a joint annuitant who is receiving a survivor's benefit shall be decreased by any additional amounts which can be paid from the RETIREMENT PLAN where such additional amounts are due to increases in the limits placed on benefits payable from qualified pension plans under Section 4l5 of the Internal Revenue Code. The amount of any such decrease shall be adjusted to reflect the type of pension elected by an ELIGIBLE EMPLOYEE under the RETIREMENT PLAN and this PLAN. Decreases under this Section 2.04 shall not be applied to decrease benefits payable under the lump sum or the five-year or ten-year certain annuity options. ARTICLE III DEATH BENEFITS -------------- 3.01 For an ELIGIBLE EMPLOYEE who has elected to receive his PLAN benefits in one of the optional forms described in Section 2.03 c. or 2.03 d. and who dies before receiving the total number of payments selected under the optional form of benefit, the PLAN 4 ADMINISTRATOR shall continue to make the scheduled benefit payments to the BENEFICIARY designated by the ELIGIBLE EMPLOYEE. If the ELIGIBLE EMPLOYEE has failed to designate a BENEFICIARY or if there is no designated BENEFICIARY surviving at the time of the ELIGIBLE EMPLOYEE'S death, the PLAN ADMINISTRATOR shall make the remaining payments to the estate of the ELIGIBLE EMPLOYEE. 3.02 In the event that an ELIGIBLE EMPLOYEE who has accrued a benefit under this PLAN dies prior to the date that a BASIC SERP BENEFIT would otherwise commence and the ELIGIBLE EMPLOYEE is married at the time of the ELIGIBLE EMPLOYEE's death, the PLAN ADMINISTRATOR shall pay a spouse's benefit to the ELIGIBLE EMPLOYEE's surviving spouse: a. If the sum of the age and SERVICE of the ELIGIBLE EMPLOYEE at the time of death equaled 70 (69.5 or more is rounded to 70) or if the ELIGIBLE EMPLOYEE was age 55 at the time of death, the spouse's benefit shall be a monthly annuity commencing on the first of the month following the month in which the ELIGIBLE EMPLOYEE dies and shall be payable for the life of the surviving spouse. The amount of the monthly benefit shall be one-half of the monthly BASIC SERP BENEFIT which would have been paid to the ELIGIBLE EMPLOYEE calculated: 1) as if he had elected to receive a BASIC SERP BENEFIT, without survivor's option; 2) the monthly annuity starting date was the first of the month following the month in which the ELIGIBLE EMPLOYEE died; and 3) without the application of early retirement reduction factors. b. If the ELIGIBLE EMPLOYEE is less than 55 years of age or had fewer than 70 points (as calculated under Section 3.02(a)) at the time of death, the surviving spouse will be entitled to receive a monthly annuity commencing on the first of the month following the month in which the ELIGIBLE EMPLOYEE would have become age 55 if he had survived. The amount of the monthly annuity payable to the surviving spouse shall be equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor's benefit, calculated as if: 1) the ELIGIBLE EMPLOYEE had terminated employment at the date of death, 2) had lived until age 55, 3) had begun to receive PENSION payments, and 4) had subsequently died. c. If a former ELIGIBLE EMPLOYEE was age 55 or older at the time of his death and not yet receiving a SERP BENEFIT under the PLAN, the surviving spouse 5 will be entitled to receive a monthly annuity in an amount equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor's benefit, calculated as if the former ELIGIBLE EMPLOYEE had begun receiving the converted SERP BENEFIT immediately prior to his death. d. If a former ELIGIBLE EMPLOYEE was younger than age 55 or had fewer than 70 points (as calculated under Section 3.02(a)) at the time of his death, the surviving spouse will be entitled to receive a monthly annuity in an amount equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor's benefit, calculated as if: 1) the former ELIGIBLE EMPLOYEE had survived until age 55, 2) had begun receiving the converted SERP BENEFIT, and 3) had subsequently died. 3.03 A surviving spouse who is entitled to receive a spouse's benefit under Section 3.02 shall not be entitled to receive any other benefit under the PLAN. ARTICLE IV ADMINISTRATIVE PROVISIONS ------------------------- 4.01 Administration. The PLAN shall be administered by the PLAN -------------- ADMINISTRATOR who shall have the authority to interpret the PLAN and make such rules as it deems appropriate. The PLAN ADMINISTRATOR shall have the duty and responsibility of maintaining records, making the requisite calculations, and disbursing payments hereunder. The PLAN ADMINISTRATOR's interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned. 4.02 Amendment and Termination. The COMPANY may amend or terminate the ------------------------- PLAN at any time, provided, however, that no such amendment or termination shall adversely affect an accrued benefit which an ELIGIBLE EMPLOYEE has earned prior to the date of such amendment or termination, nor shall any amendment or termination adversely affect a benefit which is being provided to an ELIGIBLE EMPLOYEE, surviving spouse, joint annuitant, or beneficiary under Article II or Article III on the date of such amendment or termination. Anything in this Section 4.02 to the contrary notwithstanding, the COMPANY may reduce or terminate any benefit to which an ELIGIBLE EMPLOYEE, surviving spouse, joint annuitant, or BENEFICIARY is or may become entitled provided that such ELIGIBLE EMPLOYEE, surviving spouse, joint annuitant, or BENEFICIARY is or becomes entitled to an amount equal to such benefit under another plan, practice, or arrangement of the COMPANY. 6 4.03 Nonassignability of Benefits. The benefits payable under this PLAN ---------------------------- or the right to receive future benefits under this PLAN may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for any benefits becomes bankrupt, the interest under the PLAN of the person affected may be terminated by the PLAN ADMINISTRATOR which, in its sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that it deems appropriate. 4.04 Nonguarantee of Employment. Nothing contained in this PLAN shall be -------------------------- construed as a contract of employment between the COMPANY or the ELIGIBLE EMPLOYEE, or as a right of the ELIGIBLE EMPLOYEE to be continued in the employ of the COMPANY, to remain as an officer of the COMPANY, or as a limitation on the right of the COMPANY to discharge any of its employees, with or without cause. 4.05 Benefits Unfunded and Unsecured. The benefits under this PLAN are ------------------------------- unfunded, and the interest under this PLAN of any ELIGIBLE EMPLOYEE and such ELIGIBLE EMPLOYEE's right to receive a distribution of benefits under this PLAN shall be an unsecured claim against the general assets of the COMPANY. 4.06 Applicable Law. All questions pertaining to the construction, -------------- validity, and effect of the PLAN shall be determined in accordance with the laws of the United States, and to the extent not preempted by such laws, by the laws of the State of California. Adopted pursuant to the delegation contained in the Resolution of the Board of Directors of Pacific Gas and Electric Company dated June 18, 1997. By: /s/ Gordon R. Smith ---------------------------------------- Gordon R. Smith President and Chief Executive Officer Pacific Gas and Electric Company 7 EX-10.8 8 SUPPLEMENTAL EXECUTIVE RETIREMENT SAVINGS PLAN EXHIBIT 10.8 PG&E CORPORATION SUPPLEMENTAL EXECUTIVE RETIREMENT SAVINGS PLAN TABLE OF CONTENTS -----------------
Page ---- 1. Purpose of Plan....................................................... 1 2. Definitions........................................................... 1 3. Employer Contributions................................................ 3 4. Accounting............................................................ 6 5. Distributions......................................................... 7 6. Domestic Relations Orders............................................. 9 7. Vesting............................................................... 10 8. Administration Of The Plan............................................ 10 9. Funding............................................................... 10 10. Modification Or Termination Of Plan................................... 11 11. General Provisions.................................................... 11 Execution.................................................................. 12 Appendix A................................................................. 13
PG&E CORPORATION SUPPLEMENTAL EXECUTIVE RETIREMENT SAVINGS PLAN PG&E CORPORATION ("PG&E CORP") hereby establishes the PG&E Corporation Supplemental Executive Retirement Savings Plan (the "Plan"), effective as of January 1, 1997, with respect to all individuals who were Eligible Employees as of such date, other than Eligible Employees of U.S. Generating Company, Pacific Gas and Electric Company, and PG&E CORP, with respect to whom this Plan is effective as of January 1, 1998. 1. Purpose of the Plan ------------------- The Plan is established and is maintained for the benefit of a select group of management and highly compensated employees of PG&E CORP and its Participating Subsidiaries in order to provide such employees with certain deferred compensation benefits. The Plan is an unfunded deferred compensation plan that is intended to qualify for the exemptions provided in Sections 201, 301, and 401 of ERISA. 2. Definitions ----------- The following words and phrases shall have the following meanings unless a different meaning is plainly required by the context: (a) "Applicable Plan" shall mean, with respect to any Eligible Employee, --------------- the plan in which such Eligible Employee is an active participant that is sponsored by an Employer and that is a defined contribution plan intended to be qualified under Code Section 401(a). (b) "Board of Directors" shall mean the Board of Directors of PG&E CORP, ------------------ as from time to time constituted. (c) "Code" shall mean the Internal Revenue Code of 1986, as amended. ---- Reference to a specific section of the Code shall include such section, any valid regulation promulgated thereunder, and any comparable provision of any future legislation amending, supplementing, or superseding such section. (d) "Committee" shall mean the Nominating and Compensation Committee of --------- the Board, as it may be constituted from time to time. (e) "Compensation" shall mean an Eligible Employee's base compensation, and, with respect to an Eligible Employee whose Employer does not sponsor a defined benefit pension plan intended to be qualified under Code Section 401(a), such Eligible Employee's short-term incentive payments, before any deductions to such Eligible Employee's compensation deferrals elected by such Eligible Employee under the PG&E Corporation Deferred Compensation Plan for Officers and before any deductions for contributions to a plan qualifying under Section 401(k) of the Code as salary reduction contributions or to a cafeteria plan under Section 125 of the Code. An Eligible Employee's Compensation for purposes of this Plan shall not be subject to the dollar limitation of Section 401(a)(17) of the Code (e.g., $160,000 ---- for 1998). (f) "Eligible Employee" shall mean an Employee who: ----------------- (1) Is an officer of PG&E CORP or any Participating Subsidiary and who is in Officer Band 5 or above; or (2) Is a key employee of PG&E CORP or any Participating Subsidiary and who is designated by the Committee as eligible to participate in the Plan. (g) "Eligible Employee's Account" or "Account" shall mean as to any --------------------------- ------- Eligible Employee, the separate account maintained on the books of PG&E CORP in accordance with Section 4(a) in order to reflect his or her interest under the Plan. (h) "Employee" shall mean an individual who is treated in the records of -------- an Employer as an employee of the Employer and who is not covered by a collective bargaining agreement; provided, however, such term shall not mean an individual who is a "leased employee" or who has entered into a written contract or agreement with an Employer which explicitly excludes such individual from participation in an Employer's benefit plans. The provisions of this definition shall govern, whether or not it is determined that an individual otherwise meets the definition of "common law" employee. (i) "Employers" shall mean PG&E CORP and the Participating Subsidiaries --------- designated by the Employee Benefit Committee of PG&E CORP. An initial list of the Participating Subsidiaries is contained in Appendix A to this Plan. (j) "Employer Contributions" shall mean the amounts credited to Eligible ---------------------- Employees' Accounts under the Plan by the Employers, in accordance with Section 3(d). (k) "Employer Matching Contributions" shall mean the amounts credited to ------------------------------- Eligible Employees' Accounts under the Plan by the Employers, in accordance with Section 3(b). (l) "ERISA" shall mean the Employee Retirement Income Security Act of ----- 1974, as amended. Reference to a specific section of ERISA shall include such section, any valid regulation promulgated thereunder, and any comparable provision of any future legislation amending, supplementing, or superseding such section. (m) "Investment Funds" shall mean (i) the PG&E CORP Phantom Stock Fund, ---------------- (ii) the AA Utility Bond Fund, and (iii) the S&P 500 Index Fund. The Investment Funds shall be used for tracking phantom investment results under the Plan. 2 (n) "Participating Subsidiary" shall mean a subsidiary of PG&E CORP, which ------------------------ has been designated by the Chief Executive Officer of PG&E CORP as a Participating Subsidiary under this Plan. At such times and under such conditions as the Committee may direct, one or more other subsidiaries of PG&E CORP may become Participating Subsidiaries or a Participating Subsidiary may be withdrawn from the Plan. An initial list of the Participating Subsidiaries is contained in Appendix A to this Plan. (o) "Plan" shall mean the PG&E Corporation Supplemental Executive ---- Retirement Savings Plan, as set forth in this instrument and as heretofore and hereafter amended from time to time. (p) "Plan Year" shall mean the calendar year. --------- (q) "Retirement" or "Retire" shall mean an Eligible Employee's "separation ---------- ------ from service" within the meaning of Section 401(k) of the Code. (r) "PG&E CORP" shall mean PG&E Corporation, a California corporation. --------- (s) "Valuation Date" shall mean: -------------- (1) For purposes of valuing Plan assets and Eligible Employees' Accounts for periodic reports and statements, the date as of which such reports or statements are made; and (2) For purposes of determining the amount of assets actually distributed to the Eligible Employee, his or her beneficiary, or an Alternate Payee (or available for withdrawal), a date that shall not be more than seven business days prior to the date the check is issued to the Eligible Employee. In any other case, the Valuation Date shall be the date designated by the Plan Administrator (in its discretion) or the date otherwise set forth in this Plan. In all cases, the Plan Administrator (in its discretion) may change the Valuation Date, on a uniform and nondiscriminatory basis, as is necessary or appropriate. Notwithstanding the foregoing, the Valuation Date shall occur at least annually. 3. Employer Contributions ---------------------- (a) Employer Matching Contributions. Subject to the provisions of ------------------------------- Section 10, the Employer Account of each Eligible Employee shall be credited for each Plan Year with an additional Employer Matching Contribution, calculated in the manner provided in Sections 3(a) (1), (2), and (3) below: (1) First, an amount shall be calculated equal to the maximum matching contribution that would be made under the terms of the Applicable Plan, taking into account for such Plan Year the amount of pre-tax deferrals and after-tax contributions the Eligible Employee elected under the Applicable Plan. For purposes of this calculation, amounts deferred under the PG&E Corporation Deferred Compensation Plan for Officers shall be treated as pre- tax deferrals under the Applicable Plan. 3 (2) The calculation made in accordance with this Section 3(a) (1) above shall be made without regard to any limitation on such amounts under the Applicable Plan resulting from the application of any of the limitations under Code Sections 401(m), 401(a)(17), or 415. (3) The Employer Matching Contribution to be credited to the Account of an Eligible Employee for any Plan Year shall equal the amount calculated in accordance with Sections 3(a) (1) and (2) above, reduced by the amount of matching contribution made to such Eligible Employee's account for such Plan Year under the Applicable Plan. (b) Crediting of Employer Matching Contributions. Employer Matching -------------------------------------------- Contributions shall be credited to the Eligible Employee's Account at the end of each calendar year and shall be credited only if the Eligible Employee is an Employee on the last day of such calendar year. (c) Employer Contributions. Subject to the provisions of Section 10, the ---------------------- Account of each Eligible Employee shall be credited for each Plan Year with an additional Employer Contribution, calculated in the manner provided in Sections 3(c) (1), (2), and (3) below: (1) First, an amount shall be calculated equal to the maximum profit- sharing contribution that would be made under the terms of the Applicable Plan, taking into account for such Plan Year the Eligible Employee's Compensation for such Plan Year. (2) The calculation made in accordance with this Section 3(c) (1) above shall be made without regard to any limitation on such amounts under the Applicable Plan resulting from the application of any of the limitations under Code Sections 401(a)(4), 401(a)(17), or 415. (3) The Employer Contribution to be credited to the Account of an Eligible Employee for any Plan Year shall equal the amount calculated in accordance with Sections 3(c) (1) and (2) above, reduced by the amount of profit-sharing contributions made to such Eligible Employee's account for such Plan Year under the Applicable Plan. (d) Crediting of Employer Contributions. The Employer Contributions made ----------------------------------- in respect of an Eligible Employee shall be credited to the Eligible Employee's Account at the end of each calendar years and shall be credited only if the Eligible Employee is an Employee on the last day of such calendar year. 4 (e) Investment Return on Accounts. Although no assets will be segregated ----------------------------- or otherwise set aside with respect to an Eligible Employee's Account, the amount that is ultimately payable to the Eligible Employee with respect to such Account shall be determined as if such Account had been invested in some or all of the Investment Funds. The Plan Administrator, in its sole discretion, shall adopt (and modify from time to time) such rules and procedures as it deems necessary or appropriate to implement the deemed investment of the Eligible Employees' Accounts. Such procedures generally shall provide that an Eligible Employee's Account shall be deemed to be invested among the three Investment Funds in the manner elected by the Eligible Employee in such percentages and manner as prescribed by the Plan Administrator. Eligible Employees shall be able to reallocate their Accounts between the Investment Funds and reallocate amounts newly credited to their Accounts at such time and in such manner as the Plan Administrator shall prescribe. Anything to the contrary herein notwithstanding, an Eligible Employee may not reallocate Account balances between Investment Funds if such reallocation would result in a non-exempt Discretionary Transaction as defined in Rule 16b-3 of the Securities Exchange Act of 1934, as amended, or any successor to Rule 16b-3, as in effect when the reallocation is requested. (1) AA Utility Bond Fund. Amounts credited to the AA Utility Bond Fund shall be credited with interest as of the last business day of the immediately preceding calendar quarter and prorated based on the number of days in the quarter that the balance was allocated to the AAA Utility Bond Fund. Such interest shall be at a rate equal to the AA Utility Bond Yield reported in Moody's ------- Public Utility, published in the issue of Moody's Investors -------------- ----------------- Service immediately preceding the first day of the calendar ------- quarter in which the interest is to be credited. Such interest shall become a part of the Eligible Employee's Account and shall be paid at the same time or times as the balance of the Eligible Employee's Account. Notwithstanding the above, if before the end of the quarter an Eligible Employee has requested that his or her Account balance be reallocated to another Investment Fund(s) or the Eligible Employee's Account balance has been paid to the Eligible Employee or to the Eligible Employee's beneficiary, prorated interest on the Eligible Employee's Account balance shall be calculated at a rate equal to the AA Utility Bond Yield reported in Moody's Public Utility, published in the issue of ---------------------- Moody's Investors Service immediately preceding the date of such ------------------------- reallocation or payment and shall be credited to the Eligible Employee's Account in such other Investment Fund(s) on the date of reallocation or paid directly to the Eligible Employee or the Eligible Employee's beneficiary, whichever is applicable. 5 (2) PG&E CORP Phantom Stock Fund. Amounts credited to the PG&E CORP Phantom Stock Fund shall be converted into units (including fractions computed to three decimal places) each representing a share of PG&E CORP common stock. The value of a unit for purposes of determining the number of units to credit upon initial allocation or upon reallocation from another Investment Fund, and for determining the dollar value of the aggregate number of units to be reallocated from the PG&E CORP Phantom Stock Fund to another Investment Fund, shall be the average of the daily high and low price of a share of PG&E CORP common stock as traded on the New York Stock Exchange for the 30 trading days preceding the date that (i) amounts are credited to an Eligible Employee's Account in the PG&E CORP Phantom Stock Fund, or (ii) the Plan Administrator receives a reallocation request, in the case of reallocations. Thereafter, the value of a unit shall fluctuate in accordance with the closing price of PG&E CORP common stock on the New York Stock Exchange. Each time that PG&E CORP pays a dividend on its common stock, an amount equal to such dividend payable with respect to each share of PG&E CORP common stock, multiplied by the number of units credited to an Eligible Employee's Account, shall be credited to the Eligible Employee's Account and converted into additional units. The number of additional units shall be calculated by dividing the aggregate amount of credited dividends, i.e. the dividend multiplied by the number of units credited to the Eligible Employee's Account as of the dividend record date, by the closing price of a share of PG&E CORP common stock on the New York Stock Exchange on the dividend payment date. If, after the record date but before the dividend payment date, an Eligible Employee's balance in the PG&E CORP Phantom Stock Fund has been reallocated to another Investment Fund(s) or has been paid to the Eligible Employee or to the Eligible Employee's beneficiary, then an amount equal to the aggregated dividend shall be credited to the Eligible Employee's Account in such other Investment Fund(s) or paid directly to the Eligible Employee or the Eligible Employee's beneficiary, whichever is applicable. (3) S&P 500 Index Fund. Amounts credited to the S&P 500 Index Fund shall be valued based on the difference between the value of the S&P 500 Index as reported in the Wall Street Journal on the date amounts are credited to an Eligible Employee's Account and the value of the S&P 500 Index as reported in the Wall Street Journal on the relevant Valuation Date, assuming reinvestment of all dividends under the S&P 500 Index Fund during the relevant period. 4. Accounting ---------- (a) Eligible Employees' Accounts. At the direction of the Plan ---------------------------- Administrator, there shall be established and maintained on the books of the Employer, a separate account for each Eligible Employee in order to reflect his or her interest under the Plan. 6 (b) Investment Earnings. Each Eligible Employee's Account shall initially ------------------- reflect the value of his or her Account's interest in each of the Investment Funds, deemed acquired with the amounts credited thereto. Each Eligible Employee's Account shall also be credited (or debited) as of the end of each day with the net appreciation (or depreciation), earnings and gains (or losses) with respect to the investments deemed made by his or her Account. Any such net earnings or gains deemed realized with respect to any investment of any Eligible Employee's Account shall be deemed reinvested in additional amounts of the same investment and credited to the Eligible Employee's Account. (c) Accounting Methods. The accounting methods or formulae to be used ------------------ under the Plan for the purpose of maintaining the Eligible Employees' Accounts shall be determined by the Plan Administrator. The accounting methods or formulae selected by the Plan Administrator may be revised from time to time but shall conform to the extent practicable with the accounting methods used under the Applicable Plan. (d) Valuations and Reports. The fair market value of each Eligible ---------------------- Employee's Account shall be determined as of each Valuation Date. In making such determinations and in crediting net deemed earnings and gains (or losses) in the Investment Funds to the Eligible Employees' Accounts, the Plan Administrator (in its discretion) may employ such accounting methods as the Plan Administrator (in its discretion) may deem appropriate in order to fairly reflect the fair market values of the Investment Funds and each Eligible Employee's Account. For this purpose, the Plan Administrator may rely upon information provided by the Plan Administrator or other persons believed by the Plan Administrator to be competent. (e) Statements of Eligible Employee's Accounts. Each Eligible Employee ------------------------------------------ shall be furnished with periodic statements of his or her interest in the Plan, at least annually. 5. Distributions ------------- (a) Events Permitting Distribution. Subject to Sections 5(g) and 10(c), ------------------------------ distribution of the balance credited to an Eligible Employee's Account shall be made only in the following circumstances: (1) Upon the Eligible Employee's Retirement; or (2) In the case of an Alternate Payee (as defined in Section 6(a), as directed in a domestic relations order which the Plan Administrator determines is a QDRO (as defined in Section 6(a), but only as to the portion of the Eligible Employee's Account which the QDRO states is payable to the Alternate Payee. (b) Time and Form of Termination and Retirement Distributions. --------------------------------------------------------- Distributions following an Eligible Employee's Retirement shall be made in a lump sum cash payment within 30 days after his or her Retirement. 7 (c) Death Distributions. If an Eligible Employee dies before the entire ------------------- balance of his or her Account has been distributed (whether or not the Eligible Employee had previously terminated employment and whether or not installment payments had previously commenced), the remaining balance of the Eligible Employee's Account shall be distributed to the beneficiary designated or otherwise determined in accordance with Section 5(f), as soon as practicable after the date of death. (d) Effect of Change in Eligible Employee Status. If an Eligible Employee -------------------------------------------- ceases to be an Eligible Employee, the balance credited to his or her Account shall continue to be credited (or debited) with appreciation, depreciation, earnings, gains or losses under the terms of the Plan and shall be distributed to him or her at the time and in the manner set forth in this Section 5; provided, however, that the Plan Administrator, in its sole discretion, may authorize an accelerated distribution of the balance credited to his or her Account in the form of a lump sum cash payment as of any earlier date. (e) Payments to Incompetents. If any individual to whom a benefit is ------------------------ payable under the Plan is a minor or if the Plan Administrator determines that any individual to whom a benefit is payable under the Plan is incompetent to receive such payment or to give a valid release therefor, payment shall be made to the guardian, committee, or other representative of the estate of such individual which has been duly appointed by a court of competent jurisdiction. If no guardian, committee, or other representative has been appointed, payment may be made to any person as custodian for such individual under the California Uniform Transfers to Minors Act (or similar law of another state) or may be made to or applied to or for the benefit of the minor or incompetent, the incompetent's spouse, children or other dependents, the institution or persons maintaining the minor or incompetent, or any of them, in such proportions as the Plan Administrator from time to time shall determine; and the release of the person or institution receiving the payment shall be a valid and complete discharge of any liability of PG&E CORP with respect to any benefit so paid. (f) Beneficiary Designations. Each Eligible Employee may designate, in a ------------------------ signed writing delivered to the Plan Administrator, on such form as it may prescribe, one or more beneficiaries to receive any distribution which may become payable under the Plan as the result of the Eligible Employee's death. (1) Changes and Failed Designations. An Eligible Employee may designate different beneficiaries at any time by delivering a new designation in like manner. Any designation shall become effective only upon its receipt by the Plan Administrator, and the last effective designation received by the Plan Administrator shall supersede all prior designations. If an Eligible Employee dies without having designated a beneficiary or if no beneficiary survives the Eligible Employee, the Eligible Employee's Account shall be payable to the beneficiary or beneficiaries designated or otherwise determined under such Eligible Employee's Applicable Plan. 8 (g) Undistributable Accounts. Each Eligible Employee and (in the event of ------------------------ death) his or her beneficiary shall keep the Plan Administrator advised of his or her current address. If the Plan Administrator is unable to locate the Eligible Employee or beneficiary to whom an Eligible Employee's Account is payable under this Section 5, the Eligible Employee's Account shall be frozen as of the date on which distribution would have been completed in accordance with this Section 5, and no further appreciation, depreciation, earnings, gains or losses shall be credited (or debited) thereto. PG&E CORP shall have the right to assign or transfer the liability for payment of any undistributable Account to the Eligible Employee's former Employer (or any successor thereto). (h) Plan Administrator Discretion. Within the specific time periods ----------------------------- described in this Section 5, the Plan Administrator shall have sole discretion to determine the specific timing of the payment of any Account balance under the Plan. 6. Domestic Relations Orders ------------------------- (a) Qualified Domestic Relations Orders. The Plan Administrator shall ----------------------------------- establish written procedures for determining whether a domestic relations order purporting to dispose of any portion of an Eligible Employee's Account is a qualified domestic relations order (within the meaning of Section 414(p) of the Code) (a "QDRO"). ---- (1) No Payment Unless a QDRO. No payment shall be made to any person designated in a domestic relations order (an "Alternate Payee") --------------- until the Plan Administrator (or a court of competent jurisdiction reversing an initial adverse determination by the Plan Administrator) determines that the order is a QDRO. Payment shall be made to each Alternate Payee as specified in the QDRO. (2) Time of Payment. Payment may be made to an Alternate Payee in the form of a lump sum, at the time specified in the QDRO, but no earlier than as soon as practicable following the date the QDRO determination is made. (3) Hold Procedures. Notwithstanding any contrary Plan provision, prior to the receipt of a domestic relations order, the Plan Administrator may, in its sole discretion, place a hold upon all or a portion of an Eligible Employee's Account for a reasonable period of time (as determined by the Plan Administrator) if the Plan Administrator receives notice that (a) a domestic relations order is being sought by the Eligible Employee, his or her spouse, former spouse, child or other dependent, and (b) the Eligible Employee's Account is a source of the payment under such domestic relations order. For purposes of this Section 6(a) (3), a "hold" means that no withdrawals, distributions, or investment ---- transfers may be made with respect to an Eligible Employee's Account. If the Plan Administrator places a hold upon an Eligible Employee's Account pursuant to this Section 6(a) (3), it shall inform the Eligible Employee of such fact. 9 7. Vesting ------- (a) Percent Vesting. An Eligible Employee's interest in his or her Account --------------- at all times shall be 100 percent vested and nonforfeitable. Upon the Eligible Employee's Retirement, the balance credited to his or her Account shall be distributable to him or her in the manner and at the times set forth in Section 5. 8. Administration Of The Plan -------------------------- (a) Plan Administrator. The Employee Benefit Committee of PG&E CORP is ------------------ hereby designated as the administrator of the Plan (within the meaning of Section 3(16)(A) of ERISA). The Plan Administrator delegates to the Senior Human Resource officer for PG&E CORP, or his or her designee, the authority to carry out all duties and responsibilities of the Plan Administrator under the Plan. The Plan Administrator shall have the authority to control and manage the operation and administration of the Plan. (b) Powers of Plan Administrator. The Plan Administrator shall have all ---------------------------- discretion and powers necessary to supervise the administration of the Plan and to control its operation in accordance with its terms, including, but not by way of limitation, the power to interpret the provisions of the Plan and to determine, in its sole discretion, any question arising under, or in connection with the administration or operation of, the Plan. (c) Decisions of Plan Administrator. All decisions of the Plan ------------------------------- Administrator and any action taken by it in respect of the Plan and within the powers granted to it under the Plan shall be conclusive and binding on all persons and shall be given the maximum deference permitted by law. 9. Funding ------- (a) Unfunded Plan. All amounts credited to an Eligible Employee's Account ------------- under the Plan shall continue for all purposes to be a part of the general assets of PG&E CORP. The interest of the Eligible Employee in his or her Account, including his or her right to distribution thereof, shall be an unsecured claim against the general assets of PG&E CORP. While PG&E CORP may choose to invest a portion of its general assets in investments identical or similar to those selected by Eligible Employees for purposes of determining the amounts to be credited (or debited) to their Accounts, nothing contained in the Plan shall give any Eligible Employee or beneficiary any interest in or claim against any specific assets of PG&E CORP. 10 10. Modification Or Termination Of Plan ----------------------------------- (a) Employers' Obligations Limited. The Plan is voluntary on the part of ------------------------------ the Employers, and the Employers do not guarantee to continue the Plan. PG&E CORP at any time may, by appropriate amendment of the Plan, suspend Employer Matching Contributions and/or Employer Contributions or may discontinue Employer Matching Contributions and/or Employer Contributions, with or without cause. (b) Right to Amend or Terminate. The Board of Directors, acting through --------------------------- its Nominating and Compensation Committee, reserves the right to alter, amend, or terminate the Plan, or any part thereof, in such manner as it may determine, for any reason whatsoever. (1) Limitations. Any alteration, amendment, or termination shall take effect upon the date indicated in the document embodying such alteration, amendment, or termination, provided that no such alteration or amendment shall divest any portion of an Account that is then vested under the Plan. (c) Effect of Termination. If the Plan is terminated, the balances --------------------- credited to the Accounts of the Eligible Employees affected by such termination shall be distributed to them at the time and in the manner set forth in Section 5; provided, however, that the Plan Administrator, in its sole discretion, may authorize accelerated distribution of Eligible Employees' Accounts as of any earlier date. 11. General Provisions ------------------ (a) Inalienability. Except to the extent otherwise directed by a domestic -------------- relations order which the Plan Administrator determines is a QDRO (as defined in Section 6(a) or mandated by applicable law, in no event may either an Eligible Employee, a former Eligible Employee or his or her spouse, beneficiary or estate sell, transfer, anticipate, assign, hypothecate, or otherwise dispose of any right or interest under the Plan; and such rights and interests shall not at any time be subject to the claims of creditors nor be liable to attachment, execution, or other legal process. (b) Rights and Duties. Neither the Employers nor the Plan Administrator ----------------- shall be subject to any liability or duty under the Plan except as expressly provided in the Plan, or for any action taken, omitted, or suffered in good faith. (c) No Enlargement of Employment Rights. Neither the establishment or ----------------------------------- maintenance of the Plan, the making of any Employer Matching Contributions, nor any action of any Employer or Plan Administrator, shall be held or construed to confer upon any individual any right to be continued as an Employee nor, upon dismissal, any right or interest in any specific assets of the Employers other than as provided in the Plan. Each Employer expressly reserves the right to discharge any Employee at any time, with or without cause or advance notice. 11 (d) Apportionment of Costs and Duties. All acts required of the Employers --------------------------------- under the Plan may be performed by PG&E CORP for itself and its Participating Subsidiaries, and the costs of the Plan may be equitably apportioned by the Plan Administrator among PG&E CORP and the other Employers. Whenever an Employer is permitted or required under the terms of the Plan to do or perform any act, matter or thing, it shall be done and performed by any officer or employee of the Employer who is thereunto duly authorized by the board of directors of the Employer. (e) Applicable Law. The provisions of the Plan shall be construed, -------------- administered, and enforced in accordance with the laws of the State of California and, to the extent applicable, ERISA. (f) Severability. If any provision of the Plan is held invalid or ------------ unenforceable, its invalidity or unenforceability shall not affect any other provisions of the Plan, and the Plan shall be construed and enforced as if such provision had not been included. (g) Captions. The captions contained in and the table of contents prefixed -------- to the Plan are inserted only as a matter of convenience and for reference and in no way define, limit, enlarge, or describe the scope or intent of the Plan nor in any way shall affect the construction of any provision of the Plan. Execution --------- IN WITNESS WHEREOF, PG&E CORP, by its duly authorized officer, has executed this Plan on the date indicated below. PG&E CORPORATION Dated: _______________ By:_____________________________ Title: _________________________ 12 APPENDIX A PARTICIPATING SUBSIDIARIES Participating Subsidiaries as of January 1, 1997 ------------------------------------------------ - PG&E Gas Transmission Corporation - PG&E Gas Transmission, Texas Corporation - PG&E Gas Transmission TECO, Inc. - PG&E Energy Trading-Gas Corporation - PG&E Energy Services Corporation - And the U.S. subsidiaries of each of the above-named corporations. Additional Participating Subsidiaries as of January 1, 1998 ----------------------------------------------------------- - PG&E Corporation - Pacific Gas and Electric Company - PG&E Generating Company - PG&E Corporation Support Services, Inc. - And the U.S. subsidiaries of each of the above-named corporations. 13 EX-10.12 9 PG&E CORP. LONG-TERM INCENTIVE PROGRAM EXHIBIT 10.12 PG&E CORPORATION LONG-TERM INCENTIVE PROGRAM (As amended and restated effective as of October 21, 1998) 1. Purpose of the Program ---------------------- This is the controlling and definitive statement of the PG&E Corporation Long-Term Incentive Program, as amended and restated herein (hereinafter called the PROGRAM/1/). The purpose of the PROGRAM is to advance the interests of the CORPORATION by providing ELIGIBLE PARTICIPANTS with financial incentives to promote the success of its long-term (five to ten years) business objectives, and to increase their proprietary interest in the success of the CORPORATION. It is the intent of the CORPORATION to reward those ELIGIBLE PARTICIPANTS who have a significant impact on improved long-term corporate achievements. Inasmuch as the PROGRAM is designed to encourage financial performance and to improve the value of shareholders' investment in PG&E CORPORATION, the costs of the PROGRAM will be funded from corporate earnings. 2. Program Administration ---------------------- The PROGRAM shall be administered by the COMMITTEE, except that the BOARD OF DIRECTORS shall administer the PROGRAM with respect to grants of INCENTIVE AWARDS TO NON-EMPLOYEE DIRECTORS. The BOARD OF DIRECTORS may at any time revest authority to administer the PROGRAM in all respects in the BOARD OF DIRECTORS. Subject to the provisions of the PROGRAM, the COMMITTEE or the BOARD OF DIRECTORS, as the case may be, shall have full and final authority, in its sole discretion: (a) to determine the ELIGIBLE PARTICIPANTS to whom INCENTIVE AWARDS shall be granted and the number of shares of COMMON STOCK to be awarded under each INCENTIVE AWARD, based on the recommendation of the CHIEF EXECUTIVE OFFICER (except that awards to the CHIEF EXECUTIVE OFFICER shall be based on the recommendation of the BOARD OF DIRECTORS and awards to NON-EMPLOYEE DIRECTORS shall be based on the recommendation of the COMMITTEE); (b) to determine the time or times at which INCENTIVE AWARDS shall be granted; - -------------- /1/ Capitalized words are defined in Section 20 hereof. (c) to designate the types of INCENTIVE AWARD being granted; (d) to vary the OPTION vesting schedule described in the STOCK OPTION PLAN; (e) to determine the terms and conditions, not inconsistent with the terms of the PROGRAM, of any INCENTIVE AWARD granted hereunder (including, but not limited to, the consideration and method of payment for shares purchased upon the exercise of an INCENTIVE AWARD, and any vesting acceleration or exercisability provisions in the event of a CHANGE IN CONTROL or TERMINATION), based in each case on such factors as the COMMITTEE or BOARD OF DIRECTORS shall deem appropriate; (f) to approve forms of agreement for use under the PROGRAM; (g) to construe and interpret the PROGRAM and any related INCENTIVE AWARD agreement and to define the terms employed herein and therein; (h) except as provided in Section 18 hereof, to modify or amend any INCENTIVE AWARD or to waive any restrictions or conditions applicable to any INCENTIVE AWARD or the exercise or realization thereof; (i) except as provided in Section 18 hereof, to prescribe, amend and rescind rules, regulations and policies relating to the administration of the PROGRAM; (j) except as provided in Section 18 hereof, to suspend, terminate, modify or amend the PROGRAM; (k) to delegate to one or more agents such administrative duties as the COMMITTEE or BOARD OF DIRECTORS may deem advisable, to the extent permitted by applicable law; and (l) to make all other determinations and take such other action with respect to the PROGRAM and any INCENTIVE AWARD granted hereunder as the COMMITTEE may deem advisable, to the extent permitted by applicable law. Notwithstanding the provisions contained in the foregoing paragraph, the CHIEF EXECUTIVE OFFICER shall have the authority, in his sole discretion: (a) to grant INCENTIVE AWARDS to any ELIGIBLE PARTICIPANT who, at the time of the INCENTIVE AWARD grant, (i) is not an officer of the CORPORATION or a DIRECTOR, and (ii) if such ELIGIBLE PARTICIPANT is an EMPLOYEE, is receiving an annual salary which is below the level which 2 requires approval by the COMMITTEE; (b) to determine the time or times at which INCENTIVE AWARDS shall be granted to such ELIGIBLE PARTICIPANTS; (c) to designate the types of INCENTIVE AWARD being granted to such ELIGIBLE PARTICIPANTS; and (d) to vary the OPTION vesting schedule described in the STOCK OPTION PLAN for the OPTIONS granted to such ELIGIBLE PARTICIPANTS; provided, however, that all grants of INCENTIVE AWARDS by the CHIEF EXECUTIVE OFFICER shall conform to the guidelines previously approved by the COMMITTEE. 3. Shares of Stock Subject to the Program -------------------------------------- There shall be reserved for use under the PROGRAM (subject to the provisions of Section 13 hereof) a total of 23,389,230 shares of COMMON STOCK, which shares may be authorized but unissued shares of COMMON STOCK or issued shares of COMMON STOCK which shall have been reacquired by PG&E CORPORATION. Such shares consist of (i) 13,000,000 shares of COMMON STOCK originally reserved for use under the PROGRAM at the time it first became effective on January 1, 1992, (ii) 389,230 shares of COMMON STOCK remaining under the 1986 OPTION PLAN and carried over to the PROGRAM, and (iii) 10,000,000 shares of COMMON STOCK added to the PROGRAM effective as of January 1, 1996. If (i) any INCENTIVE AWARD expires or terminates for any reason without having been exercised or purchased in full, (ii) an INCENTIVE AWARD is surrendered in exchange for one or more other INCENTIVE AWARDS, or (iii) any RESTRICTED STOCK is forfeited, then, in each such case, any unexercised, unpurchased, surrendered or forfeited shares which were subject to such INCENTIVE AWARD (except shares as to which a related TANDEM SAR has been exercised) shall again be available for the future grant of INCENTIVE AWARDS under the PROGRAM (unless the PROGRAM has terminated). In addition, shares may be reused or added back to the PROGRAM to the extent permitted by applicable law. 4. Eligibility ----------- INCENTIVE AWARDS will be granted only to ELIGIBLE PARTICIPANTS. ISOS will be granted only to EMPLOYEES. The COMMITTEE, in its sole discretion, may grant INCENTIVE AWARDS to an ELIGIBLE PARTICIPANT who is a resident or citizen of a foreign country, with such modifications as the COMMITTEE may deem advisable to reflect the laws, tax policy or customs of such foreign country. The PROGRAM shall not confer upon any RECIPIENT any right to continuation of employment, service as a DIRECTOR or consulting relationship with the CORPORATION; nor shall it interfere in any way with the right of the 3 RECIPIENT or the CORPORATION to terminate such employment, service as a DIRECTOR or consulting relationship at any time, with or without cause. 5. Designation of Incentive Awards ------------------------------- At the time of the grant of each INCENTIVE AWARD under the Program, the COMMITTEE (or the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof, or the BOARD OF DIRECTORS, in the case of INCENTIVE AWARDS granted by the BOARD OF DIRECTORS to NON-EMPLOYEE DIRECTORS) shall determine whether such INCENTIVE AWARD is to be designated as an ISO, NON-QUALIFIED STOCK OPTION, SAR, DIVIDEND EQUIVALENT, PERFORMANCE UNIT, stock grant, RESTRICTED STOCK, LSAR, PHANTOM STOCK or other STOCK-BASED AWARD; provided, however, that ISOS may be granted only to EMPLOYEES. Notwithstanding such designation, to the extent that the aggregate FAIR MARKET VALUE (determined for each share as of the date of grant of the OPTION covering each share) of the shares with respect to which OPTIONS designated as ISOS become exercisable for the first time by any RECIPIENT during any calendar year exceeds $100,000, such OPTIONS shall be treated as NON-QUALIFIED STOCK OPTIONS. Any INCENTIVE AWARD may be granted alone, contingent upon, in addition to or in TANDEM with one or more other INCENTIVE AWARDS granted under the PROGRAM. In addition, except as provided in Section 12 hereof, any INCENTIVE AWARD may be granted in exchange for one or more other INCENTIVE AWARDS. 6. Stock Options, Tandem Stock Appreciation Rights and Tandem Dividend ------------------------------------------------------------------- Equivalents ----------- Except as provided in Section 9 below (relating to grants of INCENTIVE AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion, may grant ISOS, NON-QUALIFIED STOCK OPTIONS, TANDEM SARS and TANDEM DIVIDEND EQUIVALENTS to ELIGIBLE PARTICIPANTS, subject to the terms and conditions set forth in the STOCK OPTION PLAN attached hereto as Exhibit A. 7. Performance Units ----------------- Except as provided in Section 9 below (relating to grants of INCENTIVE AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion, may grant PERFORMANCE UNITS to ELIGIBLE PARTICIPANTS, 4 subject to the terms and conditions set forth in the PERFORMANCE UNIT PLAN attached hereto as Exhibit B. 8. Other Incentive Awards ---------------------- Except as provided in Section 9 below (relating to grants of INCENTIVE AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion, may grant other INCENTIVE AWARDS (including, but not limited to, SARS granted without OPTIONS, DIVIDEND EQUIVALENTS granted without OPTIONS, stock grants, RESTRICTED STOCK, LSARS, PHANTOM STOCK or other STOCK-BASED AWARDS) to ELIGIBLE PARTICIPANTS, subject to such terms and conditions as the COMMITTEE shall deem appropriate. 9. Grants of Incentive Awards to Non-Employee Directors ---------------------------------------------------- NON-EMPLOYEE DIRECTORS will only be eligible to be granted DIRECTOR RESTRICTED STOCK, PHANTOM STOCK and NON-QUALIFIED STOCKOPTIONS in accordance with, and subject to the terms and conditions contained in, the NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN RULES attached hereto as Exhibit C. 10. Termination of Employment or Relationship with the CORPORATION -------------------------------------------------------------- The COMMITTEE may, in its sole discretion, establish terms and conditions pertaining to the effect of TERMINATION on INCENTIVE AWARDS granted to a RECIPIENT prior to TERMINATION, to the extent permitted by applicable law. 11. Tax Withholding --------------- When a RECIPIENT incurs tax liability in connection with the exercise of an INCENTIVE AWARD or the receipt of shares of COMMON STOCK pursuant to an INCENTIVE AWARD, which tax liability is subject to tax withholding under applicable tax laws, and the RECIPIENT is obligated to pay the CORPORATION an amount required to be withheld under applicable tax laws, the RECIPIENT may satisfy the withholding tax obligation by (i) electing to have the CORPORATION withhold such amount from his or her current compensation through payroll deductions, or (ii) making a direct payment to the CORPORATION in cash or by check. The COMMITTEE may, in its sole discretion, permit a RECIPIENT to satisfy all or part of his or her withholding tax obligations by having the CORPORATION withhold from the shares to be issued to the RECIPIENT that number of shares having a FAIR MARKET VALUE equal to the amount required to be withheld 5 determined on the date when taxes otherwise would be withheld in cash. The payment of withholding taxes in this manner, if permitted by the COMMITTEE, shall be subject to such restrictions as the COMMITTEE may impose, including any restrictions required by rules of the Securities and Exchange Commission. 12. Replacement of Grants --------------------- The COMMITTEE may, in its sole discretion, offer a RECIPIENT (other than NON-EMPLOYEE DIRECTORS) the option of surrendering an unexercised OPTION or other INCENTIVE AWARD in exchange for another INCENTIVE AWARD of the same type or for a different type of INCENTIVE AWARD; provided, however, that no OPTION or INCENTIVE AWARD may be exchanged for a new OPTION or INCENTIVE AWARD having an OPTION PRICE or purchase price that is lower than the OPTION PRICE or purchase price of the original OPTION or INCENTIVE AWARD. 13. Deferral of Payments -------------------- The COMMITTEE may, in its sole discretion, approve a RECIPIENT'S deferral of any cash payments which may become due under the PROGRAM. Such deferrals shall be subject to any conditions, restrictions or requirements as the COMMITTEE may determine. 14. Adjustments Upon Changes in Number or Value of Shares of Common Stock --------------------------------------------------------------------- If there are any changes in the number or value of shares of COMMON STOCK by reason of stock dividends, stock splits, reverse stock splits, recapitalizations, mergers, consolidations or other events that materially increase or decrease the number or value of issued and outstanding shares of COMMON STOCK, the COMMITTEE may make such adjustments as it shall deem appropriate, in order to prevent dilution or enlargement of rights. 15. Non-Transferability of Incentive Awards --------------------------------------- An INCENTIVE AWARD shall not be transferable by the RECIPIENT otherwise than by will or the laws of descent and distribution, or pursuant to a qualified domestic relations order as defined by the CODE, Title I of ERISA or the rules thereunder. During the lifetime of the RECIPIENT, an INCENTIVE AWARD may be exercised only by the RECIPIENT or by an alternate payee under a qualified domestic relations order. 16. Change in Control ------------------- Upon the occurrence of a CHANGE IN CONTROL (as defined below): 6 (a) Any time periods relating to the exercise or realization of any INCENTIVE AWARD granted hereunder shall be accelerated so that such INCENTIVE AWARD may be immediately exercised or realized in full; (b) All shares of RESTRICTED STOCK granted hereunder shall immediately cease to be forfeitable; and (c) All conditions relating to the realization of any STOCK-BASED AWARD granted hereunder shall immediately terminate. A "CHANGE IN CONTROL" shall be deemed to have occurred if: (a) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any trustee, agent or other fiduciary for any such plan acting in such person's capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of the CORPORATION representing twenty percent (20%) or more of the combined voting power of the CORPORATION's then outstanding securities; (b) during any two consecutive years, individuals who at the beginning of such a period constitute the BOARD OF DIRECTORS cease for any reason to constitute at least a majority of the BOARD OF DIRECTORS, unless the election, or the nomination for election by the shareholders of the CORPORATION, of each new DIRECTOR was approved by a vote of at least two-thirds (2/3) of the DIRECTORS then still in office who were DIRECTORS at the beginning of the period; or (c) the shareholders of the CORPORATION shall have approved (i) any consolidation or merger of the CORPORATION other than a merger or consolidation which would result in the voting securities of the CORPORATION outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the Combined Voting Power of the CORPORATION, such surviving entity or the parent of such surviving entity outstanding immediately after the merger or consolidation; (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the CORPORATION, or (iii) any plan or proposal for the liquidation or dissolution of the CORPORATION. For purposes of this paragraph, the term Combined Voting Power shall mean the combined voting power of the CORPORATION's or other relevant entity's then outstanding voting securities. 7 17. Listing and Registration of Shares ---------------------------------- Each INCENTIVE AWARD shall be subject to the requirement that if at any time the COMMITTEE shall determine, in its discretion, that the listing, registration or qualification of the shares covered thereby under any securities exchange or under any state or federal law or the consent or approval of any governmental regulatory body, including the California Public Utilities Commission, is necessary or desirable as a condition of, or in connection with, the granting of such INCENTIVE AWARD or the issue or purchase of shares thereunder, such INCENTIVE AWARD may not be exercised in whole or in part unless and until such listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to the COMMITTEE. 18. Amendment and Termination of the Program and Incentive Awards ------------------------------------------------------------- The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend, terminate, modify or amend the PROGRAM in any respect; provided, however, that to the extent necessary and desirable to comply with Section 422 of the CODE (or any other applicable law or regulation, including the requirements of any stock exchange on which the COMMON STOCK is listed or quoted), shareholder approval of any PROGRAM amendment shall be obtained in such a manner and to such a degree as is required by the applicable law or regulation. No suspension, termination, modification or amendment of the PROGRAM may, without the consent of the RECIPIENT, adversely affect his or her rights under INCENTIVE AWARDS theretofore granted to such RECIPIENT. In the event of amendments to the CODE or applicable rules or regulations relating to ISOS subsequent to the date hereof, the CORPORATION may amend the PROGRAM, and the CORPORATION and RECIPIENTS holding OPTION agreements may agree to amend outstanding OPTION agreements, to conform to such amendments. The BOARD OF DIRECTORS or COMMITTEE may make such amendments or modifications in the terms and conditions of any INCENTIVE AWARD as it may deem advisable, or cancel or annul any grant of an INCENTIVE AWARD; provided, however, that no such amendment, modification, cancellation or annulment may, without the consent of the RECIPIENT, adversely affect his or her rights under such INCENTIVE AWARD; and provided further the BOARD OF DIRECTORS or COMMITTEE may not reduce the OPTION PRICE or purchase price of any OPTION or INCENTIVE AWARD below the original OPTION PRICE or purchase price. Notwithstanding the foregoing, the BOARD OF DIRECTORS or COMMITTEE reserves the right, in its sole discretion, to (i) convert any outstanding ISOS to NON-QUALIFIED STOCK OPTIONS, (ii) to require a RECIPIENT to forfeit any unexercised or unpurchased INCENTIVE AWARDS, any shares received or 8 purchased pursuant to an INCENTIVE AWARD, or any gains realized by virtue of the receipt of an INCENTIVE AWARD in the event that such RECIPIENT competes against the CORPORATION, and (iii) to cancel or annul any grant of an INCENTIVE AWARD in the event of a RECIPIENT'S TERMINATION FOR CAUSE. For purposes of the PROGRAM, "TERMINATION FOR CAUSE" shall include, but not be limited to, termination because of dishonesty, criminal offense or violation of a work rule, and shall be determined by, and in the sole discretion of, the BOARD OF DIRECTORS or COMMITTEE. 19. Effective Date of the Program and Duration ------------------------------------------ The Program first became effective as of January 1, 1992. The first amendment and restatement of the PROGRAM as of January 1, 1996, was approved by the shareholders of Pacific Gas and Electric Company at its Annual Meeting on April 17, 1996. Effective January 1, 1997, the PROGRAM was assumed by PG&E CORPORATION. At its meeting on December 17, 1997, the BOARD OF DIRECTORS amended and restated the PROGRAM effective January 1, 1998, to (i) reflect the adoption of new RULE 16B-3 which became effective November 1, 1996, and (ii) provide automatic formula awards of NON- QUALIFIED STOCK OPTIONS and PHANTOM STOCK to NON-EMPLOYEE DIRECTORS within the limits of the PROGRAM as previously approved by shareholders in 1996. The COMMITTEE amended Section 16 of the PROGRAM to revise the definition of CHANGE IN CONTROL on October 21, 1998. Unless terminated sooner pursuant to Section 16 hereof, the PROGRAM shall terminate on December 31, 2005. 20. Definitions ----------- (a) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION. ------------------ (b) CHANGE IN CONTROL has the meaning set forth in Section 16 hereof. ----------------- (c) CHIEF EXECUTIVE OFFICER means the Chief Executive Officer of PG&E ----------------------- CORPORATION. (d) CODE means the Internal Revenue Code of 1986, as amended from time to ---- time. (e) COMMITTEE means the Nominating and Compensation Committee of the BOARD --------- OF DIRECTORS or any successor to such committee. (f) COMMON STOCK means common shares of PG&E CORPORATION with no par value ------------ and any class of common shares into which such common shares hereafter may be converted. 9 (g) CONSULTANT means any person, including an advisor, who is engaged by ---------- the CORPORATION to render services. (h) CORPORATION means PG&E CORPORATION, and any parent corporation (as ----------- defined in Section 424(e) of the CODE) or subsidiary corporation (as defined in Section 424(f) of the CODE). (i) DIRECTOR means any person who is a member of the BOARD OF DIRECTORS or -------- the Board of Directors of any parent corporation (as defined in Section 424(e) of the CODE) which may hereafter be established, including an advisory, emeritus or honorary director. (j) DIRECTOR RESTRICTED STOCK means RESTRICTED STOCK granted to a NON- ------------------------- EMPLOYEE DIRECTOR under the NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN. (k) DIVIDEND EQUIVALENT means a right that entitles the RECIPIENT to ------------------- receive cash or COMMON STOCK based on the dividends declared on the COMMON STOCK covered by such right. (l) ELIGIBLE PARTICIPANT means any KEY EMPLOYEE. It also means, if so -------------------- identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), other EMPLOYEES, DIRECTORS, CONSULTANTS, employees or consultants of any affiliates of PG&E CORPORATION, and other persons whose participation in the PROGRAM is deemed by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof) to be in the best interests of the CORPORATION. (m) EMPLOYEE means any person who is employed by the CORPORATION. The -------- payment of a director's fee or consulting fee by the CORPORATION shall not be sufficient to constitute "employment" by the CORPORATION. (n) ERISA means the Employee Retirement Income Security Act of 1974, as ----- amended. (o) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended. ------------ 10 (p) FAIR MARKET VALUE means the closing price of the COMMON STOCK reported ----------------- on the New York Stock Exchange Composite Transactions for the date specified for determining such value. (q) INCENTIVE AWARD means any ISO, NON-QUALIFIED STOCK OPTION, SAR, --------------- DIVIDEND EQUIVALENT, PERFORMANCE UNIT or other STOCK-BASED AWARD granted under the PROGRAM. (r) ISO means an OPTION intended to qualify as an incentive stock option --- under Section 422 of the CODE. (s) KEY EMPLOYEE means the Corporate Secretary, Treasurer, Vice Presidents ------------ and other executive officers of PG&E CORPORATION above the rank of Vice President. It also means, if so identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), executive officers of wholly-owned subsidiaries of PG&E CORPORATION (including subsidiaries which become such after adoption of the PROGRAM) and any other key management employee of PG&E CORPORATION or any wholly-owned subsidiary of PG&E CORPORATION. (t) LSAR means a limited stock appreciation right which is exercisable ---- only in the event of a CHANGE IN CONTROL. (u) 1986 OPTION PLAN means the Pacific Gas and Electric Company 1986 ---------------- Stock Option Plan, as amended to date. (v) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE. -------------------- (w) NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN RULES means the Non- ------------------------------------------------ Employee Director Stock Incentive Plan attached hereto as Exhibit C or any successor rules which the BOARD OF DIRECTORS may adopt from time to time with respect to the grant of INCENTIVE AWARDS to NON-EMPLOYEE DIRECTORS under the PROGRAM. (x) NON-QUALIFIED STOCK OPTION means any OPTION which is not an ISO. -------------------------- (y) OPTION means an option to purchase shares of COMMON STOCK granted ------ under the STOCK OPTION PLAN. (z) OPTION PRICE means the purchase price for the COMMON STOCK upon ------------ exercise of an OPTION. 11 (aa) PERFORMANCE UNIT means a performance unit granted under the ---------------- PERFORMANCE UNIT PLAN. (bb) PERFORMANCE UNIT PLAN means the Performance Unit Plan Rules attached --------------------- hereto as Exhibit B or any successor rules which the COMMITTEE may adopt from time to time with respect to the grant of PERFORMANCE UNITS under the PROGRAM. (cc) PG&E CORPORATION means PG&E CORPORATION, a California corporation. ---------------- (dd) PHANTOM STOCK means allocated hypothetical shares of COMMON STOCK that ------------- can be converted at a future date into cash or stock. (ee) PROGRAM means the PG&E Corporation Long-Term Incentive Program as ------- amended and restated herein and as may be amended from time to time. (ff) RECIPIENT means the ELIGIBLE PARTICIPANT receiving the INCENTIVE --------- AWARD, or his or her legal representative, legatees, distributees or alternate payees, as the case may be. (gg) RESTRICTED STOCK means COMMON STOCK that is subject to forfeiture by ---------------- the RECIPIENT to the CORPORATION under such circumstances as may be specified by the COMMITTEE in its sole discretion. (hh) RETIREMENT means the Actual Retirement Date under the Pacific Gas and ---------- Electric Company Retirement Plan. (ii) RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor to ---------- Rule 16b-3, as in effect when discretion is being exercised with respect to the Plan. (jj) SAR means a stock appreciation right whose value is based on the --- increase in the FAIR MARKET VALUE of the COMMON STOCK covered by such right. (kk) SECTION 16 OFFICER means any person who is designated by the BOARD OF ------------------ DIRECTORS as an executive officer of PG&E CORPORATION and any other person who is designated as an officer of PG&E CORPORATION for purposes of Section 16 of the EXCHANGE ACT. (ll) STOCK-BASED AWARD means any award that is valued in whole or in part ----------------- by reference to, or is otherwise based on, the COMMON STOCK, 12 including, but not limited to, stock grants, RESTRICTED STOCK, LSARS and PHANTOM STOCK. (mm) STOCK OPTION PLAN means the Stock Option Plan Rules attached hereto as ----------------- Exhibit A or any successor rules which the COMMITTEE may adopt from time to time with respect to the grant of OPTIONS under the PROGRAM. (nn) TANDEM refers to an INCENTIVE AWARD granted in conjunction with ------ another INCENTIVE AWARD. (oo) TERMINATION occurs when an EMPLOYEE ceases to be employed by the ----------- CORPORATION as a common law employee, when a DIRECTOR ceases to be a member of the BOARD OF DIRECTORS or the Board of Directors of any parent corporation which may hereafter be established (as the case may be), or when the relationship between the CORPORATION and a CONSULTANT or other ELIGIBLE PARTICIPANT terminates, as the case may be. (pp) TERMINATION FOR CAUSE has the meaning set forth in Section 18 hereof. --------------------- 13 EXHIBIT A PG&E CORPORATION STOCK OPTION PLAN (As amended and restated effective as of October 21, 1998) 1. Purpose of the Plan ------------------- This is the controlling and definitive statement of the PG&E Corporation Stock Option Plan, as amended and restated herein (hereinafter called the PLAN/2/). The purpose of the PLAN is to advance the interests of the CORPORATION by providing ELIGIBLE PARTICIPANTS with financial incentives to promote the success of its long-term (five to ten years) business objectives, and to increase their proprietary interest in the success of the CORPORATION. It is the intent of the CORPORATION to reward those ELIGIBLE PARTICIPANTS who have a significant impact on improved long-term corporate achievements. Inasmuch as the PLAN is designed to encourage financial performance and to improve the value of shareholders' investment in PG&E CORPORATION, the costs of the PLAN will be funded from corporate earnings. 2. Plan Administration ------------------- The PLAN shall be administered by the COMMITTEE, which shall be constituted in such a manner as to comply with the rules governing a plan intended to qualify as a discretionary plan under RULE 16b-3. Subject to the provisions of the PLAN, the COMMITTEE shall have full and final authority, in its sole discretion: (a) to determine the ELIGIBLE PARTICIPANTS to whom OPTIONS shall be granted and the number of shares of COMMON STOCK to be awarded under each OPTION, based on the recommendation of the CHIEF EXECUTIVE OFFICER (except that awards to the CHIEF EXECUTIVE OFFICER shall be shall be based on the recommendation of the BOARD OF DIRECTORS); provided, however, that the number of shares of COMMON STOCK to be awarded under each OPTION shall be subject to the limitations specified in Section 5 hereof; (b) to determine the time or times at which OPTIONS shall be granted; - -------------------------- /2/ Capitalized words are defined in Section 20 hereof. 14 (c) to designate the OPTIONS being granted as ISOS or NON-QUALIFIED STOCK OPTIONS; (d) to vary the OPTION vesting schedule described in Section 11 hereof; (e) to determine the terms and conditions, not inconsistent with the terms of the PLAN, of any OPTION granted hereunder (including, but not limited to, the consideration and method of payment for shares purchased upon the exercise of an OPTION, and any vesting acceleration or exercisability provisions in the event of a CHANGE IN CONTROL or TERMINATION), based in each case on such factors as the COMMITTEE shall deem appropriate; (f) to approve forms of agreement for use under the PLAN; (g) to construe and interpret the PLAN and any related OPTION agreement and to define the terms employed herein and therein; (h) except as provided in Section 18 hereof, to modify or amend any OPTION or to waive any restrictions or conditions applicable to any OPTION or the exercise thereof; (i) except as provided in Section 18 hereof, to prescribe, amend and rescind rules, regulations and policies relating to the administration of the PLAN; (j) except as provided in Section 18 hereof, to suspend, terminate, modify or amend the PLAN; (k) to delegate to one or more agents such administrative duties as the COMMITTEE may deem advisable, to the extent permitted by applicable law; and (l) to make all other determinations and take such other action with respect to the PLAN and any OPTION granted hereunder as the COMMITTEE may deem advisable, to the extent permitted by applicable law. Notwithstanding the provisions contained in the foregoing paragraph, the CHIEF EXECUTIVE OFFICER shall have the authority, in his sole discretion: (a) to grant OPTIONS to any ELIGIBLE PARTICIPANT who, at the time of the OPTION grant, (i) is not an officer of the CORPORATION or a DIRECTOR, and (ii) if such ELIGIBLE PARTICIPANT is an EMPLOYEE, is receiving an annual salary which is below the level which requires approval by the COMMITTEE; (b) to determine the time or times at which OPTIONS shall be granted to such ELIGIBLE PARTICIPANTS; (c) to designate the OPTIONS being granted to such ELIGIBLE PARTICIPANTS as ISOS or NON-QUALIFIED STOCK 15 OPTIONS; and (d) to vary the OPTION vesting schedule described in Section 11 hereof for the OPTIONS granted to such ELIGIBLE PARTICIPANTS; provided, however, that (x) all grants of OPTIONS by the CHIEF EXECUTIVE OFFICER shall conform to the guidelines previously approved by the COMMITTEE, and (y) the number of shares of COMMON STOCK to be awarded under each OPTION shall be subject to the limitations specified in Section 5 hereof. 3. Shares of Stock Subject to the Plan ----------------------------------- There shall be reserved for use under the PLAN and for the grant of any other incentive awards pursuant to the PROGRAM (subject to the provisions of Section 14 hereof) a total of 23,389,230 shares of COMMON STOCK, which shares may be authorized but unissued shares of COMMON STOCK or issued shares of COMMON STOCK which shall have been reacquired by PG&E CORPORATION. If any OPTION expires or terminates for any reason without having been exercised in full, then any unexercised, shares which were subject to such OPTION (except shares as to which a related TANDEM SAR has been exercised) shall again be available for the future grant of OPTIONS under the PLAN (unless the PLAN has terminated). In addition, shares may be reused or added back to the PLAN to the extent permitted by applicable law. 4. Eligibility ----------- OPTIONS will be granted only to ELIGIBLE PARTICIPANTS. ISOS will be granted only to EMPLOYEES. The COMMITTEE, in its sole discretion, may grant OPTIONS to an ELIGIBLE PARTICIPANT who is a resident or citizen of a foreign country, with such modifications as the COMMITTEE may deem advisable to reflect the laws, tax policy or customs of such foreign country. The PLAN shall not confer upon any OPTIONEE any right to continuation of employment, service as a DIRECTOR or consulting relationship with the CORPORATION; nor shall it interfere in any way with the right of the OPTIONEE or the CORPORATION to terminate such employment, service as a DIRECTOR or consulting relationship at any time, with or without cause. 5. Limitation on Options and SARs Awarded to Any Eligible Participant ------------------------------------------------------------------ The aggregate number of shares of COMMON STOCK with respect to which any ELIGIBLE PARTICIPANT may be granted OPTIONS and SARS under the PLAN during any calendar year shall in no event exceed two percent (2%) of the total number of shares reserved for use under the PLAN. 16 6. Designation of Options ---------------------- At the time of the grant of each OPTION under the PLAN, the COMMITTEE (or the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof) shall determine whether such OPTION is to be designated as an ISO or a NON-QUALIFIED STOCK OPTION; provided, however, that ISOS may be granted only to EMPLOYEES. Notwithstanding such designation, to the extent that the aggregate FAIR MARKET VALUE (determined for each share as of the date of grant of the OPTION covering each share) of the shares with respect to which OPTIONS designated as ISOS become exercisable for the first time by any OPTIONEE during any calendar year exceeds $100,000, such OPTIONS shall be treated as NON-QUALIFIED STOCK OPTIONS. 7. Option Price ------------ The OPTION PRICE of the COMMON STOCK under each OPTION issued shall be the FAIR MARKET VALUE of the COMMON STOCK on the date of grant. 8. Stock Appreciation Rights ------------------------- At the discretion of the COMMITTEE, an OPTION may be granted with or without a TANDEM SAR which permits the OPTIONEE to surrender unexercised an OPTION or portion thereof and to receive in exchange a payment having a value equal to the difference between (x) the FAIR MARKET VALUE of the COMMON STOCK covered by the surrendered portion of the OPTION on the date the SAR is exercised and (y) the OPTION PRICE for such COMMON STOCK. The SAR is subject to the same terms and conditions as the related OPTION, except that (i) the SAR may be exercised only when there is a positive spread (i.e., when the FAIR MARKET VALUE of the COMMON STOCK subject to the OPTION exceeds the OPTION PRICE), (ii) in accordance with Section 9 hereof, payment of the DEA (if any) to the OPTIONEE may be restricted, and (iii) if the OPTIONEE is a SECTION 16 OFFICER, DIRECTOR or other person whose transactions in the COMMON STOCK are subject to Section 16(b) of the EXCHANGE ACT, the SAR may be exercised only during the period beginning on the third (3rd) business day following the date of release of the CORPORATION's quarterly or annual statement of earnings and ending on the twelfth (12th) business day following such date. Upon the exercise of a SAR, the number of shares subject to exercise under the related OPTION shall be automatically reduced by the number of shares represented by the OPTION or portion thereof surrendered. No payment will be required from the OPTIONEE 17 upon the exercise of a SAR, except that any amount necessary to satisfy applicable federal, state or local tax requirements shall be withheld. 9. Dividend Equivalent Account --------------------------- At the discretion of the COMMITTEE, an OPTION may be granted with or without TANDEM DIVIDEND EQUIVALENTS. When an OPTION is granted with TANDEM DIVIDEND EQUIVALENTS, a Dividend Equivalent Account ("DEA") shall be established for the OPTIONEE. This DEA shall be credited quarterly on each dividend record date with dividends which would have been paid on the COMMON STOCK subject to the unexercised portion of the OPTION (including any portion which has not yet vested on the record date), if such portion had been exercised. Except as provided in Section 12(d) hereof, at the time the OPTION or any related SAR is exercised, the OPTIONEE shall receive all funds which have accumulated in the DEA with respect to the shares of COMMON STOCK for which the OPTION or SAR is being exercised; provided, however, that if the OPTIONEE exercises a SAR, such DEA funds shall only be paid to the OPTIONEE if (i) the percentage increase in the FAIR MARKET VALUE of the COMMON STOCK over the OPTION PRICE averages at least five percent (5%) per year for the first five (5) years after the grant, or (ii) in the case of OPTIONS held for longer than five (5) years from the date of grant, such FAIR MARKET VALUE has increased by at least twenty-five percent (25%) over the OPTION PRICE. 10. Terms of Options ---------------- The term of each ISO shall be for ten (10) years from the date of grant, subject to earlier termination as provided in Section 12 hereof. The term of each NON-QUALIFIED STOCK OPTION shall be ten (10) years and one (1) day from the date of grant, subject to earlier termination as provided in Section 12 hereof. Any provision of the PROGRAM to the contrary notwithstanding, no OPTION shall be exercised after the time limitations stated in this Section 10. 11. Limitations on Exercise ----------------------- (a) Each OPTION granted under the PROGRAM shall become exercisable and vested only to the following extent: (i) up to one-third (1/3) of the OPTIONS granted may be exercised on or after the second (2nd) anniversary of the date of grant; (ii) up to two-thirds (2/3) of the OPTIONS granted may be exercised on or after the third (3rd) anniversary of the date of grant; and (iii) up to one hundred percent (100%) of the OPTIONS granted may be exercised on or after the fourth (4th) anniversary of the date of grant. 18 (b) No OPTION under the PROGRAM designated by the COMMITTEE as an ISO and granted before January 1, 1987 may be exercised while there is outstanding in the hands of the OPTIONEE any ISO which was granted before the granting of the ISO hereunder sought to be exercised. For this purpose an ISO shall be treated as outstanding until such OPTION is (i) exercised in full, (ii) surrendered in full by exercising SARS pursuant to Section 8 hereof, or (iii) rendered void by reason of lapse of time. 12. Termination of Employment or Relationship with the CORPORATION -------------------------------------------------------------- (a) In the event of a TERMINATION by reason of a discharge or TERMINATION FOR CAUSE, any unexercised OPTIONS theretofore granted to an OPTIONEE under the PROGRAM shall forthwith terminate. (b) In the event of a TERMINATION by reason of RETIREMENT, all OPTIONS held by the OPTIONEE, to the extent that such OPTIONS have not previously expired or been exercised, shall become fully exercisable and vested, notwithstanding the provisions of Section 11(a) hereof, and the OPTIONEE shall have the right to exercise such OPTIONS in full at any time within their respective terms or within five (5) years after such RETIREMENT, whichever is shorter. This five-year period shall be extended if an OPTIONEE remains on the BOARD OF DIRECTORS after RETIREMENT. In such case, the OPTIONS may be exercised as long as the OPTIONEE remains a DIRECTOR and for a period of six (6) months thereafter, or within five (5) years after RETIREMENT, whichever is longer; provided, however, that no OPTION may be exercised after the expiration of its term. To the extent any ISO held by the OPTIONEE is exercised after the expiration of three (3) months after such TERMINATION, the exercise will be deemed to involve the exercise of a NON-QUALIFIED STOCK OPTION. (c) In the event of a TERMINATION by reason of disability or death, all OPTIONS held by the OPTIONEE, to the extent that such OPTIONS have not previously expired or been exercised, shall become fully exercisable and vested, notwithstanding the provisions of Section 11(a) hereof, and the OPTIONEE (or the OPTIONEE'S estate or a person who acquired the right to exercise such OPTIONS by bequest or inheritance) shall have the right to exercise such OPTIONS at any time within their respective terms or within one (1) year after the date of such TERMINATION, whichever is shorter. The term "disability" shall, for the purposes of the PLAN, be defined in Section 22(e)(3) of the CODE. (d) In the event of a TERMINATION by reason of a divestiture or change in control of a subsidiary of PG&E CORPORATION, which divestiture or change in control results in such subsidiary no longer qualifying as a 19 subsidiary corporation under Section 424(f) of the CODE, all OPTIONS held by the OPTIONEE, to the extent that such OPTIONS have not previously expired or been exercised, shall become fully exercisable and vested, notwithstanding the provisions of Section 11(a) hereof, and the OPTIONEE shall have the right to exercise such OPTIONS in full at any time within their respective terms or within three (3) years after such TERMINATION, whichever is shorter. This three-year period shall be extended if an OPTIONEE remains on the BOARD OF DIRECTORS after such TERMINATION. In such case, the OPTIONS may be exercised as long as the OPTIONEE remains a DIRECTOR and for a period of six (6) months thereafter, or within three (3) years after such TERMINATION, whichever is longer; provided, however, that no OPTION may be exercised after the expiration of its term. To the extent any ISO held by the OPTIONEE is exercised after the expiration of three (3) months after such TERMINATION, the exercise will be deemed to involve the exercise of a NON-QUALIFIED STOCK OPTION. (e) In the event of a TERMINATION within one year after a CHANGE IN CONTROL of the CORPORATION (other than a TERMINATION covered by clauses (a), (b), or (c) above), OPTIONEE shall have the right to exercise OPTIONS which OPTIONEE then holds (which OPTIONS will have been accelerated previously in accordance with Section 16 below), to the extent that such OPTIONS have not previously expired or been exercised, in full at any time within their respective terms or within three (3) years after such TERMINATION, whichever is shorter. This three-year period shall be extended if an OPTIONEE remains on the BOARD OF DIRECTORS after such TERMINATION. In such case, the OPTIONS may be exercised as long as the OPTIONEE remains a DIRECTOR and for a period of six (6) months thereafter, or within three (3) years after such TERMINATION, whichever is longer; provided, however, that no OPTION may be exercised after the expiration of its term. To the extent any ISO held by the OPTIONEE is exercised after the expiration of three (3) months after such TERMINATION, the exercise will be deemed to involve the exercise of a NON-QUALIFIED STOCK OPTION. (f) In the event of a TERMINATION for any reason other than those specified in subparagraphs (a) through (e) above, (i) any unexercised OPTION or OPTIONS granted under the PROGRAM shall be deemed canceled and terminated forthwith, except that the OPTIONEE may exercise any unexercised OPTIONS theretofore granted which are otherwise exercisable and vested within the provisions of Section 11(a) hereof, during the balance of their respective terms or within thirty (30) days of such TERMINATION, whichever is shorter, and (ii) the DEA (if 20 any) shall not be credited with any dividends paid after the date of such TERMINATION. (g) Notwithstanding the provisions of subparagraphs (a) through (f) above, the COMMITTEE may, in its sole discretion, establish different terms and conditions pertaining to the effect of TERMINATION, to the extent permitted by applicable federal and state law. 13. Payment for Shares Upon Exercise of Options ------------------------------------------- The exercise of any OPTION shall be contingent upon receipt by the CORPORATION of (i) cash (including any DEA funds payable to the OPTIONEE in connection with the exercise of such OPTION), (ii) check, (iii) shares of COMMON STOCK, (iv) an executed exercise notice together with irrevocable instructions to a broker to either sell the shares subject to the OPTION or hold such shares as collateral for a margin loan and to promptly deliver to the CORPORATION the amount of sale or loan proceeds required to pay the OPTION PRICE, (v) any combination of the foregoing in an amount equal to the full OPTION PRICE of the shares being purchased, or (vi) such other consideration and method of payment, other than a note from the OPTIONEE, as the COMMITTEE, in its sole discretion, may allow (which, in the case of an ISO shall be determined at the time of grant), to the extent permitted by applicable law. For purposes of this paragraph, shares of COMMON STOCK that are delivered in payment of the OPTION PRICE must have been previously owned by the OPTIONEE for a minimum of one year, and shall be valued at their FAIR MARKET VALUE as of the date of the exercise of the OPTION. The CORPORATION shall not make loans to any OPTIONEE for the purpose of exercising OPTIONS. 14. Adjustments Upon Changes in Number or Value of Shares of Common Stock --------------------------------------------------------------------- If there are any changes in the number or value of shares of COMMON STOCK by reason of stock dividends, stock splits, reverse stock splits, recapitalizations, mergers, consolidations or other events that materially increase or decrease the number or value of issued and outstanding shares of COMMON STOCK, the COMMITTEE may make such adjustments as it shall deem appropriate, in order to prevent dilution or enlargement of rights. 15. Non-Transferability of Options ------------------------------ An OPTION shall not be transferable by the OPTIONEE otherwise than by will or the laws of descent and distribution, or pursuant to a qualified domestic relations order as defined by the CODE, Title I of ERISA or the rules thereunder. During the lifetime of the OPTIONEE, an OPTION may be exercised only by the OPTIONEE or by an alternate payee under a qualified domestic relations order. 21 16. Change in Control ----------------- Upon the occurrence of a CHANGE IN CONTROL (as defined below), any time periods relating to the exercise of any OPTION granted hereunder shall be accelerated so that such OPTION may be immediately exercised in full. A "CHANGE IN CONTROL" shall be deemed to have occurred if: (a) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any trustee, agent or other fiduciary for any such plan acting in such person's capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of PG&E CORPORATION representing twenty percent (20%) or more of the combined voting power of the CORPORATION's then outstanding securities; (b) during any two consecutive years, individuals who at the beginning of such a period constitute the BOARD OF DIRECTORS cease for any reason to constitute at least a majority of the BOARD OF DIRECTORS, unless the election, or the nomination for election by the shareholders of the CORPORATION, of each new DIRECTOR was approved by a vote of at least two-thirds (2/3) of the DIRECTORS then still in office who were DIRECTORS at the beginning of the period; or (c) the shareholders of the CORPORATION shall have approved (i) any consolidation or merger of the CORPORATION other than a merger or consolidation which would result in the voting securities of the CORPORATION outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the Combined Voting Power of the CORPORATION, such surviving entity or the parent of such surviving entity outstanding immediately after the merger or consolidation; (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the CORPORATION, or (iii) any plan or proposal for the liquidation or dissolution of the CORPORATION. For purposes of this paragraph, the term Combined Voting Power shall mean the combined voting power of the CORPORATION's or other relevant entity's then outstanding voting securities. 22 17. Listing and Registration of Shares ---------------------------------- Each OPTION shall be subject to the requirement that if at any time the COMMITTEE shall determine, in its discretion, that the listing, registration or qualification of the shares covered thereby under any securities exchange or under any state or federal law or the consent or approval of any governmental regulatory body, including the California Public Utilities Commission, is necessary or desirable as a condition of, or in connection with, the granting of such OPTION or the issue or purchase of shares thereunder, such OPTION may not be exercised in whole or in part unless and until such listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to the COMMITTEE. 18. Amendment and Termination of the Plan and Options ------------------------------------------------- The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend, terminate, modify or amend the PLAN in any respect; provided, however, that, to the extent necessary and desirable to comply with Section 422 of the CODE (or any other applicable law or regulation, including the requirements of any stock exchange on which the COMMON STOCK is listed or quoted), shareholder approval of any PLAN amendment shall be obtained in such a manner and to such a degree as is required by the applicable law or regulation. No suspension, termination, modification or amendment of the PLAN may, without the consent of the OPTIONEE, adversely affect his or her rights under OPTIONS theretofore granted to such OPTIONEE. In the event of amendments to the CODE or applicable rules or regulations relating to ISOS subsequent to the date hereof, the CORPORATION may amend the PLAN, and the CORPORATION and OPTIONEES holding OPTION agreements may agree to amend outstanding OPTION agreements, to conform to such amendments. The COMMITTEE may make such amendments or modifications in the terms and conditions of any OPTION as it may deem advisable, or cancel or annul any grant of an OPTION; provided, however, that no such amendment, modification, cancellation or annulment may, without the consent of the OPTIONEE, adversely affect his or her rights under such OPTION; and provided further the COMMITTEE may not reduce the OPTION PRICE or purchase price of any OPTION or OPTION below the original OPTION PRICE or purchase price. Notwithstanding the foregoing, the COMMITTEE reserves the right, in its sole discretion, to (i) convert any outstanding ISOS to NON-QUALIFIED STOCK OPTIONS, (ii) to require a OPTIONEE to forfeit any unexercised or unpurchased OPTIONS, any shares received or purchased pursuant to an OPTION, or any gains realized by virtue of the receipt of an OPTION in the event that such OPTIONEE competes against the CORPORATION, and (iii) to cancel or annul 23 any grant of an OPTION in the event of a OPTIONEE'S TERMINATION FOR CAUSE. For purposes of the PROGRAM, "TERMINATION FOR CAUSE" shall include, but not be limited to, termination because of dishonesty, criminal offense or violation of a work rule, and shall be determined by, and in the sole discretion of, the COMMITTEE. 19. Effective Date of the Plan and Duration --------------------------------------- The PLAN first became effective as of January 1, 1992. It has since been amended and restated. The amended and restated PLAN became effective as of January 1, 1996, upon approval by the shareholders of Pacific Gas and Electric Company at its Annual Meeting on April 17, 1996. Effective January 1, 1997, the PLAN was assumed by PG&E CORPORATION. The COMMITTEE amended and restated the PLAN effective October 21, 1998. Unless terminated sooner pursuant to Section 18 hereof, the PLAN shall terminate on December 31, 2005. 20. Definitions ----------- (a) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION. ------------------ (b) CHANGE IN CONTROL has the meaning set forth in Section 16 hereof. ----------------- (c) CHIEF EXECUTIVE OFFICER means the Chief Executive Officer of PG&E ----------------------- CORPORATION. (d) CODE means the Internal Revenue Code of 1986, as amended from time to ---- time. (e) COMMITTEE means the Nominating and Compensation Committee of the BOARD --------- OF DIRECTORS or any successor to such committee. (f) COMMON STOCK means common shares of PG&E CORPORATION with no par value ------------ and any class of common shares into which such common shares hereafter may be converted. (g) CONSULTANT means any person, including an advisor, who is engaged by ---------- the CORPORATION to render services. (h) CORPORATION means PG&E CORPORATION, and any parent corporation (as ----------- defined in Section 424(e) of the CODE) or subsidiary corporation (as defined in Section 424(f) of the CODE). (i) DEA means a Dividend Equivalent Account described in Section 9 hereof. --- 24 (j) DIRECTOR means any person who is a member of the BOARD OF DIRECTORS or -------- the Board of Directors of any parent corporation (as defined in Section 424(e) of the CODE) which may hereafter be established, including an advisory, emeritus or honorary director. (k) DIVIDEND EQUIVALENT means a right that entitles the OPTIONEE to ------------------- receive cash or COMMON STOCK based on the dividends declared on the COMMON STOCK covered by such right. (l) ELIGIBLE PARTICIPANT means any KEY EMPLOYEE. It also means, if so -------------------- identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), other EMPLOYEES, DIRECTORS, CONSULTANTS, employees or consultants of any affiliates of PG&E CORPORATION, and other persons whose participation in the PROGRAM is deemed by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof) to be in the best interests of the CORPORATION; provided, however, that DIRECTORS who are not EMPLOYEES shall not be ELIGIBLE PARTICIPANTS for purposes of the PLAN. (m) EMPLOYEE means any person who is employed by the CORPORATION. The -------- payment of a director's fee or consulting fee by the CORPORATION shall not be sufficient to constitute "employment" by the CORPORATION. (n) ERISA means the Employee Retirement Income Security Act of 1974, as ----- amended. (o) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended. ------------ (p) FAIR MARKET VALUE means the closing price of the COMMON STOCK reported ----------------- on the New York Stock Exchange Composite Transactions for the date specified for determining such value. (q) ISO means an OPTION intended to qualify as an incentive stock option --- under Section 422 of the CODE. (r) KEY EMPLOYEE means the Corporate Secretary, Treasurer, Vice Presidents ------------ and other executive officers of PG&E CORPORATION above the rank of Vice President. It also means, if so identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the case of 25 OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), executive officers of wholly-owned subsidiaries of PG&E CORPORATION (including subsidiaries which become such after adoption of the PROGRAM) and any other key management employee of PG&E CORPORATION or any wholly-owned subsidiary of PG&E CORPORATION. (s) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE. --------------------- (t) NON-QUALIFIED STOCK OPTION means any OPTION which is not an ISO. -------------------------- (u) OPTION means an option to purchase shares of COMMON STOCK granted ------ under the PLAN. (v) OPTIONEE means the ELIGIBLE PARTICIPANT receiving the OPTION, or his -------- or her legal representative, legatees, distributees or alternate payees, as the case may be. (w) OPTION PRICE means the purchase price for the COMMON STOCK upon ------------ exercise of an OPTION. (x) PG&E CORPORATION means PG&E CORPORATION, a California corporation. ---------------- (y) PLAN means this Stock Option Plan as amended and restated herein and ---- as may be amended from time to time, or any successor plan which the COMMITTEE may adopt from time to time with respect to the grant of OPTIONS under the PROGRAM. (z) PROGRAM means the PG&E Corporation Long-Term Incentive Program, as ------- amended and restated effective as of January 1, 1997, and as may be amended from time to time, pursuant to which the PLAN is adopted. (aa) RETIREMENT means the Actual Retirement Date under the Pacific Gas and ---------- Electric Company Retirement Plan. (bb) RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor to ---------- Rule 16b-3, as in effect when discretion is being exercised with respect to the PLAN. 26 (cc) SAR means a stock appreciation right whose value is based on the --- increase in the FAIR MARKET VALUE of the COMMON STOCK covered by such right. (dd) SECTION 16 OFFICER means any person who is designated by the BOARD OF ------------------ DIRECTORS as an executive officer of PG&E CORPORATION and any other person who is designated as an officer of PG&E CORPORATION for purposes of Section 16 of the EXCHANGE ACT. (ee) TANDEM refers to a DIVIDEND EQUIVALENT or SAR (as the case may be) ------ granted in conjunction with an OPTION. (ff) TERMINATION occurs when an EMPLOYEE ceases to be employed by the ----------- CORPORATION as a common law employee, when a DIRECTOR ceases to be a member of the BOARD OF DIRECTORS or the Board of Directors of any parent corporation which may hereafter be established (as the case may be), or when the relationship between the CORPORATION and a CONSULTANT or other ELIGIBLE PARTICIPANT terminates, as the case may be. (gg) TERMINATION FOR CAUSE has the meaning set forth in Section 12 hereof. --------------------- 27 EXHIBIT B PG&E CORPORATION PERFORMANCE UNIT PLAN (As amended and restated effective as of October 21, 1998) This is the controlling and definitive statement of the Performance Unit Plan ("PLAN"/3/) for ELIGIBLE EMPLOYEES of PG&E CORPORATION ("CORPORATION") and such other companies, affiliates, subsidiaries, or associations as the BOARD OF DIRECTORS may designate from time to time. The PLAN was first adopted by the BOARD in 1989 and was effective January 1, 1990. It has since been amended from time to time. ARTICLE I DEFINITIONS ----------- 1.01 Board of Directors or Board shall mean the BOARD OF DIRECTORS of ------------------ the CORPORATION or, when appropriate, any committee of the BOARD which has been delegated the authority to take action with respect to the PLAN. 1.02 Committee shall mean the Nominating and Compensation Committee --------- of the BOARD OF DIRECTORS. 1.03 Corporation shall mean PG&E CORPORATION, a California ----------- corporation. 1.04 Eligible Employee shall mean employees of the CORPORATION who ----------------- are officers at the vice presidential level or above, the corporate secretary, the controller, and the treasurer of the CORPORATION, and such other employees of the CORPORATION, other companies, affiliates, subsidiaries, or associations as may be designated by the COMMITTEE. 1.05 Performance Targets shall mean the annual CORPORATION financial ------------------- and operational goals adopted by the COMMITTEE to be used in determining awards under the PLAN. 1.06 Plan shall mean the Performance Unit Plan ("PUP") as set forth ---- herein and as may be amended from time to time. - ------------ /3/ Words in all capitals are defined in Article I. 28 1.07 Plan Administrator shall mean the COMMITTEE or such individual ------------------ or individuals as that COMMITTEE may appoint to handle the day-to-day affairs of the PLAN. 1.08 Price shall mean the average market price of STOCK for the last ----- 30-day period of the YEAR preceding the YEAR in which UNITS are payable. 1.09 PUP Units shall mean the units granted to ELIGIBLE EMPLOYEES who --------- participate in the PLAN. A PUP UNIT has the equivalent value of the current market price of a share of STOCK at the time of grant. 1.10 Stock shall mean the common stock of the CORPORATION and any ----- class of common shares into which such STOCK hereafter may be converted. 1.11 Vesting Period shall mean the three calendar YEARS commencing -------------- with the YEAR in which PUP UNITS are granted. 1.12 Year shall mean a calendar year. ---- ARTICLE II 2.01 Prior to the beginning of each YEAR, the COMMITTEE shall determine whether PUP UNITS will be granted for such YEAR, the ELIGIBLE EMPLOYEES to whom PUP UNITS will be granted, and the number of PUP UNITS to be granted to each ELIGIBLE EMPLOYEE. Employees who become ELIGIBLE EMPLOYEES after the beginning of a YEAR shall be entitled to a prorata grant of PUP UNITS. 2.02 At the same time that the COMMITTEE makes its determination as to the granting of PUP UNITS, it shall also establish PERFORMANCE TARGETS. Although it is intended that PERFORMANCE TARGETS will not change in the course of the YEAR, the COMMITTEE reserves the right to modify or adjust a previously set PERFORMANCE TARGET if, in its sole discretion, extraordinary events warrant such modification or adjustment; provided, however, that no such modification or adjustment shall increase the amount of any payment that would otherwise be due based upon performance as measured against the original PERFORMANCE TARGET. 2.03 Each grant of PUP UNITS shall have its own VESTING PERIOD. Subject to modification as measured against a given YEAR's applicable PERFORMANCE TARGET, each grant of PUP UNITS shall be payable as follows: a. One-third after the end of the first YEAR of the VESTING PERIOD; 29 b. One-third after the end of the second YEAR of the VESTING PERIOD; and c. One-third after the end of the third YEAR of the VESTING PERIOD. 2.04 To determine the number of PUP UNITS earned, the applicable PERFORMANCE TARGET shall be the PERFORMANCE TARGET for the YEAR in which the PUP UNITS vest. Performance as measured against the applicable PERFORMANCE TARGET for a YEAR shall modify all PUP UNITS that vest at the end of such YEAR. The PERFORMANCE TARGETS established by the COMMITTEE may modify the number of UNITS earned from 0% to 200% of the number of vested UNITS. 2.05 ELIGIBLE EMPLOYEES shall receive a cash payment as soon as practicable following the YEAR PUP UNITS vest pursuant to the schedule set forth in Section 2.03. The amount of the payment shall be equal to the product of the number of PUP UNITS earned multiplied by the PRICE of STOCK. 2.06 Each time that the CORPORATION declares a dividend on its STOCK, an amount equal to the dividend multiplied by an ELIGIBLE EMPLOYEE's outstanding, but unearned PUP UNITS, shall be accrued on behalf of each ELIGIBLE EMPLOYEE. As soon as practicable following the end of each YEAR, ELIGIBLE EMPLOYEES shall receive a cash payment of the dividends accrued for that YEAR, modified by performance for that YEAR as measured under Section 2.04. 2.07 An ELIGIBLE EMPLOYEE may elect to defer the payment of PUP UNITS and/or dividends paid on PUP UNITS by making a timely election under the Deferred Compensation Plan. Deferrals of benefits payable under this Plan shall be subject to the rules contained in the Deferred Compensation Plan governing elections to defer and receipt of deferred amounts. ARTICLE III 3.01 Retirement. Upon retirement under the terms of Pacific Gas and ---------- Electric Company's Retirement Plan, all outstanding PUP UNITS continue to be payable according to the terms of the PLAN. Thus, the number of UNITS eventually earned by a retired employee is still subject to modification depending on the extent to which applicable PERFORMANCE TARGETS are met during the YEAR preceding the January in which UNITS become payable under the schedule of Section 2.03. A retired employee is not entitled to receive grants of PUP UNITS after normal or early retirement date, as those terms are defined under Pacific Gas and Electric Company's Retirement Plan. 30 3.02 Disability. If an ELIGIBLE EMPLOYEE is both disabled and ---------- entitled to receive benefits under Pacific Gas and Electric Company's Long Term Disability Plan, UNITS granted prior to the date of disability shall continue to be payable according to the terms of this PLAN. An ELIGIBLE EMPLOYEE is not entitled to receive grants of PUP UNITS after the date of disability as determined under the provisions of the Long Term Disability Plan. If an ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE because of disability and is not entitled to receive benefits under Pacific Gas and Electric Company's Long Term Disability Plan, all outstanding grants of PUP UNITS become vested and payable as soon as practicable in the YEAR following the YEAR in which the ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE. All of the UNITS payable shall be subject to modification based upon performance as measured against the PERFORMANCE TARGET for the YEAR in which the ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE. 3.03 Death. In the event of the death of an ELIGIBLE EMPLOYEE, all ----- outstanding grants of PUP UNITS held by the ELIGIBLE EMPLOYEE at the date of death shall become vested and payable as soon as practicable in the YEAR following the YEAR of death. All of the UNITS payable after an ELIGIBLE EMPLOYEE's death shall be subject to modification based upon performance as measured against the PERFORMANCE TARGET for the YEAR in which the death of the ELIGIBLE EMPLOYEE occurs. 3.04 Termination. If an ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE ----------- EMPLOYEE for any reason other than retirement as defined under Pacific Gas and Electric Company's Retirement Plan, disability, or death, all outstanding grants of PUP UNITS shall be canceled as of the date that the ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE unless otherwise provided in the PG&E Corporation Officer Severance Policy. 3.05 Change in Control. Upon a Change in Control as defined in the ----------------- PG&E Corporation Long Term Incentive Program (Program), all PUP UNITS shall become vested and payable as soon as practicable in the YEAR following the Change in Control in accordance with Section 16 of the Program. ARTICLE IV ADMINISTRATIVE PROVISIONS ------------------------- 4.01 Administration. The PLAN shall be administered by the PLAN -------------- ADMINISTRATOR who shall have the authority to interpret the PLAN and make such rules as it deems appropriate. The PLAN ADMINISTRATOR shall have the duty and responsibility of maintaining records, making the requisite calculations, and disbursing payments hereunder. The PLAN ADMINISTRATOR's interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned. 31 4.02 Amendment and Termination. The CORPORATION may amend or ------------------------- terminate the PLAN at any time, provided, however, that no such amendment or termination shall adversely affect PUP UNITS which an ELIGIBLE EMPLOYEE has earned prior to the date of such amendment or termination. PUP UNITS outstanding but unearned at the date of any such amendment or termination may, in the sole discretion of the CORPORATION, be canceled, and the CORPORATION shall have no obligation to provide a substitute benefit of lesser, equal, or greater value. 4.03 Nonassignability of Benefits. The benefits payable under this ---------------------------- PLAN or the right to receive future benefits under this PLAN may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for any benefits becomes bankrupt, the interest under the PLAN of the person affected may be terminated by the PLAN ADMINISTRATOR which, in its sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that it deems appropriate. 4.04 No Guarantee of Employment. Nothing contained in this PLAN -------------------------- shall be construed as a contract of employment between the CORPORATION or the ELIGIBLE EMPLOYEE, or as a right of the ELIGIBLE EMPLOYEE to be continued in the employ of the CORPORATION, to remain as an officer of the CORPORATION, or as a limitation on the right of the CORPORATION to discharge any of its employees, with or without cause. 4.05 Benefits Unfunded and Unsecured. The benefits under this PLAN ------------------------------- are unfunded, and the interest under this PLAN of any ELIGIBLE EMPLOYEE and such ELIGIBLE EMPLOYEE's right to receive a distribution of benefits under this PLAN shall be an unsecured claim against the general assets of the CORPORATION. 4.06 Applicable Law. All questions pertaining to the construction, -------------- validity, and effect of the PLAN shall be determined in accordance with the laws of the United States, and to the extent not preempted by such laws, by the laws of the State of California. 32 EXHIBIT C PG&E CORPORATION NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN (As amended and restated effective as of October 21, 1998) 1. Purpose of the Plan ------------------- This is the controlling and definitive statement of the PG&E Corporation Non-Employee Director Stock Incentive Plan (hereinafter called the PLAN/3/). The purpose of the PLAN is to advance the interests of the CORPORATION by providing NON-EMPLOYEE DIRECTORS with financial incentives to promote the success of its long-term (five to ten years) business objectives, and to increase their proprietary interest in the success of the CORPORATION. Inasmuch as the PLAN is designed to encourage financial performance and to improve the value of shareholders' investment in PG&E CORPORATION, the costs of the PLAN will be funded from corporate earnings. 2. Formula Awards of Director Restricted Stock, Non-Qualified Stock Options ------------------------------------------------------------------------ and Phantom Stock to Non-Employee Directors ------------------------------------------- All awards of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK under the PLAN shall be automatic and non-discretionary, and shall be made strictly in accordance with the provisions contained herein. No person shall have any discretion to select which NON-EMPLOYEE DIRECTORS shall be granted DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or PHANTOM STOCK. Further, no person shall have any discretion to determine the number of shares of DIRECTOR RESTRICTED STOCK awarded to a NON-EMPLOYEE DIRECTOR, and, except as otherwise provided in Section 4 with respect to a NON-EMPLOYEE DIRECTOR'S election to allocate formula awards between NON- QUALIFIED STOCK OPTIONS and PHANTOM STOCK, no person shall have any discretion to determine the number of shares underlying NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK awarded to a NON-EMPLOYEE DIRECTOR. 3. Awards of Director Restricted Stock ----------------------------------- (a) On the first business day of each calendar year beginning on January 1, 1998, during the duration of the PLAN, each person who is a NON- EMPLOYEE DIRECTOR on the first business day of the applicable calendar year shall receive a grant of DIRECTOR RESTRICTED STOCK in an amount to be determined in accordance with the formula set forth in this Section 3(a). The number of shares of DIRECTOR RESTRICTED - -------------- /4/ Capitalized words are defined in Section 15 hereof. 33 STOCK to be granted to each NON-EMPLOYEE DIRECTOR each calendar year shall be determined by (i) dividing ten thousand dollars ($10,000) by the FAIR MARKET VALUE of the COMMON STOCK on the first business day of the applicable calendar year, and (ii) rounding the resulting number down to the nearest whole share. No person shall receive more than one (1) grant of DIRECTOR RESTRICTED STOCK during any calendar year. (b) Shares of DIRECTOR RESTRICTED STOCK shall vest cumulatively as follows: (i) twenty percent (20%) of such shares on the first anniversary of the date of grant; (ii) forty percent (40%) of such shares on the second anniversary of the date of grant; (iii) sixty percent (60%) of such shares on the third anniversary of the date of grant; (iv) eighty percent (80%) of such shares on the fourth anniversary of the date of grant; and (v) one hundred percent (100%) of such shares on the fifth anniversary of the date of grant. Shares of DIRECTOR RESTRICTED STOCK may not be resold or otherwise transferred by a GRANTEE until such shares are vested in accordance with the provisions of this Section 3(b). 4. Annual Election to Receive Non-Qualified Stock Options and Phantom Stock ------------------------------------------------------------------------- By June 30 of each calendar year during the term of the Plan, each person who is then a NON-EMPLOYEE DIRECTOR shall deliver to the Corporate Secretary a written election to receive either NON-QUALIFIED STOCK OPTIONS or PHANTOM STOCK, or both, with an aggregate value of $20,000, on the first business day of the following calendar year, provided the person continues to be a NON-EMPLOYEE DIRECTOR on the date the award would otherwise be made. A NON-EMPLOYEE DIRECTOR may allocate between NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK in minimum increments with a value equal to $5,000, as determined in accordance with Section 5 below with respect to NON-QUALIFIFED STOCK OPTIONS, and Section 6 below, with respect to PHANTOM STOCK. All awards of NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK made to NON-EMPLOYEE DIRECTORS shall comply with Section 5 and Section 6 below, respectively. A NON-EMPLOYEE DIRECTOR who has failed to make a timely election or who became a NON-EMPLOYEE DIRECTOR after June 30 shall be awarded NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK, each with a value of $10,000 as determined in accordance with Section 5 and Section 6, respectively, provided that the NON-EMPLOYEE DIRECTOR continues to be a NON-EMPLOYEE DIRECTOR on the on the first business day of the following calendar year. Notwithstanding the foregoing, elections for calendar year 1998 must be received by December 31, 1997, to be effective on the first business day of calendar year 1998. 34 5. Grant of Non-Qualified Stock Options to Non-Employee Directors -------------------------------------------------------------- (a) On the first business day of each calendar year beginning on January 1, 1998, during the duration of the PLAN, each person who is then a NON-EMPLOYEE DIRECTOR and who has elected to receive an award of NON- QUALIFIED STOCK OPTIONS in accordance with Section 4, shall receive a grant of NON-QUALIFIED STOCK OPTIONS with an aggregate value equal to $5,000, $10,000, $15,000, or $20,000, as previously elected by the NON-EMPLOYEE DIRECTOR (or $10,000 in the case of a NON-EMPLOYEE DIRECTOR who has failed to make a timely election in accordance with Section 4 or who became a NON-EMPLOYEE DIRECTOR after June 30) (the "Elected Option Value"). The number of shares subject to the NON- QUALIFIED STOCK OPTIONS shall be determined by dividing the Elected Option Value by the value of a NON-QUALIFIED STOCK OPTION to purchase a single share of PG&E Corporation common stock as of the first business day of the applicable calendar year. The per stock option value shall be calculated in accordance with the Black-Scholes stock option valuation method using the average preceding November closing price of PG&E Corporation stock and reducing the per option value so calculated by twenty percent. The resulting number of NON-QUALIFIED STOCK OPTIONS shall be rounded down to the nearest whole share. No person shall receive more than one grant of NON-QUALIFIED STOCK OPTIONS during any calendar year. (b) The OPTION PRICE of the COMMON STOCK subject under each NON-QUALIFIED STOCK OPTION shall be the FAIR MARKET VALUE of the COMMON STOCK on the date of grant. The exercise of any NON-QUALIFIED STOCK OPTION shall be contingent upon receipt by the CORPORATION of (i) cash, (ii) check, (iii) shares of COMMON STOCK, (iv) an executed exercise notice together with irrevocable instructions to a broker to either sell the shares subject to the NON-QUALIFIED STOCK OPTION or hold such shares as collateral for a margin loan and to promptly deliver to the CORPORATION the amount of sale or loan proceeds required to pay the OPTION PRICE, or (v) any combination of the foregoing in an amount equal to the full OPTION PRICE of the shares being purchased. For purposes of this paragraph, shares of COMMON STOCK that are delivered in payment of the OPTION PRICE must have been previously owned by the GRANTEE for a minimum of one year, and shall be valued at their FAIR MARKET VALUE as of the date of the exercise of the NON-QUALIFIED STOCK OPTION. The CORPORATION shall not make loans to any GRANTEE for the purpose of exercising NON-QUALIFIED STOCK OPTIONS. 35 (c) Each NON-QUALIFIED STOCK OPTION granted under the Plan shall become exercisable and vested cumulatively as follows: (i) up to thirty-three percent (33%) of the NON-QUALIFIED STOCK OPTION may be exercised on or after the second anniversary of the date of grant; (ii) up to sixty- six percent (66%) of the NON-QUALIFIED STOCK OPTION may be exercised on or after the third anniversary of the date of grant; and (iii) up to one hundred percent (100%) of the NON-QUALIFIED STOCK OPTION may be exercised on or after the fourth anniversary of the date of grant. (d) The term of each NON-QUALIFIED STOCK OPTION shall be ten years and one day from the date of grant, subject to earlier termination as provided in Section 9 hereof. Any provision of the PLAN to the contrary notwithstanding, no NON-QUALIFIED STOCK OPTION shall be exercised after the time limitations stated in this Section 5(d). 6. Awards of Phantom Stock to Non-Employee Directors ------------------------------------------------- (a) On the first business day of each calendar year beginning on January 1, 1998, during the duration of the PLAN, each person who is then a NON-EMPLOYEE DIRECTOR and who has elected to receive an award of PHANTOM STOCK in accordance with Section 4, shall be credited with an amount of PHANTOM STOCK with a value (as determined by the FAIR MARKET VALUE of the COMMON STOCK on the first business day of the applicable calendar year) equal to $5,000, $10,000, $15,000, or $20,000, as previously elected by the NON-EMPLOYEE DIRECTOR (the "Elected Phantom Stock Value"). The number of shares of PHANTOM STOCK (including fractions computed to three decimal places) to be granted to each NON- EMPLOYEE DIRECTOR each calendar year shall be determined by dividing the Elected Phantom Stock Value (or $10,000 in the case of a NON- EMPLOYEE DIRECTOR who has failed to make a timely election in accordance with Section 4 or who became a NON-EMPLOYEE DIRECTOR after June 30) by the FAIR MARKET VALUE of the COMMON STOCK on the first business day of the applicable calendar year. No person shall receive more than one grant of PHANTOM STOCK during any calendar year. The shares of PHANTOM STOCK awarded to a NON-EMPLOYEE DIRECTOR shall be credited to a newly established PHANTOM STOCK account for the NON- EMPLOYEE DIRECTOR. Each share of PHANTOM STOCK shall be deemed to be equal to one share (or fraction thereof) of COMMON STOCK on the date of grant, and shall thereafter flucuate in value in accordance with the FAIR MARKET VALUE of the COMMON STOCK. (b) Each NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall be credited quarterly on each dividend payment date with additional 36 shares of PHANTOM STOCK (including fractions computed to three decimal places) determined by dividing (i) the aggregate amount of dividends, i.e,. the dividend multiplied by the number of shares of PHANTOM STOCK credited to the participant's account as of the dividend record date, by (ii) by the FAIR MARKET VALUE of the COMMON STOCK on the dividend payment date. (c) Payment of the shares of PHANTOM STOCK credited to a NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall only be made after the NON- EMPLOYEE DIRECTOR'S RETIREMENT or MANDATORY RETIREMENT from the BOARD OF DIRECTORS. Payment shall be made only in the form of shares of COMMON STOCK equal to the number of shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account on the date of distribution, rounded down to the nearest whole share. The NON- EMPLOYEE DIRECTOR may elect to receive the number of shares of COMMON STOCK to which he is entitled in a lump sum distribution of the entire amount or in a series of ten or less approximately equal annual installments, provided that distribution shall commence no later than January of the year following the year in which the NON-EMPLOYEE DIRECTOR'S RETIREMENT or MANDATORY RETIREMENT occurred. 7. Shares of Stock Subject to the Plan ----------------------------------- There shall be reserved for use under the PLAN and for the grant of any other INCENTIVE AWARDS pursuant to the PROGRAM (subject to the provisions of Section 10 hereof) a total of 23,289,230 shares of COMMON STOCK, which shares may be authorized but unissued shares of COMMON STOCK or issued shares of COMMON STOCK which shall have been reacquired by PG&E CORPORATION. 8. Dividend, Voting and Other Shareholder Rights --------------------------------------------- Except as otherwise provided in the PLAN, each GRANTEE shall have all of the rights of a shareholder of PG&E CORPORATION with respect to all outstanding shares of DIRECTOR RESTRICTED STOCK registered in his or her name, whether or not such shares are vested, including the right to receive dividends and other distributions paid or made with respect to such shares and the right to vote such shares. No GRANTEE shall have any of the rights of a shareholder of PG&E CORPORATION with respect to a NON-QUALIFIED STOCK OPTION until the shares acquired upon exercise of such NON-QUALIFIED STOCK OPTION have been issued and registered in his or her name. No GRANTEE shall have any of the rights of a shareholder of PG&E CORPORATION with respect to 37 PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account under the Plan. 9. Termination of Status as a Non-Employee Director ------------------------------------------------ (a) In the event of a TERMINATION by reason of disability or death, (i) all shares of DIRECTOR RESTRICTED STOCK held by the GRANTEE shall become fully vested, notwithstanding the provisions of Section 3(b) hereof, and the GRANTEE (or the GRANTEE'S estate or a person who acquired the shares of DIRECTOR RESTRICTED STOCK by bequest or inheritance) shall have the right to resell or transfer such shares at any time, (ii) all NON-QUALIFIED STOCK OPTIONS held by the GRANTEE, to the extent that such NON-QUALIFIED STOCK OPTIONS have not previously expired or been exercised, shall become fully vested and exercisable, notwithstanding the provisions of Section 5(c) hereof, and the GRANTEE (or the GRANTEE'S estate or a person who acquired the right to exercise the NON-QUALIFIED STOCK OPTION by bequest or inheritance) shall have the right to exercise the NON-QUALIFIED STOCK OPTIONS at any time within their respective terms or within one (1) year after the date of the GRANTEE'S death or disability, whichever is shorter, and (iii) all shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall immediately become payable to the GRANTEE (or the GRANTEE'S estate or a person who acquired the shares of PHANTOM STOCK by bequest or inheritance) in the form of a number of shares of COMMON STOCK equal to the number of shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account, rounded down to the nearest whole share. The term "disability" shall, for the purposes of the PLAN, be defined in Section 22(e)(3) of the CODE. (b) In the event of a TERMINATION by reason of MANDATORY RETIREMENT, (i) all shares of DIRECTOR RESTRICTED STOCK held by the GRANTEE shall become fully vested, notwithstanding the provisions of Section 3(b) hereof, and the GRANTEE shall have the right to resell or transfer such shares at any time, (ii) the NON-QUALIFIED STOCK OPTIONS then held by the GRANTEE, to the extent that such NON-QUALIFIED STOCK OPTIONS have not previously expired or been exercised, shall become fully vested and exercisable, notwithstanding the provisions of Section 5(c) hereof, and the GRANTEE shall have the right to exercise the NON-QUALIFIED STOCK OPTIONS at any time within their respective terms or within five (5) years after such MANDATORY RETIREMENT, whichever is shorter; and (iii) all shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall become payable to the GRANTEE in accordance with Section 6(c) hereof. 38 (c) In the event of a TERMINATION for any reason other than those specified in subparagraphs (a) and (b) above, (i) any unvested shares of DIRECTOR RESTRICTED STOCK granted hereunder shall be forfeited and the GRANTEE shall return to the CORPORATION for cancellation any stock certificates representing such forfeited shares which forfeited shares shall be deemed to be canceled and no longer outstanding as of the date of TERMINATION; and from and after the date of TERMINATION, the GRANTEE shall cease to be a shareholder with respect to such forfeited shares and shall have no dividend, voting or other rights with respect thereto, (ii) any NON-QUALIFIED STOCK OPTIONS granted hereunder that have not yet vested and become exercisable shall terminate, (iii) the GRANTEE shall have the right to exercise NON-QUALIFIED STOCK OPTIONS, to the extent that such NON-QUALIFIED STOCK OPTIONS have vested and become exercisable as of the date of TERMINATION, at any time within their respective terms or within three months after such TERMINATION, whichever is shorter, after which the NON-QUALIFIED STOCK OPTIONS shall terminate, and (iv) all shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall be forfeited on the date of TERMINATION; provided, however, that if the TERMINATION results from the NON-EMPLOYEE DIRECTOR'S RETIREMENT, then the PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall become payable in accordance with Section 6(c) hereof. (d) Notwithstanding the provisions of subparagraphs (a) through (c) above, the BOARD OF DIRECTORS may, in its sole discretion, establish different terms and conditions pertaining to the effect of TERMINATION, to the extent permitted by applicable federal and state law. 10. Adjustments Upon Changes in Number or Value of Shares of Common Stock --------------------------------------------------------------------- If there are any changes in the number or value of shares of COMMON STOCK by reason of stock dividends, stock splits, reverse stock splits, recapitalizations, mergers, consolidations or other events that materially increase or decrease the number or value of issued and outstanding shares of COMMON STOCK, the BOARD OF DIRECTORS or COMMITTEE may make such adjustments as it shall deem appropriate, in order to prevent dilution or enlargement of rights. 11. Non-Transferability ------------------- NON-QUALIFIED STOCK OPTIONS, PHANTOM STOCK, and shares of DIRECTOR RESTRICTED STOCK that have not vested in accordance with the provisions of Section 3(b) hereof, shall not be transferable by the GRANTEE otherwise than by will or the laws of descent and distribution, or pursuant to a 39 qualified domestic relations order as defined by the CODE, Title I of ERISA or the rules thereunder. 12. Change in Control ----------------- Upon the occurrence of a CHANGE IN CONTROL (as defined below), (i) any time periods relating to the vesting of any shares of DIRECTOR RESTRICTED STOCK granted hereunder shall be accelerated so that all such shares immediately become fully vested, (ii) any time periods relating to the vesting of NON- QUALIFIED STOCK OPTIONS granted hereunder shall be accelerated so that all such NON-QUALIFIED STOCK OPTIONS immediately become fully vested and exercisable for the remainder of their terms, and (iii) all shares of PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTORS' PHANTOM STOCK accounts shall become payable in accordance with Section 6(c) hereof as if the CHANGE IN CONTROL constituted a RETIREMENT. A "CHANGE IN CONTROL" shall be deemed to have occurred if: (a) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any trustee, agent or other fiduciary for any such plan acting in such person's capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of PG&E CORPORATION representing twenty percent (20%) or more of the combined voting power of PG&E CORPORATION's then outstanding securities; (b) during any two consecutive years, individuals who at the beginning of such a period constitute the BOARD OF DIRECTORS cease for any reason to constitute at least a majority of the BOARD OF DIRECTORS, unless the election, or the nomination for election by the shareholders of PG&E CORPORATION, of each new DIRECTOR was approved by a vote of at least two-thirds (2/3) of the DIRECTORS then still in office who were DIRECTORS at the beginning of the period; or the shareholders of the CORPORATION shall have approved (i) any consolidation or merger of the CORPORATION other than a merger or consolidation which would result in the voting securities of the CORPORATION outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the Combined Voting Power of the CORPORATION, such surviving entity or the parent of such surviving entity outstanding immediately after the merger or consolidation; (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the CORPORATION, or (iii) any plan or proposal for the liquidation or dissolution of the CORPORATION. For purposes of this paragraph, the term Combined Voting 40 Power shall mean the combined voting power of the CORPORATION's or other relevant entity's then outstanding voting securities. 13. Amendment and Termination of the Plan ------------------------------------- The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend, terminate, modify or amend the PLAN in any respect; provided, however, that, to the extent necessary and desirable to comply with the CODE (or any other applicable law or regulation, including the requirements of any stock exchange on which the COMMON STOCK is listed or quoted), shareholder approval of any PLAN amendment shall be obtained in such a manner and to such a degree as is required by the applicable law or regulation. No suspension, termination, modification or amendment of the PLAN may, without the consent of the GRANTEE, adversely affect his or her rights with respect to DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or PHANTOM STOCK theretofore granted to such GRANTEE. Except as provided in Section 2 hereof, the BOARD OF DIRECTORS or COMMITTEE may make such amendments or modifications in the terms and conditions of any grant of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or PHANTOM STOCK as it may deem advisable, or cancel or annul any grant of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or PHANTOM STOCK; provided, however, that no such amendment, modification, cancellation or annulment may, without the consent of the GRANTEE, adversely affect his or her rights with respect to such grant. 14. Effective Date of the Plan and Duration --------------------------------------- This PLAN became effective as of January 1, 1996, upon approval by the shareholders of Pacific Gas and Electric Company at its Annual Meeting on April 17, 1996. Effective January 1, 1997, the PLAN was assumed by PG&E CORPORATION. At its meeting on December 17, 1997, the BOARD OF DIRECTORS amended and restated the PLAN effective January 1, 1998, to (i) reflect the adoption of new RULE 16B-3 which became effective November 1, 1996, and (ii) provide automatic formula awards of NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK to NON-EMPLOYEE DIRECTORS within the limits of the PROGRAM as previously approved by shareholders in 1996. The COMMITTEE amended Section 12 of the PLAN effective October 21, 1998. Unless terminated sooner pursuant to Section 13 hereof, the PLAN shall terminate on December 31, 2005. 41 15. Definitions ----------- (a) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION. ------------------ (b) CHANGE IN CONTROL has the meaning set forth in Section 12 hereof. ----------------- (c) CODE means the Internal Revenue Code of 1986, as amended from time to ---- time. (d) COMMITTEE means the Nominating and Compensation Committee of the BOARD --------- OF DIRECTORS or any successor to such committee. (e) COMMON STOCK means common shares of PG&E CORPORATION with no par value ------------ and any class of common shares into which such common shares hereafter may be converted. (f) CORPORATION means PG&E CORPORATION, and any parent corporation (as ----------- defined in Section 424(e) of the CODE) or subsidiary corporation (as defined in Section 424(f) of the CODE). (g) DIRECTOR means any person who is a member of the BOARD OF DIRECTORS or -------- the Board of Directors of any parent corporation (as defined in Section 424(e) of the CODE) which may hereafter be established, including an advisory, emeritus or honorary director. (h) DIRECTOR RESTRICTED STOCK means RESTRICTED STOCK granted to a NON- ------------------------- EMPLOYEE DIRECTOR under the PLAN. (i) EMPLOYEE means any person who is employed by the CORPORATION. The -------- payment of a director's fee or consulting fee by the CORPORATION shall not be sufficient to constitute "employment" by the CORPORATION. (j) ERISA means the Employee Retirement Income Security Act of 1974, as ----- amended. (k) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended. ------------ (l) FAIR MARKET VALUE means the closing price of the COMMON STOCK reported ----------------- on the New York Stock Exchange Composite Transactions for the date specified for determining such value. (m) GRANTEE means the NON-EMPLOYEE DIRECTOR receiving the DIRECTOR ------- RESTRICTED STOCK, NON-QUALIFIED STOCK 42 OPTIONS and PHANTOM STOCK or his or her legal representative, legatees, distributees or alternate payees, as the case may be. (n) MANDATORY RETIREMENT means retirement as a DIRECTOR at age 70 or at -------------------- such other age as may be specified in the retirement policy for the BOARD OF DIRECTORS or the Board of Directors of any parent corporation which may hereafter be established (as the case may be), as in effect at the time of a NON-EMPLOYEE DIRECTOR'S TERMINATION. (o) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE. --------------------- (p) NON-QUALIFIED STOCK OPTION means a option to purchase shares of COMMON -------------------------- STOCK which is not intended to qualify as an incentive stock option under Section 422 of the CODE. (q) PG&E CORPORATION means PG&E CORPORATION, a California corporation. ---------------- (r) PHANTOM STOCK means allocated hypothetical shares of COMMON STOCK that ------------- can be converted at a future date into stock. (s) PLAN means this Non-Employee Director Stock Incentive Plan, as may be ---- amended from time to time, or any successor plan which the COMMITTEE or BOARD OF DIRECTORS may adopt from time to time with respect to the grant of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS, PHANTOM STOCK or other stock-based incentive awards under the PROGRAM. (t) PROGRAM means the PG&E Corporation Long-Term Incentive Program, as ------- amended and restated effective as of January 1, 1998, and as may be amended from time to time, pursuant to which this PLAN is adopted. (u) RESTRICTED STOCK means COMMON STOCK that is subject to forfeiture by ---------------- the GRANTEE to the CORPORATION under such circumstances as may be specified by the COMMITTEE. (v) RETIREMENT means TERMINATION of service on the BOARD OF DIRECTORS ---------- after serving continuously for five consecutive years. (w) RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor to ---------- Rule 16b-3, as in effect when discretion is being exercised with respect to the PLAN. 43 (x) TERMINATION occurs when a NON-EMPLOYEE DIRECTOR ceases to be a member ----------- of the BOARD OF DIRECTORS or the Board of Directors of any parent corporation which may hereafter be established (as the case may be). 44 EX-10.13 10 PG&E CORP. EXECUTIVE STOCK OWNERSHIP PROGRAM EXHIBIT 10.13 PG&E CORPORATION EXECUTIVE STOCK OWNERSHIP PROGRAM Administrative Guidelines ------------------------- (As amended October 21, 1998) 1. Description. The Executive Stock Ownership Program ("Program") was approved ----------- by the Nominating and Compensation Committee of the Board of Directors on October 15, 1997. The Program is an important element of the Committee's compensation policy of aligning executive interests with those of the Corporation's shareholders. As an integral part of the Program, the Committee also authorized the use of Special Incentive Stock Ownership Premiums ("SISOPs") which are designed to provide incentives to Eligible Executives to assist in achieving minimum stock ownership targets established by the Committee. These Guidelines were originally adopted by the Committee on November 19, 1997, amended by the Committee on July 22, 1998, and subsequently amended on October 21, 1998. These amended Guidelines, along with the written materials provided to the Committee on October 15, 1997, describe the Program which became effective on January 1, 1998. The Program is administered by the Corporation's Senior Human Resources Officer. 2. Eligible Executives. The Chief Executive Officer shall designate the ------------------- officers of the Corporation and its affiliates who shall be Eligible Executives covered by the Program. Initially, the officers covered by the Guidelines and the applicable stock ownership Target are:
Officer Band Position Stock Ownership Target ------------------------------------------------------------------------------------- 1 CEO 3 x base salary ------------------------------------------------------------------------------------- 2 Heads of Business Lines, 2 x base salary CFO, & General Counsel ------------------------------------------------------------------------------------- 3 SVPs of Corp. 1.5 x base salary -------------------------------------------------------------------------------------
3. Annual Milestones. Under the Guidelines, stock ownership levels are ----------------- designed to be achieved by the end of the fifth calendar year following the calendar year in which an officer first becomes an Eligible Executive ("Target Date"). Annual Milestones have been established as a means of measuring progress towards achieving Targets and of providing incentives for Eligible Executives to expeditiously meet their Targets. The Annual Milestone at the end of the first full calendar year is 20 percent of the Target, and the Annual Milestone for each succeeding year is an additional 20 percent of the Target. Annual Milestones shall be adjusted to reflect changes in base salary; provided, however, that in each instance any such modification shall be amortized over the remaining original five-year term. Following the Target Date, annual Targets also shall be modified to reflect changes in base salary. 1 4. Calculation of Stock Ownership Levels. Stock ownership level is the --------------------------- dollar value of stock and stock equivalents owned by an Eligible Executive and calculated as of the last day of the calendar year ("Measurement Date"). The purpose of this calculation is to determine the value of the stock or stock equivalents owned by the Eligible Executive as compared with the Annual Milestone or Target for that executive. For purposes of this calculation, the value per share of stock or stock equivalent ("Measurement Value") is the average closing price of PG&E Corporation common stock as traded on the New York Stock Exchange for the last thirty (30) trading days of the year. a) The value of stock beneficially owned by the Eligible Executive is determined by multiplying the number of shares owned beneficially on the Measurement Date times the Measurement Value. b) The value of PG&E Corporation phantom stock units credited to the Eligible Executive's account in the PG&E Corporation Deferred Compensation Plan for Officers ("DCP") is determined by multiplying the number of phantom stock units credited to the Eligible Executive's DCP account on the Measurement Date times the Measurement Value. c) The value of stock held in the PG&E Corporation stock fund of any defined contribution plan maintained by PG&E Corporation or any of its subsidiaries is the value of the Eligible Executive's PG&E Corporation stock fund on the Measurement Date. d) The value of vested stock options is the difference between the number of options multiplied by the Measurement Value minus the number of options multiplied by the option exercise price (for purposes of this calculation, any value attributable to dividend equivalents is excluded). 5. Award of SISOPs. SISOPs are awarded to Eligible Executives who achieve and --------------- maintain stock ownership levels prior to the end of the third year following the year in which an officer first became an Eligible Executive. For purposes of determining awards, the total stock ownership level is calculated as set forth under paragraph 4, on the Measurement Date. The amount of a SISOP award shall be equal to: a) For the first year, 20 percent of the amount of the Eligible Executive's stock ownership level at the end of the year, up to the Annual Milestone, plus an additional 30 percent of the amount by which the stock ownership level exceeds the Annual Milestone up to the target; and b) For each of the second and third years, 20 percent of the amount up to the Annual Milestone by which the end of the year stock ownership level exceeds the beginning of the year stock ownership level, plus an additional 30 percent of the amount by which the end of the year balance exceeds the Annual Milestone, up to the Target. Each time a SISOP award calculation is made, a second calculation also is made to determine the minimum number of shares which must be retained by the Eligible Executive to avoid forfeiture of the SISOP award ("Minimum Ownership Level") as discussed below in paragraph 8. This calculation converts the dollar value of the stock ownership level used as the basis for qualifying for SISOPs into a number of shares of stock. It is calculated by dividing the stock ownership level by the Measurement Value. 2 Thus, for example, if an Eligible Executive's stock ownership level was $250,000 and the Measurement Value was $25 per share, then the Minimum Ownership Level would be 10,000 shares. For purposes of this calculation, the maximum share ownership level used is the Eligible Executive's Target. If an Eligible Executive has a share ownership level higher than his/her Target, the increment over the Target is not included. Thus, for example, if an Eligible Executive has a Target of $750,000 and his/her share ownership level is $900,000, then only $750,000 is used to calculate the Minimum Ownership Level. 6. SISOPs Credited to the Deferred Compensation Plan. Upon award, SISOPs are -------------------------------------------------- credited to the Eligible Executive's DCP account and converted into units of phantom stock each equal in value to a share of PG&E Corporation common stock ("SISOP units") as determined in accordance with paragraph 6 of the DCP. The SISOP units constitute "incentive awards" authorized to be awarded by the Committee to Eligible Executives under the PG&E Corporation Long-Term Incentive Program ("LTIP"). Upon credit of SISOP units to an Eligible Executive's DCP account, an equal number of shares of PG&E Corporation common stock shall be reserved for issuance from the pool of shares authorized for issuance under the LTIP. Once a SISOP unit is credited to the Eligible Executive's DCP account, it shall be subject to all of the terms and conditions specifically applicable to SISOP units under the DCP. Once vested in accordance with paragraph 7 below, SISOP units are distributed in the form of an equal number of shares of PG&E Corporation common stock as provided in the DCP. 7. Vesting. SISOPs vest only upon the expiration of three years after the date -------- of award (provided the Eligible Executive continues to be employed on such date), or, if earlier, upon an Eligible Executive's death, disability, or retirement, or upon a Change in Control as defined in the LTIP. An Eligible Executive's unvested SISOPs will be forfeited upon termination of employment unless otherwise provided in the PG&E Corporation Officer Severance Policy. 8. Forfeiture of SISOP Units. So long as SISOP units remain unvested, such ------------------------- units are subject to forfeiture if, on each Measurement Date, the Eligible Executive's stock ownership is less than the Minimum Ownership Level established when the SISOPs were granted (see paragraph 5). To determine forfeiture, the following steps are followed on each Measurement Date: a) The number of shares and PG&E Corporation phantom stock units credited to the Eligible Executive's DCP account is determined. b) The share-equivalent of the value of the vested "in the money" stock options is determined by dividing the value of such options (computed in the manner described in 4(d)) by the current Measurement Value (e.g., if the value of the vested "in the money" options is $100,000 and the current Measurement Value is $25 per share, then the share equivalent is 4,000 shares). c) The number of shares, PG&E Corporation phantom stock units, and share- equivalents of vested "in the money" options is added together. This total ("Current Holdings") is compared with the Minimum Ownership Level determined when the SISOPs were granted. If the Current Holdings are equal to or greater than the Minimum Ownership Level, then no unvested SISOP units are forfeited. If the Current Holdings are less than the 3 Minimum Ownership Level, then the unvested SISOP units are forfeited in the same proportion as the Current Holdings are less than Minimum Ownership Level (for example, if the Current Holdings are 20 percent less than the Minimum Ownership Level, then 20 percent of the SISOP units are forfeited). 9. Failure to Achieve or Maintain Target. Failure to achieve stock ownership -------------------------------------- levels at Target on the Target Date, or to maintain stock ownership levels at Target on any Measurement Date thereafter, will result in the deferral into the PG&E Corporation Phantom Stock Fund of the DCP of annual awards from the Performance Unit Plan ("PUP") and the Short Term Incentive Plan ("STIP"). As of any Measurement Date, to the extent that stock ownership levels are below Target, PUP awards shall be converted into PG&E Corporation Phantom Stock Units and held in the PG&E Corporation Phantom Stock Fund of the DCP. If, with the addition of the phantom stock units attributable to the PUP award, the stock ownership level is still below Target for any Measurement Date, any STIP award above target STIP also shall be converted into phantom stock units, to the extent necessary to achieve the Target stock ownership level. Such conversion of PUP and STIP awards shall continue for successive Measurement Dates, if necessary, until Target is met. Phantom stock units attributable to PUP and STIP awards described in this paragraph 9 will be paid from the DCP in a lump sum in January of the year following the year in which the Eligible Executive's employment terminates, or upon such earlier date as may have been elected by the Eligible Executive within thirty days after the date of mandatory deferral of PUP and/or STIP awards which date shall not be earlier than three (3) years after the date of mandatory deferral. 4 EX-10.14 11 PG&E CORP. OFFICER SEVERANCE POLICY EXHIBIT 10.14 PG&E CORPORATION OFFICER SEVERANCE POLICY 1. Purpose ------- This is the controlling and definitive statement of the Officer Severance Policy of PG&E Corporation ("Policy"). Since Officers are employed at the will of PG&E Corporation and its subsidiaries ("Corporation"), their employment with the Corporation may be terminated at any time, with or without cause. The Policy, which was first adopted effective November 1, 1998, provides Officers of the Corporation in Officer Compensation Bands I through V with severance benefits in the event that their employment is terminated./1/ Severance benefits for officers not covered by this Policy will be provided under policies or programs developed by the appropriate lines of business in consultation with and the approval by the Senior Human Resources Officer of the Corporation. The purpose of the Policy is to attract and retain senior management by defining terms and conditions for severance benefits, to provide severance benefits that are part of a competitive total compensation package, to provide consistent treatment for all terminated officers, and to minimize potential litigation costs associated with Officer termination of employment. 2. Termination of Employment ------------------------- (a) If Corporation exercises its right to terminate an Officer's employment without cause, it shall give the Officer thirty (30) days' advance written notice or pay in lieu thereof. Except as provided in Section 2(b) below, in consideration of the Officer's agreement to the obligations described in Section 3 below and to the arbitration provisions described in Section 11 below, Corporation shall also provide the following payments and benefits to Officer: (i) The Corporation shall pay Officer a severance payment, equal to (x) two, for Officers in Officer Bands I, II or III or (y) one and one-half, for Officers in Officer Bands IV or V times (the "Severance Multiple") the sum of the Officer's annual base compensation and the Officer's Short-Term Incentive Plan target award at the time of his or her termination, to be paid in a lump sum. Annual base compensation shall mean the Officer's monthly base pay - ------------------------ /1/ Severance benefits for Officers who are currently covered by an employment agreement will continue to be provided solely under such agreements until their expiration at which time this Policy will become effective for such Officers. for the month in which the Officer is given notice of termination, multiplied by 12. If Officer is a participant in the Corporation's Defined Benefit Supplemental Executive Retirement Plan ("SERP"), Officer may elect to convert any portion of the amount described in the preceding sentence to provide for additional years of service and/or additional years to Officer's age for purposes of calculating a benefit under the SERP. The value of any amount so converted shall be calculated using the same actuarial factors used in calculating benefits under the Retirement Plan for Employees of Pacific Gas and Electric Company. Any payments made hereunder shall be less applicable taxes; (ii) If Officer is a participant in the SERP and if the additional age resulting from a conversion under Section 2(a)(i) does not result in an age of 55 or greater, Officer may elect to begin receiving an immediately payable SERP benefit. If Officer elects to receive an immediately payable SERP benefit the Administrator shall use an interest rate and actuarial factors which the Administrator, in its sole discretion, has determined are appropriate to reflect the true economic value to the Corporation of providing an immediately payable SERP benefit; (iii) The incentive awards granted to Officer under the Corporation's Long-Term Incentive Program which have not yet vested as of the date of termination will continue to vest over a period of years or portion thereof equal to the Severance Multiple after the date of termination as if the Officer had remained employed for such period. For vested stock options as of the date of termination, the Officer shall have the right to exercise such stock options at any time within their respective terms or within five years after termination, whichever is shorter. For stock options that vest during a period of years or portion thereof equal to the Severance Multiple, the Officer shall have the right to exercise such options at any time within five years after termination. Awards under the Performance Unit Plan shall continue to vest and be payable during a period of years or portion thereof equal to the Severance Multiple. Any unvested Performance Unit Plan awards remaining at the end of such period shall be forfeited; (iv) For Officers in Officer Bands I, II or III, two thirds of the unvested Company stock units in the Officer's account in the Corporation's Deferred Compensation Plan for Officers which were awarded in connection with the Executive Stock Ownership Program requirements ("SISOPs") shall vest upon the Officer's termination and one third shall be forfeited. For Officers in Officer Bands IV and V, one third of any unvested SISOPs shall vest upon the Officer's termination and two thirds shall be forfeited. Unvested stock units attributable to SISOPs which becomes vested under this provision shall be distributed to Officer in accordance with the Deferred Compensation Plan after such stock units vest; -2- (v) For a period of years or portion thereof equal to the Severance Multiple, the Corporation shall pay the Officer's COBRA premiums; (vi) If Officer is terminated after serving consecutively for six months in a fiscal year, Officer shall be entitled to receive a prorated bonus under the Corporation's Short-Term Incentive Plan, at the time such bonus would otherwise be paid, if any; (vii) To the extent not theretofore paid or provided, the Corporation shall timely pay or provide to the Officer any other amounts or benefits required to be paid or provided or which the Officer is eligible to receive under any plan, contract or agreement of the Corporation and its affiliated companies; and (viii) Such career transition services as the Corporation's Senior Human Resources Officer shall determine is appropriate. (b) Section 2(a) shall not apply in the event that the Corporation terminates an Officer's employment "for cause." "For cause" means that the Corporation, acting in good faith based upon information then known to it, determines that the Officer has engaged in, committed, or is responsible for (1) serious misconduct, gross negligence, theft, or fraud against the Corporation; (2) refusal or unwillingness to perform his duties; (3) inappropriate conduct in violation of Corporation's equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationship of the Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty; or (9) any breach of the restrictive covenants contained in Section 3. Upon termination "for cause," the Corporation shall have no liability to the Officer other than for accrued salary, vacation benefits, and any vested rights the Officer may have under the Corporation's benefit and compensation plans under the general terms and conditions of the applicable plan. 3. Obligations of Officer ---------------------- (a) Release of Claims. The Corporation shall have no obligation to ------------------ commence the payment of the amounts and benefits described in Section 2(a) until the latter of (1) the delivery by Officer to the Corporation a fully executed comprehensive general release of any and all known or unknown claims that he or she may have against the Corporation and a covenant not to sue in the form prescribed by the Administrator, and (2) the expiration of any revocation period associated with the release to which the Officer may be entitled under law. -3- (b) Covenant Not to Compete. (i) During the period of Officer's employment ----------------------- with the Corporation or its subsidiaries and for a period of years or portion thereof equal to the Severance Multiple thereafter (the "Restricted Period"), Officer shall not, in any county within the State of California or in any city, county or area outside the State of California within the United States or in the countries of Canada or Mexico, directly or indirectly, whether as partner, employee, consultant, creditor, shareholder, or other similar capacity, promote, participate, or engage in any activity or other business competitive with Corporation's business or that of any of its subsidiaries or affiliates, without the prior written consent of Corporation's Chief Executive Officer. Notwithstanding the foregoing, Officer may have an interest in any public company engaged in a competitive business so long as Officer does not own more than 2 percent of any class of securities of such company, Officer is not employed by and does not consult with, or becomes a director of, or otherwise engage in any activities for, such competing company. (ii) The Corporation and its subsidiaries presently conduct their businesses within each county in the State of California and in areas outside California that are located within the United States, and it is anticipated that the Corporation and its subsidiaries will also be conducting business within the countries of Canada and Mexico. Such covenants are necessary and reasonable in order to protect the Corporation and its subsidiaries in the conduct of their businesses. To the extent that the foregoing covenant or any provision of this Section 3(b)(e) shall be deemed illegal or unenforceable by a court or other tribunal of competent jurisdiction with respect to (i) any geographic area, (ii) any part of the time period covered by such covenant, (iii) any activity or capacity covered by such covenant, or (iv) any other term or provision of such covenant, such determination shall not affect such covenant with respect to any other geographic area, time period, activity or other term or provision covered by or included in such covenant. (c) Soliciting Corporation Customers and Employees. During the Restricted ---------------------------------------------- Period, Officer shall not, directly or indirectly, solicit or contact any customer or any prospective customer of the Corporation for any commercial pursuit that could be reasonably construed to be in competition with the Corporation, or induce, or attempt to induce, any employees, agents or consultants of or to the Corporation or any of its subsidiaries or affiliates to do anything from which Officer is restricted by reason of this covenant nor shall Officer, directly or indirectly, offer or aid to others to offer employment to, or interfere or attempt to interfere with any employment, consulting or agency relationship with, any employees, agents or consultants of the Corporation, its subsidiaries and affiliates, who received compensation of $75,000 or more during the preceding six (6) months, to work for any business competitive with any business of the Corporation, its subsidiaries or affiliates. (d) Confidentiality. Officer shall not at any time (including after --------------- termination of employment) divulge to others, use to the detriment of the Corporation, or use in any business competitive with any business of the Corporation, any trade secret, -4- confidential or privileged information obtained during his employment with the Corporation, without first obtaining the written consent of the Corporation's Chief Executive Officer. This paragraph covers but is not limited to discoveries, inventions (except as otherwise provided by California law), improvements, and writings, belonging to or relating to the affairs of the Corporation or of any of its subsidiaries or affiliates, or any marketing systems, customer lists or other marketing data. Officer shall, upon termination of employment for any reason, deliver to the Corporation all data, records and communications, and all drawings, models, prototypes or similar visual or conceptual presentations of any type, and all copies or duplicates thereof, relating to all matters contemplated by this paragraph. (e) Assistance in Legal Proceedings. During the Restricted Period, Officer ------------------------------- shall, upon reasonable notice from Corporation, furnish information and proper assistance (including testimony and document production) to Corporation as may be reasonably required by Corporation in connection with any legal, administrative or regulatory proceeding in which it or any of its subsidiaries or affiliates is, or may become, a party, or in connection with any filing or similar obligation of Corporation imposed by any taxing, administrative or regulatory authority having jurisdiction, provided, however, that Corporation shall pay all reasonable expenses incurred by Officer in complying with this paragraph. (f) Remedies. Upon Officer's failure to comply with the provisions of this --------- Section 3, the Corporation shall have the right to immediately terminate the payment of the amounts and benefits described in Section 2(a) to Officer and Corporation shall have no further obligations under this Policy. As damages for breach or threatened breach of any of the covenants set forth in this Section 3 will be difficult to determine and will not afford a full and adequate remedy, the Corporation in addition to seeking actual damages in connection therewith and ceasing its obligations hereunder, may seek specific performance of any such covenant in any court of competent jurisdiction, including without limitation, by the issuance of a temporary or permanent injunction. 4. Administration -------------- The Policy shall be administered by the Chief Human Resources Officer of the Corporation ("Administrator"), who shall have the authority to interpret the Policy and make and revise such rules as may be reasonably necessary to administer the Policy. The Administrator shall have the duty and responsibility of maintaining records, making the requisite calculations, securing Officer releases, and disbursing payments hereunder. The Administrator's interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned. -5- 5. No Mitigation ------------- Payment of the amounts and benefits under Section 2(a) (except as otherwise provided in Section 2(a)(iv)) shall not be subject to offset, counterclaim, recoupment, defense or other claim, right or action which the Corporation may have, and shall not be subject to a requirement that Officer mitigate or attempt to mitigate damages resulting from Officer's termination of employment. 6. Amendment and Termination ------------------------- The Corporation, acting through its Nominating and Compensation Committee, reserves the right to amend or terminate the Policy at any time; provided, however, that any amendment which would reduce the aggregate level of benefits, or terminate the Policy, shall not become effective prior to the third anniversary of the Corporation giving notice to Officers of such amendment or termination. 7. Nonassignability of Benefits ---------------------------- The payments under this Policy or the right to receive future payments under this Policy may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for payments becomes bankrupt, the payments under the Policy of the person affected may be terminated by the Administrator who, in his or her sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that he or she deems appropriate. 8. Nonguarantee of Employment -------------------------- Officers covered by the Policy are at-will employees, and nothing contained in this Policy shall be construed as a contract of employment between the Officer and the Corporation (or, where applicable, a subsidiary or affiliate of the Corporation), or as a right of the Officer to continued employment, or to remain as an Officer, or as a limitation on the right of the Corporation (or a subsidiary or affiliate of the Corporation) to discharge Officer at any time, with or without cause. 9. Benefits Unfunded and Unsecured ------------------------------- The payments under this Policy are unfunded, and the interest under this Policy of any Officer and such Officer's right to receive payments under this Policy shall be an unsecured claim against the general assets of the Corporation. -6- 10. Applicable Law -------------- All questions pertaining to the construction, validity, and effect of the Policy shall be determined in accordance with the laws of the United States and, to the extent not preempted by such laws, by the laws of the state of California. 11. Arbitration ----------- With the exception of any request for injunctive or other equitable relief, any dispute or controversy arising out of this Policy, or out of Officer's employment with Corporation (or with the employing subsidiary) or termination thereof, including tort, breach of contract, breach of covenant of good faith and fair dealing, and discrimination or harassment under applicable federal, state, or local laws, shall be resolved exclusively by final and binding arbitration in accordance with the Commercial Arbitration Rules of the American Arbitration Association then in effect. Provided, however, that in making its determination, the arbitrator shall be limited to accepting the position of the Officer or the position of the Corporation, as the case may be. The only claims not covered by this Section 11 are claims for benefits under workers' compensation or unemployment insurance laws; such claims will be resolved under those laws. The place of arbitration shall be San Francisco, California. Parties may be represented by legal counsel at the arbitration but must bear their own fees for such representation. The losing party in any dispute or controversy shall pay all of the prevailing party's costs, including any arbitrator or administrative fees and reasonable attorneys' fees. Both the Officer and the Corporation specifically waive any right to a jury trial on any dispute or controversy covered by this Section 11. Judgment may be entered on the arbitrators award in any court having jurisdiction. -7- EX-11 12 COMPUTATION OF EARNINGS PER COMMON SHARE EXHIBIT 11 PG&E CORPORATION COMPUTATION OF EARNINGS PER COMMON SHARE
- -------------------------------------------------------------------------------------------------------------------- Year ended December 31, ---------------------------------------- (in thousands, except per share amounts) 1998 1997 1996 - -------------------------------------------------------------------------------------------------------------------- EARNINGS PER COMMON SHARE (EPS) AS SHOWN IN THE STATEMENT OF CONSOLIDATED INCOME Earnings available for common stock $ 719,488 $ 715,940 $ 722,096 ========== ========== ========== Average common shares outstanding 381,907 410,040 412,542 ========== ========== ========== Basic EPS $ 1.88 $ 1.75 $ 1.75 ========== ========== ========== DILUTED EPS (1) Earnings available for common stock $ 719,488 $ 715,940 $ 722,096 ========== ========== ========== Average common shares outstanding 381,907 410,040 412,542 Add exercise of options, reduced by the number of shares that could have been purchased with the proceeds from such exercise (at average market price) 1,198 211 9 ---------- ---------- ---------- Average common shares outstanding as adjusted 383,106 410,251 412,551 ========== ========== ========== Diluted EPS $ 1.88 $ 1.75 $ 1.75 ========== ========== ==========
- ------------------------------------------------------------------------------- (1) This presentation is submitted in accordance with Statement of Financial Accounting Standards No. 128. EX-12.1 13 COMPUTAION OF RATIOS OF EARNINGS TO FIXED CHARGES EXHIBIT 12.1 PACIFIC GAS AND ELECTRIC COMPANY COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
- ------------------------------------------------------------------------------------------------------ Year ended December 31, ---------------------------------------------------------- (dollars in millions) 1998 1997 1996 1995 1994 - ------------------------------------------------------------------------------------------------------ Earnings: Net income $ 729 $ 768 $ 755 $ 1,339 $ 1,007 Adjustments for minority interests in losses of less than 100% owned affiliates and the Company's equity in undistributed losses (income) of less than 50% owned affiliates - - 3 4 (3) Income tax expense 629 609 555 895 837 Net fixed charges 673 628 683 716 729 ------- -------- -------- -------- -------- Total Earnings $ 2,031 $ 2,005 $ 1,996 $ 2,954 $ 2,570 ======= ======== ======== ======== ======== Fixed Charges: Interest on long- term debt, net $ 585 $ 485 $ 574 $ 616 $ 639 Interest on short- term borrowings 50 101 75 83 77 Interest on capital leases 2 2 3 3 2 AFUDC debt 12 17 8 11 13 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust 24 24 24 3 - ------- -------- -------- -------- -------- Total Fixed Charges $ 673 $ 629 $ 684 $ 716 $ 731 ======= ======== ======== ======== ======== Ratios of Earnings to Fixed Charges 3.02 3.19 2.92 4.13 3.52 - ------------------------------------------------------------------------------------------------------
Note: For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to fixed charges, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, cash distributions from and equity in undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest of subordinated debentures held by trust, interest on capital leases, and earnings required to cover the preferred stock dividend requirements. EX-12.2 14 FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
EXHIBIT 12.2 PACIFIC GAS AND ELECTRIC COMPANY COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS - ---------------------------------------------------------------------------------------------------- Year ended December 31, ------------------------------------------------------- (dollars in millions) 1998 1997 1996 1995 1994 - ---------------------------------------------------------------------------------------------------- Earnings: Net income $ 729 $ 768 $ 755 $ 1,339 $ 1,007 Adjustments for minority interests in losses of less than 100% owned affiliates and the Company's equity in undistributed losses (income) of less than 50% owned affiliates - - 3 4 (3) Income tax expense 629 609 555 895 837 Net fixed charges 673 628 683 716 729 -------- -------- -------- -------- -------- Total Earnings $ 2,031 $ 2,005 $ 1,996 $ 2,954 $ 2,570 ======== ======== ======== ======== ======== Fixed Charges: Interest on long- term debt, net $ 585 $ 485 $ 574 $ 616 $ 639 Interest on short- term borrowings 50 101 75 83 77 Interest on capital leases 2 2 3 3 2 AFUDC debt 12 17 8 11 13 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust 24 24 24 3 - -------- -------- -------- -------- -------- Total Fixed Charges $ 673 $ 629 $ 684 $ 716 $ 731 -------- -------- -------- -------- -------- Preferred Stock Dividends: Tax deductible dividends $ 9 $ 10 $ 10 $ 11 $ 5 Pretax earnings required to cover non-tax deductible preferred stock dividend requirements 31 39 39 100 96 -------- -------- -------- -------- -------- Total Preferred Stock Dividends $ 40 $ 49 $ 49 $ 111 $ 101 -------- -------- -------- -------- -------- Total Combined Fixed Charges and Preferred Stock Dividends $ 713 $ 678 $ 733 $ 827 $ 832 ======== ======== ======== ======== ======== Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 2.85 2.96 2.72 3.57 3.09 - ----------------------------------------------------------------------------------------------------
Note: For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to combined fixed charges and preferred stock dividends, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, cash distributions from and equity in undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, interest of subordinated debentures held by trust, and earnings required to cover the preferred stock dividend requirements of majority owned subsidiaries. "Preferred stock dividends" represent pretax earnings which would be required to cover such dividend requirements. EX-13 15 ANNUAL REPORT TO SHAREHOLDERS EXHIBIT 13 SELECTED FINANCIAL DATA
(in millions, except per share amounts) 1998 1997 1996 1995 1994 PG&E CORPORATION(1) - ------------------- For the Year Operating revenues $19,942 $15,400 $ 9,610 $ 9,622 $10,350 Operating income 2,007 1,728 1,896 2,763 2,424 Net income 719 716 722 1,269 950 Earnings per common share 1.88 1.75 1.75 2.99 2.21 Dividends declared per common share 1.20 1.20 1.77 1.96 1.96 At Year-End Book value per common share $ 21.08 $ 21.30 $ 20.73 $ 20.77 $ 20.07 Common stock price per share 31.50 30.31 21.00 28.38 24.38 Total assets 33,234 31,115 26,237 26,871 27,738 Long-term debt (excluding current portions) 7,422 7,659 7,770 8,049 8,676 Rate reduction bonds (excluding current portions) 2,321 2,611 -- -- -- Redeemable preferred stock and securities of subsidiaries (excluding current portions) 635 750 694 694 725 PACIFIC GAS AND ELECTRIC COMPANY - -------------------------------- For the Year Operating revenues $ 8,924 $ 9,495 $ 9,610 $ 9,622 $10,350 Operating income 1,876 1,831 1,896 2,763 2,424 Income available for common stock 702 735 722 1,269 950 At Year-End Total assets $22,950 $25,147 $26,237 $26,871 $27,738 Long-term debt (excluding current portions) 5,444 6,218 7,770 8,049 8,676 Rate reduction bonds (excluding current portions) 2,321 2,611 -- -- -- Redeemable preferred stock and securities (excluding current portions) 579 694 694 694 725
- --------------- (1) PG&E Corporation became the holding company for Pacific Gas and Electric Company on January 1, 1997. The Selected Financial Data of PG&E Corporation and Pacific Gas and Electric Company (the Utility) for the years 1994 through 1996 are identical because they reflect the accounts of the Utility as the predecessor of PG&E Corporation. Matters relating to certain data above are discussed in Management's Discussion and Analysis and in Notes to the Consolidated Financial Statements. 17 MANAGEMENT'S DISCUSSION AND ANALYSIS PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. PG&E Corporation's businesses provide energy services throughout North America. PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company (the Utility), provides natural gas and electric service to one of every 20 Americans. PG&E Corporation's four unregulated businesses provide a wide range of energy products and services through its wholesale and retail unregulated business operations. PG&E Corporation's wholesale unregulated business operations consist of U.S. Generating Company (USGen) which develops, builds, operates, owns, and manages power generation facilities that serve wholesale and industrial customers; PG&E Gas Transmission (PG&E GT) which operates approximately 9,000 miles of natural gas pipelines, natural gas storage facilities, and natural gas processing plants in the Pacific Northwest (PG&EGTNW) and Texas (PG&E GTT); and PG&E Energy Trading (PG&E ET) which purchases and resells energy commodities and related financial instruments in major North American markets, serving PG&E Corporation's other unregulated businesses, unaffiliated utilities, and large end-use customers. PG&E Corporation's retail unregulated business operations consist of PG&E Energy Services (PG&E ES) which provides competitively priced electricity, natural gas, and related services to lower overall energy costs for industrial, commercial, and institutional customers. This is a combined annual report of PG&E Corporation and Pacific Gas and Electric Company. It includes separate consolidated financial statements for each entity. The consolidated financial statements of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility, and PG&E Corporation's other wholly owned and controlled subsidiaries. The consolidated financial statements of the Utility reflect the accounts of the Utility and its wholly owned subsidiaries. PG&E Corporation was formed in 1997 as the parent holding company for the Utility and the unregulated businesses. Information for 1996 in PG&E Corporation's consolidated financial statements is identical to information in the Utility's consolidated financial statements because they represent the accounts of Utility as the predecessor of PG&E Corporation. This combined annual report, including our Letter to Shareholders and this Management's Discussion and Analysis (MD&A), contains forward-looking statements about the future that are necessarily subject to various risks and uncertainties. These statements are based on the beliefs and assumptions of management and on information currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes," and other similar expressions. Factors that could cause future results to differ materially from those expressed in or implied by the forward-looking statements or historical results include the impact or outcome of: * the pace and extent of the ongoing restructuring of the electric and gas industries across the United States; * the outcome of regulatory and legislative proceedings and operational changes related to industry restructuring; * any changes in the amount the Utility is allowed to collect (recover) from its customers for certain costs which prove to be uneconomic under the new competitive market (called transition costs) in accordance with the Utility's plan for recovering those costs; * the successful integration and performance of our recently acquired assets; * our ability to successfully compete outside our traditional regulated markets; * internal and external Year 2000 software and hardware issues; * the outcome of ongoing regulatory proceedings, including: the Utility's cost of capital proceeding; the Utility's 1999 general rate case; the Utility's proposal to adopt performance based ratemaking (PBR); the Utility's transmission rate case applications; and the California Public Utilities Commission's (CPUC) regulatory proceedings including its audit of the Utility's affiliate transactions; * fluctuations in commodity gas and electric prices and our ability to successfully manage such price fluctuations; and * the pace and extent of competition in the California generation market and its impact on the Utility's costs and resulting collection of transition costs. 18 Although the ultimate impacts of the above factors are uncertain, these and other factors may cause future earnings to differ materially from results or outcomes we currently seek or expect. Each of these factors is discussed in greater detail in this MD&A. In this MD&A, we first discuss our competitive and regulatory environment. We then discuss earnings and changes in our results of operations for 1998, 1997, and 1996. Finally, we discuss liquidity and financial resources, various uncertainties that could affect future earnings, and our risk management activities. Our MD&A applies to both PG&E Corporation and the Utility. The MD&A should be read in conjunction with the associated consolidated financial statements of both PG&E Corporation and the Utility. Competitive and Regulatory Environment This section provides a discussion of the competitive environment in the evolving energy industry, the California transition plans, the New England electricity market, and regulatory matters. The Competitive Environment in the Evolving Energy Industry 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 (bundled) basis, with rates charged by the energy companies designed to include all of the costs of providing these services. Now, energy utilities face intensifying pressures to make competitive those activities that are not natural monopoly services. The most significant of these services are electricity generation and natural gas supply. The driving forces behind these competitive pressures are customers who believe they can obtain energy at lower unit prices and competitors who want access to those customers. Regulators and legislators are responding to those customers and competitors by providing more competition in the energy industry. Regulators and legislators are requiring utilities to "unbundle" rates (separate their various energy services and the prices of those services). This allows customers to compare unit prices of the Utility and other pro-viders when selecting their energy service provider. In the natural gas industry, Federal Energy Regulatory Commission (FERC) Order 636 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 (typically a local gas distribution company) buys the gas commodity from the pipeline. In the electric industry, the Public Utilities Regulatory Policies Act of 1978 specifically provided that unregulated companies could become wholesale generators of electricity and that utilities were required to purchase and use power generated by these unregulated companies in meeting their customers' needs. The National Energy Policy Act of 1992 was designed to increase competition in the wholesale unregulated generation market by requiring access to electric utility transmission systems by all wholesale unregulated generators, sellers, and buyers of electricity. Now, an increasing number of states throughout the country have either implemented plans or are considering proposals to separate the generation from the transmission and distribution of electricity through some form of electric industry restructuring. To date, the states, not the federal government, have taken the initiative on electric industry restructuring at the retail level. While at least five bills mandating deregulation of the electric industry were introduced in the U.S. Congress over the past two years, none have been passed. As a result, the pace, extent, and methods for restructuring the electric industry vary widely throughout the country. For instance, California, Illinois, Pennsylvania, and several New England states have passed electric industry restructuring legislation. Other states are considering restructuring proposals. There are also some states that have passed legislation precluding or significantly slowing down deregulation. Differences in how individual states view electric industry restructuring often relate to the existing unit cost of energy supplies within each state. Generally, states having higher energy unit costs are moving more quickly to deregulate energy supply markets. Implementation of our national energy strategy depends, in part, upon the opening of energy markets to provide customer choice of supplier. Undue delays 19 MANAGEMENT'S DISCUSSION AND ANALYSIS by states or federal legislation to deregulate the electric generation and natural gas supply business could impact the pace of growth of our retail unregulated business operations. California Transition Plans The Electric Business: In 1998, California became one of the first states in the country to implement an electric industry restructuring plan. Today, many Californians may choose to purchase their electricity from (1) investor-owned utilities such as Pacific Gas and Electric Company, or (2) unregulated retail electricity suppliers (for example, marketers, including PG&E Energy Services, brokers, and aggregators). The restructuring plan contemplates that the investor-owned utilities, including the Utility, will continue to provide distribution services to substantially all customers within their service territories, including providing electricity to customers who choose not to be served by another service provider. California electric industry restructuring has two major components: the competitive market framework and the electric transition plan, which are discussed below. Competitive Market Framework: To create a competitive generation market, a Power Exchange (PX) and an Independent System Operator (ISO) began operating in 1998. The Utility is required to sell to the PX all of the electricity generated by its power plants and electricity acquired under contract with unregulated generators. Also, the Utility is required to buy from the PX all electricity needed to provide service to retail customers that continue to choose the Utility as their electricity supplier. The ISO schedules delivery of electrici ty for all market participants to the transmission system. The Utility continues to own and maintain a portion of the transmission system, but the ISO controls the operation of the system. During 1998, the Utility continued its efforts to develop and implement changes to its business processes and systems, including the customer information and billing system, to accommodate electric industry restructuring. To the extent that the Utility is unable to develop and implement such changes in a successful and timely manner, there could be an adverse impact on the Utility's or PG&E Corporation's future results of operations. Electric Transition Plan: Market-based revenues, determined by the market through sales to the PX, may not be sufficient to recover (that is, to collect from customers) all of the Utility's generation costs. To allow California investor-owned utilities the opportunity to recover their transition costs (generation costs that would not be recovered through market-based revenues) and to ensure a smooth transition to a competitive market, the California legislature developed a transition plan in the form of state legislation that was passed in 1996. The transition plan will remain in effect until the earlier of December 31, 2001, or when the Utility has recovered its authorized transition costs as determined by the CPUC, with provisions that certain transition costs can be recovered after the transition period. At the conclusion of the transition period, the Utility will be at risk to recover any of its remaining generation costs through market- based revenues. The transition plan contains three principal elements: (1) an electric rate freeze and rate reduction, (2) the recovery of transition costs, and (3) divestiture of utility-owned generation facilities. Each element is discussed below. Rate Freeze and Rate Reduction: The first element of the transition plan is an electric rate freeze and an electric rate reduction. In 1997 and 1998, the Utility held rates for its larger customers at 1996 levels, and it will hold their rates at that level until the end of the transition period. On January 1, 1998, the Utility reduced electric rates for its residential and small commercial customers by 10 percent from 1996 levels, and it will hold their rates at that level until the end of the transition period. Collectively, these actions are called a rate freeze. To pay for the 10 percent rate reduction, the Utility refinanced $2.9 billion of its transition costs with the proceeds of rate reduction bonds (see Note 9 of Notes to Consolidated Financial Statements). The bonds allow for the rate reduction by lowering the carrying cost on a portion of the transition costs and by deferring recovery of a portion of these transition costs until after the transition period. 20 Transition costs are being recovered from all Utility distribution customers through a nonbypassable charge regardless of the customer's choice of electricity supplier. As the customer charge for transition costs is nonbypassable, the Utility believes that the availability of choice to its customers will not have a material impact on its ability to recover transition costs. Revenues from frozen electric rates provide for the recovery of authorized Utility costs, including transmission and distribution service, public purpose programs, and nuclear decommissioning. To the extent the revenues from frozen rates exceed authorized Utility costs, the remaining revenues constitute the competitive transition charge (CTC) which recovers the transition costs. These CTC revenues are subject to seasonal fluctuations in the Utility's sales volumes and certain other factors. Transition Cost Recovery: Transition costs consist of: (1) above-market sunk costs (sunk costs are costs associated with Utility-owned generation assets that are fixed and unavoidable and currently included in the Utility customers' electric rates) and future costs, such as costs related to plant removal of Utility-owned generation facilities, (2) costs associated with the Utility's long-term contracts to purchase power at above-market prices from qualifying facilities and other power suppliers, and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods to be included in rates in subsequent periods.) Above-market sunk costs result when the book value of a facility is in excess of its market value. Conversely, below-market sunk costs result when the market value of a facility is in excess of its book value. The total amount of generation facility costs to be included as transition costs will be based on the aggregate of above-market and below-market values. The above-market portion of these costs is eligible for recovery as a transition cost. The below-market portion of these costs will reduce other unrecovered transition costs. A valuation of a Utility-owned generation facility where the market value exceeds the book value could result in a material charge to Utility earnings if the valuation of the facility is determined based upon any method other than a sale of the facility to a third party. This is because any excess of market value over book value would be used to reduce other transition costs. The Utility will not be able to determine the exact amount of above-market non-nuclear sunk costs that will be recoverable as transition costs until a market valuation process (appraisal, spin, sale, or other valuation method) is completed for each of its generation facilities. Several of these valuations occurred in 1997 and 1998, when the Utility agreed to sell seven of its electric plants. The market value of these facilities determined by these sales exceeded the book value and will therefore reduce the amount of transition costs to be recovered. In addition, in December 1998, the Utility requested that the CPUC allow it to hire appraisers to set the value of its hydroelectric generation system. (See Generation Divestiture below.) The remainder of the valuation process is expected to be completed by December 31, 2001. Nuclear sunk costs were separately determined through a CPUC proceeding and were subject to a final verification audit. This audit was completed in August 1998, the results of which are currently under review. (See Regulatory Matters below for further details.) Costs associated with the Utility's long-term contracts to purchase electric power at above-market prices are included as transition costs. Over the remaining life of these contracts, the Utility estimates that it will purchase 322 million megawatt-hours. To the extent that the individual contract prices are above the market price, the Utility will be able to collect the difference between the contract price and the market price from customers, as a transition cost, over the term of the contract. The contracts expire at various dates through 2028. During 1998, the average price paid per kilowatt-hour (kWh) under the Utility's long-term contracts for electric power was 7.4 cents per kWh. The average cost of electric energy for energy purchased at market rates from the PX for the period from April 1, 1998, to December 31, 1998, was 3.2 cents per kWh. Generation-related regulatory assets and obligations (net generation-related regulatory assets) are included as transition costs. These net regulatory assets consist of those created prior to the transition period and those created during the transition period. In 1998, the staff of the Securities and Exchange Commission (SEC) issued interpretive guidance related to assets which are being transitioned to a deregulated environment. The 21 MANAGEMENT'S DISCUSSION AND ANALYSIS guidance states that an impairment analysis should be performed for such assets and that the impairment analysis should exclude transition cost revenues. The Utility has determined that certain of its generation facilities are considered impaired under the SEC's interpretive guidance. Because the Utility expects to recover the impaired assets as a transition cost, it recorded a regulatory asset for the impaired amounts as required. As a result, in 1998, $3.9 billion was reclassified from property, plant, and equipment to regulatory assets on the Utility's balance sheet. Prior year amounts were also reclassified. The Utility's generation-related regulatory assets total $5.4 billion at December 31, 1998. Under the transition plan, most transition costs can be recovered until December 31, 2001. This recovery period is significantly shorter than the recovery period of the generation assets prior to restructuring and is referred to as accelerated recovery. Accordingly, the Utility is amortizing its transition costs, including most generation-related regulatory assets over the transition period. The CPUC believes that the transition plan reduces risks associated with recovery of all the Utility's generation assets, including the Diablo Canyon Nuclear Power Plant (Diablo Canyon) and the hydroelectric facilities. As a result, during the transition period, the Utility is receiving a reduced return on common equity for all of its generation assets, including those generation assets reclassified to regulatory assets. In 1998, the reduced return on common equity was 6.77 percent as compared to an authorized return on common equity of 11.20 percent. The reduced return on common equity related to generation assets will be in effect throughout the transition period. Certain transition costs can be included in a nonbypassable charge to distribution customers after the transition period. These costs include: (1) certain employee-related transition costs, (2) above-market payments under existing long-term contracts to purchase power, discussed above, and (3) unrecovered electric industry restructuring implementation costs. In addition, transition costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds. Further, the Utility's nuclear decommissioning costs are being recovered through a CPUC-authorized charge, which will extend until sufficient funds exist to decommission our nuclear facility. During the rate freeze, this charge and the rate reduction bond debt service will not increase the Utility customers' electric rates. Excluding these exceptions, the Utility will write-off any transition costs not recovered during the transition period. Under the terms of the transition plan, revenues provided for the recovery of most non-nuclear transition costs are based upon the acceleration of such costs within the transition period. For nuclear transition costs, revenues provided for transition cost recovery are based on: (1) an established incremental cost incentive price per kWh generated by Diablo Canyon to recover certain ongoing costs and capital additions, and (2) the accelerated recovery of the investment in Diablo Canyon from a period ending in 2016 to a five-year period ending December 31, 2001. The Utility is amortizing its eligible transition costs, including generation-related regulatory assets, over the transition period in conjunction with the available CTC revenues. Effective January 1, 1998, the Utility started collecting these eligible transition costs through the nonbypassable CTC. During 1998, regulatory assets related to electric utility restructuring decreased by $609 million. This decrease reflects the recovery of eligible transition costs of $486 million through accelerated amortization and $123 million through the gain on the sale of generating plants. During the transition period, the CPUC will review the Utility's compliance with the accounting methods used by the Utility to recover transition costs and the amount of transition costs requested for recovery. The CPUC is currently reviewing non-nuclear transition costs amortized during the first six months of 1998. The Utility expects the CPUC to issue decisions regarding this review in the second half of 1999. Transition costs that are disallowed by the CPUC for collection from the Utility customers will be written off. Generation Divestiture: In 1998, the Utility completed the sale of three fossil-fueled generation plants for $501 million. These three fossil-fueled plants had a combined book value at the time of the sale of $346 million and had a combined capacity of 2,645 megawatts (MW). 22 Also in 1998, the Utility agreed to sell three other fossil-fueled generation plants and its complex of geothermal generation facilities. The winning bids total $1,014 million. As of December 31, 1998, these four plants had a combined book value of $523 million and had a combined capacity of 4,289 MW. The sales are subject to the approval of regulatory agencies, including the CPUC, and conditioned upon the transfer of various permits and licenses. The Utility expects to complete the sale of these four plants in 1999. The Utility will retain a liability for required environmental remediation related to all of its fossil-fueled and geothermal generation plants of any pre-closing soil or groundwater contamination at the plants it has or will sell. The Utility records its estimated liability for the retained environmental remediation obligation as part of the determination of the gain or loss on the sale of each plant. Any net gains from the sale of our Utility-owned generation plants will be used to offset other transition costs. As a result, we do not believe sales of any generation facilities to a third party will have a material impact on our results of operations. The Utility is currently evaluating its options related to its remaining non- nuclear generation facilities, primarily the hydroelectric generation system. In May 1998, the Utility notified the CPUC that it does not plan to retain the hydroelectric assets as part of the Utility. In December 1998, the Utility filed with the CPUC its proposed appraisal process for valuing generation assets, primarily the hydroelectric system. The Utility expects to receive a response to this request in 1999. At December 31, 1998, the book value of the Utility's net investment in hydroelectric generation assets was $1.4 billion. If the Utility decides to dispose of the hydroelectric generation assets by any method other than a sale of the assets to a third party, a material charge could result to the extent that the market value of the assets exceeds their book value. The market value of the hydroelectric assets is expected to exceed their book value by a material amount. Financial Impact: The Utility's ability to continue recovering its transition costs will be dependent on several factors including: (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs ultimately approved for recovery by the CPUC, (3) the market value of the remaining Utility-owned generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, (6) the extent to which the Utility's authorized revenues to recover distribution costs are increased or decreased (see Regulatory Matters), and (7) the market price of electricity. Given our current evaluation of these factors, we believe that the Utility will recover its transition costs under the terms of the approved transition plan. However, a change in one or more of these factors could affect the probability of recovery of transition costs and result in a material charge. The Gas Business: Restructuring of the natural gas industry on both the national and the state level has given choices to California utility customers to meet their gas supply needs. The Gas Accord Settlement (Accord), a multi-party settlement approved by the CPUC in 1997, continues the process of restructuring the gas industry in California. The Accord was implemented in 1998, and has four principal elements: 1. The Accord separates or "unbundles" the rates for the Utility's gas transportation system. The Utility now offers transmission, distribution, and storage services as separate and distinct services to its noncore customers. Unbundling gives these customers the opportunity to select from a menu of services offered by the Utility and enables them to pay only for the services that they use. Unbundling also makes access to the transmission system possible for all gas marketers and shippers, as well as noncore end-users. As a result, the Accord makes the Utility's transmission system more accessible to a greater number of customers. 2. The Accord increases the opportunity for the Utility's core customers to select the commodity gas supplier of their choice. Greater customer choice increases competition among suppliers providing gas to core customers and reduces the Utility's role in purchasing gas for such customers. Despite these changes, the Utility continues to purchase gas as a regulated supplier for those who request it, serving a majority of core customers in its service territory. 23 MANAGEMENT'S DISCUSSION AND ANALYSIS 3. The Accord changes the way in which the Utility's costs of purchasing gas for core customers through 2002 are regulated. The Accord replaces CPUC reasonableness reviews with the core procurement incentive mechanism (CPIM), a form of incentive ratemaking that provides the Utility a direct financial incentive to procure gas and transportation services at the lowest reasonable costs by comparing all procurement costs to an aggregate market-based benchmark. If costs fall within a range (tolerance band) around the benchmark, costs are considered reasonable and fully recoverable from ratepayers. If procurement costs fall outside the tolerance band, ratepayers and shareholders share savings or costs, respectively. The CPIM results for 1997 and 1998 had an immaterial impact on the Utility's results of operations. 4. The Accord settled various regulatory issues involving the Utility and various other parties. Resolution of these issues did not have a material adverse impact on the Utility's or our financial position or results of operations. The Accord also establishes gas transmission rates within California for the period from March 1998 through December 2002 for the Utility's core and noncore customers and eliminates regulatory protection for variations in sales volumes for noncore transmission revenues. As a result, the Utility is at risk for variations between actual and forecasted noncore transmission throughput volumes. However, we do not expect these variations to have a material adverse impact on the Utility's or our financial position or results of operations. Rates for gas distribution services will continue to be set by the CPUC and designed to provide the Utility an opportunity to recover its costs of service and include a return on its investment. The regulatory mechanisms for setting gas distribution rates are discussed below under Regulatory Matters. New England Electricity Market Three New England states where our unregulated businesses operate electric generation facilities (Massachusetts, New Hampshire, and Rhode Island) were, like California, among the first states in the country to introduce electric industry restructuring. Connecticut also has passed electric industry restructuring legislation. As a result of this restructuring, the wholesale unregulated electricity market in New England features a bid-based market and an independent system operator. In September 1998, PG&E Corporation, through its indirect subsidiary USGen New England, Inc., completed the acquisition of a portfolio of electric generation assets and power supply contracts from New England Electric System (NEES). (See Note 5 of Notes to Consolidated Financial Statements.) The NEES assets include hydroelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of about 4,000 MW. Including fuel and other inventories and transaction costs, the financing requirements for this transaction were approximately $1.8 billion, funded through $1.3 billion of USGen debt and a $425 million equity contribution from PG&E Corporation. The net purchase price has been allocated as follows: (1) electric generating assets of $2.3 billion, (2) receivable for support payments of $0.8 billion, and (3) contractual obligations of $1.3 billion. As part of the New England electric industry restructuring, the local utility companies providing service to retail customers were required to offer Standard Offer Service (SOS) to their customers. Retail customers may select alternative suppliers at any time. The SOS is intended to provide customers with a price benefit (the commodity electric price offered to the retail customer is expected to be less than the market price) for the first several years, followed by a price disincentive that is intended to stimulate the retail market. Retail customers may continue to receive SOS through June 30, 2002, in New Hampshire (subject to early termination on December 31, 2000, at the discretion of the New Hampshire Public Service Commission), through December 31, 2004, in Massachusetts, and through December 31, 2009, in Rhode Island. However, if any customers elect to have their electricity provided by an alternate supplier, they are precluded from going back to the SOS. 24 In connection with the purchase of the generation assets, we entered into agreements to supply the electric capacity and energy requirements necessary for NEES to meet its SOS obligations. NEES is responsible for passing on to us the revenues generated from the SOS. Like California utilities, the New England utilities entered into agreements with unregulated companies to provide energy and capacity at prices which are anticipated to be in excess of market prices. We assumed NEES's contractual rights and duties under several of these power-purchase agreements, which in aggregate provide for 800 MW of capacity. However, NEES will make support payments to us toward the cost of these agreements. The support payments by NEES total $1.1 billion in the aggregate (undiscounted) and are due in monthly installments from September 1998 through January 2008. In certain circumstances, with our consent, NEES may make a full or partial lump sum accelerated payment. Initially, approximately 90 percent of the acquired operating capacity, including capacity and energy generated by other companies and provided to us under power-purchase agreements, is dedicated to providing services to customers receiving SOS. Regulatory Matters The Utility is the only subsidiary with significant regulatory activity at this time. Items affecting future Utility authorized revenues include: the 1999 general rate case, the 1999 cost of capital proceeding, the distribution performance based ratemaking application, and the CPUC's gas strategy order instituting rulemaking. These items are discussed below. Any requested change in authorized revenues resulting from any of these proceedings would not impact the Utility's customer electric rates through the transition period because these rates are frozen in accordance with the electric transition plan. However, the amount of remaining revenues providing for the recovery of transition costs would be affected. The Utility's 1999 General Rate Case (GRC): In December 1997, the Utility filed its 1999 GRC application with the CPUC. During the GRC process, the CPUC examines the Utility's distribution costs to determine the amount we can charge customers. The Utility has requested rate increases to maintain and improve gas and electric distribution reliability, safety, and customer service. The requested revenues, as updated, include an increase of $445 million in electric base revenues and an increase of $377 million in gas base revenues over authorized 1998 revenues. The Office of Ratepayer Advocates (ORA) branch of the CPUC has recommended a decrease of $80 million in electric revenues and an increase of $104 million in gas base revenues. However, recommendations by the ORA do not represent the positions of the CPUC. In December 1998, the CPUC issued a decision on interim rate relief in the GRC. The decision granted the Utility's request to increase its electric revenues by $445 million and its gas revenues by $377 million on an interim basis pending a decision in the GRC. The decision allows the Utility to reflect the revenue increases, resulting from the Utility request, in regulatory assets recorded under regulatory adjustment mechanisms approved by the CPUC. The decision does not increase any electric or gas rates charged to customers on an interim basis. The regulatory assets will be adjusted to reflect the final decision of the CPUC in the 1999 GRC when the decision is issued. We cannot predict the amount of revenue increase or decrease the CPUC ultimately will approve. If the CPUC issues an unfavorable decision for the Utility, the ability of the Utility to earn its authorized rate of return, at the current service levels, for the years 1999 through 2001 could be adversely affected. The current procedural schedule provides for a final CPUC decision in March 1999. The 1999 GRC will not affect the authorized revenues of electric and gas transmission services or gas storage services. The authorized revenues for gas transmission and storage services are determined through the Gas Accord and electric transmission revenues are determined by the FERC as described below. Electric Transmission: Since April 1, 1998, all electric transmission revenues are authorized by the FERC. In December 1997, the FERC issued an order which put into effect, subject to refund, rates to recover annual electric transmission revenues of $301 million from the Utility's former 25 MANAGEMENT'S DISCUSSION AND ANALYSIS bundled rate transmission customers. These rates became effective on April 1, 1998, the operational date of the ISO and PX. In May 1998, the FERC allowed a $30 million increase in electric transmission revenues, effective October 30, 1998, also subject to refund. The Utility's 1999 Cost of Capital Proceeding: The Utility filed its cost of capital application in May 1998. If approved, the authorized return on rate base for distribution assets would be 9.53 percent. The 1999 cost of common equity would be 12.1 percent which is higher than the 11.2 percent authorized in 1998. This request would result in an increase of $49.7 million in electric distribution revenues and an increase of $15.5 million in gas distribution revenues over authorized 1998 revenues. The ORA has recommended an overall return on rate base for electric and gas distribution operations of 7.85 and 8.17 percent, respectively, and a cost of common equity of 8.64 and 9.32 percent, respectively. If adopted, the ORA's recommendation would result in a decrease from authorized 1998 revenues in electric and gas distribution revenues of $162.5 million and $37.8 million, respectively. However, recommendations by the ORA do not represent the positions of the CPUC. We expect a final CPUC decision in early 1999. The Utility's Distribution Performance Based Ratemaking (PBR) Application: The Utility filed its distribution PBR proposal in November 1998. If approved as filed, the distribution PBR will determine the Utility's gas and electric distribution revenues for the years 2000 through 2004. Under the Utility's proposal, distribution revenues for the year 2000 would be determined by multiplying total distribution revenues by a rate formula, based principally on inflation less a proposed productivity factor of 1.1 percent and 0.82 percent for electric distribution and gas distribution, respectively. These productivity factors will be fixed for the five year duration of the PBR. The revenues for years 2000 through 2004 would be determined by multiplying total distribution revenues by the PBR authorized rate. We have proposed different formulas for small customers (principally residential and commercial customers) and large customers. The proposal also includes a sharing mechanism for earnings that are significantly above or below the authorized weighted average cost of capital. In addition, the proposed PBR includes rewards and penalties that will depend upon the Utility's ability to achieve performance standards for electric distribution reliability; maintenance, repair, and replacement; customer service; and employee safety. The Commission will have hearings in the PBR proceeding in August 1999 to determine adopted values for the PBR formula and sharing parameters. The final schedule is uncertain, but a Commission decision is expected after January 1, 2000. In this event, the Utility proposes to implement the PBR-based distribution component rates retroactively to January 1, 2000. The CPUC's Gas Strategy Order Instituting Rulemaking (OIR): In 1998, the Governor of California signed Senate Bill 1602, allowing the CPUC to investigate issues associated with the further restructuring of natural gas services. If the CPUC determines that further restructuring for core customers is in the public interest, it shall submit its findings to the Legislature. However, Senate Bill 1602 prohibits the CPUC from enacting any such gas industry restructuring decisions prior to January 1, 2000. The CPUC's Audit of Affiliate Transactions: PG&E Corporation became the holding company of the Utility in 1997. At that time, we transferred the unregulated subsidiaries of the Utility to PG&E Corporation. A condition of the CPUC's approval of the holding company formation was that the ORA oversee an audit of transactions between the Utility and its affiliates for the period 1994 to 1996. The audit was completed in November 1997. The principal claim in the resulting audit report, substantially denied by the Utility, was that the Utility underbilled affiliates by $35 million during the period from 1994 to 1996. The auditors recommended the CPUC impose new conditions, affecting the financing and business structure of PG&E Corporation. We are opposing the recommended new conditions. A final CPUC decision is expected during the first quarter of 1999. 26 If the CPUC imposed the recommended financial conditions on PG&E Corporation without modification, such conditions could have an adverse impact on our ability to implement our national energy strategy. The Diablo Canyon Sunk Costs Audit: In August 1998, an independent accounting firm retained by the CPUC completed a financial verification audit of the Utility's Diablo Canyon plant accounts as of December 31, 1996. The audit resulted in the issuance of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. (Sunk costs are costs associated with Utility-owned generating facilities that are fixed and unavoidable and currently included in the Utility customers' electric rates.) The independent accounting firm also issued an agreed-upon special procedures report which questioned $200 million of the $3.3 billion sunk costs. The CPUC will review any proposed adjustments to Diablo Canyon's recoverable costs, which resulted from the report. At this time, the Utility cannot predict what actions, if any, the CPUC may take regarding the audit report. Results of Operations In this section, we present the components of our results of operations for 1998, 1997, and 1996. The table below shows for 1998, 1997, and 1996, certain items from our Statement of Consolidated Income detailed by (1) Utility, (2) wholesale and (3) retail business operations of PG&E Corporation. (In the "Total" column, the table shows the combined results of operations for these three groups.) The information for PG&E Corporation (the "Total" column) excludes all transactions between its subsidiaries (such as the purchase of natural gas by the Utility from the unregulated business operations). Following this table we discuss earnings and explain why the components of our results of operations varied from the year before for 1998 and 1997.
Wholesale Retail ---------------------------------- ------ PG&E GT ------------- (In millions) Utility USGen NW Texas PG&E ET PG&E ES Corp./Other Eliminations Total ------- ----- -- ----- ------- ------- ----------- ------------ ----- 1998 Operating revenues $8,924 $649 $237 $1,941 $8,509 $379 $ 8 $(705) $19,942 Operating expenses 7,048 489 101 1,996 8,528 470 3 (700) 17,935 ------ ---- ---- ------ ------ ---- ---- ----- ------- Operating income (loss) 1,876 160 136 (55) (19) (91) 5 (5) 2,007 Other income, net 64 Interest expense 782 Income taxes 570 ------ ---- ---- ------ ------ ---- ---- ----- ------- Net income $ 719 ======= 1997 Operating revenues $9,495 $148 $233 $1,004 $4,808 $145 $13 $(446) $15,400 Operating expenses 7,664 176 127 1,023 4,840 190 98 (446) 13,672 ------ ---- ---- ------ ------ ---- ---- ----- ------- Operating income (loss) 1,831 (28) 106 (19) (32) (45) (85) -- 1,728 Other income, net 201 Interest expense 665 Income taxes 548 ------ ---- ---- ------ ------ ---- ---- ----- ------- Net income $ 716 ======= 1996 Operating revenues $8,989 $105 $264 $ -- $ 283 $ -- $ 27 $ (58) $ 9,610 Operating expenses 7,179 118 136 -- 283 -- 56 (58) 7,714 ------ ---- ---- ------ ------ ---- ---- ----- ------- Operating income (loss) 1,810 (13) 128 -- -- -- (29) -- 1,896 Other income, net 13 Interest expense 632 Income taxes 555 ------ ---- ---- ------ ------ ---- ---- ----- ------- Net income $ 722 =======
27 MANAGEMENT'S DISCUSSION AND ANALYSIS Overall Results: PG&E Corporation: Net income increased to $719 million in 1998 from $716 million in 1997. The increase in 1998 net income was the result of a $279 million increase in operating income, net of lower returns on the Utility's generation assets. This increase was offset partially by increased interest costs for the Utility's rate reduction bonds and debt associated with the recent unregulated wholesale acquisitions of assets in Texas and New England. The operating income increase of $279 million was primarily due to the growth of our wholesale and retail operations which contributed $149 million of the increase. This operating income increase was achieved despite operating losses at PG&E ES and PG&E GTT. USGen contributed positively to operating income which includes income generated from its portfolio management activities. The operating losses at PG&EES reflect the continued start-up operations and the impact of the developing retail energy market. At PG&E GTT, the natural gas liquids operations have been adversely affected by the low price differential between natural gas liquids (NGLs) prices and the cost of natural gas, which is used to produce NGLs. In addition, low gas prices and a narrow spread in the price of gas transported across Texas have reduced PG&E GTT's transportation and gas sales. The 1998 net income also includes a loss on the sale of our Australian energy holdings. The sale represented a significant premium in Australian currency of PG&E Corporation's 1996 investment in the assets. However, there was a 22 percent currency devaluation of the Australian dollar against the U.S. dollar during the past two years. The net transaction resulted in a charge of approximately $23 million in the second quarter of 1998. (See Note 5 of Notes to Consolidated Financial Statements.) Net income decreased from $722 million in 1996 to $716 million in 1997. The 1997 net income includes charges of approximately $51 million associated with the write off of investments in power generation projects at USGen, which were offset by the gain realized on the sale of our interests in International Generation Company, Ltd. In April 1997, PG&E Enterprises, a wholly owned subsidiary of PG&E Corporation, sold its interest in International Generating Company, Ltd., which resulted in an after-tax gain of $120 million. Utility: Net income for the Utility decreased $39 million in 1998 from 1997 due to the reduced rate of return on generation assets and increased interest expense associated with the rate reduction bonds, discussed below. Net income for the Utility increased $13 million in 1997 from 1996. Net income for 1997 included a gain on the buy out of a long-term gas contract. The increase in 1997 is also related to the increase in revenues associated with electric transmission and distribution system reliability, discussed below. This increase is partially offset by the reduction in returns on the Utility's Diablo Canyon facility as required by electric industry restructuring legislation and spending for system reliability and safety. Operating Revenues: Utility: Utility operating revenues decreased $571 million in 1998 from 1997. This decrease is primarily due to: (1) a $410 million decrease for the 10 percent electric rate reduction provided to residential and small commercial customers, which was partially offset by $108 million of higher revenues due to increased consumption of electricity by these customers; (2) a $151 million decrease in revenues from medium and large electric customers, many of whom are now purchasing their electricity directly from unregulated power generators; (3) a $63 million decrease in sales to commercial and agricultural electric customers resulting from their lower demand for irrigation water pumping as a result of heavier rainfall in the current year; and (4) a $100 million decrease for the termination of the volumetric (ERAM) and energy cost (ECAC) revenue balancing accounts. The ERAM and ECAC accounts were replaced with the transition cost balancing account, which affects expenses, rather than revenues. Utility operating revenues in 1997 increased $506 million from 1996. The largest portion of the increase was due to electric transition cost recovery, which began January 1, 1997, with respect to Diablo Canyon. A portion of the increase is due to increased revenues 28 associated with electric transmission and distribution system reliability. There was also an increase in energy cost revenues to recover energy cost increases and changes in sales volumes provided by the Utility's balancing account mechanisms in place in 1997 and 1996. Under these mechanisms, energy revenues generally equal energy costs and, thus, increases in the cost of energy do not affect operating income. Wholesale Unregulated Business Operations: Operating revenues associated with wholesale unregulated business operations increased $5,143 million in 1998 from 1997. This was primarily due to revenue increases of $3,701 million from PG&E ET, $937 million from PG&E GTT and $501 million from USGen. Energy trading volumes grew at PG&E ET as growth of PG&E Corporation and deregulation of the energy markets continued. PG&E GTT's revenues increased as a result of twelve months of revenue from the Texas acquisitions versus seven months in 1997. USGen's revenue increased as a result of an increase in the portfolio management activity and the acquisition of NEES in 1998. Operating revenues associated with wholesale unregulated business operations increased $5,541 million in 1997 from 1996. This was primarily due to a $4,525 million increase in energy commodities revenues and an increase in revenues resulting from our 1997 acquisitions. Retail Unregulated Business Operations: Retail unregulated business operations contributed $379 million of revenue in 1998, an increase of $234 million from 1997. This increase is primarily due to deregulation in California and the expansion of our energy services business in the electric and gas commodity markets. Operating revenues associated with retail unregulated business operations totaled $145 million in 1997, the first year of operation. Operating Expenses: Utility: Utility operating expenses in 1998 decreased $616 million from 1997. This decrease reflects a reduction in the amount of amortization of transition costs, primarily due to lower revenues from residential and small commercial customers discussed above in Operating Revenues-Utility. Also contributing to the decrease in operating expenses was a reduction in gas transportation demand charges of $134 million, due to the expiration of contracted pipeline capacity. Utility operating expenses in 1997 increased $485 million from 1996. The increase was due primarily to an increase in amortization of Diablo Canyon costs which are being recovered as a transition cost as discussed above, an increase in cost of energy, and an increase in expenditures associated with system reliability. These increases were partially offset by a decrease in expenses resulting from several charges in 1996 associated with gas transportation commitments and a litigation reserve. Wholesale Unregulated Business Operations: Operating expenses for our wholesale unregulated business operations increased $4,948 million in 1998 from 1997. This reflects the increase in the volumes of energy commodities purchased at PG&EETand operating costs associated with our newly acquired New England assets at USGen and the gas transportation assets at PG&E GTT. Wholesale unregulated business operations operating expenses in 1997 increased $5,629 million from 1996, which reflects the increase in the volume of energy commodities purchased due to our 1997 acquisitions. Retail Unregulated Business Operations: Retail unregulated business operations operating expenses increased $280 million in 1998 as compared to 1997. This increase is primarily due to the expansion of our energy services business. Retail unregulated business operations operating expenses totaled $190 million in 1997, the first year of operation. Other Income, Net: Other income, net was $64 million in 1998 as compared to $201 million in 1997. The decrease was primarily due to the $23 million loss on the sale of our Australian holdings, discussed above, and a $120 million gain recorded in 1997. 29 MANAGEMENT'S DISCUSSION AND ANALYSIS Other income, net increased by $188 million in 1997 as compared to 1996 primarily due to a $120 million gain realized on the sale of interests in International Generating Company, Ltd. Interest Expense: Interest expense increased $117 million in 1998 from 1997. This increase was primarily a result of increased interest costs for the Utility's rate reduction bonds and debt for the acquisition of the Texas and New England assets. Interest expense in 1997 increased $33 million from 1996 primarily due to interest costs related to the Texas acquisitions. Income Taxes: Income taxes in 1998 increased $22 million from 1997. The overall effective tax rate increased 0.9 percent in 1998 largely due to accelerated book depreciation and amortization related to electric industry restructuring. These increases were partially offset by a lowered effective state tax rate resulting from our expanded business operations. The effective tax rate decreased slightly in 1997 as compared to 1996, resulting in a $7 million decrease in 1997 taxes. Common Stock Dividend: We base our common stock dividend on a number of financial considerations, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk. Our current quarterly common stock dividend is $.30 per common share, which corresponds to an annualized dividend of $1.20 per common share. We continually review the level of our common stock dividend taking into consideration the impact of the changing regulatory environment throughout the nation, the resolution of asset dispositions, the operating performance of our business units, and our capital and financial resources in general. The CPUC requires the Utility to maintain its CPUC-authorized capital structure, potentially limiting the amount of dividends the Utility may pay PG&E Corporation. In 1998, the Utility was in compliance with its CPUC-authorized capital structure. PG&E Corporation and the Utility believe that the Utility will continue to meet this requirement in the future without affecting PG&E Corporation's ability to pay common stock dividends. Liquidity and Financial Resources Cash Flows from Operating Activities: Net cash provided by PG&E Corporation's operating activities totaled $2.3 billion, $2.6 billion, and $2.6 billion in 1998, 1997, and 1996, respectively. Net cash provided by the Utility's operating activities totaled $2.6 billion, $1.8 billion, and $2.6 billion in 1998, 1997, and 1996, respectively. Cash Flows from Financing Activities: PG&E Corporation: We fund investing activities from cash provided by operations after capital requirements and, to the extent necessary, external financing. Our policy is to finance our investments with a capital structure that minimizes financing costs, maintains financial flexibility, and, with regard to the Utility, complies with regulatory guidelines. Based on cash provided from operations and our investing and disposition activities, we may repurchase equity and long-term debt in order to manage the overall size and balance of our capital structure. During 1998, 1997, and 1996, we issued $63 million, $54 million, and $220 million of common stock, respectively, primarily through the Dividend Reinvestment Plan, the Stock Option Plan, and the Long-Term Incentive Plan. During 1997, we also issued $1.1 billion of common stock to acquire the natural gas assets in Texas. During 1998, 1997, and 1996, we paid dividends of $470 million, $524 million, and $844 million, respectively. During 1998, 1997, and 1996, we repurchased $1,158 million, $804 million, and $455 million, respectively, of our common stock. In February 1999, PG&E Corporation used the remaining portion of an existing authorization to repurchase 16.6 million shares at a price of $30.25 per share. In 1998, our unregulated business operations retired $75 million of long-term debt and retired the notes used in our acquisition of the Australian holdings. During 1997, our unregulated business operations issued $30 million and retired $109 million of long-term debt. Also in 1997, we assumed $780 million of 30 long-term debt in connection with the acquisition of the natural gas assets in Texas. In 1996, we entered into additional loan agreements of $92 million to finance the acquisition of our energy holdings in Australia. We maintain a number of credit facilities throughout our organization to support commercial paper programs, letters of credit, and other short term liquidity requirements. At PG&E Corporation, we maintain two $500 million revolving credit facilities, one of which expires in November 1999 and the other in 2002. The PG&E Corporation credit facilities are used to support the commerical paper program and other liquidity needs. The facility expiring in 1999 may be extended annually for additional one-year periods upon agreement between the lending institutions and us. There was $683 million of commercial paper outstanding at December 31, 1998. In September 1998, USGen obtained $1,675 million in revolving credit facilities. Of these, $575 million is specifically related to the New England operations. Of the New England facility, $475 million was used to execute a sale leaseback transaction related to the newly acquired New England assets and subsequently cancelled. No amounts are outstanding under the New England facilities at December 31, 1998. USGen, itself, maintains two credit facilities of $550 million each. One agreement expires in August 1999 and the other in 2003. These facilities were used in the acquisition of the New England assets and for general corporate purposes. The total amount outstanding at December 31, 1998, backed by the facilities, was $540 million in eurodollar loans and $233 million in commercial paper. Of these loans, $550 million is classified as noncurrent in the consolidated balance sheet. At December 31, 1998, PG&E GTT had $70 million of outstanding short-term bank borrowings related to two separate credit facilities. These lines are cancelable upon demand and bear interest at each respective bank's quoted money market rate. The borrowings are unsecured and unrestricted as to use. PG&E GT NW maintains a $200 million revolving credit facility which expires in the year 2000. At December 31, 1998 and 1997, PG&E GT NW had outstanding commercial paper balances of $104 million and $80 million, respectively, supported by this revolving facility. These balances were classified as noncurrent obligations in the consolidated balance sheet. Utility: In 1998, the Utility repurchased $1.6 billion of its common stock from PG&E Corporation to maintain its authorized capital structure. The Utility's long-term debt that either matured, was redeemed, or was repurchased during 1998 totaled $1.4 billion. Of this amount, (1) $249 million related to the Utility's redemption of its 8% mortgage bonds due October 1, 2025; (2) $252 million related to the Utility's repurchase of various other mortgage bonds; (3) $397 million related to the maturity of the Utility's 5 3\8% mortgage bonds; (4) $204 million related to the other scheduled maturities of long-term debt; and (5) $290 million related to rate reduction bonds maturing. In 1997 and 1996, the Utility redeemed or repurchased $225 million and $1,113 million, respectively, of long-term debt to manage the overall balance of its capital structure. In 1997, the Utility replaced $360 million of fixed interest rate pollution control bonds with the same amount of variable interest rate pollution control bonds. In 1996, the Utility replaced $988 million of variable interest rate and fixed interest rate pollution control mortgage bonds and loan agreements with the same amount of variable interest rate pollution control loan agreements. In 1998, the Utility redeemed its Series 7.44% preferred stock with a face value of $65 million and its Series 6 7\8% preferred stock with a face value of $43 million. During 1997 and 1996, the Utility did not redeem or repurchase any of its preferred stock. In December 1997, a subsidiary of the Utility issued $2.9 billion of rate reduction bonds through a special purpose entity established by the California Infrastructure and Economic Development Bank. The proceeds were used by the Utility to retire debt and reduce equity. (See Note 9 of Notes to Consolidated Financial Statements.) 31 MANAGEMENT'S DISCUSSION AND ANALYSIS The Utility maintains a $1 billion revolving credit facility, which expires in 2002. The Utility may extend the facility annually for additional one-year periods upon agreement with the banks. This facility is used to support the Utility's commercial paper program and other liquidity requirements. At December 31, 1998, the Utility had $567 million of commercial paper and $101 million of bank notes outstanding. No amounts were outstanding at December 31, 1997. Debt Obligations and Rate Reduction Bonds: The table below provides information about our debt obligations and rate reduction bonds at December 31, 1998:
Expected maturity date 1999 2000 2001 2002 2003 Thereafter Total - ---------------------- ---- ---- ---- ---- ---- ---------- ----- (dollars in millions) Utility: Long-term debt Variable rate obligations -- $200 $100 $738 $310 -- $1,348 Fixed rate obligations $260 $266 $274 $382 $372 $2,802 $4,356 Average interest rate 6.2% 6.6% 8.0% 7.8% 6.3% 7.1% 7.1% Rate reduction bonds $290 $290 $290 $290 $290 $1,161 $2,611 Average interest rate 6.1% 6.2% 6.2% 6.3% 6.4% 6.4% 6.3% ---- ---- ---- ---- ---- ------ ------ Wholesale and Retail Unregulated Business Operations: Long-term debt Variable rate obligations $ 7 $115 $ 12 $ 10 $560 $ 125 $ 829 Fixed rate obligations $ 71 $117 $ 94 $126 $ 46 $ 773 $1,227 Average interest rate 10.4% 9.1% 9.1% 8.7% 9.9% 8.2% 8.6% ---- ---- ---- ---- ---- ------ ------
Cash Flows from Investing Activities: The primary uses of cash for investing activities are additions to property, plant, and equipment; unregulated investments in partnerships; and acquisitions. The Utility's estimated capital spending for 1999 is $1.7 billion. Utility capital expenditures are based on estimates prepared for the Utility's GRC, but exclude capital expenditures for divested fossil and geothermal power plants. These estimates may be reduced if the CPUC authorized base revenues are significantly lower than those requested by the Utility in its GRC filing. In 1998, the Utility had proceeds of $501 million from the sale of three fossil-fueled generation plants. Also in 1998, PG&E Corporation sold its Australian energy holdings, for proceeds of approximately $126 million. In 1997, PG&E Corporation sold its interest in International Generating Company, Ltd., resulting in an after-tax gain of approximately $120 million. Also in 1998, the Utility agreed to sell three other fossil-fueled generation plants and to sell its complex of geothermal generation facilities. The winning bids total $1,014 million. As of December 31, 1998, these four plants had a combined book value of $523 million and had a combined capacity of 4,289 MW. The sales are subject to the approval of regulatory agencies, including the CPUC, and conditioned upon the transfer of various permits and licenses. The Utility expects to complete the sale of these four plants in 1999. Environmental Matters: We are subject to laws and regulations established to both maintain and improve the quality of the environment. Where our properties contain hazardous substances, these laws and regulations require us to remove those substances or remedy effects on the environment. At December 31, 1998, the Utility expects to spend $296 million over the next 30 years for cleanup costs at identified sites. If other responsible parties fail to pay or expected outcomes change, then these costs may be as much as $487 million. Of the $296 million, the Utility has recovered $104 million (including remediation of generation plants divested, discussed above) and expects to recover another $160 million in future rates. The Utility mitigates its cost by seeking recovery from insurance carriers and other third parties. (See Note 15 of Notes to Consolidated Financial Statements.) 32 The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. 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 estimated 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 expected outcomes change. Year 2000: The Year 2000 issue exists because many computer programs use only two digits to refer to a year, and were developed without considering the impact of the upcoming change in the century. If PG&E Corporation's computer systems fail or function incorrectly due to not being made Year 2000 ready, they could directly and adversely affect our ability to generate or deliver our products and services or could otherwise affect revenues, safety, or reliability for such a period of time as to lead to unrecoverable consequences. Our plan to address the Year 2000 issues focuses on mission-critical systems whose components are categorized as in-house software, vendor software, embedded systems, and computer hardware. The four phases of our plan to address these systems are inventory and assessment, remediation, testing, and certification. Certification occurs when mission-critical systems are formally determined to be Year 2000 ready. Our Year 2000 project is generally proceeding on schedule. The following table indicates our Year 2000 progress as of January 11, 1999. The percentages in this table reflect approximations based on a standardized reporting system that combines subsidiary results to provide a consistent, company-wide view. Year 2000 Readiness of Mission-Critical Items Remediation Testing Certification Complete Complete Complete ----------- -------- ------------- In-house software 94% 91% 11% Vendor software 53% 26% 2% Embedded systems 95% 91% 0% Computer hardware 92% 60% 0% Changes in company inventories, or issues uncovered in subsequent phases for an item previously reported as completed, may lead to downward adjustments in percentages from period to period. Also, the completion of these phases does not address external interdependencies that could affect the ability of the company to be Year 2000 ready. Even after systems are certified, we may continue various kinds of testing through the end of 1999. Although 91 percent of remediation and testing of embedded systems has been completed, the remaining 9 percent in this area may require some of the more challenging work. In addition to internal systems, we also depend upon external parties, including customers, suppliers, business partners, gas and electric system operators, government agencies, and financial institutions to support the functioning of our business. To the extent that any of these parties are considered mission-critical to our business and experience Year 2000 problems in their systems, our mission-critical business functions may be adversely affected. To deal with this vulnerability, we have another phased approach. The primary phases for dealing with external parties are: (1) inventory, (2) action planning, (3) risk assessment, and (4) contingency planning. We have completed our inventory and action planning phases for mission-critical external parties. We expect to complete the risk assessment by March 1999 and the contingency planning phase by July 1999. Although we expect our efforts and those of our external parties to be largely successful, we recognize that with the complex interaction of today's computing and communications systems, we cannot be certain we will be completely successful. Therefore, contingency plans for Year 2000 readiness are being developed and tested throughout 1999 to address our external dependencies as well as any significant schedule delays of mission-critical system work, should they occur. These plans will take into account possible interruptions of power, computing, financial, and communications infrastructures. Due to the speculative nature of contingency planning, however, it is uncertain whether these plans will be sufficient to remove the risk of material impacts on our operations resulting from Year 2000 problems. 33 MANAGEMENT'S DISCUSSION AND ANALYSIS In 1997 and through December 1998, we spent approximately $108 million to assess and remediate Year 2000 problems. About $64 million of this cost was for software systems that we replaced for business purposes generally unrelated to addressing Year 2000 readiness, but whose schedule we advanced to meet Year 2000 requirements. The replacement costs for these accelerated systems were capitalized. Our estimate of future costs to address mission-critical Year 2000 issues is approximately $140 million. About $60 million of these remaining Year 2000 costs will be capitalized because they relate to the purchase and installation of systems and equipment for general business purposes and the remaining $80 million will be expensed. Based on our current schedule for the completion of Year 2000 tasks, we expect to secure Year 2000 readiness of our mission-critical systems by the end of the third quarter of 1999. However, as our current schedule is partially dependent on the efforts of third parties, their delays may cause our schedule to change. If we, or third parties with whom we have significant business relationships, fail to achieve Year 2000 readiness of mission-critical systems, there could be a material adverse impact on the Utility's and PG&E Corporation's financial position, results of operations, and cash flows. Inflation: Financial statements, which are prepared in accordance with generally accepted accounting principles, report operating results in terms of historical costs and do not evaluate the impact of inflation. Inflation affects our construction costs, operating expenses, and interest charges. In addition, the Utility's electric revenues will not reflect the impact of inflation due to the current electric rate freeze. However, inflation at the levels currently being experienced is not expected to have a material adverse impact on the Utility's or our financial position or results of operations. Price Risk Management Activities: We have established a price risk management policy which allows derivatives to be used for both hedging and non-hedging purposes (a derivative is a contract whose value is dependent on or derived from the value of some underlying asset). We use derivatives for hedging purposes primarily to offset underlying commodity price risks. We also participate in markets using derivatives to gather market intelligence, create liquidity, and maintain a market presence. Such derivatives include forward contracts, futures, swaps, and options. Net open positions often exist or are established due to PG&E Corporation's assessment of its response to changing market conditions. To the extent that PG&E Corporation has an open position, it is exposed to the risk that fluctuating market prices may adversely impact its financial results. Our price risk management policy and the trading and risk management policies of our subsidiaries prohibit the use of derivatives whose payment formula includes a multiple of some underlying asset. PG&E Corporation prepares a daily assessment of its portfolio market risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the size and probability of future potential losses. The quantification of market risk using value-at-risk provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of important assumptions including the selection of a confidence level for losses, volatility of prices, market liquidity, and a holding period. PG&E Corporation utilizes historical data for calculating the price volatility of PG&E Corporation's positions and how likely the prices of those positions will move together. The model includes all derivative and commodity investments for its trading portfolio and only derivative commodity investments for its hedging portfolio (but not the related underlying hedged position). PG&E Corporation expresses value-at-risk as a dollar amount of the potential loss in the fair value of its portfolio based on a 95 percent confidence level using a one-day liquidation period. Therefore, there is a 5 percent probability that a portfolio will incur a loss in one day greater than its value-at-risk. The value-at-risk is aggregated for PG&E Corporation as a whole by correlating the daily returns of the portfolios for natural gas, natural gas liquids, and power for the previous 22 trading days. PG&E Corporation's daily value-at-risk for commodity price sensitive derivative instruments as of December 31, 1998, is $6.2 million for trading activities and $0.2 million for non-trading activities. 34 Value-at-risk has several limitations as a measure of portfolio risk including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, inadequate indication of the exposure of a portfolio to extreme price movements, and the inability to address the risk resulting from intraday trading activities. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, which is required to be adopted in years beginning after June 15, 1999. The Statement permits early adoption as of the beginning of any fiscal quarter. PG&E Corporation expects to adopt the new Statement no later than January 1, 2000. The Statement will require PG&E Corporation to recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will be offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings or will be recognized in other comprehensive income until the hedged items are recognized in earnings. PG&E Corporation is currently evaluating what the effect of SFAS No. 133 will be on the earnings and financial position of PG&E Corporation. PG&E Corporation uses the mark-to-market method of accounting for its commodity trading and price risk management activities. In November 1998, the Emerging Issues Task Force of the Financial Accounting Standards Board released Issue 98-10, Accounting for Energy Trading and Risk Management Activities. This Issue states that all energy-related contracts entered into with the objective of generating profits on or from exposure to shifts or changes in market prices be marked to market with the gains and losses reflected in the income statement. The Task Force stipulates implementation for fiscal years beginning after December 15, 1998. PG&E Corporation does not believe that the effect of adoption of this standard on earnings or the financial position of PG&E Corporation will be material. Legal Matters: In the normal course of business, both the Utility and PG&E Corporation are named as parties in a number of claims and lawsuits. (See Note 15 of Notes to Consolidated Financial Statements for further discussion of significant pending legal matters.) 35 PG&E Corporation STATEMENT OF CONSOLIDATED INCOME (in millions, except per share amounts) Year ended December 31, ----------------------------- 1998 1997 1996 ------- ------- ------- Operating Revenues Utility $ 8,924 $ 9,495 $ 8,989 Energy commodities and services 11,018 5,905 621 ------- ------- ------- Total operating revenues 19,942 15,400 9,610 ------- ------- ------- Operating Expenses Cost of energy for utility 3,029 3,287 3,142 Cost of energy commodities and services 10,194 5,481 356 Operating and maintenance, net 3,103 3,052 2,994 Depreciation, amortization, and decommissioning 1,609 1,852 1,222 ------- ------- ------- Total operating expenses 17,935 13,672 7,714 ------- ------- ------- Operating Income 2,007 1,728 1,896 Interest expense, net (782) (665) (632) Other income, net 64 201 13 ------- ------- ------- Income Before Income Taxes 1,289 1,264 1,277 Income taxes 570 548 555 ------- ------- ------- Net Income $ 719 $ 716 $ 722 ======= ======= ======= Weighted Average Common Shares Outstanding 382 410 413 Earnings Per Common Share, Basic and Diluted $ 1.88 $ 1.75 $ 1.75 Dividends Declared Per Common Share $ 1.20 $ 1.20 $ 1.77 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 36 PG&E Corporation CONSOLIDATED BALANCE SHEET (in millions) Balance at December 31, 1998 1997 ---- ---- Assets Current Assets Cash and cash equivalents $ 286 $ 237 Short-term investments 55 1,160 Accounts receivable Customers, net 1,856 1,514 Regulatory balancing accounts -- 458 Energy marketing 507 830 Price risk management 1,416 500 Inventories and prepayments 835 626 -------- -------- Total current assets 4,955 5,325 Property, Plant, and Equipment Utility 23,996 23,764 Wholesale and retail unregulated business operations Electric generation 1,967 -- Gas transmission 3,347 3,415 Construction work in progress 407 492 Other 127 55 -------- -------- Total property, plant, and equipment (at original cost) 29,844 27,726 Accumulated depreciation and decommissioning (12,026) (11,617) -------- -------- Net property, plant, and equipment 17,818 16,109 Other Noncurrent Assets Regulatory assets 6,347 6,900 Nuclear decommissioning funds 1,172 1,024 Other 2,942 1,757 -------- -------- Total noncurrent assets 10,461 9,681 -------- -------- Total Assets $ 33,234 $ 31,115 ======== ======== 37 PG&E Corporation CONSOLIDATED BALANCE SHEET (in millions) Balance at December 31, 1998 1997 ---- ---- Liabilities and Equity Current Liabilities Short-term borrowings $ 1,644 $ 103 Current portion of long-term debt 338 659 Current portion of rate reduction bonds 290 290 Accounts payable Trade creditors 1,001 754 Other 443 466 Regulatory balancing accounts 79 -- Energy marketing 381 758 Accrued taxes 103 226 Price risk management 1,412 512 Other 1,064 893 ------- ------- Total current liabilities 6,755 4,661 Noncurrent Liabilities Long-term debt 7,422 7,659 Rate reduction bonds 2,321 2,611 Deferred income taxes 3,861 4,029 Deferred tax credits 283 339 Other 3,746 2,024 ------- ------- Total noncurrent liabilities 17,633 16,662 Preferred Stock of Subsidiaries 480 595 Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures 300 300 Common Stockholders' Equity Common stock, no par value, authorized 800,000,000 shares, issued and outstanding, 382,603,564 and 417,665,891 5,862 6,366 Reinvested earnings 2,204 2,531 ------- ------- Total common stockholders' equity 8,066 8,897 ------- ------- Commitments and Contingencies (Notes 1, 2, 3, 4, 5, 14, and 15) -- -- ------- ------- Total Liabilities and Stockholders' Equity $33,234 $31,115 ======= ======= The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement 38 PG&E Corporation STATEMENT OF CONSOLIDATED CASH FLOWS (in millions) For the year ended December 31, ------------------------------- 1998 1997 1996 ---- ---- ---- Cash Flows From Operating Activities Net income $ 719 $ 716 $ 722 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning 1,609 1,852 1,222 Deferred income taxes and tax credits-net (107) (159) (150) Other deferred charges and noncurrent liabilities 18 121 116 Loss (gain) on sale of assets 23 (120) -- Net effect of changes in operating assets and liabilities: Accounts receivable -- trade (342) (242) (70) Regulatory balancing accounts receivable 537 126 302 Inventories and prepayments (161) (4) 32 Price risk management assets and liabilities, net (16) 12 -- Accounts payable -- trade 247 210 217 Accrued taxes (123) (54) 36 Other working capital 199 (85) (6) Other-net (302) 245 160 ------- ------- ------- Net cash provided by operating activities 2,301 2,618 2,581 ------- ------- ------- Cash Flows From Investing Activities Capital expenditures (1,619) (1,822) (1,230) Acquisitions and investments in unregulated projects (1,779) (116) (229) Proceeds from sale of assets 1,106 146 -- Other-net 48 21 (120) ------- ------- ------- Net cash used by investing activities (2,244) (1,771) (1,579) ------- ------- ------- Cash Flows From Financing Activities Net borrowings (repayments) under credit facilities 2,115 (587) (115) Long-term debt issued -- 386 1,088 Long-term debt matured, redeemed, or repurchased (1,552) (961) (1,472) Proceeds from issuance of rate reduction bonds -- 2,881 -- Preferred stock redeemed or repurchased (108) -- -- Common stock issued 63 54 220 Common stock repurchased (1,158) (804) (455) Dividends paid (470) (524) (844) Other-net (3) (39) (14) ------- ------- ------- Net cash used by financing activities (1,113) 406 (1,592) ------- ------- ------- Net Change in Cash and Cash Equivalents (1,056) 1,253 (590) Cash and Cash Equivalents at January 1 1,397 144 734 ------- ------- ------- Cash and Cash Equivalents at December 31 $ 341 $ 1,397 $ 144 ======= ======= ======= Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 774 $ 624 $ 598 Income taxes 770 801 640 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 39 PG&E CORPORATION STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY
Total Additional Common Common Paid-in Reinvested Stock Stock Capital Earnings Equity ------ ---------- ---------- ------- (dollars in millions) BALANCE DECEMBER 31, 1995 $2,070 $ 3,716 $ 2,813 $ 8,599 ------ ------- ------- ------- Net income 722 722 Common stock issued (9,290,102 shares) 47 173 220 Common stock repurchased (19,811,396 shares) (99) (182) (174) (455) Cash dividends declared Common stock (729) (729) Other 3 4 7 ------ ------- ------- ------- BALANCE DECEMBER 31, 1996 2,018 3,710 2,636 8,364 ------ ------- ------- ------- Net income 716 716 Holding company formation 3,710 (3,710) -- Common stock issued (2,302,544 shares) 54 54 Acquisitions (45,683,005 shares) 1,069 1,069 Common stock repurchased (33,823,950 shares) (496) (308) (804) Cash dividends declared Common stock (485) (485) Other 11 (28) (17) ------ ------- ------- ------- BALANCE DECEMBER 31, 1997 6,366 -- 2,531 8,897 ------ ------- ------- ------- Net income 719 719 Common stock issued (2,028,303 shares) 63 63 Common stock repurchased (37,090,630 shares) (565) (593) (1,158) Cash dividends declared Common stock (466) (466) Other (2) 13 11 ------ ------- ------- ------- BALANCE DECEMBER 31, 1998 $5,862 $ -- $ 2,204 $ 8,066 ====== ======= ======= =======
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 40 Pacific Gas and Electric Company STATEMENT OF CONSOLIDATED INCOME
1998 1997 1996 -------- -------- -------- (in millions) Year ended December 31, Operating Revenues Electric utility $7,191 $7,691 $7,160 Gas utility 1,733 1,804 1,829 Energy commodities and services -- -- 621 ------ ------ ------ Total operating revenues 8,924 9,495 9,610 ------ ------ ------ Operating Expenses Cost of electric energy 2,321 2,501 2,261 Cost of gas 708 786 881 Cost of energy commodities and services -- -- 356 Operating and maintenance, net 2,581 2,629 2,994 Depreciation, amortization, and decommissioning 1,438 1,748 1,222 ------ ------ ------ Total operating expenses 7,048 7,664 7,714 ------ ------ ------ Operating Income 1,876 1,831 1,896 Interest expense, net (621) (570) (632) Other income, net 103 116 46 ------ ------ ------ Income Before Income Taxes 1,358 1,377 1,310 Income taxes 629 609 555 ------ ------ ------ Net Income 729 768 755 ------ ------ ------ Preferred dividend requirement 27 33 33 ------ ------ ------ Income Available for Common Stock $ 702 $ 735 $ 722 ====== ====== ======
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 41 PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET
1998 1997 -------- -------- (in millions) Balance at December 31, Assets Current Assets Cash and cash equivalents $ 73 $ 80 Short-term investments 17 1,143 Accounts receivable Customers, net 1,383 1,204 Regulatory balancing accounts -- 458 Related parties 14 459 Inventories Fuel oil and nuclear fuel 187 207 Gas stored underground 130 102 Materials and supplies 159 189 Prepayments 50 25 -------- -------- Total current assets 2,013 3,867 Property, Plant, and Equipment Electric 16,924 16,913 Gas 7,072 6,851 Construction work in progress 273 421 -------- -------- Total property, plant, and equipment (at original cost) 24,269 24,185 Accumulated depreciation and decommissioning (11,397) (11,134) -------- -------- Net property, plant, and equipment 12,872 13,051 Other Noncurrent Assets Regulatory assets 6,288 6,846 Nuclear decommissioning funds 1,172 1,024 Other 605 359 -------- -------- Total noncurrent assets 8,065 8,229 -------- -------- Total Assets $ 22,950 $ 25,147 ======== ========
42 PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET
1998 1997 -------- -------- (in millions) Balance at December 31, Liabilities and Equity Current Liabilities Short-term borrowings $ 668 $ -- Current portion of long-term debt 260 580 Current portion of rate reduction bonds 290 290 Accounts payable Trade creditors 718 441 Related parties 60 134 Regulatory balancing accounts 79 -- Other 374 424 Accrued taxes 2 229 Deferred income taxes 3 149 Other 558 527 ------- ------- Total current liabilities 3,012 2,774 Noncurrent Liabilities Long-term debt 5,444 6,218 Rate reduction bonds 2,321 2,611 Deferred income taxes 3,060 3,304 Deferred tax credits 283 338 Other 2,045 1,810 ------- ------- Total noncurrent liabilities 13,153 14,281 Preferred Stock With Mandatory Redemption Provisions 6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137 Company Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures 7.90%, 12,000,000 shares, due 2025 300 300 Stockholders' Equity Preferred stock without mandatory redemption provisions Nonredeemable -- 5% to 6%, outstanding 5,784,825 shares 145 145 Redeemable -- 4.36% to 7.04%, outstanding 5,973,456 shares 142 257 Common stock, $5 par value, authorized 800,000,000 shares; issued and outstanding, 341,353,455 and 403,504,292 1,707 2,018 Additional paid in capital 2,094 2,564 Reinvested earnings 2,260 2,671 ------- ------- Total stockholders' equity 6,348 7,655 Commitments and Contingencies (Notes 1, 2, 3, 4, 5, 14, and 15) -- -- ------- ------- Total Liabilities and Stockholders' Equity $22,950 $25,147 ======= =======
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 43 PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED CASH FLOWS
1998 1997 1996 -------- -------- -------- (in millions) For the year ended December 31, Cash Flows From Operating Activities Net income $ 729 $ 768 $ 755 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning 1,438 1,748 1,222 Deferred income taxes and tax credits-net (257) (182) (150) Other deferred charges and noncurrent liabilities 31 133 116 Net effect of changes in operating assets and liabilities: Accounts receivable 266 (582) (70) Regulatory balancing accounts receivable 537 126 302 Inventories and prepayments (3) 12 32 Accounts payable -- trade 203 (80) 217 Accrued taxes (227) (62) 36 Other working capital (50) (128) (6) Other-net (39) 15 127 ------- ------ ------- Net cash provided by operating activities 2,628 1,768 2,581 Cash Flows From Investing Activities Capital expenditures (1,382) (1,522) (1,230) Acquisitions and investments in unregulated projects -- -- (229) Proceeds from sale of generation assets 501 -- -- Other-net 22 (117) (120) ------- ------ ------- Net cash used by investing activities (859) (1,639) (1,579) ------- ------ ------- Cash Flows From Financing Activities Net borrowings (repayments) under credit facilities 668 (681) (115) Long-term debt issued -- 355 1,088 Long-term debt matured, redeemed, or repurchased (1,413) (852) (1,472) Proceeds from issuance of rate reduction bonds -- 2,881 -- Preferred stock redeemed (108) -- -- Common stock repurchased (1,600) -- -- Dividends paid (444) (739) (844) Other-net (5) (14) (249) ------- ------ ------- Net cash used by financing activities (2,902) 950 (1,592) Net Change in Cash and Cash Equivalents (1,133) 1,079 (590) Cash and Cash Equivalents at January 1 1,223 144 734 ------- ------ ------- Cash and Cash Equivalents at December 31 $ 90 $1,223 $ 144 ======= ====== ======= Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 600 $ 547 $ 598 Income taxes 1,115 841 640
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 44 PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY, PREFERRED STOCK, AND PREFERRED SECURITIES
Preferred Preferred Company Stock Stock Obligated Total Without With Mandatorily Additional Common Mandatory Mandatory Redeemable Common Paid-in Reinvested Stock Redemption Redemption Preferred (dollars in millions) Stock Capital Earnings Equity Provisions Provisions Securities - ------------------------------------------------------------------------------------------------------------------------------------ Balance December 31, 1995 $ 2,070 $3,716 $ 2,813 $ 8,599 $ 402 $137 $300 - ----------------------------------------------------------------------------------------------------------------------------------- Net income 755 755 Common stock issued (9,290,102 shares) 47 173 220 Common stock repurchased (19,811,396 shares) (99) (182) (174) (455) Cash dividends declared Preferred stock (33) (33) Common stock (729) (729) Other 3 4 7 - ----------------------------------------------------------------------------------------------------------------------------------- Balance December 31, 1996 2,018 3,710 2,636 8,364 402 137 300 - ----------------------------------------------------------------------------------------------------------------------------------- Net income 768 768 Holding company formation (1,146) (1,146) Cash dividends declared Preferred stock (33) (33) Common stock (699) (699) Other (1) (1) - ----------------------------------------------------------------------------------------------------------------------------------- Balance December 31, 1997 2,018 2,564 2,671 7,253 402 137 300 - ----------------------------------------------------------------------------------------------------------------------------------- Net income 729 729 Common stock repurchased (62,150,837 shares) (311) (481) (808) (1,600) Preferred stock redeemed (4,323,948 shares) (3) (3) (105) Cash dividends declared Preferred stock (28) (28) Common stock (300) (300) Other 11 (1) 10 (10) - ----------------------------------------------------------------------------------------------------------------------------------- Balance December 31, 1998 $ 1,707 $2,094 $ 2,260 $ 6,061 $ 287 $137 $300 ====================================================================================
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 45 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1: General Basis of Presentation: PG&E Corporation became the holding company of Pacific Gas and Electric Company (the Utility) on January 1, 1997. Prior to that time, the Utility was the predecessor of PG&E Corporation. Effective with PG&E Corporation's formation, the Utility's interests in its unregulated subsidiaries were transferred to PG&E Corporation. This is a combined annual report of PG&E Corporation and the Utility. Therefore, the Notes to Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation, the Utility, and PG&E Corporation's other wholly owned subsidiaries. The Utility's consolidated financial statements include its accounts as well as those of its wholly owned subsidiaries. PG&E Corporation and the Utility have identical 1996 consolidated financial statements because they represent the accounts of the Utility as predecessor of PG&E Corporation. All significant intercompany transactions have been eliminated from the consolidated financial statements. Certain amounts in the prior years' consolidated financial statements have been reclassified to conform to the 1998 presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets, and liabilities and the disclosure of contingencies. Actual results could differ from these estimates. Accounting principles utilized include those necessary for rate-regulated enterprises which reflect the ratemaking policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). Operations: PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. PG&E Corporation's businesses provide energy services throughout North America. PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company, provides natural gas and electric service to one of every 20 Americans. PG&E Corporation's four unregulated businesses provide a wide range of energy products and services through its wholesale and retail unregulated business operations. PG&E Corporation's wholesale unregulated business operations consist of U.S. Generating Company (USGen) which develops, builds, operates, owns, and manages power generation facilities that serve wholesale and industrial customers; PG&E Gas Transmission (PG&E GT) which operates approximately 9,000 miles of natural gas pipelines, natural gas storage facilities, and natural gas processing plants in the Pacific Northwest (PG&EGTNW) and Texas (PG&E GTT); and PG&E Ener gy Trading (PG&E ET) which purchases and resells energy commodities and related financial instruments in major North American markets, serving PG&E Corporation's other unregulated businesses, unaffiliated utilities, and large end-use customers. PG&E Corporation's retail unregulated business operations consist of PG&E Energy Services (PG&E ES) which provides competitively priced electricity, natural gas, and related services to lower overall energy costs for industrial, commercial, and institutional customers. Regulation and Statements of Financial Accounting Standards (SFAS) No. 71: The Utility is regulated by the CPUC, the FERC, and the Nuclear Regulatory Commission (NRC) among others. The gas transmission business in the Pacific Northwest is regulated by the FERC. The gas transmission business in Texas is regulated by the Texas Railroad Commission. PG&E Corporation and the Utility account for the financial effects of regulation in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement allows for the deferral as a regulatory asset costs that otherwise would have been expensed if it is probable that the costs will be recovered in future regulated revenues. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires PG&E Corporation and the Utility to write off regulatory assets when they are no longer probable of recovery. On an ongoing basis, PG&E Corporation and the Utility review their regulatory 46 assets and liabilities for the continued applicability of SFAS No. 71 and the effect of SFAS No. 121. Regulatory assets and liabilities are comprised of the following:
December 31, 1998 1997 - ------------------------------------------------------------------------------------------------------- (in millions) Utility: Generation-related transition costs/(1)/ $5,355 $5,964 Unamortized loss, net of gain, on reacquired debt 289 283 Regulatory assets for deferred income tax 293 253 Other (net) 351 346 - ------------------------------------------------------------------------------------------------------- Total Utility $6,288 $6,846 Wholesale 59 54 ------------- Regulatory assets $6,347 $6,900 ------------- Regulatory liabilities $526 $ 477 -------------
/(1)/ See Note 2 of Notes to Consolidated Financial Statements, for further discussion. Regulatory assets and liabilities are amortized over the period that the costs are reflected in regulated revenues. The majority of the Utility's regulatory assets are included in generation-related transition costs. The Utility is amortizing its eligible transition costs, including generation- related regulatory assets, over the transition period in conjunction with the available competitive transition charge (CTC) revenues. During 1998, regulatory assets related to electric utility restructuring decreased by $609 million. This decrease reflects the recovery of eligible transition costs of $486 million through accelerated amortization and $123 million through the gain on the sale of generating plants. Revenues and Regulatory Balancing Accounts: In connection with electric industry restructuring, use of the Utility's sales and energy cost balancing accounts for electric utility revenues has been discontinued in 1998. These balancing accounts have been replaced with regulatory adjustment mechanisms which impact expenses instead of revenues. (See Note 2.) For gas utility revenues, sales balancing accounts accumulate differences between authorized and actual base revenues. Further, gas cost balancing accounts accumulate differences between the actual cost of gas and the revenues designated for recovery of such costs. The regulatory balancing accounts accumulate balances until they are refunded to or received from Utility customers through authorized rate adjustments. Utility revenues included amounts for services rendered but unbilled at the end of each year. Accounting for Price Risk Management Activities: PG&E Corporation, primarily through its subsidiaries, engages in price risk management activities for both non-hedging and hedging purposes. PG&E Corporation conducts non-hedging activities principally through its unregulated subsidiary, PG&E ET. Derivative and other financial instruments associated with PG&E Corporation's electric power, natural gas, natural gas liquids, and related non-hedging activities are accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, PG&E Corpo-ration's non-hedging contracts, including both physical contracts and financial instruments, are recorded at market value, which approximates fair value. The market prices used to value these transactions reflect management's best estimates considering various factors including market quotes, time value, and volatility factors of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions. Changes in the market value of these contract portfolios, resulting primarily from newly originated transactions and the impact of commodity price and interest rate movements, are recognized in operating revenues in the period of change. Unrealized gains and losses of these contract portfolios are recorded as assets and liabilities, respectively, from price risk management. In addition to the non-hedging activities discussed above, PG&E Corporation may engage in hedging activities using futures, forward contracts, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies when there is a high degree of correlation between price movements in the derivative and the item designated as being hedged. PG&E Corporation accounts for hedge transactions under the deferral method. Initially, PG&E Corporation defers unrealized gains and losses on these transactions and classifies 47 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS them as assets or liabilities. When the hedged transaction occurs, PG&E Corporation recognizes the gain or loss in operating expense. In instances where the anticipated correlation of price movements does not occur, hedge accounting is terminated and future changes in the value of the derivative are recognized as gains or losses. If the hedged item is sold, the value of the associated derivative is recognized in income. For regulatory reasons, the Utility manages price risk independently from the activities in PG&E Corporation's unregulated business. In the first quarter of 1998, the CPUC granted approval for the Utility to use financial instruments to manage price volatility of gas purchased for the Utility's electric generation portfolio. The approval limits the Utility's outstanding financial instruments to $200 million, with downward adjustments occurring as the Utility divests its fossil-fueled generation plants. (See Utility Generation Divestiture, below.) Authority to use these risk management instruments ceases upon the full divestiture of fossil-fueled generation plants or at the end of the current electric rate freeze (see Rate Freeze and Rate Reduction, below), whichever comes first. In the second quarter of 1998, the CPUC granted conditional authority to the Utility to use natural gas-based financial instruments to manage the impact of natural gas prices on the cost of electricity purchased pursuant to existing power-purchase contracts. Under the authority granted in the CPUC decision, no natural gas-based financial instruments shall have an expiration date later than December 31, 2001. Further, if the rate freeze ends before December 31, 2001, the Utility shall net any outstanding financial instrument contracts through equal and opposite contracts, within a reasonable amount of time. Also during the fourth quarter, the CPUC granted conditional authority to the Utility to use natural gas-based financial instruments to manage price and revenue risks associated with its natural gas transmission and storage assets. Property, Plant, and Equipment: Plant additions and replacements are capitalized. The capitalized costs include labor, materials, construction overhead, and capitalized interest or an allowance for funds used during construction (AFUDC). AFUDC is the estimated cost of debt and equity funds used to finance regulated plant additions. The Utility recovers AFUDC in rates through depreciation expense over the useful life of the related asset. The original cost of retired plant and removal costs less salvage value is charged to accumulated depreciation upon retirement of plant in service for the Utility and the unregulated businesses that apply SFAS No. 71. For our wholesale and retail unregulated business operations, the cost and accumulated depreciation of property, plant, and equipment retired or otherwise disposed of are removed from related accounts and included in the determination of the gain or loss on disposition. Property, plant, and equipment is depreciated using a straight-line remaining-life method. PG&E Corporation's composite depreciation rates were 4.11 percent, 3.70 percent, and 3.37 percent for the years ended December 31, 1998, 1997, and 1996, respectively. The Utility's composite depreciation rates were 4.15 percent, 3.52 percent, and 3.37 percent for the years ended December 31, 1998, 1997, and 199 6, respectively. Gains and Losses on Reacquired Debt: Any gains and losses on reacquired debt associated with regulated operations that are subject to the provisions of SFAS No. 71 are deferred and amortized over the remaining original lives of the debt reacquired, consistent with ratemaking principles. Gains and losses on reacquired debt associated with unregulated operations are recognized in earnings at the time such debt is reacquired. Inventories: Inventories include material and supplies, gas stored underground, nuclear fuel, and fuel oil. Materials and supplies and gas stored underground are valued at average cost. Stored nuclear fuel inventory is stated at lower of average cost or market. Nuclear fuel in the reactor is amortized based on the amount of energy output. Fuel oil is valued by the last-in-first-out method. Cash Equivalents and Short-Term Investments: Cash equivalents (stated at cost, which approximates market) include working funds and consist primarily of eurodollar time deposits, bankers acceptances, and 48 some commercial paper with original maturities of three months or less. Income Taxes: PG&E Corporation uses the liability method of accounting for income taxes. Income tax expense includes current and deferred income taxes resulting from operations during the year. Tax credits are amortized over the life of the related property. PG&E Corporation files a consolidated federal income tax return that includes domestic subsidiaries in which its ownership is 80 percent or more. The Utility and various other subsidiaries are parties to a tax-sharing arrangement with PG&E Corporation. PG&E Corporation files consolidated state income tax returns when applicable. The Utility reports taxes on a stand-alone basis. Related Party Agreements: In accordance with various agreements, the Utility and other subsidiaries provide and receive various services from their parent, PG&E Corporation. Services include the Utility's provision of general and administrative services. The Utility and other subsidiaries receive general and administrative services and financing from PG&E Corporation. Corporate costs, such as administrative costs, interest, and income taxes, are allocated to subsidiaries using a variety of factors including their share of employees, operating expenses, assets, and other cost causal methods. Also, the Utility purchases gas transmission services from PG&EGTNW. Note 2: California Electric Industry Restructuring In 1998, California became one of the first states in the country to implement an electric industry restructuring plan. California electric industry restructuring has two major impacts on the financial statements. The two major components are the competitive market framework and the electric transition plan, which are discussed below. Competitive Market Framework: To create a competitive generation market, a Power Exchange (PX) and an Independent System Operator (ISO) began operating in 1998. The Utility is required to sell to the PX all of the electricity generated by its power plants and electricity acquired under contractual agreements with unregulated generators. Also, the Utility is required to buy from the PX all electricity needed to provide service to retail customers that continue to choose the Utility as their electricity supplier. The ISO schedules delivery of electricity for all market participants to the transmission system. The Utility continues to own and maintain a portion of the transmission system, but the ISO controls the operation of the system. For the year ended December 31, 1998, the cost of energy for the Utility, reflected on the Statement of Consolidated Income, is comprised of the cost of PX purchases, ancillary services (standby power and miscellaneous services) purchased from the ISO, cost of transmission, and the cost of Utility generation, net of sales to the PX as follows: For the year ended December 31, 1998 - ---------------------------------------------------------------------- (in millions) Cost of fuel for electric generation $2,030 Cost of purchases from the PX 723 Net cost of ancillary services 406 Proceeds from sales to the PX (838) - ---------------------------------------------------------------------- Cost of electric energy $2,321 - ---------------------------------------------------------------------- The Utility's cost of energy is recovered from retail customers under the terms of the restructuring plan. California Transition Plan: Market-based revenues determined by the market through sales to the PX may not be sufficient to recover (that is, to collect from customers) all of the Utility's generation costs. To allow California investor-owned utilities the opportunity to recover their transition costs (generation costs that would not be recovered through market-based revenues) and to ensure a smooth transition to a competitive market, the California legislature developed a transition plan in the form of state legislation that was passed in 1996. The transition plan will remain in effect until the earlier of December 31, 2001, or when the Utility has recovered its authorized transition costs as determined by the CPUC, with provisions that certain transition costs can be recovered after the transition period. At the conclusion of the transition period, the Utility will be at risk to recover any of its remaining generation costs through market-based revenues. The transition plan contains three principal elements 49 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS consisting of the determination of: (1) an electric rate freeze and rate reduction, (2) the recovery of transition costs, and (3) divestiture of utility- owned generation facilities. Each element is discussed below. * Rate Freeze and Rate Reduction: The first element of the transition plan is an electric rate freeze and an electric rate reduction. In 1997 and 1998, the Utility held rates for its larger customers at 1996 levels, and it will hold their rates at that level until the end of the transition period. On January 1, 1998, the Utility reduced electric rates for its residential and small commercial customers by 10 percent from 1996 levels, and it will hold their rates at that level until the end of the transition period. Collectively, these actions are called a rate freeze. To pay for the 10 percent rate reduction, the Utility refinanced $2.9 billion of its transition costs with the proceeds of rate reduction bonds. (See Note 9.) The bonds allow for the rate reduction by lowering the carrying cost on a portion of the transition costs and by deferring recovery of a portion of these transition costs until after the transition period. The frozen rates include a component for transition cost recovery. Transition costs are being recovered from all Utility distribution customers through a nonbypassable charge regardless of the customer's choice of electricity supplier. As the customer charge for transition costs is nonbypassable, the Utility does not believe that the availability of choice to its customers will have a material impact on its ability to recover transition costs. Revenues from frozen electric rates provide for the recovery of authorized Utility costs, including transmission and distribution service, public purpose programs, nuclear decommissioning, and rate reduction bond debt service. To the extent the revenues from frozen rates exceed authorized Utility costs, the remaining revenues constitute the CTC which recovers the transition costs. These CTC revenues are subject to seasonal fluctuations in the Utility's sales volumes and certain other factors. * Transition Cost Recovery: Transition costs consist of: (1) above-market sunk costs (sunk costs are costs associated with Utility-owned generation assets that are fixed and unavoidable and currently included in the Utility customers' electric rates) and future costs, such as costs related to plant removal of Utility-owned generation facilities, (2) costs associated with the Utility's long-term contracts to purchase power at above-market prices from qualifying facilities and other power suppliers, and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods to be included in rates in subsequent periods.) Above-market sunk costs result when the book value of a facility is in excess of its market value. Conversely, below-market sunk costs result when the market value of a facility is in excess of its book value. The total amount of generation facility costs to be included as transition costs will be based on the aggregate of above-market and below-market values. The above-market portion of these costs is eligible for recovery as a transition cost. The below-market portion of these costs will reduce other unrecovered transition costs. A valuation of a Utility-owned generation facility where the market value exceeds the book value could result in a material charge to Utility earnings if the valuation of the facility is determined based upon any method other than a sale of the facility to a third party. This is because any excess of market value over book value would be used to reduce other transition costs. The Utility will not be able to determine the exact amount of above-market non-nuclear sunk costs that will be recoverable as transition costs until a market valuation process (appraisal, spin, sale, or other valuation method) is completed for each of its generation facilities. Several of these valuations occurred in 1997 and 1998, when the Utility agreed to sell seven of its electric plants. The market value of these facilities determined by these sales exceeded the book value and will therefore reduce the amount of transition costs to be recovered. In addition, in December 1998, the Utility requested that the CPUC allow it to hire appraisers to set the value of its hydroelectric generation system. (See Generation Divestiture below.) The remainder of the valuation process is expected to be completed by December 31, 2001. Nuclear sunk costs were separately determined through a CPUC proceed- 50 ing and were subject to a final verification audit. This audit was completed in August 1998, the results of which are currently under review. The Utility has long-term contracts to purchase electric power at above- market prices. To the extent that individual contract prices are above market price, the Utility is collecting the difference between the contract price and the market price from customers, as a transition cost, over the term of the contract. The contracts expire at various dates through 2028. The total amount of the above-market costs under long-term contracts will be based on several variables, including the capacity factors of the related generating facilities and future market prices for electricity. During 1998, the average price paid per kilowatt hour (kWh) under the Utility's long-term contracts for electric power was 7.4 cents per kWh. The average cost of electric energy for energy purchased at market rates from the PX (a measure of market prices) for the period from April 1, 1998, to December 31, 1998, was 3.2 cents per kWh. Generation-related regulatory assets and obligations (net generation-related regulatory assets) are included as transition costs. These net regulatory assets consist of those created prior to the transition period and those created during the transition period. In 1998, the staff of the Securities and Exchange Commission (SEC)issued interpretive guidance related to assets which are being transitioned to a deregulated environment. The guidance states that an impairment analysis should be performed for such assets and that the impairment analysis should exclude transition cost revenues. Following this guidance, the Utility determined that $3.9 billion of its generation assets were impaired. The Utility has determined that certain of its generation facilities are considered impaired under the SEC interpretive guidance. Because the Utility expects to recover the impaired assets as a transition cost, it recorded a regulatory asset for the impaired amounts as required. As a result, in 1998, $3.9 billion was reclassified from property, plant, and equipment to regulatory assets on the Utility's balance sheet. Prior year amounts were also reclassified. The Utility's generation-related net regulatory assets total $5.4 billion at December 31, 1998. Under the transition plan, most transition costs can be recovered until December 31, 2001. This recovery period is significantly shorter than the recovery period of the generation assets prior to restructuring and is referred to as accelerated recovery. Accordingly, the Utility is amortizing its transition costs, including most generation-related regulatory assets over the transition period. The CPUC believes that the transition plan reduces risks associated with recovery of all the Utility's generation assets, including the Diablo Canyon Nuclear Power Plant (Diablo Canyon) and the hydroelectric facilities. As a result, during the transition period, the Utility is receiving a reduced return on common equity for all of its generation assets, including those generation assets reclassified to regulatory assets. In 1998, the reduced return on common equity was 6.77 percent as compared to an authorized return on common equity of 11.20 percent. The reduced return on common equity, related to generation assets, will be in effect throughout the transition period. Certain transition costs can be included in a non-bypassable charge to distribution customers after the transition period. These costs include: (1) certain employee-related transition costs, (2) above-market payments under existing long-term contracts to purchase power, discussed above, and (3) unrecovered electric industry restructuring implementation costs. In addition, transition costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds. Further, the Utility's nuclear decommissioning costs are being recovered through a CPUC-authorized charge, which will extend until sufficient funds exist to decommission our nuclear facility. During the rate freeze, this charge and the rate reduction bond debt service will not increase the Utility customers' electric rates. Excluding these exceptions, the Utility will write-off any transition costs not recovered during the transition period. Under the terms of the transition plan, revenues provided for the recovery of most non-nuclear transition costs are based upon the acceleration of such costs within the transition period. For nuclear transition costs, revenues provided for transition cost recovery are based on: (1) an established incremental cost incentive price per kWh generated by Diablo Canyon to recover certain ongoing costs and capital additions, and (2) the 51 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS accelerated recovery of the investment in Diablo Canyon from a period ending in 2016 to a five-year period ending December 31, 2001. The Utility is amortizing its eligible transition cost, including generation- related regulatory assets, over the transition period in conjunction with available CTC revenues. Effective January 1, 1998, the Utility started collecting these eligible transition costs through the nonbypassable CTC. During 1998, regulatory assets related to electric utility restructuring decreased by $609 million. This decrease reflects the recovery of eligible transition costs of $486 million through accelerated amortization and $123 million through the gain on the sale of generating plants. During the transition period, the CPUC will review the Utility's compliance with the accounting methods used by the Utility to recover transition costs and the amount of transition costs requested for recovery. The CPUC is currently reviewing non-nuclear transition costs amortized during the first six months of 1998. The Utility expects the CPUC to issue a decision regarding this review in the second half of 1999. Transition costs that are disallowed by the CPUC for collection from the Utility customers will be written off. In addition, in August 1998, an independent accounting firm retained by the CPUC completed its financial verification audit of the Utility's Diablo Canyon plant accounts at December 31, 1996. The audit resulted in the issuance of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. (Sunk costs are costs associated with Utility-owned generating facilities that are fixed and unavoidable and currently included in the Utility customers' electric rates.) The independent accounting firm also issued an agreed-upon special procedures report, requested by the CPUC, which questioned $200 million of the $3.3 billion sunk costs. The CPUC will review any proposed adjustments to Diablo Canyon's recoverable costs, which resulted from the report. At this time, the Utility cannot predict what actions, if any, the CPUC may take regarding the audit report. * Generation Divestiture: In 1998, the Utility completed the sale of three fossil-fueled generation plants for $501 million. These three fossil-fueled plants had a combined book value at the time of the sale of $346 million and had a combined capacity of 2,645 megawatts (MW). Also in 1998, the Utility agreed to sell three other fossil-fueled generation plants and its complex of geothermal generation facilities. The winning bids total $1,014 million. As of December 31, 1998, these four plants had a combined book value of $523 million and had a combined capacity of 4,289 MW. The sales are subject to the approval of regulatory agencies, including the CPUC, and conditioned upon the transfer of various permits and licenses. The Utility expects to complete the sale of these four plants in 1999. The Utility will retain a liability for required environmental remediation related to all of its fossil-fueled generation and geothermal plants of any pre- closing soil or groundwater contamination at the plants it has or will sell. The Utility records its estimated liability for the retained environmental remediation obligation as part of the determination of the gain or loss on the sale of each plant. Any net gains from the sale of the Utility-owned generation plants will be used to offset other transition costs. As a result, PG&E Corporation does not believe sales of any generation facilities to a third party will have a material impact on its results of operations. The Utility is currently evaluating its options related to its remaining non- nuclear generation facilities, primarily the hydroelectric generation system. In May 1998, the Utility notified the CPUC that it does not plan to retain the hydroelectric generation assets as part of the Utility. In December 1998, the Utility filed with the CPUC its proposed appraisal process for valuing generation assets, primarily the hydroelectric facilities. The Utility expects to receive a response to this request in 1999. At December 31, 1998, the book value of the Utility's net investment in hydroelectric generation assets was $1.4 billion. If the Utility decides to dispose of the hydroelectric generation assets by any method other than a sale of the assets to a third party, a material charge could result to the extent that the market value of the assets exceeds their book value. The 52 market value of the hydroelectric assets is expected to exceed their book value by a material amount. Financial Impact of Transition Plan: The Utility's ability to continue recovering its transition costs will be dependent on several factors, including: (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs ultimately approved for recovery by the CPUC, (3) the market value of the remaining Utility-owned generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, (6) the extent to which the Utility's authorized revenues to recover distribution costs are increased or decreased, and (7) the market price of electricity. Given the current evaluation of these factors, PG&E Corporation believes that the Utility will recover its transition costs under the terms of the approved transition plan. However, a change in one or more of these factors could affect the probability of recovery of transition costs and result in a material charge. Note 3: Price Risk Management and Financial Instruments The following table is a summary of the contract or notional amounts and maturities of PG&E Corporation's contracts used for non-hedging activities related to commodity price risk management as of December 31, 1998. Short and as of December 31, 1998 are immaterial.
Maximum Natural Gas and Purchase Sale Term in Electricity Contracts (Long) (Short) Years - ------------------------------------------------------------------------------ (billions of MMBtu equivalents/(a)/) Non-Hedging Activities Swaps 6.12 5.94 8 Options 1.39 1.18 5 Futures 0.44 0.46 4 Forward Contracts 3.68 3.53 5 - ------------------------------------------------------------------------------
/(a)/ One MMBtu is equal to one million British thermal units. PG&E Corporation's electric power contracts, measured in megawatts, were converted to MMBtu equivalents using a conversion factor of 10 MMBtu's per 1 megawatt-hour.
Maximum Purchase Sale Term in Natural Gas Liquids Contracts (Long) (Short) Years - ------------------------------------------------------------------------------ (millions of barrels) Non-Hedging Activities Swaps 15.13 20.96 2 Options 19.24 17.69 1 Futures 24.16 25.18 1 Forward Contracts 5.01 5.29 2 - ------------------------------------------------------------------------------
Volumes shown for swaps represent notional volumes that are used to calculate amounts due under the agreements and do not represent volumes exchanged. Moreover, notional amounts are indicative only of the volume of activity and are not a measure of market risk. The following table discloses the estimated fair values of price risk management assets and liabilities as of December 31, 1998. PG&E Corporation's net gains and losses on swaps, options, futures, and forward contracts held during the year for non-hedging purposes were $69 million, $(49) million, $(63) million, and $101 million, respectively. The ending and average fair values and associated carrying amounts of derivative contracts used for hedging purposes are not material as of December 31, 1998.
Average Ending Fair Value Fair Value - ------------------------------------------------------------------------------ (in millions) Assets Non-Hedging Activities Swaps $ 494 $ 947 Options 121 154 Futures 115 150 Forward Contracts 342 499 - ------------------------------------------------------------------------------ Total $1,072 $1,750 -------------------------- Noncurrent portion 334 - ------------------------------------------------------------------------------ Current portion $1,416 -------------
53 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Average Ending Fair Value Fair Value - ---------------------------------------------------------------------------- (in millions) Liabilities Non-Hedging Activities Swaps $ 476 $ 908 Options 147 201 Futures 111 186 Forward Contracts 282 398 - ---------------------------------------------------------------------------- Total $1,016 $1,693 ------------------------- Noncurrent portion 281 - ---------------------------------------------------------------------------- Current portion $1,412 -----------
The impact of price risk management assets and liabilities on PG&E Corporation's results of operations for fiscal 1997 was immaterial. In valuing its electric power, natural gas, and natural gas liquids portfolios, PG&E Corporation considers a number of market risks and estimated costs and continuously monitors the valuation of identified risks and adjusts them based on present market conditions. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided herein are not necessarily indicative of the amounts that PG&E Corporation could realize in the current market. Generally, exchange-traded futures contracts require deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. Margin cash requirements for over-the-counter financial instruments are specified by the particular instrument and often do not require margin cash and are settled monthly. Both exchange-traded and over- the-counter options contracts require payment/receipt of an option premium at the inception of the contract. Margin cash for commodities futures and cash on deposit with counterparties was immaterial at December 31, 1998. Note 4: Concentrations of Market and Credit Risk Market Risk: Market risk is the risk that changes in market prices will adversely effect earnings and cash flows. PG&E Corporation is primarily exposed to the market risk associated with energy commodities such as electric power, natural gas, and natural gas liquids. Therefore, PG&E Corporation's price risk management activities primarily involve buying and selling fixed price commodity commitments into the future. Net open positions often exist or are established due to PG&E Corporation's assessment of and response to changing market conditions. To the extent that PG&E Corporation has an open position, it is exposed to the risk that fluctuating market prices may adversely impact its financial results. Credit Risk: The use of financial instruments to manage the risks associated with changes in energy commodity prices creates exposure resulting from the possibility of nonperformance by counterparties pursuant to the terms of their contractual obligation. The counterparties in PG&E Corporation's portfolio consist primarily of investor owned and municipal utilities, energy trading companies, financial institutions, and oil and gas production companies. PG&E Corporation minimizes credit risk by dealing primarily with creditworthy counterparties in accordance with established credit approval practices and limits. PG&E Corporation routinely assesses the financial strength of its counterparties and may require letters of credit or parental guarantees when the financial strength of a counterparty is not considered sufficient. PG&E Corporation has experienced no material losses due to the nonperformance of counterparties in 1998. The credit exposure of the five largest counterparties comprised approximately $127 million of the total credit exposure associated with financial instruments used to manage price risk. Counterparties considered to be investment grade or higher comprise 71 percent of the total credit exposure. Note 5: Acquisitions and Sales In January 1997, PG&E Corporation acquired Teco Pipeline Company for $378 million, consisting of $317 million of PG&E Corporation common stock and the purchase of a $61 million note. In April 1997, through one of its wholly owned subsidiaries, PG&E Corporation sold its interest in International Generating Company, Ltd., which resulted in an after-tax gain of approximately $120 million. 54 In July 1997, PG&E Corporation completed its acquisition of Valero Energy Corporation's natural gas business and a gas marketing business located in Texas. PG&E Corporation issued approximately 31 million shares of its common stock to acquire Valero along with the assumption of $780 million in long-term debt, equating to a purchase price of approximately $1.5 billion. The acquisition was accounted for as a purchase and accordingly, the purchase price has been allocated to the assets acquired and the liabilities assumed based on estimated fair values. In September 1997, PG&E Corporation became the sole owner of USGen, an independent power developer and manager; U.S. Operating Services Company, USGen's operations and maintenance affiliate; and USGen Power Services, L.P., USGen's power marketing affiliate. Additionally, PG&E Corporation has acquired all or part of interest in several power projects that are affiliated with USGen. In July 1998, PG&E Corporation sold its Australian energy holdings. The sale represents a premium on the price in local currency of PG&E Corporation's 1996 investment in the assets. However, the transaction resulted in a non-recurring charge of $.06 per share in the second quarter of 1998. This charge was primarily due to the 22 percent currency devaluation of the Australian dollar against the U.S. dollar during the past two years. In September 1998, PG&E Corporation, through its indirect subsidiary USGen New England, Inc., completed the acquisition of a portfolio of electric generating assets and power supply contracts from the New England Electric System (NEES). The acquisition has been accounted for using the purchase method of accounting. Accordingly, the purchase price has been allocated to the assets purchased and the liabilities assumed based upon a preliminary assessment of the fair values at the date of acquisition. Including fuel and other inventories and transaction costs, PG&E Corporation's financing requirements were approximately $1.8 billion, funded through $1.3 billion of USGen debt and a $425 million equity contribution from PG&ECorporation. The net purchase price has been allocated as follows: (1) electric generating assets of $2.3 billion classified as property, plant, and equipment; (2) receivable for support payments of $0.8 billion; and (3)contractual obligations of $1.3 billion classified as current liabilities and other noncurrent liabilities. The NEES assets include hydroelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of 4,000 MW. In addition, USGen assumed 23 multi-year power-purchase agreements representing an additional 800 MW of production capacity. USGen entered into agreements with NEES as part of the acquisition, which: (1) provide that NEES shall make support payments over the next ten years to USGen for the purchase power agreements; and (2) require that USGen provide electricity to NEES under contracts that expire over the next six to eleven years. Note 6: Common Stock PG&E Corporation: PG&E Corporation has authorized 800 million shares of no-par common stock of which 382,603,564 and 417,665,891 shares were issued and outstanding as of December 31, 1998 and 1997, respectively. As of December 31, 1997, the Board of Directors had authorized the repurchase of up to $1.7 billion of PG&E Corporation's common stock on the open market or in negotiated transactions. As part of this authorization, in January 1998, PG&E Corporation repurchased in a specific transaction 37 million shares of common stock. As of December 31, 1998, approximately $570 million remains available under this repurchase authorization. In February 1999, PG&E Corporation used this remaining authorization to purchase 16.6 million shares at a price of $30.25 per share. In connection with this transaction, PG&E Corporation has entered into a forward contract with an investment institution. PG&E Corporation will retain the risk of increases and the benefit of decreases in the price of the common shares purchased through the forward contract. This obligation will not be terminated until the investment institution has replaced the shares sold to PG&E Corporation through purchases on the open market or through privately negotiated transactions. The contract is anticipated to expire by year-end. 55 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Utility: All of the Utility's stock outstanding is held by PG&E Corporation. In connection with the formation of the holding company, all of the Utility's common stock was converted on a share for share basis to PG&E Corporation common stock. The Utility has authorized 800 million shares of $5 par value common stock of which 341,353,455 and 403,504,292 shares are issued and outstanding at December 31, 1998 and 1997, respectively. The CPUC requires the Utility to maintain its CPUC-authorized capital structure, potentially limiting the amount of dividends the Utility may pay PG&E Corporation. In 1998, the Utility was in compliance with its CPUC-authorized capital structure. Note 7: Preferred Stock and Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures Preferred Stock: The Utility has authorized 75,000,000 shares of $25 par value preferred stock which may be issued as redeemable or nonredeemable preferred stock. At December 31, 1998 and 1997, the Utility has issued and outstanding 5,784,825 shares of nonredeemable preferred stock. At December 31, 1998 and 1997, the Utility has issued and outstanding 5,973,456 and 10,297,404 shares of redeemable preferred stock, respectively. The Utility's redeemable preferred stock is subject to redemption at the Utility's option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. Annual dividends and redemption prices per share at December 31, 1998, range from $1.09 to $1.76 and from $25.00 to $27.25, respectively. In 1998, the Utility redeemed its Series 7.44% preferred stock with a face value of $65 million. Also in 1998, the Utility redeemed its Series 6 7\8% preferred stock with a face value of $43 million. During 1997 and 1996, the Utility did not redeem or repurchase any of its preferred stock. The Utility's redeemable preferred stock with mandatory redemption provisions consists of 3 million shares of the 6.57% series and 2.5 million shares of the 6.30% series at December 31, 1998. The 6.57% series and 6.30% series may be redeemed at the Utility's option beginning in 2002 and 2004, respectively, at par value plus accumulated and unpaid dividends through the redemption date. These series of preferred stock are subject to mandatory redemption provisions entitling them to sinking funds providing for the retirement of stock outstanding. Holders of the Utility's nonredeemable preferred stock 5%, 5.5%, and 6% series have rights to annual dividends per share ranging from $1.25 to $1.50. Dividends on all preferred stock are cumulative. All shares of preferred stock have voting rights and equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The estimated fair value of the Utility's preferred stock with mandatory redemption provisions at December 31, 1998 and 1997, was $143 million and $146 million, respectively, based on quoted market prices. Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures: The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust), has outstanding 12 million shares of 7.90% cumulative quarterly income preferred securities (QUIPS), with an aggregate liquidation value of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to the Utility 371,135 shares of common securities with an aggregate liquidation value of $9 million. The Trust in turn used the net proceeds from the QUIPS offering and issuance of the common stock securities to purchase subordinated debentures issued by the Utility with a face value of $309 million, an interest rate of 7.9 percent, and a maturity date of 2025. These subordinated debentures are the only assets of the Trust. Proceeds from the sale of the subordinated debentures were used to redeem and repurchase higher-cost preferred stock. The Utility's guarantee of the QUIPS, considered together with the other obligations of the Utility with respect to the QUIPS, constitutes a full and unconditional guarantee by the Utility of the Trust's contractual obligations under the QUIPS issued by the Trust. 56 The subordinated debentures may be redeemed at the Utility's option beginning in 2000 at par value plus accrued interest through the redemption date. The proceeds of any redemption will be used by the Trust to redeem QUIPS in accordance with their terms. Upon liquidation or dissolution of the Utility, holders of these QUIPS would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment. The estimated fair value of the Utility's QUIPS at December 31, 1998 and 1997, was $303 million and $304 million, respectively, based on quoted market prices. Note 8: Long-Term Debt Long-term debt at December 31, 1998 and 1997, consisted of the following:
December 31, 1998 1997 (in millions) Utility long-term debt First and refunding mortgage bonds Maturity Interest rates 1999-2002 5.500% to 8.75% $ 682 $1,241 2003-2007 5.875% to 6.250% 902 974 2008-2020 6.35% to 8.02% 160 160 2021-2026 5.85% to 8.80% 2,117 2,498 - ----------------------------------------------------------------------- Principal amounts outstanding 3,861 4,873 Unamortized discount net of premium (32) (42) - ----------------------------------------------------------------------- Total mortgage bonds 3,829 4,831 Pollution control loan agreements, variable rates, due 2010-2026 1,348 1,348 Unsecured medium-term notes, 5.37% to 8.45%, due 1999-2014 498 587 Other Utility long-term debt 29 32 - ----------------------------------------------------------------------- Total Utility long-term debt 5,704 6,798 Current portion of long-term debt 260 580 - ----------------------------------------------------------------------- Total Utility long-term debt, net of current portion 5,444 6,218 Long-term debt of wholesale and retail unregulated business operations First mortgage notes 10.02% to 11.50%, due 1999-2009 370 409 Senior notes 10.58%, due 1999-2000 69 105 7.10%, due 2005 250 250 Medium term notes 6.61% to 9.29%, due 2000-2012 298 298 Senior debentures 7.80%, due 2025 148 148 Amounts outstanding under credit facilities (See Note 10) 654 80 Other long-term debt 267 230 - ----------------------------------------------------------------------- Total wholesale and retail unregulated business operations long-term debt 2,056 1,520 Current portion of long-term debt 78 79 - ----------------------------------------------------------------------- Long-term debt, net of current portion 1,978 1,441 - ----------------------------------------------------------------------- Total long-term debt $7,422 $7,659 ========================
Utility: * First and Refunding Mortgage Bonds: First and refunding mortgage bonds are issued in series and bear annual interest rates ranging from 5.50 percent to 8.80 percent. All real properties and 57 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS substantially all personal properties of the Utility are subject to the lien of the bonds, and the Utility is required to make semi-annual sinking fund payments for the retirement of the bonds. Additional bonds may be issued subject to CPUC approval, up to a maximum total amount outstanding of $10 billion assuming compliance with indenture covenants for earnings coverage and available property balances as security. The Utility redeemed or repurchased $501 million and $167 million of the bonds in 1998 and 1997, respectively, with interest rates ranging from 6.25 percent to 8.80 percent. These bonds were to mature from 2002 to 2026. Included in the total of outstanding bonds at December 31, 1998 and 1997, are $345 million of bonds held in trust for the California Pollution Control Financing Authority (CPCFA) with interest rates ranging from 5.85 percent to 6.625 percent and maturity dates ranging from 2009 to 2023. In addition to these bonds, the Utility holds long-term pollution control loan agreements with the CPCFA as described below. * Pollution Control Loan Agreements: Pollution control loan agreements from the CPCFA totaled $1,348 million at December 31, 1998 and 1997. Interest rates on the loans vary with average annual interest rates. For 1998 the interest rates ranged from 2.56 percent to 3.68 percent. These loans are subject to redemption by the holder under certain circumstances. These loans are primarily secured by irrevocable letters of credit which mature 2000 through 2003. Wholesale and Retail Unregulated Business Operations: Long-term debt of wholesale and retail unregulated business operations consists of first mortgage bonds and other secured and unsecured obligations. The first mortgage notes are comprised of three series due serially from 1999 to 2009, and are secured by mortgages and security interests in the natural gas transmission and natural gas processing facilities and other real and personal property of PG&E GTT. The mortgage indenture requires semi-annual payments with one-half of each interest payment and one-fourth of each annual principal payment escrowed quarterly in advance. The mortgage indenture also contains covenants which restrict the ability of PG&E GTT to incur additional indebtedness and precludes cash distributions if certain cash flow coverages are not met. Other long-term debt consists of project financing associated with unregulated generation facilities, premiums and other loans. Repayment Schedule: At December 31, 1998, PG&E Corporation's combined aggregate amounts of maturing long-term debt and sinking fund requirements, for the years 1999 through 2003, are $338 million, $698 million, $480 million, $1,256 million and $1,288 million, respectively. The Utility's share of those maturities and sinking fund requirements is $260 million, $466 million, $374 million, $1,120 million and $682 million, respectively. Fair Value: The estimated fair value of PG&E Corporation's total long-term debt at December 31, 1998 and 1997, was $8.1 billion and $8.3 billion, respectively. The estimated fair value of the Utility's total long-term debt at December 31, 1998 and 1997, was $6.0 billion and $7.0 billion, respectively. The estimated fair value of long-term debt was determined based on quoted market prices, where available. Where quoted market prices were not available, the estimated fair value was determined using other valuation techniques (for example, the present value of future cash flows). Note 9: Rate Reduction Bonds In December 1997, PG&E Funding LLC (SPE), a special-purpose entity wholly owned by the Utility, issued $2.9 billion of rate reduction bonds to the California Infrastructure and Economic Development Bank Special Purpose Trust PG&E-1 (Trust), a special-purpose entity. The terms of the bonds generally mirror the terms of the pass-through certificates issued by the Trust. The proceeds of the rate reduction bonds were used by the SPE to purchase from the Utility the right, known as "transition property," to be paid a specified amount from a nonbypassable tariff levied on residential and small commercial customers which was authorized by the CPUC pursuant to state legislation. 58 The rate reduction bonds have maturities ranging from ten months to ten years, and bear interest at rates ranging from 6.01 percent to 6.48 percent. The bonds are secured solely by the transition property and there is no recourse to the Utility or PG&E Corporation. At December 31, 1998, $2.6 billion of rate reduction bonds were outstanding. The combined expected principal payments on the rate reduction bonds for the years 1999 through 2003 are $290 million for each year. The estimated fair value of the rate reduction bonds was $2.6 billion at December 31, 1998. The estimated fair value of the bonds was determined based on quoted market prices. While the SPE is consolidated with the Utility for purposes of these financial statements, the SPE is legally separate from the Utility. The assets of the SPE are not available to creditors of the Utility or PG&E Corporation, and the transition property is legally not an asset of the Utility or PG&E Corporation. Note 10: Credit Facilities PG&E Corporation: At December 31, 1998 and 1997, PG&E Corporation had borrowed $2,298 million and $183 million, respectively, under various credit facilities discussed below. $654 million and $80 million of these borrowings December 31, 1998 and 1997, respectively are classified as long-term debt. (See Note 8.) The weighted average interest rate on the short-term borrowings was 5.6 percent and 6.9 percent for 1998 and 1997, respectively. The carrying amount of short-term borrowings approximates fair value. PG&E Corporation maintains two $500 million revolving credit facilities. One expires in November 1999 and the other in 2002. The facility expiring in November 1999 may be extended annually for additional one-year periods upon agreement between PG&E Corporation and the lending institutions. These credit facilities are used to support PG&E Corporation's commercial paper program and other liquidity needs. At December 31, 1998, PG&E Corporation had $683 million of commercial paperoutstanding supported by these facilities. No amounts were outstanding at December 31, 1997. 59 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Utility: The Utility maintains a $1 billion revolving credit facility which expires in 2002. The facility may be extended annually for additional one-year periods upon agreement between the Utility and the banks. At December 31, 1998, the Utility had $567 million of commercial paper outstanding and $101 million of bank notes outstanding. No amounts were outstanding at December 31, 1997. Wholesale and Retail Unregulated Business Operations: USGen has $1,675 million in revolving credit facilities, of which $575 million is specifically related to its New England operations. The $575 million line is comprised of a $100 million facility, expiring in 2003, and a $475 million facility, used to execute a sale leaseback transaction and subsequently cancelled. As of December 31, 1998, no amounts were outstanding under these facilities. The remaining facility is a $1.1 billion revolving credit agreement comprised of two $550 million facilities, one of which expires in 2003, and the other of which expires in August 1999. As of December 31, 1998, the long-term facility has a $540 million eurodollar loan drawn on it, and it also supports $10 million of outstanding commercial paper. Both are classified as noncurrent debt in the consolidated balance sheet. (See Note 8.) As of December 31, 1998, the short-term facility supported $223 million in outstanding commercial paper, which had a weighted average rate of 5.6 percent. PG&E GT NW maintains a $200 million revolving credit facility which expires in the year 2000. At December 31, 1998 and 1997, PG&E GT NW had outstanding commercial paper balances of $104 mil-lion and $80 million, respectively, supported by this revolving facility. These balances were classified as noncurrent debt in the consolidated balance sheet. (See Note 8.) PG&E GTThad $70 million and $100 million of outstanding short-term bank borrowings related to two separate credit facilities at December 31, 1998 and 1997, respectively. These lines are cancelable upon demand and bear interest at each respective bank's quoted money market rate. The borrowings are unsecured and unrestricted as to use. Note 11: Nuclear Decommissioning Decommissioning of the Utility's nuclear power plants is scheduled to begin in 2015 with scheduled completion in 2034. Nuclear decommissioning means to safely remove nuclear facilities from service and reduce 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 1997 site study, is $1.5 billion in 1998 dollars (or $5.1 billion in future dollars). This estimate assumes after-tax earnings on the tax-qualified and nontax-qualified decommissioning funds of 6.16 percent and 5.21 percent, respectively, as well as a future annual escalation rate of 5.5 percent for decommissioning costs. 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, and costs of labor, materials, and equipment. The estimated total obligation is being recognized proportionately over the license of each facility. For the years ended December 31, 1998, 1997, and 1996, nuclear decommissioning costs recovered in rates were $33 million per year, respectively. Based on the 1997 site study, the amount proposed to be recovered in rates in 1999 and annually, until the commencement of decommissioning, is $33 million. This amount is currently under review in the Utility's 1999 General Rate Case and will continue to be reviewed in future nuclear decommissioning cost triennial proceedings. At December 31, 1998, the total nuclear decommissioning obligation accrued was $1.2 billion and is included in the balance sheet classification of accumulated depreciation and decommissioning. Decommissioning costs recovered in rates are placed in external trust funds. These funds along with accumulated earnings will be used exclusively for decommissioning and cannot be released from the trust funds until authorized by the CPUC. The following table provides a summary of amortized cost and fair value, based on quoted market prices, of these nuclear decommissioning funds:
Year ended December 31, Maturity Dates 1998 1997 - ----------------------------------------------------------------------- (in millions) Amortized cost U.S. government and agency issues 1999-2028 $ 379 $ 422 Equity securities -- 246 257 Municipal bonds and other 1999-2030 164 70 Gross unrealized holding gains 394 287 Gross unrealized holding losses (11) (12) - ----------------------------------------------------------------------- Fair value (net, of tax) $1,172 $1,024 ===================
The proceeds received from sales of securities were $1.4 billion in each year in 1998 and 1997. The gross realized gains on sales of securities held as available-for-sale were $52 million and $40 million, in 1998 and 1997, respectively, and the gross realized losses on sales of securities held as available-for-sale were $39 million and $24 million, in 1998 and 1997, respectively. The cost of debt and equity securities sold is determined by specific identification. Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel. The Utility has signed a contract with the DOE to provide for the disposal of spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities. The DOE's current estimate for an available site to begin accepting physical possession of the spent nuclear fuel is 2010. 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 2006. It is likely that an interim or permanent DOE storage facility will not be available for Diablo Canyon's spent fuel by 2006. The Utility is examining options for providing additional temporary spent fuel storage at Diablo Canyon or other facilities, pending disposal or storage at a DOE facility. 60 Note 12: Employee Benefit Plans Several of PG&E Corporation's subsidiaries provide noncontributory defined benefit pension plans for their employees. In addition, these subsidiaries provide contributory defined benefit medical plans for certain retired employees and their eligible dependents and noncontributory defined benefit life insurance plans for certain retired employees (referred to collectively as other benefits). For both pension and other benefit plans, the Utility's plan represents substantially all of the plan assets and the benefit obligation. Therefore, all descriptions and assumptions are based on the Utility's plan. The schedules below aggregate all of PG&E Corporation's plans. The following schedule reconciles the plans' funded status (the difference between fair value of plan assets and the benefit obligation) to the prepaid or accrued benefit cost recorded on the consolidated balance sheet:
Pension Benefits Other Benefits ------------------ ------------------- December 31, 1998 1997 1998 1997 - ---------------------------------------------------------------------------------------------------------------------------------- (in millions) Change in benefit obligation Benefit obligation at January 1 $(4,457) $(4,231) $(907) $(921) Service cost for benefits earned (108) (102) (19) (22) Interest cost (334) (315) (64) (64) Plan amendments 1 (47) -- -- Special term benefits -- (11) -- (15) Actuarial gain (loss) (321) 16 (36) 63 Benefits and expenses paid 242 233 77 52 - -------------------------------------------------------------------------------------------------------------------------------- Benefit obligation at December 31 (4,977) (4,457) (949) (907) Change in plan assets Fair value of plan assets at January 1 6,419 5,526 823 669 Actual return on plan assets 919 1,139 173 144 Company contributions 27 2 18 48 Plan participant contribution -- -- 13 11 Benefits and expenses paid (261) (248) (76) (49) - -------------------------------------------------------------------------------------------------------------------------------- Fair value of plan assets at December 31 7,104 6,419 951 823 Plan assets in excess of benefit obligation 2,127 1,962 2 (84) (Benefit obligation in excess of plan assets) Unrecognized prior service cost 104 121 19 20 Unrecognized net loss (gain) (2,025) (2,133) (430) (375) Unrecognized net transition obligation 79 93 366 393 - -------------------------------------------------------------------------------------------------------------------------------- Prepaid (accrued) benefit cost $ 285 $ 43 $(43) $(46) =========================================
The Utility's share of the plan's assets in excess of the benefit obligation for pensions in 1998 and 1997 was $2,134 million and $2,003 million, respectively. The Utility's share of the prepaid (accrued) benefit cost for the pensions in 1998 and 1997 was $301 million and $60 million, respectively. The plan assets of the Utility exceeded its share of the benefit obligation for other benefits by $24 million in 1998. In 1997, the Utility's share of the benefit obligation in excess of the plan assets was $64 million. The Utility's share of the accrued benefit liability for other benefits in 1998 and 1997 was $26 million and $29 million, respectively. Unrecognized prior service costs and the net gains are amortized on a straight-line basis over the average remaining service period of active plan participants. The transition obligations for pension benefits and other benefits are being amortized over 17.5 years from 1987. Net benefit income (cost) was as follows: 61 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pension Benefits Other Benefits -------------------- -------------------- December 31, 1998 1997 1996 1998 1997 1996 - ----------------------------------------------------------------------------------------------- (in millions) Service cost for benefits earned $(108) $(102) $(101) $(19) $(21) $(22) Interest cost (333) (316) (304) (64) (64) (66) Expected return on assets 567 486 434 73 60 49 Amortized prior service and transition cost (26) (22) (23) (28) (28) (28) Actuarial gain (loss) recognized 114 74 43 22 13 4 - ------------------------------------------------------------------------------------------------ Benefit income (cost) $ 214 $120 $49 $(16) $(40) $(63) ========================================================
The Utility's share of the net benefit income for pensions in 1998, 1997, and 1996 was $215 million, $123 million, and $49 million, respectively. The Utility's share of the net benefit cost for other benefits in 1998, 1997, and 1996 was $12 million, $38 million, and $61 million, respectively. Net benefit income (cost) is calculated using expected return on plan assets of 9.0 percent. The difference between actual and expected return on plan assets is included in net amortization and deferral and is considered in the determination of future net benefit income (cost). In 1998, 1997, and 1996, actual return on plan assets exceeded expected return. In conformity with SFAS No. 71, regulatory adjustments have been recorded in the income statement and balance sheet of the Utility which reflect the difference between Utility pension income determined for accounting purposes and Utility pension income determined for ratemaking, which is based on a funding approach. The CPUC has also authorized the Utility to recover the costs associated with its other benefit plans for 1993 and beyond. Recovery is based on the lesser of the annual accounting costs or the annual contributions on a tax-deductible basis to the appropriate trusts. The following actuarial assumptions were used in determining the plans' funded status and net benefit income (cost). Year-end assumptions are used to compute funded status, while prior year-end assumptions are used to compute net benefit income (cost).
Pension Benefits Other Benefits ---------------------- ---------------------- December 31, 1998 1997 1996 1998 1997 1996 - -------------------------------------------------------------------------------- Discount rate 7.0% 7.5% 7.5% 7.0% 7.5% 7.5% Rate of future compensation increases 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% Expected long-term rate of return on plan assets 9.0% 9.0% 9.0% 9.0% 9.0% 9.0%
The assumed health care cost trend rate for 1999 is approximately 9.0 percent, grading down to an ultimate rate in 2005 of approximately 6.0 percent. The assumed health care cost trend rate can have a significant effect on the amounts reported for health care plans. A one percentage point change would have the following effects:
1-Percentage- 1-Percentage- (in millions) Point Increase Point Decrease - ---------------------------------------------------------------------------------------------------------------- Effect on total service and interest cost components $ 8 $ (7) Effect on postretirement benefit obligation $ 79 $(72)
Long-term Incentive Program: PG&E Corporation maintains a Long-term Incentive Program (Program) which provides for grants of stock options to eligible participants with or without associated stock appreciation rights and dividend equivalents. As of December 31, 1998, 24.5 million shares of common stock have been authorized for award under the program with 10,844,471 shares still available under this plan. At December 31, 1998, stock options on 11,225,564 shares, granted at option prices ranging from $21.125 to $34.25, were outstanding, of which 2,440,008 were exercisable. In 1998, 6,367,100 options were granted at an average option price of $30.52, for an approximate value of $24,258,651 using the Black-Scholes valuation method. Outstanding stock options expire ten years and one day after the date of grant and become exercisable on a 62 cumulative basis at one-third each year commencing two years from the date of grant. In 1998, 1997, and 1996, stock options on 710,271; 235,315; and 72,960 shares, respectively, were exercised at option prices ranging from $16.75 to $34.25. In addition, on January 4, 1999, PG&E Corporation granted 6,173,500 options at $30.9375, the then current market price. Note 13: Income Taxes The significant components of income tax expense were:
PG&E Corporation Utility -------------------- -------------------- Year ended December 31, 1998 1997 1996 1998 1997 1996 - ----------------------------------------------------------------------------------- (in millions) Current $677 $ 707 $ 705 $ 886 $ 791 $ 705 Deferred (52) (119) (132) (201) (142) (132) Tax credits-net (55) (40) (18) (56) (40) (18) - ----------------------------------------------------------------------------------- Total income tax expense $570 $ 548 $ 555 $ 629 $ 609 $ 555 =================================================
The significant components of net deferred income tax liabilities were:
PG&E Corporation Utility December 31, 1998 1997 1998 1997 - ----------------------------------------------------------------------------------------------------------------------------------- (in millions) Deferred income tax assets $ 1,219 $1,108 $ 843 $ 96 - ----------------------------------------------------------------------------------------------------------------------------------- Deferred income tax liabilities: Regulatory balancing accounts 43 311 40 311 Plant in service 3,722 3,621 2,930 3,144 Income tax regulatory asset 391 430 381 420 Other 968 924 555 540 - ----------------------------------------------------------------------------------------------------------------------------------- Total deferred income tax liabilities 5,124 5,286 3,906 4,415 - ----------------------------------------------------------------------------------------------------------------------------------- Total net deferred income taxes $3,905 $4,178 $3,063 $3,453 ======================================== Classification of net deferred income taxes: Included in current liabilities $ 44 $ 149 $ 3 $ 149 Included in noncurrent liabilities 3,861 4,029 3,060 3,304 Total net deferred income taxes $3,905 $4,178 $3,063 $3,453 ========================================
The differences between income taxes and amounts determined by applying the federal statutory rate to income before income tax expense were:
PG&E Corporation Utility --------------------------- ---------------------- Year ended December 31, 1998 1997 1996 1998 1997 1996 - ----------------------------------------------------------------------------------------------------------------------- Federal statutory income tax rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) 3.3 5.3 3.8 6.6 4.6 3.7 Effect of regulatory treatment of depreciation differences 10.4 8.1 6.0 9.8 7.5 5.9 Tax credits-net (4.3) (3.2) (1.4) (4.1) (2.9) (1.4) Effect of foreign earnings at different tax rate .6 (2.2) -- -- -- -- Other-net (.8) .3 -- (1.0) -- (.8) - ------------------------------------------------------------------------------------------------------------------------ Effective tax rate 44.2% 43.3% 43.4% 46.3% 44.2% 42.4% =========================================================
63 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Historically, the benefits of certain temporary differences have been utilized to reduce the Utility's customers rates. Accordingly, a regulatory asset has been recorded reflecting the pre-tax amount that will be recovered from customers as the temporary difference reverses. In connection with the California electric restructuring plan, the Utility is collecting the regulatory asset over four years. Note 14: Commitments Utility: * Letters of Credit: The Utility uses $385 million in standby letters of credit and surety bonds to secure future workers' compensation liabilities. * Restructuring Trust Guarantees: Tax-exempt restructuring trusts have been established to oversee the development of the operating framework for the competitive generation market in California. (See Note 2.) The CPUC has authorized California utilities to guarantee bank loans of up to $300 million to be used by the trusts for this purpose. Under this authorization, the Utility has guaranteed up to a maximum of $135 million of these loans. The bank loans will be repaid and the guarantees removed when the trusts obtain proceeds from permanent financing or rate recovery. * Power-Purchase Contracts: By federal law, the Utility is required to purchase electric energy and capacity provided by cogenerators and small power producers. The CPUC established a series of power-purchase contracts and set the applicable terms, conditions, price options, and eligibility requirements. Under these contracts, the Utility is required to make payments only when energy is supplied or when capacity commitments are met. The total cost of these payments is recoverable in rates. The Utility's contracts with these power producers expire on various dates through 2028. Total energy payments are expected to decline in the years 1999 through 2001. Total capacity payments are expected to remain at current levels during this period. Deliveries from these power producers account for approximately 23 percent of the Utility's 1998 electric energy requirements, and no single contract accounted for more than five percent of the Utility's energy needs. The Utility has negotiated early termination or suspension of certain power- purchase contracts. These amounts are expected to be recovered in rates and as such are reflected as deferred charges in the accompanying balance sheet. At December 31, 1998, the total discounted future payments remaining under early termination or suspension contracts is $48 million. 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. These costs are also recoverable in rates. At December 31, 1998, the undiscounted future minimum payments under these contracts are $32 million for each of the years 1999 through 2003 and a total of $280 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 7.5 percent of the Utility's 1998 electrict energy requirements. The amount of energy received and the total payments made under all of these power-purchase contracts were:
Year ended December 31, 1998 1997 1996 - ------------------------------------------------------------ (in millions) Kilowatt-hours received 25,994 24,389 26,056 Energy payments 943 1,157 1,136 Capacity payments 529 538 521 Irrigation district and water agency payments 53 56 52
* Natural Gas Transportation Commitments: The Utility has long-term gas transportation service contracts with various Canadian and interstate pipeline companies. For the duration of these contracts, the Utility has agreed to pay the pipeline companies an amount each year for capacity rights on their pipelines. The amount that the Utility pays each year varies due to changes in the rates of the pipeline companies. The 64 total amounts the Utility paid under these contracts were $113 million, $255 million, and $269 million in 1998, 1997, and 1996, respectively. These amounts include payments made by the Utility to PG&E GT of $49 million, $49 million, and $57 million in 1998, 1997, and 1996, respectively. The Utility's obligations related to capacity held pursuant to long-term contracts on various pipelines are as follows: - -------------------------------------------------------------------- (in millions) 1999 $102 2000 102 2001 99 2002 83 2003 83 Thereafter 188 - -------------------------------------------------------------------- Total $657 ======= As a result of regulatory changes, the Utility no longer procures gas for most of its industrial and larger commercial (noncore) customers, resulting in a decrease in the Utility's need for capacity on these pipelines. Despite these changes, the Utility continues to procure gas for substantially all of its residential and smaller commercial (core) customers and its noncore customers who choose bundled service. To the extent that the Utility's current capacity holdings exceed demand for gas transportation by its customers, the Utility will continue its efforts to broker such excess capacity. Wholesale and Retail Unregulated Business Operations: * Power-Purchase Contracts: As a part of the acquisition of a portfolio of electric generating assets and power supply contracts from NEES (See Note 5), NEES transferred to USGen contractual rights and duties under several power-purchase contracts with third- party independent power producers, which in the aggregate provide for approximately 800 MW of capacity. Under the transfer agreement, USGen is required to pay to NEES amounts due to the third-party power producers under the power-purchase contracts. USGen's payment obligations to NEES are reduced by NEES's monthly payment obligation, which equals, in the aggregate, approximately $1.1 billion, payable in monthly installments from September 1998 through January 2008. In certain circumstances, NEES, with the consent of USGen, will make a full or partial lump-sum accelerated payment of the monthly payment obligation to such party as USGen may direct. The approximate dollar obligations under these agreements are as follows: - -------------------------------------------------------------------- (in millions) 1999 $ 261 2000 272 2001 263 2002 238 2003 217 Thereafter 2,024 - -------------------------------------------------------------------- Total $3,275 ========= * Natural Gas Transportation Commitments: As a part of the acquisition of a portfolio of electric generating assets and power supply contracts from NEES (See Note 5), NEES transferred to USGen four natural gas purchase agreements with contract expirations ranging from October 2008 to October 2013, as well as eleven natural gas transportation contracts with contract expirations ranging from October 2006 to October 2014. The approximate dollar obligations under the natural gas transportation agreements are as follows: (in millions) 1999 $ 58 2000 58 2001 58 2002 58 2003 57 Thereafter 465 - -------------------------------------------------------------------- Total $754 ======== * Standard Offer Agreements: As a part of the acquisition of a portfolio of electric generating assets and power supply contracts from NEES (See Note 5), USGen entered into agreements to supply the electric capacity and energy necessary for NEES to meet its obligations to provide standard offer service. The agreements to provide standard offer service range in length from 6 to 11 years. The price per MW hour is standard for all agreements. The approximate dollar obligations under the agreements are as follows: 65 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - -------------------------------------------------------------------- (in millions) 1999 $ 788 2000 767 2001 712 2002 483 2003 345 Thereafter 302 - -------------------------------------------------------------------- Total $3,397 ========== Note 15: Contingencies Nuclear Insurance: The Utility has insurance for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). Under this insurance, if a nuclear generating facility suffers a loss due to a prolonged accidental outage, then the Utility may be subject to maximum retrospective assessments of $17 million (property damage) and $5 million (business interruption), in each case per policy period, in the event losses exceed the resources of NEIL. The Utility has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. The Utility has secondary financial protection which provides an additional $9.6 billion in coverage, which is mandated by federal legislation. It 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 $200 million, then 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. Environmental Remediation: The Utility may be required to pay for environmental remediation at sites where the Utility has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) or the California Hazardous Substance Account Act. These sites include former manufactured gas plant sites, power plant sites, and sites used by the Utility for the storage or disposal of potentially hazardous materials. Under CERCLA, the Utility may be responsible for remediation of hazardous substances even if the Utility did not deposit those substances on the site. The Utility records a liability when site assessments indicate remediation is probable and a range of reasonably likely cleanup costs can be estimated. 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. The remediation costs also reflect: (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) 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 lower end of this range. The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. 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 had an accrued liability of $296 million and $232 million at December 31, 1998 and 1997, respectively, for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants. Environmental remediation at identified sites may be as much as $487 million if, among other things, 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 estimated this 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 expected outcomes change. Of the $296 million liability, discussed above, the Utility has recovered $104 million and expects to recover another $160 million in future rates. Additionally, the Utility mitigates its cost by seeking recovery of its costs from insurance carriers and from other third parties as appropriate. Legal Matters: * Chromium Litigation: Several civil suits are pending against the Utility in California state courts. The suits seek an unspecified 66 amount of compensatory and punitive damages for alleged personal injuries and, in some cases, property damage, resulting from alleged exposure to chromium in the vicinity of the Utility's gas compressor stations at Hinkley, Kettleman, and Topock, California. Two of these suits also name PG&E Corporation as a defendant. Currently, there are claims pending on behalf of approximately 2,300 individuals. The Utility is responding to the suits and asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including statute of limitations or 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. PG&E Corporation believes that the ultimate outcome of these matters will not have a material impact on its or the Utility's financial position or results of operations. * Texas Franchise Fee Litigation: In connection with PG&E Corporation's acquisition of Valero Energy Corporation, now known as PG&E GTT, PG&E GTT succeeded to the litigation described below. PG&E GTT and various of its affiliates are defendants in at least two class action suits and five separate suits filed by various Texas cities. Generally, these cities allege, among other things, that: (1) owners or operators of pipelines occupied city property and conducted pipeline operations without the cities' consent and without compensating the cities; and (2) the gas marketers failed to pay the cities for accessing and utilizing the pipelines located in the cities to flow gas under city streets. Plaintiffs also allege various other claims against the defendants for failure to secure the cities' consent. Damages are not quantified. In 1998, a jury trial was held in the separate suit brought by the City of Edinburg (the City). This suit involved, among other things, a particular franchise agreement entered into by a former subsidiary of PG&E GTT (now owned by Southern Union Gas Company (SU)) and the City and certain conduct of the defendants. On December 1, 1998, based on the jury verdict, the court entered a judgment in the City's favor, and awarded damages of $5.3 million, and attorneys' fees of up to $3.5 million plus interest. The court found that various PG&E GTT and SU defendants were jointly and severally liable for $3.3 million of the damages and all the attorneys' fees. Certain PG&E GTT subsidiaries were found solely liable for $1.4 million of the damages. The court did not clearly indicate the extent to which the PG&E GTT defendants could be found liable for the remaining damages. The PG&E GTT defendants intend to appeal the judgment. PG&E Corporation believes that the ultimate outcome of these matters could have a material adverse impact on its financial position or results of operations. Note 16: Segment Information PG&E Corporation's reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdictions. The accounting policies of the reportable operating segments are the same as those described in Note 1. PG&E Corporation's reportable segments are des-cribed below. Utility: PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company, provides natural gas and electric service to one of every 20 Americans. Wholesale Unregulated Business Operations: PG&E Corporation's wholesale unregulated business operations consist of USGen which develops, builds, operates, owns, and manages power generation facilities that serve wholesale and industrial customers; PG&EGT which operates approximately 9,000 miles of natural gas pipelines, natural gas storage facilities, and natural gas processing plants in the Pacific Northwest and Texas; and PG&EET which purchases and resells energy commodities and related financial instruments in major North American markets, serving PG&E Corporation's other unregulated businesses, unaffiliated utilities, and large end-use customers. 67 Retail Unregulated Business Operations: PG&ECorporation's retail unregulated business operations consist of PG&E ES which provides competitively priced electricity, natural gas, and related services to lower overall energy costs Segment information for the years 1998, 1997, and 1996 was as follows:
Wholesale Retail ------------------------------------- --------- PG&E ET -------------------- Corp. & Elimi- Utility USGen/(5)/ NW TEXAS/(5)/ PG&E ET PG&E ES Other/(2)/ nations Total - ------------------------------------------------------------------------------------------------------------------------------------ (in millions) 1998 Operating revenues $ 8,919 $ 645 $ 185 $1,640 $8,183 $365 $ 8 $ (3) $19,942 Intersegment revenues/(1)/ 5 4 52 301 326 14 -- (702) -- - ------------------------------------------------------------------------------------------------------------------------------------ Total operating revenues 8,924 649 237 1,941 8,509 379 8 (705) 19,942 - ------------------------------------------------------------------------------------------------------------------------------------ Depreciation, amortization and decommissioning 1,438 52 39 65 5 7 3 -- 1,609 Interest expense/(3)/ (621) (43) (43) (77) (7) (1) (30) 40 (782) Other income (expense) 76 18 3 13 5 (1) (6) (44) 64 Income taxes/(4)/ 629 28 31 (47) (17) (41) (13) -- 570 Net income 702 106 65 (71) (6) (52) (18) (7) 719 Capital expenditures 1,396 98 49 39 12 38 1 -- 1,633 Total assets at year-end $22,950 $3,844 $1,169 $2,655 $2,555 $ 202 $ 601 $(742) $33,234 1997 Operating revenues $ 9,495 $ 148 $ 186 $ 800 $4,613 $ 145 $ 13 $ -- $15,400 Intersegment revenues/(1)/ -- -- 47 204 195 -- -- (446) -- - ------------------------------------------------------------------------------------------------------------------------------------ Total operating revenues 9,495 148 233 1,004 4,808 145 13 (446) 15,400 - ------------------------------------------------------------------------------------------------------------------------------------ Depreciation, amortization and decommissioning 1,748 19 38 33 3 1 10 -- 1,852 Interest expense/(3)/ (570) (5) (41) (26) (2) (1) (32) 12 (665) Other income (expense) 83 (25) 1 13 3 -- 138 (12) 201 Income taxes/(4)/ 609 (17) 26 (8) (12) (17) (33) -- 548 Net income 735 (41) 40 (24) (19) (29) 54 -- 716 Capital expenditures 1,529 23 34 45 5 15 50 -- 1,701 Total assets at year-end $25,147 $989 $1,208 $2,800 $1,452 $60 $370 $(911) $31,115 1996 Operating revenues $ 8,989 $105 $ 206 $ -- $ 283 $-- $27 $ -- $ 9,610 Intersegment revenues/(1)/ -- -- 58 -- -- -- -- (58) -- - ------------------------------------------------------------------------------------------------------------------------------------ Total operating revenues 8,989 105 264 -- 283 -- 27 (58) 9,610 - ------------------------------------------------------------------------------------------------------------------------------------ Depreciation, amortization and decommissioning 1,177 12 32 -- -- -- 1 -- 1,222 Interest expense/(3)/ (600) (7) (45) -- -- -- 20 -- (632) Other income (expense) 20 9 (4) -- -- -- (12) -- 13 Income taxes/(4)/ 526 (6) 31 -- -- -- 4 -- 555 Net income 706 (6) 50 -- -- -- (28) -- 722 Capital expenditures 1,231 -- 173 -- -- -- -- -- 1,404 Total assets at year-end $23,567 $881 $1,772 $-- $-- $-- $205 $(188) $26,237
/(1)/ Intersegment electric and gas revenues are recorded at market prices, which for the Utility and PG&E GT NW are tariffed rates prescribed by the CPUC and FERC, respectively. /(2)/ Assets of PG&E Corporation are included in the Other column exclusive of investment in its subsidiaries. /(3)/ Net interest expense incurred by PG&E Corporation is allocated to the segments using specific identification. /(4)/ Income tax expense for the Utility is computed on a stand-alone basis. The balance of the consolidated income tax provision is allocated among the unregulated wholesale and retail segments. /(5)/ Income from equity-method investees for 1998, 1997, and 1996 was $113 million, $41 million, and $36 million, respectively, for USGen, and $3 million and $2 million, respectively, for PG&E GT Texas. 68 QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
Quarter ended December 31 September 30 June 30 March 31 - ------------------------------------------------------------------------------------------------------- (in millions, except per share amounts) 1998 PG&E Corporation Operating revenues $5,495 $5,307 $4,787 $4,353 Operating income 456 529 557 465 Net income 196 210 174 139 Earnings per common share, basic and diluted .51 .55 .46 .36 Dividends declared per common share .30 .30 .30 .30 Common stock price per share High 35.00 33.38 33.19 33.19 Low 30.44 30.06 30.13 29.38 Utility Operating revenues $2,218 $2,563 $2,117 $2,026 Operating income 443 513 494 426 Income available for common stock 169 199 186 148 1997 PG&E Corporation Operating revenues $4,889 $4,063 $3,083 $3,365 Operating income 265 628 371 464 Net income 94 257 193 172 Earnings per common share, basic and diluted .22 .62 .49 .42 Dividends declared per common share .30 .30 .30 .30 Common stock price per share High 30.94 24.94 25.00 24.25 Low 23.00 22.69 22.38 20.88 Utility Operating revenues $2,401 $2,541 $2,279 $2,274 Operating income 390 626 370 445 Income available for common stock 180 269 122 164
69 REPORT OF INDEPENDENT PUBLIC ACCOUTANTS To the Shareholders and the Board of Directors of PG&E Corporation and Pacific Gas and Electric Company: We have audited the accompanying consolidated balance sheets of PG&E Corporation (a California corporation) and subsidiaries and Pacific Gas and Electric Company (a California corporation) and subsidiaries as of December 31, 1998, and 1997, and the related statements of consolidated income, cash flows, and common stock equity of PG&E Corporation and subsidiaries and the related statements of consolidated income, cash flows and common stock equity, preferred stock and preferred securities of Pacific Gas and Electric Company and subsidiaries for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the management of PG&E Corporation and Pacific Gas and Electric Company. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overal l financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial positions of PG&E Corporation and subsidiaries, and of Pacific Gas and Electric Company and subsidiaries, as of December 31, 1998, and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP San Francisco, California February 8, 1999 RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS At both PG&E Corporation and Pacific Gas and Electric Company (the Utility) management is responsible for the integrity of the accompanying consolidated financial statements. These statements have been prepared in accordance with generally accepted accounting principles. Management considers materiality and uses its best judgment to ensure that such statements reflect fairly the financial position, results of operations, and cash flows of PG&E Corporation and the Utility. PG&E Corporation and the Utility maintain systems of internal controls supported by formal policies and procedures which are communicated throughout PG&E Corporation and the Utility. These controls are adequate to provide reasonable assurance that assets are safeguarded from material loss or unauthorized use and that necessary records are produced for the preparation of consolidated financial statements. There are limits inherent in all systems of internal controls, based on recognition that the costs of such systems should not exceed the benefits to be derived. PG&E Corporation and the Utility believe that their systems of internal control provide this appropriate balance. PG&E Corporation management also maintains a staff of internal auditors who evaluate the adequacy of, and assess the adherence to, these controls, policies, and procedures for all of PG&E Corporation, including the Utility. Both PG&E Corporation's and the Utility's consolidated financial statements have been audited by Arthur Andersen LLP, PG&E Corporation's independent public accountants. The audit includes a review of the internal accounting controls and performance of other tests necessary to support an opinion. The auditors' report contains an independent informed judgment as to the fairness, in all material respects, of reported results of operations and financial position. The Audit Committee of the Board of Directors for PG&E Corporation meets regularly with management, internal auditors, and Arthur Andersen LLP, jointly and separately, to review internal accounting controls and auditing and financial reporting matters. The internal auditors and Arthur Andersen LLP have free access to the Audit Committee, which consists of five outside directors. The Audit Committee has reviewed the financial data contained in this report. PG&E Corporation and the Utility are committed to full compliance with all laws and regulations and to conducting business in accordance with high standards of ethical conduct. Management has taken the steps necessary to ensure that all employees and other agents understand and support this commitment. Guidance for corporate compliance and ethics is provided by an officers' Ethics Committee and by a Legal Compliance and Business Ethics organization. PG&E Corporation and the Utility believe that these efforts provide reasonable assurance that each of their operations is conducted in conformity with applicable laws and with their commitment to ethical conduct. 70 EX-23 16 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS EXHIBIT 23 [LETTERHEAD OF ARTHUR ANDERSEN LLP] CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 8, 1999, incorporated by reference in this Form 10-K, into the Company's previously filed registration statements as follows: (1) PG&E Corporation's Form S-3 Registration Statement File No. 333-16255 (relating to PG&E Corporation's Dividend Reinvestment Plan); (2) Pacific Gas and Electric Company's Form S-3 Registration Statement File No. 33-64136 (relating to $2,000,000,000 aggregate principal amount of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds and Medium-Term Notes); (3) Pacific Gas and Electric Company's Form S-3 Registration Statement File No. 33-50707 (relating to $1,500,000,000 aggregate principal amount of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds); (4) PG&E Corporation's Form S-8 Registration Statement File No. 33-50601 (relating to the Pacific Gas and Electric Company Savings Fund Plan for Employees); (5) PG&E Corporation's Form S-8 Registration Statement File No. 33-23692 (relating to PG&E Corporation's 1986 Stock Option Plan); (6) Pacific Gas and Electric Company's Form S-3 Registration Statement File No. 33-62488 (relating to 10,000,000 shares of Pacific Gas and Electric Company's Redeemable First Preferred Stock); (7) Form S-3 Registration Statement File No. 33-61959 (relating to $335,000,000) aggregate liquidation value of Cumulative Quarterly Income Preferred Securities); (8) PG&E Corporation's Form S-8 Registration Statement File No. 333-16253 (relating to PG&E Corporation's Long-Term Incentive Program), (9) PG&E Corporation's Form S-3 Registration Statement File No.333-25685 (relating to the resale of PG&E Corporation shares held by certain shareholders), (10) PG&E Corporation's Post-Effective Amendment on Form S-8 to Form S-4 Registration Statement File No. 333-27015 (relating to Valero Energy Corporation Stock Option Plan No. 4, Valero Energy Corporation Stock Option Plan No. 5, and Valero Energy Corporation Executive Stock Incentive Plan), (11) PG&E Corporation's Form S-8 Registration Statement File No. 333-33657 (relating to PG&E Gas Transmission, Texas Corporation Savings Fund Plan), (12) PG&E Corporation's Form S-8 Registration Statement File No. 333-68155 (relating to PG&E Gas Transmission, Northwest Corporation Savings Fund Plan for Non-Management Employees, PG&E Gas Transmission, Northwest Corporation Savings Fund Plan for Management Employees, and (13) PG&E Corporation's Form S-8 Registration Statement File No. 333-69437 (relating to PG&E Energy Services Retirement Plan, U.S. Generating Company 401(k) Profit-Sharing Plan, and U.S. Generating Company 401(k) Profit-Sharing Plan for Bargaining Unit Employees. /s/ ARTHUR ANDERSEN LLP San Francisco, California March 5, 1999 EX-24.1 17 RESOL OF BOARD OF DIR-PG&E CORP/PACIFIC GAS & ELEC Exhibit 24.1 RESOLUTION OF THE ----------------- BOARD OF DIRECTORS OF --------------------- PG&E CORPORATION ---------------- February 17, 1999 ----------------- BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES is hereby authorized to sign on behalf of this corporation and as attorneys in fact for the Chairman of the Board, President, and Chief Executive Officer, the Senior Vice President, Chief Financial Officer, and Treasurer, and the Vice President and Controller of this corporation the Form 10-K Annual Report for the year ended December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and all amendments and other filings or documents related thereto to be filed with the Securities and Exchange Commission, and to do any and all acts necessary to satisfy the requirements of the Securities Exchange Act of 1934 and the regulations of the Securities and Exchange Commission adopted thereunder with regard to said Form 10-K Annual Report. I, LINDA Y.H. CHENG, do hereby certify that I am an Assistant Corporate Secretary of PG&E CORPORATION, a corporation organized and existing under the laws of the State of California; that the above and foregoing is a full, true, and correct copy of a resolution which was duly adopted by the Board of Directors of said corporation at a meeting of said Board which was duly and regularly called and held at the office of said corporation on February 17, 1999; and that this resolution has never been amended, revoked, or repealed, but is still in full force and effect. WITNESS my hand and the seal of said corporation hereunto affixed this 5th day of March, 1999. /s/ Linda Y.H. Cheng ------------------------------- Linda Y.H. Cheng Assistant Corporate Secretary PG&E CORPORATION C O R P O R A T E S E A L RESOLUTION OF THE ----------------- BOARD OF DIRECTORS OF --------------------- PACIFIC GAS AND ELECTRIC COMPANY -------------------------------- February 17, 1999 ----------------- BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES is hereby authorized to sign on behalf of this company and as attorneys in fact for the President and Chief Executive Officer, the Senior Vice President-Treasurer and Chief Financial Officer, and the Vice President and Controller of this corporation the Form 10-K Annual Report for the year ended December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and all amendments and other filings or documents related thereto to be filed with the Securities and Exchange Commission, and to do any and all acts necessary to satisfy the requirements of the Securities Exchange Act of 1934 and the regulations of the Securities and Exchange Commission adopted thereunder with regard to said Form 10-K Annual Report. I, LINDA Y.H. CHENG, do hereby certify that I am Senior Assistant Corporate Secretary of PACIFIC GAS AND ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of California; that the above and foregoing is a full, true, and correct copy of a resolution which was duly adopted by the Board of Directors of said corporation at a meeting of said Board which was duly and regularly called and held at the office of said corporation on February 17, 1999; and that this resolution has never been amended, revoked, or repealed, but is still in full force and effect. WITNESS my hand and the seal of said corporation hereunto affixed this 5th day of March, 1999. /s/ Linda Y.H. Cheng ------------------------------- Linda Y.H. Cheng Senior Assistant Corporate Secretary PACIFIC GAS AND ELECTRIC COMPANY C O R P O R A T E S E A L EX-24.2 18 POWERS OF ATTORNEY Exhibit 24.2 POWER OF ATTORNEY Each of the undersigned Directors of PG&E Corporation hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his or her attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his or her capacity as such Director of said corporation the Form 10-K Annual Report for the year ended December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, we have signed these presents this 17th day of February, 1999. ROBERT D. GLYNN, JR. RICHARD A. CLARKE - ------------------------------------- -------------------------------------- DAVID A. COULTER REBECCA Q. MORGAN - ------------------------------------- -------------------------------------- C. LEE COX MARY S. METZ - ------------------------------------- -------------------------------------- BARRY LAWSON WILLIAMS REBECCA B. MADDEN - ------------------------------------- -------------------------------------- WILLIAM S. DAVILA - ------------------------------------- -------------------------------------- DAVID M. LAWRENCE, M.D - ------------------------------------- -------------------------------------- JOHN C. SAWHILL - ------------------------------------- POWER OF ATTORNEY ROBERT D. GLYNN, JR., the undersigned, Chairman of the Board, Chief Executive Officer, and President of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Chairman of the Board and Chief Executive Officer (principal executive officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, I have signed these presents this 17th day of February, 1999. /s/ Robert D. Glynn, JR -------------------------------------------- Robert D. Glynn, Jr. POWER OF ATTORNEY MICHAEL E. RESCOE, the undersigned, Senior Vice President and Chief Financial Officer of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Senior Vice President and Chief Financial Officer (principal financial officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, I have signed these presents this 17th day of February, 1999. /s/ Michael E. Rescoe -------------------------------------------- Michael E. Rescoe POWER OF ATTORNEY CHRISTOPHER P. JOHNS, the undersigned, Vice President and Controller of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Vice President and Controller (principal accounting officer) of said corporation the Form 10 K Annual Report for the year ended December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, I have signed these presents this 17th day of February, 1999. /S/ Christopher P. Johns ----------------------------------- Christopher P. Johns POWER OF ATTORNEY Each of the undersigned Directors of Pacific Gas and Electric Company hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his or her attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his or her capacity as such Director of said corporation the Form 10-K Annual Report for the year ended December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, we have signed these presents this 17th day of February, 1999. ROBERT D. GLYNN, JR. RICHARD A. CLARKE - ---------------------------------- ---------------------------------------- DAVID A. COULTER REBECCA Q. MORGAN - ---------------------------------- ---------------------------------------- C. LEE COX MARY S. METZ - ---------------------------------- ---------------------------------------- BARRY LAWSON WILLIAMS RICHARD B. MADDEN - ---------------------------------- ---------------------------------------- WILLIAM S. DAVILA GORDON R. SMITH - ---------------------------------- ---------------------------------------- DAVID M. LAWRENCE, MD - ---------------------------------- ---------------------------------------- JOHN C. SAWHILL - ---------------------------------- ---------------------------------------- POWER OF ATTORNEY GORDON R. SMITH, the undersigned, President and Chief Executive Officer of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as President and Chief Executive Officer (principal executive officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, I have signed these presents this 17th day of February , 1999. /s/ Gordon R. Smith --------------------------------------- Gordon R. Smith POWER OF ATTORNEY KENT M. HARVEY, the undersigned, Senior Vice President - Treasurer and Chief Financial Officer of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN RUEGER, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Senior Vice President - Treasurer and Chief Financial Officer (principal financial officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, I have signed these presents this 17th day of February, 1999. /s/ Kent M. Harvey --------------------------------------- Kent M. Harvey POWER OF ATTORNEY CHRISTOPHER P. JOHNS, the undersigned, Vice President and Controller of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Vice President and Controller (principal accounting officer) of said corporation the Form 10-K Annual Report for the year ended December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, I have signed these presents this 17th day of February, 1999. /s/ Christopher P. Johns --------------------------------------- Christopher P. Johns EX-27.1 19 FINANCIAL DATA SCHEDULE - PG&E CORPORATION WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PG&E CORPORATION AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000,000 12-MOS DEC-31-1998 JAN-01-1998 DEC-31-1998 PER-BOOK 17,818 0 4,955 2,998 7,463 33,234 5,862 0 2,204 8,066 300 480 6,065 1,644 0 1,357 338 0 0 0 14,984 33,234 19,942 570 17,935 17,935 2,007 64 2,071 782 719 0 719 466 340 2,301 $1.88 $1.88
EX-27.2 20 FINANCIAL DATA SCHEDULE - PACIFIC GAS & ELECTRIC C
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFIC GAS AND ELECTRIC COMPANY AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000,000 12-MOS DEC-31-1998 JAN-01-1998 DEC-31-1998 PER-BOOK 12,872 0 2,013 2,880 5,185 22,950 1,707 2,094 2,260 6,061 437 287 4,877 668 0 567 260 0 0 0 9,793 22,950 8,924 629 7,048 7,048 1,876 103 1,979 621 729 27 702 300 340 2,628 0.00 0.00
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