-----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, QXSsmswdfrQvcF46tOioTy7+RzkEHiUTnC84XhPLGBH3EUbWQDhScmGRXBS7CzmX oxRTNOXM55+vf16/8MglKw== 0000929624-98-000494.txt : 19980309 0000929624-98-000494.hdr.sgml : 19980309 ACCESSION NUMBER: 0000929624-98-000494 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 20 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980305 SROS: NYSE SROS: PCX 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: 98558513 BUSINESS ADDRESS: STREET 1: 77 BEALE ST STREET 2: P O BOX 770000 MAIL CODE B32 CITY: SAN FRANCISCO STATE: CA ZIP: 94177 BUSINESS PHONE: 4159737000 MAIL ADDRESS: STREET 1: 77 BEALE ST B32 STREET 2: PO BOX 770000 CITY: SAN FRANCISCO STATE: CA ZIP: 94177 FORMER COMPANY: FORMER CONFORMED NAME: PG&E PARENT CO INC DATE OF NAME CHANGE: 19951214 10-K405 1 FORM 10-K FOR 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, 1997 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 94177 (ZIP CODE) (ZIP CODE) (415) 973-7000 (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 Stock Exchange PACIFIC GAS AND ELECTRIC COMPANY First Preferred Stock, cumulative, American Stock Exchange and par value $25 per share: Pacific Stock Exchange
Redeemable: 7.04%, 6 7/8, 5% Series A, 5%, 4.80%, 4.50%, 4.36%. Mandatorily Redeemable: 6.57%, 6.30% Nonredeemable: 6%, 5 1/2%, 5% 7.90% Cumulative Quarterly Income Preferred Securities, Series A (liquidation preference $25), issued by PG&E Capital I and guaranteed by Pacific Gas and Electric American Stock Exchange and Company Pacific Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] 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 17, 1998: PG&E Corporation Common Stock $11,426 million Pacific Gas and Electric Company First Preferred Stock $463 million COMMON STOCK OUTSTANDING AS OF FEBRUARY 17, 1998: PG&E Corporation: 381,010,366 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 Part II (Items 5, 6, 7 and 8) December 31, 1997......................... Part IV (Item 14) (2) Designated portions of the Joint Proxy Statement relating to the 1998 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..................................................... 5 Regulation of Pacific Gas and Electric Company................... 6 State Regulation................................................. 6 Federal Regulation............................................... 6 Licenses and Permits............................................. 6 Regulation of PG&E Corporation and Other Subsidiaries............ 7 Pacific Gas and Electric Company Rate Matters.................... 8 California Ratemaking Mechanisms................................. 8 Electric Ratemaking.............................................. 9 Gas Ratemaking................................................... 11 1998 Revenues.................................................... 11 Capital Requirements and Financing Programs...................... 12 Price Risk Management Programs................................... 13 ELECTRIC UTILITY OPERATIONS...................................... 15 Electric Industry Restructuring Legislation...................... 15 Independent System Operator and Power Exchange................... 15 Voluntary Generation Asset Divestiture........................... 15 Direct Access.................................................... 16 Rate Levels and Rate Reduction Bonds............................. 17 Recovery of Transition Costs..................................... 17 Public Purpose Programs.......................................... 18 Electric Operating Statistics.................................... 20 Electric Generating and Transmission Capacity.................... 22 Diablo Canyon.................................................... 23 Diablo Canyon Operations......................................... 23 Diablo Canyon Ratemaking......................................... 24 Nuclear Fuel Supply and Disposal................................. 25 Insurance........................................................ 26 Decommissioning.................................................. 26 Other Electric Resources......................................... 27 QF Generation and Other Power-Purchase Contracts................. 27 Geothermal Generation............................................ 28 Helms Pumped Storage Plant....................................... 28 Electric Transmission and Distribution........................... 28 GAS UTILITY OPERATIONS........................................... 30 Gas Operations................................................... 30 Gas Operating Statistics......................................... 31 Natural Gas Supplies............................................. 32 Gas Regulatory Framework......................................... 32 Transportation Commitments....................................... 33
i TABLE OF CONTENTS--(CONTINUED)
PAGE ---- Gas Reasonableness Proceedings................................. 34 1988-1990 Canadian Gas Procurement Activities.................. 34 PGT/Pacific Gas and Electric Company Pipeline Expansion........ 34 PG&E CORPORATION'S GAS TRANSMISSION OPERATIONS................. 36 PG&E CORPORATION'S INDEPENDENT POWER GENERATION OPERATIONS..... 37 PG&E CORPORATION'S ENERGY SERVICES AND COMMODITIES............. 39 ENVIRONMENTAL MATTERS.......................................... 40 Environmental Matters.......................................... 40 Environmental Protection Measures.............................. 40 Air Quality.................................................... 40 Water Quality.................................................. 41 Hazardous Waste Compliance and Remediation..................... 41 Potential Recovery of Hazardous Waste Compliance and Remediation Costs.............................................. 43 Compressor Station Litigation.................................. 43 Electric and Magnetic Fields................................... 43 Low Emission Vehicle Programs.................................. 44 Item 2. Properties..................................................... 44 Item 3. Legal Proceedings.............................................. 44 Compressor Station Chromium Litigation......................... 45 Texas Franchise Fee Litigation................................. 46 Item 4. Submission of Matters to a Vote of Security Holders............ 49 EXECUTIVE OFFICERS OF THE REGISTRANTS.......................... 50 PART II Market for the Registrant's Common Equity and Related Item 5. Stockholder Matters............................................ 53 Item 6. Selected Financial Data........................................ 53 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.......................................... 53 Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 53 Item 8. Financial Statements and Supplementary Data.................... 53 Changes in and Disagreements with Accountants on Accounting and Item 9. Financial Disclosure........................................... 54 PART III Item 10. Directors and Executive Officers of the Registrant............. 54 Item 11. Executive Compensation......................................... 54 Item 12. Security Ownership of Certain Beneficial Owners and Management. 54 Item 13. Certain Relationships and Related Transactions................. 54 PART IV Exhibits, Financial Statement Schedules, and Reports on Form 8- Item 14. K.............................................................. 54 Signatures..................................................... 59 Report of Independent Public Accountants....................... 60 Financial Statement Schedules.................................. 61
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 Bechtel........... Bechtel Enterprises, Inc. 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 California Superfund........ California Hazardous Substance Account Act CARE.............. California Alternate Rates for Energy CCAA.............. California Clean Air Act CEC............... California Energy Commission Central Coast Board............ Central Coast Regional Water Quality Control Board CERCLA............ Comprehensive Environmental Response, Compensation, and Liability Act CFCA.............. Core Fixed Cost Account CIG............... customer identified gas program 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 Duke Energy....... Duke Energy Power Services, Inc. ECAC.............. Energy Cost Adjustment Clause EDRA.............. electric deferred refund account El Paso........... El Paso Natural Gas Company EMF............... electric and magnetic fields Enterprises....... PG&E Enterprises EPA............... United States Environmental Protection Agency ERAM.............. Electric Revenue Adjustment Mechanism FERC.............. Federal Energy Regulatory Commission Gas Accord........ Gas Accord Settlement Geysers........... The Geysers Power Plant GRC............... General Rate Case GTT............... PG&E Gas Transmission, Texas Corporation 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 InterGen.......... International Generating Company, Ltd.
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 LDC............... local distribution company 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, formerly known as the Division of Ratepayer Advocates PBR............... performance-based ratemaking PEPR.............. Pipeline Expansion Project Reasonableness case 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 ET........... PG&E Corporation's energy commodities activities, PG&E Energy Trading or PG&E ET PGT............... Pacific Gas Transmission Company, now known as PG&E Gas Transmission, Northwest Corporation PGT Expansion..... the 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 Teco.............. Teco Pipeline Company TRA............... Transition Revenue Account transition period. the period during which electric rates are frozen at 1996 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 TURN.............. The Utility Reform Network USGen............. U.S. Generating Company USOSC............. U.S. Operating Services Company Vantus............ Vantus Energy Corporation 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 the United States and in Australia. Effective January 1, 1997, Pacific Gas and Electric Company and its subsidiaries became subsidiaries of PG&E Corporation, which was incorporated in 1995. 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 (sometimes referred to in this report as the "Company"). Because PG&E Corporation did not become the holding company for Pacific Gas and Electric Company until January 1, 1997, the 1995 and 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 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 their telephone number is (415) 973-7000. As of December 31, 1997, PG&E Corporation had $30.6 billion in assets. PG&E Corporation generated $15.4 billion in operating revenues for 1997. As of December 31, 1997, PG&E Corporation and its subsidiaries and affiliates had approximately 23,500 employees. During 1997, PG&E Corporation expanded its energy-related business activities, which now include the gas and electric utility operations of Pacific Gas and Electric Company; the ownership and operation of natural gas pipelines, natural gas storage facilities, and natural gas processing plants, primarily in the Pacific Northwest, Texas and Australia, 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 and its affiliates; 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). Pacific Gas and Electric Company, incorporated in California in 1905, is an operating public utility engaged principally in the business of providing electric and natural gas services throughout most of Northern and Central California. As of December 31, 1997, Pacific Gas and Electric Company had $25.1 billion in assets. The Company generated $9.5 billion in operating revenues for 1997. As of December 31, 1997, Pacific Gas and Electric Company had approximately 21,000 employees. The gas and electric utility operations of Pacific Gas and Electric Company represent the principal component of PG&E Corporation's business, contributing 62% of PG&E Corporation's total revenues in 1997. Pacific Gas and Electric Company's utility operations contributed $1.77 of PG&E Corporation's total 1997 earnings per share of $1.75. (Pacific Gas and Electric Company's earnings were offset by losses at some of PG&E Corporation's other businesses: PG&E Energy Services, PG&E Energy Trading, and U.S. Generating Company.) 1 Pacific Gas and Electric Company's utility service territory covers 70,000 square miles with an estimated population of approximately 12 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, 1997, Pacific Gas and Electric Company served approximately 4.5 million electric customers. In 1997, 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, Pacific Gas and Electric Company has entered into agreements to sell three fossil-fueled power plants and has announced plans to sell an additional four power plants plus its geothermal facilities in 1998. See "Electric Utility Operations--Electric Industry Restructuring Legislation" below.) Pacific Gas and Electric 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, Pacific Gas and Electric 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 3.7 million gas customers at December 31, 1997. To ensure a diverse and competitive mix of natural gas supplies, Pacific Gas and Electric Company purchases gas from both Canadian and United States suppliers. In 1997, about 66% of Pacific Gas and Electric Company's gas supply came from fields in Canada, about 3% came from fields in California, and about 31% came from fields in other states (substantially all from the U.S. Southwest). In 1997, the CPUC approved the Gas Accord Settlement (Gas Accord), a comprehensive multi-party settlement agreement to restructure Pacific Gas and Electric Company's gas services and its role in the gas market, establish gas transmission rates for the period from March 1, 1998 through December 2002, and resolve various gas regulatory issues. On July 31, 1997, a wholly owned subsidiary of PG&E Corporation merged with Valero Energy Corporation, (Valero) in Texas (now known as PG&E Gas Transmission, Texas Corporation). As a result of the merger, PG&E Corporation acquired Valero's natural gas and natural gas liquids pipelines, natural gas storage facilities, natural gas processing plants, and various gas marketing companies. Through its January 1997 acquisition of Teco Pipeline Company (Teco) in Texas (now known as PG&E Gas Transmission, Teco, Inc.), PG&E Corporation also acquired interests in various natural gas pipelines, natural gas processing facilities, and an operation in Houston, Texas, involved in the purchase and sale of energy commodities and related financial instruments. PG&E Gas Transmission, Northwest Corporation (formerly Pacific Gas Transmission Company or PGT) owns and operates an interstate natural gas pipeline in the Pacific Northwest. See "PG&E Corporation's Gas Transmission Operations" below. Also in 1997, PG&E Corporation established PG&E Energy Services Corporation (formerly Vantus Energy Corporation) to compete in the direct access market in California and to provide customers nationwide with competitively priced natural gas and electricity services to manage and make more efficient their energy consumption. See "PG&E Corporation's Energy Services and Commodities" below. Although the direct access market was scheduled to begin in California on January 1, 1998, in late December 1997, the Independent System Operator (ISO) and the Power Exchange (PX) announced that there would be a delay in the commencement of a direct access market until certain operational and logistical issues are resolved, and that they expected direct access to begin by March 31, 1998. The ISO is the corporation proposed by California electric industry restructuring legislation to operate and control the state's electric transmission facilities and to provide comparable open access to electric transmission service. The PX is the corporation proposed by the California Public Utilities Commission (CPUC) to provide a competitive auction process to establish the price of electricity. See "Electric Utility Operations--Electric Industry Restructuring Legislation" below. 2 In August 1997, PG&E Corporation announced plans to acquire, through affiliates of U.S. Generating Company (USGen), a portfolio of electric generating assets and power supply contracts from the New England Electric System for approximately $1.59 billion plus $85 million for certain employee- related costs. In September 1997, PG&E Corporation acquired full ownership of USGen, originally formed as a joint venture with Bechtel Enterprises, Inc. (Bechtel). PG&E Corporation also acquired full ownership of certain other partnerships affiliated with USGen, as well as all or a portion of Bechtel's interests in various power projects affiliated with USGen. See "PG&E Corporation's Independent Power Generation Operations" below. The following information includes forward-looking statements that involve a number of risks, uncertainties, and assumptions. Words such as "estimates," "expects," "intends," "anticipates," "plans," and similar expressions identify those statements which are forward-looking. A number of factors that could cause actual results to differ materially from those indicated in the forward- looking statements include, but are not limited to, the ongoing restructuring of the electric and gas industries and the outcome of regulatory proceedings related to that restructuring, and other factors which are described in more detail below. The ultimate impacts of both increased competition and the changing regulatory environment on future results are uncertain, but are expected to fundamentally change how PG&E Corporation's utility operations are conducted. The outcome of these changes and other matters discussed below may cause future results to differ materially from historic results, or 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 existing regulatory framework to a framework under which competition is allowed in certain segments of the gas and electric industries. For several years, Pacific Gas and Electric Company has been working with its regulators to achieve an orderly transition to competition and to ensure that the Company has an opportunity to recover investments made under traditional regulatory policies. Beginning in 1998, a significant portion of Pacific Gas and Electric Company's business will be transformed from the current utility monopoly to a competitive operation. During the transition period, the return on Diablo Canyon and certain other generation assets will be significantly lower than historical levels. See "Electric Utility Operations--Diablo Canyon--Diablo Canyon Ratemaking" below. These changes will affect PG&E Corporation's financial results and may result in greater earnings volatility. ELECTRIC INDUSTRY In 1995, the CPUC issued a decision that provides a plan to restructure California's electric industry. The decision acknowledges that much of utilities' current costs and commitments result from past CPUC decisions and that, in a competitive generation market, utilities would not recover some of these costs through market-based revenues. To assure the continued financial integrity of California utilities, the CPUC authorized recovery of these above-market costs, called transition costs, through a nonbypassable charge, called the competition transition charge or CTC, to be collected over a period of years. 3 In 1996, legislation adressing electric industry restructuring, Assembly Bill 1890 (AB 1890), was signed into law in California. AB 1890 adopts the basic tenets of the CPUC's restructuring decision and establishes the operating framework for a competitive electric generation market. Key features of AB 1890 include: --mandatory unbundling of transmission, distribution, and generation services; --formation of the PX to provide a competitive auction process to establish the price of electricity in California; --establishment of the ISO to ensure system reliability and provide electric generators and energy service providers with open and comparable access to transmission services; --an electric rate freeze at 1996 levels until the earlier of March 31, 2002, or when the particular utility has recovered its generation-related transition costs (the transition period); --a 10% rate reduction on January 1, 1998, for residential and small commercial customers, financed through "rate reduction bonds;" --nonbypassable charges (the competition transition charge or CTC) to provide the opportunity for utilities to recover their transition costs and accelerated recovery of transition costs associated with utility- owned generation facilities; --direct access to competitive generation resources for all retail electric customers to start no later than January 1, 1998; --market valuation for utility-owned fossil generation assets by 2001, followed by an end to cost-of-service ratemaking for most plants; and --continued support for renewable generation resources, conservation, and other public purpose programs. Under AB 1890, Pacific Gas and Electric Company and other utilities will continue to own transmission and distribution facilities and must continue to offer bundled electric service to customers who wish to continue receiving it. Although ownership of transmission facilities will be retained, utilities will relinquish control of the facilities to the ISO. As required by AB 1890, electric rates were frozen on January 1, 1997 at 1996 levels, and on January 1, 1998, rates for residential and small commercial customers were reduced by 10% and will be held at the reduced level. The rate freeze will continue until the end of the transition period. During 1997, the CPUC issued many decisions to establish the ratemaking and accounting mechanisms necessary to implement AB 1890. Many of the key features of AB 1890 were implemented by January 1, 1998, such as the rate freeze, the 10% rate reduction for residential and small commercial customers, formation of the ISO and PX, and commencement of the market valuation process. However, direct access for all retail electric customers has been delayed. In December 1997, the ISO and the PX announced that they were unable to commence operations on January 1, 1998, and that they expected to be operational by March 31, 1998, at which time direct access would begin. See "Electric Utility Operations--Electric Industry Restructuring Legislation" below. At the federal level, the ISO is regulated by the Federal Energy Regulatory Commission (FERC). In October 1997, the FERC granted conditional authority for the California ISO to commence operations and for the California PX to charge market-based rates for electricity. See "Electric Utility Operations--Electric Transmission" below. Additional information concerning electric industry restructuring, the expected operating framework for a competitive generation market, and the financial impact of these changes on PG&E Corporation is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 43 of the 1997 Annual Report to Shareholders. 4 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. Currently, Pacific Gas and Electric Company's customers may buy gas directly from competing suppliers and purchase transmission- and distribution-only services from Pacific Gas and Electric Company. Pacific Gas and Electric Company's transmission and distribution services have historically 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. In 1995 and 1996, Pacific Gas and Electric Company actively pursued changes in the California gas industry in an effort to promote competition and increase options for all customers, as well as to position the Company for the competitive marketplace. In 1996, Pacific Gas and Electric Company submitted to the CPUC the Gas Accord, a multi-party settlement agreement which resulted from an extensive negotiation process begun in 1995 among a broad coalition of customer groups and industry participants. On August 1, 1997, the CPUC unanimously approved the 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. The Gas Accord increases opportunities for Pacific Gas and Electric Company's core customers to purchase gas from competing suppliers and, therefore, will 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, the CPUC's traditional after-the-fact reasonableness review of Pacific Gas and Electric Company's core gas procurement costs for the period 1994 to 2002 are replaced by a core procurement incentive mechanism (CPIM), a form of incentive regulation. Under the CPIM, Pacific Gas and Electric Company is able to recover its gas commodity and interstate transportation costs and receives benefits or incurs penalties depending on whether its actual core procurement costs are within, below, or above a "tolerance band" constructed around market benchmarks. Actual core procurement costs measured for the period June 1, 1994, through December 31, 1997, have generally been within the CPIM "tolerance band." The Gas Accord establishes gas transmission and storage rates for the period from March 1, 1998, through December 2002. During the Gas Accord 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 rule-making 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. The CPUC will be studying various new alternative market structures for the California natural gas industry with the goal of encouraging competition and customer choice, while maintaining a high standard of consumer protection. 5 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 of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 24, and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on page 46 of the 1997 Annual Report to Shareholders. REGULATION OF PACIFIC GAS AND ELECTRIC COMPANY STATE REGULATION The CPUC consists of five members appointed by the Governor 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, to determine its future policies. 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 state-wide plan of action in case of energy shortages. In addition, the CEC certifies power-plant sites and related facilities within California. Under electric industry restructuring legislation, 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 "Electric Utility Operations-- Electric Industry Restructuring Legislation--Public Purpose Programs" below. FEDERAL REGULATION The FERC regulates electric transmission rates and access, compliance with the uniform systems of accounts, and electric contracts involving sales of electricity for resale. After the ISO and PX commence operations, the FERC will have jurisdiction over Pacific Gas and Electric Company's electric transmission revenue requirements and rates, which previously were included in CPUC-authorized bundled 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. 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 imposed by the granting agency. 6 REGULATION OF PG&E CORPORATION AND OTHER SUBSIDIARIES PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (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 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 in the event 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 will be responding to the audit report, and the CPUC will hold hearings to determine if the additional recommended conditions should be imposed on the holding company. 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 Corporation, the non-regulated energy marketing subsidiary of PG&E Corporation) to compete in the affiliated utility's service territory. The decision permits non-regulated affiliates to use the same 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 also adopts complex and detailed rules requiring the separation of regulated utilities and their non-regulated affiliates, through the maintenance of separate books and records, physical separation of facilities, and the separation of certain functions, such as energy-related purchases and sales, and marketing, among others. The decision also contains rules regarding disclosure and use of information 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 on December 31, 1997. 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. In addition, the power generation projects that USGen and its affiliates 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 Public Utility Holding Company Act of 1935. EWG status is granted by FERC upon application by the project. Some projects have received authority from FERC to charge market- 7 based rates for the power they sell, rather than traditional cost-based rates. Many of USGen's affiliated projects are qualifying facilities (QF) 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. 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 Gas Transmission Teco, Inc., and other affiliates operating in Texas. The RRC gas proration rules govern the wellhead production and purchase of gas. Intrastate pipelines can provide intrastate gas transportation at negotiated rates which are 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 may also regulate certain sales of gas. Currently, the price of natural gas sold under a majority of PG&E Gas Transmission, Texas Corporation'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. Other regulatory matters are described throughout this report. PACIFIC GAS AND ELECTRIC COMPANY RATE MATTERS 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. Pacific Gas and Electric Company's next scheduled GRC will establish base revenues effective January 1, 1999. 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 Pacific Gas and Electric 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. On December 12, 1997, Pacific Gas and Electric Company filed its Test Year 1999 GRC application with the CPUC, requesting increases in electric and gas base revenues of $693 million and $501 million, respectively, over base revenues authorized in 1997. The requested increase in base revenues reflects increasing levels of electric and gas demand as well as customer growth in the service territory, the costs of continued and enhanced maintenance activities, and increased capital expenditures. If granted by the CPUC, the requested increase would be effective January 1, 1999. The requested increase of $693 million in electric base revenues as compared to 1997 will not increase customer electric rates because these rates will continue to be frozen. Under the frozen electric rates, the portion of total actual revenue which 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. 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 8 and maintenance, a continuation of tree-trimming programs, and enhanced customer service and information technology systems. Since the FERC will authorize the rates to be collected from customers for electric transmission services once direct access begins, the GRC application does not seek approval of base revenues to recover the cost of transmission services. The requested increase in electric base revenues is in addition to increases for system safety and reliability provided by AB 1890, as discussed in "1998 Revenues" below. Gas customers would experience an increase in gas distribution rates if the CPUC approves the requested gas base revenue increase. 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. 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. ELECTRIC RATEMAKING In 1996, the CPUC issued a "roadmap" decision outlining the necessary steps to accomplish electric industry restructuring. During 1997, the CPUC issued many decisions to implement AB 1890 and the new market structure beginning in 1998, including decisions related to unbundling of rates, transition costs, performance based ratemaking (PBR), and other activities that affect rates and revenue requirements. In its roadmap decision, the CPUC established a separate annual proceeding to consider ratemaking issues related to each electric utility's revenues, which will consolidate all pending revenue changes and track utility revenues at present rate levels for the purpose of comparison with authorized amounts. Beginning in 1998, this annual Revenue Adjustment Proceeding (RAP) will review, track, and compare each electric utility's authorized revenue requirements with the actual recorded revenues, and will make any necessary adjustments or updates due to authorized revenues for alternative ratemaking mechanisms, various power purchase contracts, public purpose programs, nuclear facilities, nuclear decommissioning, transition costs, and other proceedings. Pacific Gas and Electric Company has filed numerous regulatory applications and proposals that detail its transition cost recovery plan during the transition period. Pacific Gas and Electric Company's recovery plan includes (1) separating or unbundling of its previously approved cost-of-service revenue requirement for its electric operations into distribution, transmission, public purpose programs (PPPs), and generation, (2) determining revenues available to recover transition costs, and (3) development of a ratemaking mechanism to track and match revenues and cost recovery during the transition period. In August 1997, the CPUC adopted Pacific Gas and Electric Company's proposed unbundling of its 1998 authorized electric revenue requirements with some exceptions. The decision enables Pacific Gas and Electric Company to separate revenues provided by frozen rates into transmission, distribution, PPPs, and generation based upon their respective costs of service. The generation category includes energy costs, generation operating costs, nuclear decommissioning costs, and transition costs. When direct access begins, bills for all customers will describe what portion of the bill is attributable to transmission, distribution, PPPs, energy, and transition costs and other nonbypassable charges. Under the restructuring legislation, most transition costs must be recovered by March 31, 2002. The CPUC believes that the shorter amortization period reduces risks associated with recovery of generation facilities, including Diablo Canyon. As a result, in November 1997 (but retroactive to July 28, 1997), the CPUC reduced the authorized rate of return on common equity for Pacific Gas and Electric Company's non-nuclear electric generation-related assets including hydroelectric and geothermal facilities, to 90% of the Company's embedded cost of debt, for a reduced rate of return on common equity equal to 6.77%, as compared to the previously authorized 1997 rate of return on common equity of 11.6%. Effective January 1, 1997, the rate of return on common equity on Diablo Canyon was reduced to 90% of Pacific Gas and Electric Company's embedded cost of long-term debt, for a return on common equity of 6.77%. See "Electric Utility Operations--Diablo Canyon--Diablo Canyon Ratemaking" below. The reduced rate of return for the Company's non-nuclear electric generation-related assets and for Diablo Canyon will be in effect for the duration of the transition period. 9 Before 1998, the Electric Revenue Adjustment Mechanism (ERAM) allowed rate adjustments to offset the effect on base revenues of differences between actual electric sales volumes and the forecasted volumes used to set electric rates. The ERAM eliminated the impact on earnings of sales fluctuations, including those resulting from conservation and weather conditions. Base revenue differences resulting from the disparity between actual and forecasted electric sales accumulated in a balancing account, with interest. In connection with electric industry restructuring, the CPUC eliminated the ERAM effective January 1, 1998. Until direct access begins, ERAM-related revenues will be recorded in a separate memorandum account established in connection with the delay of direct access. Before 1998, most of Pacific Gas and Electric Company's fuel, purchased- power, and energy-related costs of providing electric service, as well as revenues attributable to Diablo Canyon generation, were recovered through a balancing account mechanism called the Energy Cost Adjustment Clause (ECAC). Under the ECAC balancing account procedure, actual costs were compared with revenues designated for recovery of such costs, and the difference was recorded as either an undercollection or overcollection. In prior years, rates would be adjusted such that the amount of overcollections would be returned to ratepayers through lower rates and undercollections would be recovered through higher rates. However, as part of the electric industry restructuring, the CPUC eliminated the ECAC balancing account effective January 1, 1998. In December 1996, the CPUC issued a decision establishing an electric deferred refund account (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 CPUC-ordered gas disallowances, amounts resulting from reasonableness disputes, and fuel- related cost refunds made to Pacific Gas and Electric Company based on regulatory agency decisions, plus interest charges. The CPUC ordered Pacific Gas and Electric Company to file advice letters by January 31 of each year, setting forth its annual refund plans for directly refunding to electric customers the amounts accumulated in the EDRA. The CPUC also ordered Pacific Gas and Electric Company to include initially in the EDRA any such credits already recorded in ECAC and ERAM but not yet amortized in rates. The effect of this was to reduce the amount available to offset Pacific Gas and Electric Company's transition costs by approximately $75 million. In February 1998, Pacific Gas and Electric Company refunded approximately $61 million of EDRA funds to customers. The ISO will designate certain electric generation facilities as necessary to remain available and operational to maintain the reliability of the electric transmission system. These facilities are called "must-run" facilities. In general, sunk costs and on-going operating costs of must-run facilities are recoverable through different types of FERC-authorized contracts between must-run facilities and the ISO and, in some cases, also through PX revenues. For an initial three-month period, all must-run facilities will be under the same type of contract. Thereafter, the type of contract for a particular must-run facility may change based upon the ISO's evaluation of facility operating factors and system reliability needs. Subject to CPUC approval, the type of contract and generation (i.e., fossil, hydroelectric, or geothermal) will determine whether (1) all of the facility's sunk costs and ongoing operating costs are eligible for transition cost recovery, (2) the portion of the facility's sunk costs and ongoing operating costs, which are not recovered through ISO or PX revenues, are eligible for transition cost recovery, (3) differences between authorized and actual revenues for the facility will be included in the transition cost recovery mechanism, and (4) the facility may participate in the PX. 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 (including the Helms pumped storage facility) 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 General Rate Case adopted expenses), and actual fuel expenses. A reduced rate of return on common equity of 6.77% will apply to these facilities. This alternative revenue requirement mechanism will be in place through 2001, unless the CPUC determines otherwise. 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 of 10 Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 43 of the 1997 Annual Report to Shareholders. GAS RATEMAKING As noted above (see "Competition and the Changing Regulatory Environment-- Gas Industry"), the CPUC approved the Gas Accord in 1997. Additional information concerning the potential financial impact of the Gas Accord is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 24, and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on page 46 of the 1997 Annual Report to Shareholders. As part of the Gas Accord, the CPUC's traditional reasonableness reviews of Pacific Gas and Electric Company's core gas costs have been be replaced with a CPIM (which is also discussed above in "Competition and the Changing Regulatory Environment-Gas Industry") for the period June 1, 1994, through 2002. The Biennial Cost Allocation Proceeding (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, the CPUC also authorized Pacific Gas and Electric Company to set its natural gas rates for core customers each month rather than annually. Because Pacific Gas and Electric Company's gas costs are passed through to customers, this change will better align customer prices with actual gas costs. 1998 REVENUES Under frozen rates, any change in Pacific Gas and Electric Company's electric revenue requirements resulting from the items discussed below will not change electric customer rates. Decreases in electric revenue requirements will increase revenue from frozen rates available for collection from customers as the competition transition charge (CTC) for recovery of transition costs. Conversely, increases in electric revenue requirements will decrease revenue from frozen rates available for collection from customers as CTC for recovery of transition costs. AB 1890-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. In January 1998, the CPUC authorized a 1998 base revenue increase of $86 million in addition to the 1997 authorized base revenue increase of $164 million. Recovery of Transition Costs. In June 1997, the CPUC issued a decision adopting CTC ratemaking and accounting mechanisms to enable the utilities to measure their transition costs and track the recovery of transition costs. Revenues collected under frozen electric rates will be allocated to distribution, transmission, and generation services and PPPs based upon their respective cost-of-service, and to nuclear decommissioning, rate reduction bond debt service (for residential and small commercial customers), and transition cost recovery at levels authorized by the CPUC. Elimination of ECAC and ERAM. Effective January 1, 1998, the ECAC and ERAM balancing accounts were eliminated and the December 31, 1997, balances in these accounts were transferred to the Interim Transition Cost Balancing Account (ITCBA). The ECAC was undercollected by $468 million, and the ERAM was overcollected by $309 million. On January 1, 1998, the ITCBA balance of $160 million undercollection was transferred to the Transition Cost Balancing Account (TCBA). Until direct access begins, fuel and fuel-related costs which would otherwise have been included in an ECAC adjustment will be recorded in a memorandum account to be later transferred to the ITCBA. Costs recorded in the ITCBA are subject to a subsequent 11 reasonableness review, in which the CPUC determines whether those costs were reasonably incurred. Costs found to be unreasonable may be disallowed, or deducted, from the amount to be recovered in rates. When direct access begins, costs will be recovered from the market price, the TCBA, the Transition Revenue Account (TRA), or any other cost recovery mechanism approved by the CPUC. Cost of Capital. The CPUC's decision in the 1998 Cost of Capital proceeding authorized a utility return on common equity of 11.20%, a decrease from the 1997 level of 11.60%. The decision authorizes a utility capital structure for Pacific Gas and Electric Company of 48.00% common equity, 5.80% preferred stock, and 46.20% long-term debt. The combined authorized costs of debt, preferred stock, and the 11.20% return on common equity result in an overall return on utility rate base of 9.17%, a decrease from the 9.45% authorized for 1997. Since (i) the CPUC separately reduced the rate of return on Pacific Gas and Electric Company generation-related assets including Diablo Canyon, (ii) the FERC will authorize the rate of return for electric transmission assets at a later date, and (iii) transmission and storage rates have been set in the Gas Accord, the reduced rate of return of 11.20% adopted in the 1998 Cost of Capital Proceeding only applies to Pacific Gas and Electric Company's electric and gas distribution assets. The authorized cost of capital will decrease 1998 authorized electric and gas revenue by $25 million and $9 million, respectively. Pacific Gas and Electric Company has requested a rehearing of this decision. BCAP. In 1997, Pacific Gas and Electric Company filed its 1998 BCAP application. The Company is requesting an overall annual revenue requirement for the two-year BCAP period of approximately $1.5 billion of which approximately $107 million will be allocated for the collection of balancing accounts. The current annual revenue requirement is approximately $1.8 billion of which approximately $303 million has been allocated for the collection of balancing accounts. No rate changes resulting from the BCAP are expected to be implemented before August 1, 1998. AEAP. The 1997 Annual Earnings Assessment Proceeding (AEAP), which determines shareholder incentives earned for Pacific Gas and Electric Company's demand side management (DSM) programs, was submitted in December 1997. All of the parties to the proceeding agree that Pacific Gas and Electric Company is entitled to an incentive payment of approximately $32 million for Pacific Gas and Electric Company's 1996 DSM programs, to be collected in installments over a 10-year period. After consolidating the adjusted incentive payment installments from prior years, the net revenue change in 1998 from DSM shareholder incentives should be an electric decrease of approximately $4 million and a gas decrease of approximately $2 million. A CPUC decision adopting the shareholder incentives is expected during the first quarter of 1998. Electric Transmission Revenues. Prior to 1998, most electric transmission revenues were authorized by the CPUC as part of the GRC. In 1998, electric transmission revenues are expected to be authorized by the FERC. In 1997, Pacific Gas and Electric Company filed an application with the FERC requesting electric transmission revenues of $305 million. This requested revenue requirement is comparable to electric transmission revenues in CPUC-authorized 1997 electric rates. 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 $1,829 million for 1997. New investments totaled $41 million in 1997. The following table sets forth PG&E Corporation's estimated total capital requirements, consisting of capital expenditures for Pacific Gas and Electric Company's utility functions, including Diablo Canyon, as well as capital requirements for PG&E Corporation's other lines of business, and amounts for maturing debt and sinking funds for the years 1998 through 2000. These are forward-looking statements which involve a number of assumptions and uncertainties. Actual amounts may differ materially from the estimated amounts shown below. 12 PG&E CORPORATION CAPITAL REQUIREMENTS (IN MILLIONS)
1998 1999 2000 ------ ------ ------ Utility Capital Requirements (1).......................... $1,835 $1,739 $1,617 Other Capital Requirements (2)............................ 2,091 246 192 Maturing Debt and Sinking Funds........................... 784 559 740 ------ ------ ------ Total Capital Requirements............................ $4,710 $2,544 $2,549 ====== ====== ======
- -------- (1) Utility expenditures including Pacific Gas and Electric Company's electric and gas operations, 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. In August 1997, PG&E Corporation announced plans to acquire, through USGen, a portfolio of electric generating assets and power supply contracts from the New England Electric System for $1.59 billion. Including fuel and other inventories and transaction costs, financing requirements are expected to total approximately $1.75 billion, which amount is included in the table above. Most of the capital expenditures for Pacific Gas and Electric Company for 1998 through 2000 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 expenditures to improve the safety and reliability of Pacific Gas and Electric Company's electric transmission and distribution system consistent with AB 1890, as well as major projects associated with customer service improvements. PG&E Corporation estimates that its total capital requirements for the years 1998 through 2000 will include approximately $2 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 1998-2000 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 programs and estimates above are subject to revision and actual amounts may vary based upon changes in assumptions as to 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. In January 1997, PG&E Corporation acquired Teco and its subsidiaries for approximately $378 million, consisting of the purchase of a $61 million note, and $317 million of PG&E Corporation common stock. On July 31, 1997, PG&E Corporation acquired Valero's natural gas and natural gas liquids business. In the Valero acquisition, approximately 31 million shares of PG&E Corporation common stock were issued and approximately $780 million in long term debt was assumed. PRICE RISK MANAGEMENT PROGRAMS PG&E Corporation established an officer-level price risk management committee, and adopted a price risk management policy approved by the PG&E Corporation Board of Directors, 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. 13 The price 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 price 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. In 1997, PG&E Corporation approved and implemented trading and risk management policies for PG&E ET, and continued to seek approval from the CPUC to manage commodity price risks in Pacific Gas and Electric Company's business. The fair value of the market risk sensitive instruments (which includes the hedging and non-hedging instruments described above) as of December 31, 1997, is immaterial for financial instruments subject to commodity price risk. Additionally, as of December 31, 1997, PG&E Corporation calculated value-at- risk based on a 95 percent confidence level using five-day holding periods. Using this methodology, the potential for near-term losses in future earnings, fair values, and cash flows from reasonably possible near-term changes in market prices for financial instruments subject to commodity price risk is immaterial. PG&E Corporation anticipates an increase in the level of trading and risk management activity in 1998 due to expected growth in its national energy businesses and a continuing effort to manage anticipated price risks in Pacific Gas and Electric Company's business. Pacific Gas and Electric Company manages price risk independently from the activities of PG&E Corporation's other subsidiaries. 14 ELECTRIC UTILITY OPERATIONS ELECTRIC INDUSTRY RESTRUCTURING LEGISLATION In 1997, the relevant regulatory authorities took steps to implement AB 1890, including establishing the ISO and PX, and implementing direct access. AB 1890 also provides for the financing of the 10 percent rate reduction through rate reduction bonds, recovery of transition costs, and the funding of public purpose programs. INDEPENDENT SYSTEM OPERATOR AND POWER EXCHANGE AB 1890 requires the CPUC to facilitate the development of an ISO and a PX, and establishes a five-member Oversight Board to oversee the ISO and PX and appoint the members of the ISO and PX Governing Boards. In May 1997, the ISO and PX were formed as California non-profit corporations. The ISO and PX Governing Boards include 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. In March 1997, the trustee for the development of the ISO and PX, filed the documents with FERC that explained the structure, rates, terms and conditions applicable to the new market structure. While those documents have been subsequently revised and clarified in more recent filings by the duly constituted governing boards of the ISO and PX, on October 30, 1997, the FERC granted conditional authority for the ISO to begin operations and for the PX to charge market-based rates for electricity. Under AB 1890, it is intended that both California's investor-owned utilities and its publicly owned utilities relinquish 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. In December 1997, the ISO announced a delay of its operations and its formal assumption of control of the utilities' transmission systems. The PX also announced a delay in the commencement of its operations. Both the ISO and the PX announced that they expected to begin operations by March 31, 1998, at which time direct access will begin. The FERC requires that it be given at least 15 days notice before ISO and PX operations commence. VOLUNTARY GENERATION ASSET DIVESTITURE In 1997, California utilities produced a significant portion of the state's electric generation needs. In a competitive market, the CPUC is concerned that this level of generation may give existing utilities undue influence on the PX price. To alleviate this concern, Pacific Gas and Electric Company has indicated that it is willing to proceed with voluntary economic divestiture of at least 98% of its fossil-fueled power plants and all of its geothermal facilities. In December 1997, the CPUC approved Pacific Gas and Electric Company's sale of three electric generating plants with a combined capacity of 2,645 megawatts (MW) to Duke Energy Power Services, Inc. (Duke Energy) in Pacific Gas and Electric Company's first power plant auction. The aggregate bid was $501 million for these three fossil-fueled plants: 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 combined book value for these three fossil-fueled plants is approximately $370 million as of December 31, 1997. Pacific Gas and Electric Company will retain liability for required environmental remediation of any preclosing soil or groundwater contamination at these plants. Subject to various conditions, including regulatory approval of the transfer of various permits and licenses, and the commencement of direct access, Pacific Gas and Electric Company expects the sale to close in 1998. In 1997 Pacific Gas and Electric Company announced plans to conduct the second auction of four of its five remaining fossil-fueled power plants (the Hunters Point and Potrero Power Plants, both located in San Francisco County, and the Contra Costa and Pittsburg Power Plants, both located in Contra Costa County) and all of its geothermal facilities (The Geysers located in Lake and Sonoma counties) in 1998, subject to CPUC approval. These 15 plants have a combined generating capacity of 4,718 MW and a combined book value at December 31, 1997 of approximately $790 million. In January 1998, Pacific Gas and Electric Company filed its application to seek CPUC approval for the sale of these plants. In its application, Pacific Gas and Electric Company indicated that the auction for these plants would begin on March 16, 1998. Together, the eight power plants represent 98% of Pacific Gas and Electric Company's fossil-fueled generating capacity and all of its geothermal generating capacity. The facilities generate approximately 22% of Pacific Gas and Electric Company's total electric energy sold to customers. Pacific Gas and Electric Company is evaluating its options related to its remaining generation facilities and may decide not to retain its economic investments in those facilities. Any gain from the sale of power plants would 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 will continue to operate and maintain the power plants that are sold under a two-year operations and maintenance agreement with the new owner. To the extent that payments to Pacific Gas and Electric Company under these agreements exceed the Company's cost of operating the plants, the Company would offset other transition costs. Conversely, to the extent Pacific Gas and Electric Company's operating costs exceed the revenues from these agreements, the Company would have lower earnings. DIRECT ACCESS AB 1890 authorizes direct transactions between electricity suppliers and customers, beginning January 1, 1998. As described above, direct access has been delayed due to the delay in the start of operations of the ISO and PX. The ISO and PX expect to commence operations by March 31, 1998. In May 1997, the CPUC issued a decision which authorizes full implementation of direct access for all electric customers. In October 1997, the CPUC approved implementing tariffs, rate schedules, and service agreements. Customers participating in direct access would 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 begins. As of February 19, 1998 Pacific Gas and Electric Company had accepted over 11,781 direct access requests. 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.) The customer will be responsible for the cost of the meter and the meter installation. Also in May 1997, the CPUC issued a decision addressing the separation, or unbundling, of utility revenue cycle services, which include metering and billing. Under this decision, when direct access begins, energy service providers supplying the direct access market will be able to choose one of three billing options: (1) consolidated energy supplier billing, under which the utility would bill the energy supplier for the services provided directly by the utility to the customer and the supplier, in turn, would provide a consolidated bill to the customer; (2) Consolidated distribution company billing, under which the utility would place the supplier's energy charge on a distribution bill; or (3) dual billing, under which the energy supplier and the utility would bill separately for their own services. In December 1997, the CPUC adopted procedures and standards for non-utility performance of unbundled metering and meter data management services. Beginning 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. 16 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 ten months to ten years, and bearing interest at rates ranging from 5.94% to 6.48%. Pacific Gas and Electric Company will collect 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. Various consumer groups filed a voter initiative with the California Attorney General which seeks among other things, to (i) require investor-owned California utilities to provide an additional 10% rate reduction to residential and small commercial customers; (ii) eliminate transition cost recovery for nuclear investments by utilities (other than reasonable decommissioning costs); (iii) restrict transition cost recovery for non- nuclear investments (other than costs associated with QFs), unless the CPUC finds that the utility would be deprived of the opportunity to earn a fair rate of return; (iv) and prohibit the collection of any customer charges for rate reduction bonds, or alternatively, require the utility to offset such charges with an equal credit to customers. In February 1998, the California Secretary of State released the title and summary prepared for the proposed initiative by the California Attorney General's office. The sponsors of the initiative are now seeking sufficient signatures to qualify the initiative for the November 1998, statewide ballot. If the proposed initiative were voted into law, costly and time-consuming litigation may ensue. The Company believes that under applicable federal and state constitutional principles relating to the impairment of contracts, the State of California through such an initiative, could not repeal or amend the Company's authorization to collect principal, interest, and related costs for the rate reduction bonds if such repeal or amendment would substantially impair the rights of the bondholders. RECOVERY OF TRANSITION COSTS AB 1890 authorizes utilities 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 March 31, 2002, although certain transition costs may be recovered after March 31, 2002. These costs include certain employee-related transition costs, costs 17 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. 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. Pacific Gas and Electric Company has also announced plans to conduct the second auction of four of its five remaining fossil-fueled power plants and its geothermal facilities in 1998, subject to CPUC approval. 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 November and December 1997, the CPUC issued two decisions confirming the eligibility of Pacific Gas and Electric Company's various categories of non- nuclear generation-related costs for accelerated recovery as transition costs and adopting tariffs associated with enforcement of the nonbypassable CTC. The CPUC reduced the authorized rate of return on common equity to 6.77% for all Pacific Gas and Electric Company's non-nuclear generation-related assets, including hydroelectric and geothermal facilities, for a total rate of return of 7.13% for these assets. The reduced rate of return was retroactive to July 28, 1997, and will be effective for the duration of the transition period. The CPUC has ordered the utilities to file applications by June 1, 1998, to request recovery of transition costs in 1999. The annual transition cost proceeding will be used to develop a record to establish the guidelines for computing the transition costs on an ongoing basis and a mechanism for tracking the amount of transition costs and revenues recovered each year for the nuclear facilities based on actual recorded data. This proceeding will establish the reasonableness of accelerating recovery of transition costs and of estimating the market value of the assets subject to market valuation, and review actual employee transition costs, review all costs and revenues related to the PX and ISO revenues, and transition cost balancing account entries. In February 1998, Pacific Gas and Electric Company, along with the other California utilities, requested that the June 1, 1998, filing date be postponed to September 1, 1998, to reflect the delay of the commencement of direct access. 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, low-income energy efficiency programs at not less than $14 million per year, and the low-income rate discount program at approximately $38 million per year. In February 1997, the CPUC adopted a decision that turns over administration of the funding for public interest research and development, and renewable technologies programs to the CEC, beginning January 1, 1998. 18 The decision also changed the way some programs are administered. Before 1998, Pacific Gas and Electric Company and other utilities administered public purpose programs for energy efficiency and conservation, and low-income customer assistance. Under the CPUC's decision, the CPUC will appoint independent boards to oversee energy efficiency and low-income assistance programs. These boards will solicit competitive bids to determine who will administer the programs from January 1, 1998, through 2001. In December 1997, the CPUC approved Pacific Gas and Electric Company's continuing to act as interim administrator of energy efficiency programs until October 1, 1998. Thereafter, an open-bidding process is expected to be completed to select energy efficiency program administrators. Additional information concerning AB 1890 and its financial impact on PG&E Corporation is provided in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 43 of the 1997 Annual Report to Shareholders. 19 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 --------------------------------------------------------- 1997 1996 1995 1994 1993 ---------- ---------- ---------- ---------- ---------- CUSTOMERS (AVERAGE FOR THE YEAR): Residential............ 3,915,370 3,874,223 3,825,413 3,788,044 3,748,831 Commercial............. 465,461 459,001 454,718 452,049 449,619 Industrial............. 1,121 1,248 1,253 1,260 1,243 Agricultural........... 86,359 87,250 88,546 90,520 91,376 Public street and highway lighting...... 17,955 17,583 17,089 16,709 16,096 Other electric utilities............. 47 28 35 29 28 ---------- ---------- ---------- ---------- ---------- Total............... 4,486,313 4,439,333 4,387,054 4,348,611 4,307,193 ========== ========== ========== ========== ========== GENERATED, RECEIVED AND SOLD--KWH (IN MILLIONS): Generated: Hydroelectric plants.. 13,549 15,158 16,608 7,791 14,403 Thermal-electric plants: Fossil fueled........ 14,655 11,620 13,729 29,543 19,070 Geothermal........... 4,829 4,514 4,001 6,024 6,491 Nuclear.............. 17,071 16,720 16,269 15,265 16,816 ---------- ---------- ---------- ---------- ---------- Total thermal- electric plants.... 36,555 32,854 33,999 50,832 42,377 Wind and solar plants. 1 2 1 1 -- Received from other sources: (1).......... 55,745 57,134 54,935 47,199 48,859 ---------- ---------- ---------- ---------- ---------- Total gross system output(2).......... 105,850 105,148 105,543 105,823 105,639 Less: Delivered for interchange or exchange.............. 3,000 4,000 4,261 3,275 8,848 Delivered for the account of others(1).. 16,611 19,356 18,946 18,622 13,726 Helms pumpback energy(3)............. 661 898 937 467 452 Company use, losses, etc.(4)............... 6,200 6,500 6,040 7,838 6,960 ---------- ---------- ---------- ---------- ---------- Total energy sold... 79,378 74,394 75,359 75,621 75,653 ========== ========== ========== ========== ========== POWER PLANT FUEL SUPPLY (IN THOUSANDS): Natural gas (equivalent barrels).............. 23,983 20,193 23,143 44,119 28,791 Fuel oil............... 0 686 756 2,395 2,080 Nuclear (equivalent barrels).............. 29,152 28,574 27,814 26,135 28,724 ---------- ---------- ---------- ---------- ---------- Total............... 53,135 49,453 51,713 72,649 59,595 ========== ========== ========== ========== ========== POWER PLANT FUEL COSTS (AVERAGE COST PER MILLION BTU'S): Natural gas............ $ 2.87 $ 1.83 $ 2.06 $ 2.19 $ 2.86 Fuel oil............... $ 0 $ 2.66 $ 1.28 $ 2.83 $ 3.49 Weighted average....... $ 2.87 $ 1.92 $ 2.03 $ 2.23 $ 2.90 SALES--KWH (IN MILLIONS): Residential............ 25,946 25,458 24,391 24,326 24,111 Commercial............. 28,887 27,868 27,014 26,195 26,258 Industrial............. 16,876 15,786 16,879 16,010 16,492 Agricultural........... 3,932 3,631 3,478 4,426 3,672 Public street and highway lighting...... 446 438 425 418 419 Other electric utilities............. 3,291 1,213 3,172 4,246 4,701 ---------- ---------- ---------- ---------- ---------- Total energy sold... 79,378 74,394 75,359 75,621 75,653 ========== ========== ========== ========== ========== REVENUES (IN THOUSANDS): Residential............ $3,082,013 $3,033,613 $2,979,590 $2,980,966 $2,952,893 Commercial............. 2,932,560 2,840,101 2,964,568 2,892,302 2,914,855 Industrial............. 1,028,378 1,005,694 1,160,938 1,128,561 1,183,728 Agricultural........... 413,711 396,469 395,531 477,330 419,628 Public street and highway lighting...... 53,183 55,372 56,154 55,545 55,976 Other electric utilities............. 118,781 81,855 133,566 201,133 242,433 ---------- ---------- ---------- ---------- ---------- Revenues from energy sales.............. 7,628,626 7,413,104 7,690,347 7,735,837 7,769,513 Miscellaneous.......... (9,439) 112,303 92,538 142,771 87,991 Regulatory balancing accounts.............. 71,441 (365,192) (396,578) 142,939 19,421 ---------- ---------- ---------- ---------- ---------- Operating revenues.. $7,690,628 $7,160,215 $7,386,307 $8,021,547 $7,876,925 ========== ========== ========== ========== ==========
- -------- (1) Includes energy supplied through Pacific Gas and Electric Company's system by the City and County of San Francisco for San Francisco's own use and for sale by San Francisco to its customers, by the Department of Energy for government use and sale to its customers, and by the State of California for California Water Project pumping, as well as energy supplied by QFs and purchases from other utilities. (2) Includes energy output from Modesto and Turlock Irrigation Districts' own resources. (3) Represents energy required for pumping operations. (4) Includes use by business units other than the electric utility business units. 20
YEARS ENDED DECEMBER 31 ------------------------------------------------- 1997 1996 1995 1994 1993 --------- --------- --------- --------- --------- SELECTED STATISTICS: Total customers (at year- end)........................ 4,500,000 4,500,000 4,400,000 4,400,000 4,400,000 Average annual residential usage (kWh)................. 6,627 6,571 6,377 6,422 6,431 Average billed revenues per kWh (c): Residential................. 11.88 11.92 12.22 12.25 12.25 Commercial.................. 10.15 10.19 10.97 11.04 11.10 Industrial.................. 6.09 6.37 6.88 7.05 7.18 Agricultural................ 10.52 10.92 11.37 10.78 11.43 Net plant investment per customer ($)................ 3,027 3,198 3,228 3,362 3,436 Electric control area capability(megawatts)(1).... 23,157 22,724 22,099 21,851 23,009 Electric net control area peak demand(megawatts)(2)... 21,862 21,437 20,317 19,118 19,607
- -------- (1) Area net capability at time of annual peak, based on actual water conditions. (2) Net control area peak demand includes demand served by Modesto and Turlock Irrigation Districts' own resources. 21 ELECTRIC GENERATING AND TRANSMISSION CAPACITY As described above in "Electric Industry Restructuring Legislation-- Voluntary Generation Asset Divestiture," in 1997, Pacific Gas and Electric Company entered into an agreement for the sale of three fossil-fueled power plants and announced plans to sell an additional four fossil-fueled power plants and its geothermal facilities. As of December 31, 1997, Pacific Gas and Electric Company owned and operated the following generating plants, all located in California, listed by energy source:
NET OPERATING NUMBER CAPACITY GENERATION TYPE COUNTY LOCATION OF UNITS KW --------------- --------------- -------- ---------- Hydroelectric: Conventional Plants....... 16 counties in Northern and 109 2,698,100 Central California 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(1).......... San Francisco 3 377,000 Morro Bay(2).............. San Luis Obispo 4 1,002,000 Moss Landing(2)........... Monterey 2 1,478,000 Pittsburg(1).............. Contra Costa 7 2,022,000 Potrero(1)................ San Francisco 1 207,000 --- ---------- Steam Subtotal............ 21 5,871,000 --- ---------- Combustion Turbines: Hunters Point(1).......... San Francisco 1 52,000 Oakland(2)................ Alameda 3 165,000 Potrero(1)................ San Francisco 3 156,000 Mobile Turbines(3)........ Humboldt and Mendocino 3 45,000 --- ---------- Combustion Turbines Subtotal................. 10 418,000 --- ---------- Geothermal: The Geysers Power Plant(1)(4).............. Sonoma and Lake 14 1,224,000 Nuclear: Diablo Canyon............. San Luis Obispo 2 2,160,000 --- ---------- Thermal Subtotal........ 47 9,673,000 --- ---------- Total.............................................. 159 13,583,100 === ==========
- -------- (1) In 1997, Pacific Gas and Electric Company announced plans to sell these power plants and its geothermal facilities in connection with electric industry restructuring. (2) In 1997, Pacific Gas and Electric Company entered into an agreement to sell these power plants in connection with electric industry restructuring. (3) Listed to show capability; subject to relocation within the system as required. (4) The Geysers Power Plant net operating capacity is based on adequate geothermal steam supply conditions. Any decrease in capacity, at peak, is included as unavailable capacity in the control area net capacity table below. 22 The following table sets forth the available capacity for the control area (the area served by Pacific Gas and Electric Company and various publicly owned systems in Northern California) at the date of peak (including reduction for scheduled and forced outages and based on actual water conditions) by various sources of generation available to the control area and the total amount of generation provided by these sources during the year ended December 31, 1997.
CONTROL AREA NET CAPACITY (AT DATE OF 1997 PEAK) ---------------------- KW % -------------- ---------- Sources of Electric Generation: Company-Owned Plants: Fossil Fueled.... 6,289,000 48 Geothermal....... 1,224,000 9 Nuclear.......... 2,160,000 17 -------------- ------- Total Thermal... 9,673,000 74 Hydroelectric (available)..... 3,326,000 26 Solar............ 0 0 -------------- ------- Total Company- Owned Capacity.. 12,999,000 100 ============== ======= Less Unavailable Capacity........ (1,906,200) -------------- Total Company Available Capacity........ 11,092,800 48 Capacity Received from Others: QF Producers (available)..... 2,948,800 13 Area Producers & Imports......... 9,115,400 39 -------------- ------- Capacity from Others.......... 12,064,200 52 -------------- ------- Total Available Capacity........ 23,157,000 100 ============== ======= Total Area Demand(1)(2)..... 21,862,000 ==============
GENERATION YEAR ENDED DECEMBER 31, 1997(3) -------------------- KWH THOUSANDS % -------------- ------ Electric Generation: Company-Owned Plants: Fossil Fueled.... 14,654,952 14 Geothermal....... 4,829,743 5 Nuclear.......... 17,070,798 17 -------------- ------ Total Thermal... 36,555,493 36 Hydroelectric.... 13,549,123 13 Solar............ 1,164 0 -------------- ------ Total Company Generation...... 50,105,780 49 Helms Pumpback Energy.......... (661) 0 -------------- ------ Net Company Generation...... 50,105,119 49 ============== ====== Generation Received from Others: QF Producers..... 19,700,000 19 Area Producers & Imports......... 33,194,881 32 -------------- ------ Generation from Others......... 52,894,881 51 ============== ====== Total Area Generation...... 103,000,000 100 ============== ======
- -------- (1) The maximum control area peak demand to date was 21,862,000 kW which occurred in August 1997. (2) The reserve capacity margin at the time of the 1996 control area peak, taking into account short-term firm capacity purchases from utilities located outside Pacific Gas and Electric Company's service area: Pacific Gas and Electric Company's load responsibility for spinning reserve (capability already connected to the system and ready to meet instantaneous changes in demand) to the control area peak was 6.4% of the peak demand and total reserve (spinning reserve and capability available within a short period of time) was 7.4%. (3) Represents actual year net generation from sources shown. Generation received from others is based on the best available information at the publication date of this document. 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, 1997, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 80.3% and 82.7%, respectively. The table below outlines Diablo Canyon's refueling schedule for the next five years. In the past, Diablo Canyon refueling outages typically have occurred every 18 months. Beginning in 1996, Pacific Gas and Electric Company schedules refueling outages every 20 to 21 months, and it has been seeking NRC licensing authority to schedule such outages once every 24 months beginning in 2001. Though nominal 20-month cycles are firm, achieving a 24-month cycle is uncertain and its implementation could be delayed. The schedule below assumes 23 that a refueling outage for a unit will last approximately six 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.
1998 1999 2000 2001 2002 -------- --------- --------- ----- ----- Unit 1 Refueling............................. January September March Startup............................... March November May Unit 2 Refueling............................. February September April Startup............................... March November May
DIABLO CANYON RATEMAKING Prior to 1997, ratemaking for Diablo Canyon was determined by basing revenues primarily on the amount of electricity generated by the plant, rather than on traditional cost-based ratemaking. Under the prior ratemaking treatment, revenues were based on a pre-established price per kWh of electricity generated by the plant. That price consisted of a fixed component (3.15 cents per kWh) and a separate component that declined until 2000, at which point the variable component would have begun to escalate. For example, the total price per kWh for the year 1996 was 10.50 cents. Under this "performance-based" approach, Pacific Gas and Electric Company assumed a significant portion of the operating risk of the plant because the extent and timing of the recovery of actual operating costs, depreciation, and a return on the investment in the plant primarily depended on the amount of power produced and the level of costs incurred. Pacific Gas and Electric Company's earnings were affected directly by plant performance and costs incurred. Under this ratemaking treatment, earnings relating to Diablo Canyon could fluctuate significantly as a result of refueling or other extended plant outages, plant expenses, and the effects of a peak-period pricing mechanism. In connection with electric industry restructuring, in 1996, Pacific Gas and Electric Company proposed to price electric generation from Diablo Canyon at market prices and to complete recovery of its investment in Diablo Canyon by the end of 2001. Pacific Gas and Electric Company proposed to replace the Diablo Canyon performance-based ratemaking mechanism described above with: (1) a sunk cost revenue requirement to recover net investment in plant, including a return on this net investment, and (2) a performance-based Incremental Cost Incentive Price (ICIP) mechanism to recover the facility's variable and other operating costs and capital addition costs. As proposed by Pacific Gas and Electric Company, the sunk cost revenue requirement would be set to accelerate recovery of Diablo Canyon sunk costs from a period ending in 2016 to a five- year period ending in 2001. The related return on common equity associated with Diablo Canyon sunk costs would be reduced to 90 percent of Pacific Gas and Electric Company's long-term cost of debt. Pacific Gas and Electric Company's proposed ICIP mechanism would establish a rate per kWh generated by the facility. This rate would be based upon a fixed forecast of ongoing costs, capital additions, and capacity factors for the period 1997 through 2001. In May 1997, the CPUC issued a decision on Pacific Gas and Electric Company's proposal with an effective date of January 1, 1997. Under the decision, Pacific Gas and Electric Company's sunk costs will be recovered through a sunk cost revenue requirement, at a reduced return on common equity equal to 90 percent of Pacific Gas and Electric Company's embedded cost of debt, for a reduced total return of 7.17% which will be effective through 2001. The CPUC decision substantially reduces the level of Pacific Gas and Electric Company's proposed ICIP pricing through which ongoing operating costs and capital additions will be recovered. The CPUC decision adopts a fixed forecast of ICIP for 1997-2001, as shown below. The revenues are based on an assumed capacity factor of 83.6 percent. 24 INCREMENTAL COST INCENTIVE PRICES AND ESTIMATED TOTAL CPUC REVENUE REQUIREMENT
ESTIMATED TOTAL REVENUE REQUIREMENT ---------------------------------- 1997 1998 1999 2000 2001 ------ ------ ------ ------ ------ ($ IN MILLIONS) ICIP (cents per kWh)...................... 3.26 3.31 3.37 3.43 3.49 Sunk Cost Recovery........................ $1,385 $1,322 $1,259 $1,197 $1,135 ICIP Revenues............................. 515 523 532 542 552 ------ ------ ------ ------ ------ Total Revenue Requirement................. $1,900 $1,845 $1,791 $1,739 $1,687
The CPUC decision 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. Pacific Gas and Electric Company has sought a rehearing of the CPUC decision. 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. More information concerning the financial impact of Diablo Canyon ratemaking is included in "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 Annual Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 43 of the 1997 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 2000, 1999, and 2002, respectively. The fuel fabrication contract for the two units will supply their requirements for the next eight 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 has 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 officially acknowledged that it will not be able 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 2012, 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 25 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 Humboldt Bay Power Plant (Humboldt) at Humboldt for 20 to 30 years and, ultimately, to decommission the unit. The license amendment issued by the NRC allows storage of spent fuel rods at Humboldt until a federal repository is established. Pacific Gas and Electric Company has agreed to remove all nuclear waste as soon as possible after the federal disposal site is available. 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). The company, 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 Pacific Gas and Electric Company's 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 $23 million (property damage) and $7 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 $8.7 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 $159 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 $1.4 billion in 1997 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. The trust funds maintain substantially all of their investments in debt and equity securities. All earnings on the trust fund are reinvested. Monies may not be released from the external trust funds until authorized by the CPUC. As of December 31, 1997, Pacific Gas and Electric Company had accumulated external trust funds with an estimated fair value of $1 billion, based on quoted market prices, to be used for the decommissioning of the Company's nuclear facilities. In the past, the amount recovered in rates for nuclear decommissioning costs through an annual allowance has been reviewed by the CPUC as part of the GRC. The CPUC considers the trusts' asset levels, together with revised earnings and decommissioning cost 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, 1997, nuclear decommissioning costs recovered in rates were $33 million. 26 In compliance with AB 1890, effective on January 1, 1998, nuclear decommissioning costs, which are not transition costs, are 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. In its roadmap decision, the CPUC established a Nuclear Decommissioning Costs Triennial Proceeding to determine the decommissioning costs and establish the annual revenue requirement and attrition factors over 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 1998 through 2001. Total capacity payments are expected to remain at current levels during this period. Deliveries from these power producers accounted for approximately 18% of Pacific Gas and Electric Company's 1997 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, 1997, the total discounted future payments remaining under early termination or suspension contracts is $53 million. Pacific Gas and Electric Company also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, Pacific Gas and Electric 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 are incurred by the providers. These contracts expire on various dates from 2004 to 2031. The total cost of these payments is recoverable in rates. At December 31, 1997, the undiscounted future minimum payments under these contracts are $34 million for each of the years 1998 through 2002 and a total of $349 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 4% of Pacific Gas and Electric Company's 1997 electric energy requirements. The amount of energy received and the total payments made under all these power-purchase contracts were:
1997 1996 1995 ------ ------ ------ (IN MILLIONS) Kilowatt-hours received................................ 24,389 26,056 26,468 Energy payments........................................ $1,157 $1,136 $1,140 Capacity payments...................................... $ 538 $ 521 $ 484 Irrigation district and water agency payments.......... $ 56 $ 52 $ 50
As of December 31, 1997, Pacific Gas and Electric Company had commitments to purchase approximately 5,400 megawatts (MW) of capacity under CPUC-mandated power-purchase agreements. Of the 5,400 MW, approximately 4,600 MW were operational. Development of the balance is uncertain and it is estimated that very few of the remaining contracts will become operational. The 4,600 MW of operational capacity consists of 2,900 MW from cogeneration projects, 700 MW from wind projects, and 1,000 MW from other projects, including biomass, waste-to-energy, geothermal, solar, and hydroelectric. 27 GEOTHERMAL GENERATION Pacific Gas and Electric Company's geothermal units at The Geysers Power Plant (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. Pacific Gas and Electric Company's agreements with several of its steam suppliers permit the Company to curtail generation at The Geysers at the Company's discretion. The consolidated Geysers capacity factor is forecast to be approximately 48% of installed capacity in 1998, which includes economic curtailments, forced outages, scheduled overhauls, and projected steam shortage curtailments, as compared to the actual Geysers capacity factor of 45% in 1997. In connection with electric industry restructuring, in January 1998, Pacific Gas and Electric Company filed an application with the CPUC seeking approval to sell The Geysers, subject to CPUC and other regulatory approvals. See "Electric Utility Operations--Electric Industry Restructuring Legislation-- Voluntary Generation Asset Divestiture" above. HELMS PUMPED STORAGE PLANT Helms is a three-unit hydroelectric combined generating and pumped storage facility, completion of which was delayed due to a water conduit rupture in September 1982 and various start-up problems related to the plant's generators. Helms became commercially operable in June 1984. As a result of the damage caused by the rupture and the delay in the operational date, Pacific Gas and Electric Company incurred additional costs which were not initially included in rate base, and lost revenues during the period the plant was under repair. In September 1996, the CPUC approved a settlement resolving the treatment of remaining unrecovered Helms costs. As part of the 1996 GRC decision issued in December 1995, the CPUC directed Pacific Gas and Electric Company to perform a cost-effectiveness study of Helms. The CPUC indicated the study should consider changes in rate recovery for the plant including, among other things, the option of retirement with recovery of the investment without a return. The cost-effectiveness study submitted by Pacific Gas and Electric Company in July 1996 concluded that the continued operation of Helms is cost-effective. Pacific Gas and Electric Company recommended that the CPUC take no action based on the study, but address Helms along with other generating plants in the context of electric industry restructuring. Pacific Gas and Electric Company's net investment in Helms at December 31, 1997 was $691 million. Under electric industry restructuring, the uneconomic above-market portion of the Company's net investment in Helms is eligible for recovery as a transition cost. However, Pacific Gas and Electric Company will be placed at risk to recover its future operating costs in the newly restructured electric generation market. Because the CPUC has not specifically addressed the cost-effectiveness study, Pacific Gas and Electric Company is currently unable to predict whether there will be further changes in rate recovery resulting from the study. See "Pacific Gas and Electric Company Rate Matters--Electric Ratemaking" above. ELECTRIC TRANSMISSION AND DISTRIBUTION To transport energy to load centers, Pacific Gas and Electric Company as of December 31, 1997, owned and operated approximately 18,516 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations having a capacity of approximately 33,814,855 kilovolt-amperes (kVa), excluding power plant interconnection facilities. Energy is distributed to customers through approximately 108,170 circuit miles of distribution system and distribution substations having a capacity of approximately 23,000,000 kVa. Under AB 1890, it is intended that California's investor-owned utilities and its publicly owned utilities relinquish control, but not ownership, of their transmission facilities to the ISO. In 1997, the FERC issued various decisions to implement the formation and operation of the ISO and the PX as contemplated by AB 1890. The ISO will control the operation of the transmission system and provide open access transmission service on a nondiscriminatory basis. The FERC approved the various forms of agreements for must-run facilities that will be entered into between the utilities and the ISO to ensure grid reliability. The FERC also granted conditional 28 authority for operation of the ISO and the PX. After the ISO and the PX announced a delay in commencement of their operations, the FERC issued an order requiring the ISO and the PX to provide the FERC 15 days notice before the intended commencement date of operations and the ISO's assumption of operational control of certain transmission facilities. 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. 29 GAS UTILITY OPERATIONS Pacific Gas and Electric Company owns and operates an integrated gas transmission, storage, and distribution system in California. At December 31, 1997, Pacific Gas and Electric Company's system, including the PG&E Expansion (Line 401), consisted of approximately 5,700 miles of transmission pipelines, three gas storage facilities, and approximately 36,700 miles of gas distribution lines. GAS OPERATIONS Pacific Gas and Electric Company's peak day send-out of gas on its integrated system in California during the year ended December 31, 1997, was 4,145 million cubic feet (MMcf). The total volume of gas throughput during 1997 was approximately 888,000 MMcf, of which 262,000 MMcf was sold to direct end-use or resale customers, 173,000 MMcf was used by Pacific Gas and Electric Company primarily for its fossil-fueled electric generating plants, and 452,000 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 1997 Supplemental Report updates Pacific Gas and Electric Company's annual gas requirements forecast (excluding bypass volumes) for the years 1997 through 2010 forcasting growth in gas throughput served by Pacific Gas and Electric Company of 2% per year. 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 Pacific Gas and Electric Company's system entirely. The 1997 Supplemental Report forecasts a total bypass volume of 133,600 MMcf for 1998. 30 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 ---------------------------------------------------------- 1997 1996 1995 1994 1993 ---------- ---------- ---------- ---------- ---------- CUSTOMERS (AVERAGE FOR THE YEAR): Residential............ 3,491,963 3,455,086 3,417,556 3,372,768 3,339,859 Commercial............. 198,453 198,071 197,939 196,509 195,815 Industrial............. 1,650 1,500 1,500 1,400 1,265 Other gas utilities.... 3 2 2 2 4 ---------- ---------- ---------- ---------- ---------- Total............... 3,692,069 3,654,659 3,616,997 3,570,679 3,536,943 ========== ========== ========== ========== ========== GAS SUPPLY--THOUSAND CUBIC FEET (MCF) (IN THOUSANDS): Purchased: From Canada........... 280,084 253,209 261,800 319,453 329,693 From California....... 10,655 28,130 31,158 31,757 32,096 From other states..... 131,074 110,604 117,538 249,733 243,058 ---------- ---------- ---------- ---------- ---------- Total purchased..... 421,813 391,943 410,496 600,943 604,847 Net from storage (to storage).............. 14,160 6,871 (10,921) 3,591 (12,234) ---------- ---------- ---------- ---------- ---------- Total............... 435,973 398,814 399,575 604,534 592,613 Pacific Gas and Electric Company use, losses, etc.(1)....... 173,789 134,375 129,671 297,604 161,895 ---------- ---------- ---------- ---------- ---------- Net gas for sales... 262,184 264,439 269,904 306,930 430,718 ========== ========== ========== ========== ========== BUNDLED GAS SALES AND TRANSPORTATION SERVICE--MCF (IN THOUSANDS): Residential............ 191,327 190,246 191,724 214,358 206,053 Commercial............. 60,803 62,178 64,135 72,183 82,048 Industrial............. 10,054 12,015 14,045 19,495 133,178 Other gas utilities.... 0 0 0 894 9,439 ---------- ---------- ---------- ---------- ---------- Total............... 262,184 264,439 269,904 306,930 430,718 ========== ========== ========== ========== ========== TRANSPORTATION SERVICE ONLY--MCF (IN THOU- SANDS): Vintage system (Substantially all Industrial)(2)........ 218,660 189,695 143,921 142,393 101,888 PG&E Expansion (Line 401).................. 233,269 237,776 240,506 200,755 20,513 ---------- ---------- ---------- ---------- ---------- Total............... 451,929 427,471 384,427 343,148 122,401 ========== ========== ========== ========== ========== REVENUES (IN THOUSANDS): Bundled gas sales and transportation service: Residential........... $1,170,135 $1,109,463 $1,205,223 $1,268,966 $1,152,494 Commercial............ 374,084 362,819 421,397 444,805 467,962 Industrial............ 46,592 42,520 42,106 57,297 367,221 Other gas utilities... 3,701 510 0 2,371 25,654 ---------- ---------- ---------- ---------- ---------- Bundled gas revenues........... 1,594,512 1,515,312 1,668,726 1,773,439 2,013,331 Transportation only revenue: Vintage system (Substantially all Industrial).......... 207,160 180,197 167,325 132,509 56,733 PG&E Expansion (Line 401)................. 90,180 85,144 82,904 58,442 8,097 ---------- ---------- ---------- ---------- ---------- Transportation service only revenue.......... 297,340 265,341 250,229 190,951 64,830 Miscellaneous.......... 50,295 (9,271) (18,018) 40,427 (16,692) Regulatory balancing accounts.............. (137,787) 57,864 (43,771) (101,443) 95,339 Subsidiaries(3)........ 0 210,556 201,951 177,688 264,925 ---------- ---------- ---------- ---------- ---------- Operating revenues.. $1,804,360 $2,039,802 $2,059,117 $2,081,062 $2,421,733 ========== ========== ========== ========== ==========
- -------- (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 72,958 MMcf, 78,552 MMcf, 100,207 MMcf, 79,749 MMcf, and 7,205 MMcf for 1997, 1996, 1995, 1994 and 1993, 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. 31
YEARS ENDED DECEMBER 31 ------------------------------------------------- 1997 1996 1995 1994 1993 --------- --------- --------- --------- --------- SELECTED STATISTICS: Total customers (at year- end)....................... 3,700,000 3,700,000 3,600,000 3,500,000 3,600,000 Average annual residential usage (Mcf)................ 55 55 56 64 62 Heating temperature -- % of normal(1).................. 71.7 75.7 75.3 104.4 89.9 Average billed bundled gas sales revenues per Mcf: Residential................ 6.12 $5.83 $6.29 $5.92 $5.59 Commercial................. 6.15 5.84 6.57 6.16 5.70 Industrial................. 4.63 3.54 3.00 2.94 2.76 Average billed transportation only revenue per Mcf: Vintage system............. 0.71 0.67 0.69 0.60 0.52 PG&E Expansion (Line 401).. 0.39 0.36 0.34 0.29 0.39 Net plant investment per customer (2)............... $1,031 $1,378 $1,315 $1,340 $1,339
- -------- (1) Over 100% indicates colder than normal. (2) The net plant investment per customer figure for 1997 is lower than in previous years because it excludes 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, 1997, approximately 66% of Pacific Gas and Electric 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 3% was purchased from various California producers; and approximately 31% was purchased in other states (substantially all from U.S. Southwest sources and transported by the El Paso Natural Gas Company or Transwestern Pipeline Company pipelines). The following table shows the 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 ---------------------------------------------------------------------------------------------- 1997 1996 1995 1994 1993 ------------------ ------------------ ------------------ ------------------ ------------------ 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................. 280,084 $ 1.77 253,209 $ 1.57 261,800 $ 1.34 319,453 $ 1.94 329,693 $ 2.26 California............. 10,655 2.12 28,130 $ 1.90 31,158 $ 1.32 31,757 1.55 32,096 1.65 Other states (substantially all U.S. Southwest)....... 131,074 3.75 110,604 $3.72 117,538 $2.64 249,733 2.41 243,058 2.84 -------- ------ -------- ------ -------- ------ -------- ------ -------- ------ Total/Weighted Average. 421,813 $2.39 391,943 $2.21 410,496 $1.71 600,943 $2.12 604,847 $2.46 ======== ====== ======== ====== ======== ====== ======== ====== ======== ======
- -------- (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. The average prices for California gas include only commodity gas prices delivered to Pacific Gas and Electric Company's gas system. 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 "Competition and the Changing Regulatory Environment--Gas Industry"), the Gas Accord separates, or "unbundles," the rates for Pacific Gas and Electric Company's gas transmission services from its distribution services, increases the opportunities for core customers 32 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 "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 $255 million in 1997. This amount includes payments made to PG&E Gas Transmission, Northwest Corporation of approximately $49 million in 1997, which payments 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 Gas Transmission, Northwest Corporation 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 Gas Transmission, Northwest Corporation system to support its core and core subscription customers. Although this capacity commitment exceeds the amount needed to support Pacific Gas and Electric Company's core and core subscription customers, the Company has been able to assign substantially all of its unused capacity on PG&E Gas Transmission, Northwest Corporation's system to other shippers. 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 Gas Transmission, Northwest Corporation and El Paso Natural Gas Company. (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 $29 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 of capacity for 1992. It indicated that it would disallow costs through the term of the contract unless Pacific Gas 33 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. GAS REASONABLENESS PROCEEDINGS Recovery of gas costs through Pacific Gas and Electric Company's regulatory balancing account mechanisms is subject to a CPUC determination that such costs were incurred reasonably. Before June 1, 1994, annual reasonableness proceedings were conducted by the CPUC on a historic calendar year basis. As discussed above (see "Competition and the Changing Regulatory, Environment-- Gas Industry"), the annual reasonableness proceedings have been replaced by the CPIM. 1988-1990 CANADIAN GAS PROCUREMENT ACTIVITIES In March 1994, the CPUC issued a final decision on Pacific Gas and Electric Company's Canadian gas procurement activities during 1988 through 1990. The CPUC found that Pacific Gas and Electric Company could have saved its customers money if it had bargained more aggressively with its existing Canadian suppliers or bought less expensive gas from other Canadian sources. The decision ordered a disallowance of $90 million of gas costs, plus accrued interest estimated at approximately $25 million through December 31, 1993. Although Pacific Gas and Electric Company had challenged this decision by the CPUC in federal court, as part of the Gas Accord, the Company has agreed to forgo recovery of the $90 million disallowance ordered in the 1988-1990 reasonableness proceeding. In November 1997, Pacific Gas and Electric Company's federal lawsuit was dismissed with prejudice. PGT/PACIFIC GAS AND ELECTRIC COMPANY PIPELINE EXPANSION In November 1993, PG&E Gas Transmission, Northwest Corporation (formerly 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 Pacific Gas and Electric 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 Gas Transmission, Northwest Corporation (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 remains at risk for cost recovery of the PG&E Expansion through rates; however, a portion of the PG&E Expansion will be combined with other Pacific Gas and Electric Company transmission assets (specifically, a portion of Pacific Gas and Electric 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. 34 In 1994, Pacific Gas and Electric Company filed its application in the Pipeline Expansion Project Reasonableness case (PEPR) requesting that the CPUC find reasonable the full capital costs of the PG&E Expansion (estimated to be $810 million). In that proceeding, the ORA recommended a minimum of $100 million in capital costs be disallowed, while two intervenors jointly recommended a $237 million disallowance or reallocation of costs among customers. In addition, in 1996, a CPUC administrative law judge (ALJ) ordered consolidation of the market impact phase of the PEPR and the ITCS proceeding described above. An ALJ also ordered reopening of the 1993 PG&E Pipeline Expansion Rate Case to allow reconsideration of issues regarding the decision to construct the PG&E Expansion. The CPUC's 1997 decision approving the Gas Accord affirms the CPUC's 1994 finding that the decision to construct the PG&E Expansion was reasonable based on Pacific Gas and Electric Company management's knowledge at the time. The Gas Accord decision accepts the Gas Accord's proposal to set rates for Line 401 during the Gas Accord period based on total capital costs of $736 million. 35 PG&E CORPORATION'S GAS TRANSMISSION OPERATIONS During 1997, PG&E Corporation expanded its operations in the "midstream" portion of the gas business, which includes (1) the gas gathering, processing, storage, and transportation of natural gas, (2) the marketing of natural gas to gas distribution companies, electric utilities, municipalities, marketers, independent power producers, and end-use customers, and (3) the transportation of natural gas for these customers, producers and other pipelines. Through its January 1997 acquisition of Teco in Texas (now known as PG&E Gas Transmission Teco, Inc.), PG&E Corporation acquired various interests in natural gas pipeline systems in Texas, various investments in gas gathering and processing facilities, and a gas marketing operation in Houston, Texas. On July 31, 1997, PG&E Corporation completed its acquisition of Valero's natural gas and related businesses, including its gas gathering, transportation, and storage facilities, and its facilities relating to the processing, transportation, and marketing of natural gas liquids (NGLs). Valero's 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. PG&E Corporation acquired approximately 6,400 miles of natural gas pipeline and Valero's joint ownership or leasehold interests in approximately 1,100 miles of pipeline, including the Valero-Teco West Texas pipeline from Waha in west Texas to the San Antonio area. This pipeline system has the capacity to transport more than 3 bcf of gas per day. PG&E Corporation acquired a long-term lease of 7.2 bcf of storage capacity, approximately 536 miles of NGL pipelines and eight natural gas processing plants with a combined capacity of approximately 1.5 bcf per day of gas throughput, capable of producing approximately 93,000 barrels per day of NGLs. PG&E Gas Transmission, Northwest Corporation (formerly Pacific Gas Transmission Company or PGT) 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 billion cubic feet (bcf) per day of natural gas. It also owns two smaller diameter pipeline extensions within Oregon, totaling 106 miles. A subsidiary of PG&E Corporation also owns the PG&E Queensland Gas Pipeline, an approximately 389- mile of mostly 12-inch pipeline in Queensland, Australia, which provides natural gas transportation service to customers in the vicinity of the pipeline. In September 1996, the FERC approved a settlement of PG&E Gas Transmission, Northwest Corporation's 1994 rate case. The major issue in this proceeding was whether PG&E Gas Transmission, Northwest Corporation'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 "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%. Several parties are seeking rehearing of the FERC order approving the settlement, but PG&E Gas Transmission, Northwest Corporation currently expects the settlement to be upheld. 36 PG&E CORPORATION'S INDEPENDENT POWER GENERATION OPERATIONS 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. As of December 31, 1997, USGen, headquartered in Bethesda, Maryland, and its affiliates had ownership interests in 15 operating plants in eight states. The total generating capacity of these 15 plants is 3,249 MW. PG&E Corporation's combined net equity ownership in these plants as of December 31, 1997, represented 1,457 MW. The plants were largely financed with a combination of equity or equity commitments from the project sponsors and non-recourse debt. 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 4,400 MW in eight states. Together with its power marketing affiliate, USGen Power Services, L.P. (now PG&E Energy Trading--Power, L.P.), USGen and its affiliated or managed facilities sold 38.4 million megawatt-hours (MWh) of electricity into the wholesale electric market in 1997. In a series of transactions commencing in September 1997 and ending in January 1998, subsidiaries of PG&E Corporation acquired Bechtel Enterprises' interests in USGen, USOSC, and USGen Power Services, L.P. (now PG&E Energy Trading--Power, L.P.). PG&E Corporation also acquired all or a portion of Bechtel's interests in six independent power generating facilities which were jointly owned by PG&E Corporation and Bechtel, or by PG&E Corporation, Bechtel, and various third parties. On August 6, 1997, PG&E Corporation announced that it had agreed to acquire a portfolio of non-nuclear electric generating assets and power supply contracts from the New England Electric System (NEES) for $1.59 billion. These assets will be held by an affiliate of USGen. The $1.59 billion purchase price includes $225 million to be paid to NEES when customer choice of energy power suppliers is broadly available in New England. This amount will decline in accordance with a prorated schedule if the implementation of customer choice of energy power suppliers in New England occurs after January 1, 1999. In addition to the purchase price, NEES will also receive $85 million from USGen or its affiliates to pay for employee retraining, early retirement, and severance for NEES' employees affected by industry restructuring. USGen or one of its affiliates will also assume certain existing collective bargaining agreements between NEES and its labor unions. Including fuel and other inventories and transaction costs, financing requirements are expected to reach approximately $1.75 billion, of which approximately $1 billion will be funded through a combination of project level debt as well as debt of affiliates of USGen. In addition, up to $750 million of equity will be contributed over two years and will be financed initially using short-term debt of PG&E Corporation. The NEES facilities to be acquired consist of two hydroelectric systems with 14 stations, three fossil-fuel stations with 11units, and a pumped storage facility, with a combined generating capacity of approximately 4,000 MW. USGen or its affiliates will also assume the purchase obligations under 23 multi- year power purchase agreements between NEES' subsidiary, New England Power, and other utility and non-utility wholesale suppliers representing an additional 1,100 MW of production capacity. The terms of the acquisition call for New England Power to make annual support payments ranging approximately from $150 million to $170 million through early 2008 to offset the cost of power associated with these above-market contracts. The annual payment is a fixed obligation and is not dependent on the actual costs under the agreements, market prices, or NEES' regulatory status. As part of the electric industry deregulation in Massachusetts and Rhode Island, NEES' retail customers in those states may choose to continue receiving power from NEES (the "Standard Offer") at a fixed price or may choose a new power supplier. NEES' retail customers may make this choice through the year 2004 in Massachusetts and through the year 2009 in Rhode Island. It is expected that in the first half of 1998 NEES will auction its wholesale supply obligations under the Standard Offer to third parties. NEES' remaining supply obligation for these customers will be assigned to USGen, or one or more of its affiliates. 37 NEES will also assign to USGen or one or more of its affiliates its rights to supply power under several long-term power supply agreements, totaling approximately 100 MW. The acquisition also includes 100 million cubic feet per day of long-term natural gas supply and pipeline commitments, as well as a twelve-year lease on a self-unloading coal transportation vessel. PG&E Corporation's acquisition of NEES' assets, which is expected to be completed in 1998, is subject to a number of conditions, including approval of the FERC and state regulators. NEES' sale of these generating facilities and power supply contracts was prompted, in part, by the anticipated deregulation of the electric industry in several New England states. In Massachusetts, electric industry restructuring legislation took effect on March 1, 1998. A referendum will be voted on in November 1998, to repeal this legislation. 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 Standard Offer 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. In the second quarter of 1997, Bechtel acquired PG&E Corporation's partnership interest in International Generating Company, Ltd. (InterGen), a company formed to develop, own, and operate international electric generation projects. PG&E Corporation realized an after-tax gain of $120 million on the sale. 38 PG&E CORPORATION'S ENERGY SERVICES AND COMMODITIES PG&E Energy Services Corporation provides gas and electric energy services and commodities nationwide where permitted under applicable laws. PG&E Energy Services also provides commercial, industrial, and institutional customers with a wide range of services, including competitively priced electric and gas commodities, billing and information management services, energy management services, regulatory and rate analysis, and power quality solutions. PG&E Energy Services targets primarily industrial, commercial, and institutional customers. In 1997, PG&E Energy Services embarked on an aggressive campaign to open new offices in the United States, primarily to support its direct sales efforts and to establish a presence and market its services in emerging energy markets. It now has over 20 offices nationwide. PG&E Energy Services will compete with other non-utility electric retailers in California when direct access begins. See "Electric Utility Operations-- Electric Industry Restructuring Legislation" above. PG&E Energy Trading, headquartered in Houston, Texas, purchases bulk volumes of power and natural gas from PG&E Corporation affiliates; USGen and PG&E Gas Transmission, and from the wholesale market. PG&E Energy Trading then schedules, transports, and resells these commodities, either directly or through PG&E Energy Services--repackaging them to meet customers' individual delivery, price, and reliability needs. 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 supports PG&E Energy Services Corporation with a broad portfolio of energy products and services for the retail market. For more information, see "Price Risk Management Programs" above. 39 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 reflects Pacific Gas and Electric Company's 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 Pacific Gas and Electric Company'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, 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 have generally been recovered in rates. ENVIRONMENTAL PROTECTION MEASURES Pacific Gas and Electric Company's estimated expenditures for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements.With the sale of the Morro Bay, Moss Landing, and Oakland power plants, and the planned sale of the Contra Costa, Pittsburg, Hunters Point, Potrero, and Geysers power plants, Pacific Gas and Electric Company no longer expects to incur significant oxides of nitrogen (NOx) emission reduction compliance costs. See "Electric Utility Operations--Electric Industry Restructuring Legislation--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 Company's other natural gas compressor stations in California. Eventually the rules are likely to require NOx reductions of up to 80% at these natural gas compressor stations. Pacific Gas and Electric Company currently estimates that the total cost of complying with these rules will be up to $34 million over four years. 40 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. The new comprehensive assessment is scheduled for submission to the Central Coast Board in the first quarter of 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. Pacific Gas and Electric 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. Pacific Gas and Electric 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. To address the impacts of operation and maintenance activities at the Delta plants on sensitive species, Pacific Gas and Electric 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" (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. HAZARDOUS WASTE COMPLIANCE AND REMEDIATION Pacific Gas and Electric Company assesses, 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 the many hazardous waste storage, handling, and disposal requirements promulgated by the United States Environmental Protection Agency (EPA) under the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), along with California's 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 41 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. Pacific Gas and Electric Company has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites which operated in Pacific Gas and Electric Company's service territory. Pacific Gas and Electric Company owns all or a portion of 29 of these manufactured gas plant sites. Pacific Gas and Electric 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. Pacific Gas and Electric Company currently estimates that this program may result in expenditures of approximately $8 million to $11 million over the period 1998 through 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. Pacific Gas and Electric Company has been designated as a potentially responsible party (PRP) under the California Hazardous Substance Account Act (California Superfund) with respect to several manufactured gas plant sites. 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 PRP under CERCLA (the federal Superfund law) with respect to the Purity Oil Sales site in Malaga, California, the Jibboom Junkyard site in Sacramento, California, the Industrial Waste Processing site near Fresno, California, and the Lorentz Barrel and Drum site in San Jose, California. The Purity Oil Sales site is a former used oil recycling facility at which Pacific Gas and Electric Company is one of nine PRPs named in an EPA order requiring groundwater remediation at the site. Pacific Gas and Electric Company has also entered into an Administrative Order with the EPA to address soil contamination at the site. With respect to the Casmalia site near Santa Maria, California, Pacific Gas and Electric 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 Pacific Gas and Electric 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 Pacific Gas and Electric Company and other parties to initiate measures with respect to the study and remediation of that site. In addition to the sites discussed above, Pacific Gas and Electric Company has also been identified as a PRP at certain disposal sites under the California Superfund. Pacific Gas and Electric Company has also been sued for reimbursement of cleanup costs incurred by the State of California at Pacific Gas and Electric Company's former Jibboom Street Station B power plant in Sacramento, California. 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 Pacific Gas and Electric 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, 1997, of $232 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 $442 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 Pacific Gas and Electric Company is responsible. This upper limit of the range of costs was estimated using assumptions least favorable to Pacific Gas and Electric 42 Company based upon a range of reasonably possible, outcomes. Costs may be higher if Pacific Gas and Electric Company is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change. 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, under the proposed mechanism, utilities will have the opportunity to recover the shareholder portion of the cleanup costs from insurance carriers. Under the mechanism, 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. Pacific Gas and Electric Company can seek to recover hazardous substance cleanup costs under the new mechanism 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 will retain 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. In 1997, the CPUC approved Pacific Gas and Electric Company's proposal, with respect to certain generation plants to be divested, to prepare a forecast of environmental remediation costs for plants to be divested and use the forecast to adjust the current plant decommissioning cost estimate which will be recovered through the CTC ratemaking mechanism. Pacific Gas and Electric Company's revised estimate of costs to remediate environmental contamination for which it will remain liable at the Morro Bay, Moss Landing, and Oakland power plant is $39 million. Pacific Gas and Electric Company expects to recover $157 million of the $232 million accrued liability, discussed above, in future rates. The liability also includes $58 million related to power plant decommissioning for environmental clean-up, which is recovered through depreciation. Additionally, Pacific Gas and Electric 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. Pacific Gas and Electric Company had previously notified its insurance carriers that it seeks coverage under its comprehensive general liability policies to recover costs incurred at certain specified sites. In general, Pacific Gas and Electric Company's carriers neither admitted nor denied coverage, but requested additional information from the Company. Although Pacific Gas and Electric Company has received some amounts in settlements with certain of its insurers (approximately $55 million through December 31, 1997), 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 43 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. Pacific Gas and Electric 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 and other utilities are involved in 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 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 is a defendant in civil litigation in which plaintiffs allege 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 barring plaintiffs' personal injury claims. Plaintiffs have filed an appeal of this decision with the California Supreme Court. 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 $36 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 headings of this report entitled "PG&E Corporation's Gas Transmission Operations," "PG&E Corporation's Independent Power Generation Operations," and "PG&E Corporation's Energy Services and Commodities." 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. 44 COMPRESSOR STATION CHROMIUM LITIGATION Pacific Gas and Electric Company has been named as a defendant in several civil actions filed in California courts on behalf of more than 3,000 plaintiffs, and claims by approximately 2,800 plaintiffs are still pending. These cases are Aguayo v. Betz, Pacific Gas and Electric Company, et al., filed March 15, 1995, in Los Angeles County Superior Court; Aguilar v. Pacific Gas and Electric Company, Betz, et al., filed October 4, 1996, in Los Angeles County Superior Court; Adams v. Betz, filed September 21, 1994, in Los Angeles County Superior Court; Acosta, et al. v. Betz, Pacific Gas and Electric Company, et al., filed November 27, 1996, in Los Angeles Superior Court; Riep, et al. v. Pacific Gas and Electric Company, Betz, et al., filed February 14, 1997, in San Francisco Superior Court; Petitt, et al. v. Pacific Gas and Electric Company, Betz, et al., filed May 6, 1997, in Los Angeles Superior Court; Little and Mustafa v. Pacific Gas and Electric Company and PG&E Corporation, filed September 10, 1997, in San Bernardino Superior Court; and Whipple, et al. v. Pacific Gas and Electric Company and PG&E Corporation, filed September 10, 1997, in San Bernardino Superior Court. (Plaintiffs have agreed to dismiss PG&E Corporation in these last two suits.) These eight cases are collectively referred to as the "Aguayo Litigation." Each of the complaints in the Aguayo Litigation, except Little 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 Kettleman, Hinkley and Topock, California. The plaintiffs in the Aguayo Litigation include Pacific Gas and Electric Company employees, former Pacific Gas and Electric Company employees, relatives of Pacific Gas and Electric Company employees or former employees, residents in the vicinity of the compressor stations, and persons who visited the gas compressor stations, alleging exposure to chromium at or near the 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 parents. In the Adams case, the claims remaining against Pacific Gas and Electric Company arise from a cross-claim filed by Betz Chemical Company, the supplier of water treatment products containing chromium used at the gas compressor stations. In the Whipple case, pending in San Bernardino Superior Court, 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. All discovery and discovery motion practice in four of the five cases brought in Los Angeles Superior Court (Acosta v. Betz, Aguilar v. Pacific Gas and Electric Company, Aguayo v. Pacific Gas and Electric Company, and Adams v. Betz) has been referred by the judge to a discovery referee. Test plaintiffs have been chosen in the Aguayo matter, and discovery is ongoing. During 1997, more than 300 plaintiffs were dismissed from Aguayo v. Pacific Gas and Electric Company for failure to respond to discovery or otherwise pursue their claims. Discovery is beginning in the Acosta and Aguilar matters. Pacific Gas and Electric Company has a motion for good faith settlement pending in the Adams matter, as that case involves the same plaintiffs as a matter that Pacific Gas and Electric Company previously settled. The fifth case brought in Los Angeles Superior Court by eight plaintiffs (Pettit v. Pacific Gas and Electric Company) was not served on Pacific Gas and Electric Company until December 1997, and Pacific Gas and Electric Company filed an answer in January 1998. In Riep v. Pacific Gas and Electric Company, pending in San Francisco Superior Court, a trial date has been set for August 3, 1998. 45 Pacific Gas and Electric Company is responding to the complaints and asserting affirmative defenses. Pacific Gas and Electric 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, and Pacific Gas and Electric 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 In connection with PG&E Corporation's acquisition of Valero Energy Corporation, now known as PG&E Gas Transmission, Texas Corporation (GTT), PG&E Corporation entities succeeded to the litigation described below. City of San Benito, City of Primera, and City of Port Isabel v. Rio Grande Valley Gas Company, Valero Energy Corporation (now known as GTT), Southern Union Company, et al., 107th State District Court, Cameron County, Texas. On December 31, 1996, a petition was filed by the Texas cities of San Benito, Primera, and Port Isabel against Rio Grande Valley Gas Company (RGVG), Valero (now known as PG&E Gas Transmission, Texas Corporation), Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now known as Valero Gas Marketing Company), Reata Industrial Gas L.P. (now known as PG&E Reata Energy, L.P.), Valero Transmission L.P. (now known as PG&E Texas Pipeline, L.P.), and Valero Transmission Company (now known as VT Company), and two Southern Union entities: Southern Union Company ("SU") and Mercado Gas Services, Inc. On November 4, 1997, the cities of San Benito, Primera, and Port Isabel filed an amended petition and an amended motion for class action certification, and dismissed RGVG and the other SU entities. The amended petition named as defendants PG&E Gas Transmission, Texas Corporation and most of its subsidiaries (excluding the Canadian gas trading company and power trading company), PG&E Gas Transmission Teco, Inc. and most of its subsidiaries, and PG&E Energy Trading Corporation. In the amended petition, plaintiffs allege, among other things, that (1) the defendants that own or operate pipelines (in their capacities as merchants or transporters) have occupied city property and conducted pipeline operations without the cities' consent and without compensating the cities for use of the cities' properties and (2) the defendants that are gas marketers have failed to pay cities for accessing and utilizing pipelines located in the cities to flow gas under city streets to end-use gas customers. The petition also alleges various tort and statutory claims against defendants for failure to secure the consents. On November 5, 1997, orders were signed certifying a class, setting an opt out deadline of December 31, 1997, and ordering notice to all potential class members. The class certified consists of every incorporated municipality in Texas (excepting the cities of Edinburg, Mercedes, and Weslaco, which have filed separate actions) where any of the defendants engaged in business activities related to natural gas or natural gas liquids. The court named the cities of San Benito, Primera, and Port Isabel as class representatives. Fewer than 20 cities had opted out by the deadline. Some of the cities which opted out include Austin, Brownsville, Houston, Pharr, and San Antonio. One purported class member has filed a notice to vacate the class certified. Defendants' motion to transfer venue of this case to Bexar County, Texas, is currently pending. City of Edinburg v. Rio Grande Valley Gas Co., Valero Energy Corporation (now known as GTT), Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Southern Union Gas Co., and Southern Union Gas Co., 92nd State District Court, Hidalgo County, Texas. 46 On August 31, 1995, the City of Edinburg (City) filed a lawsuit against certain Valero and Southern Union companies. The City's pleadings assert various contract and tort actions, but all such claims are based on the theory that when Rio Grande Valley Gas Company (RGVG), as the local distribution company (LDC), was granted a franchise to sell gas and construct, maintain, own, and operate gas pipelines in city streets, such authorization extended to RGVG only and to no other entity. (On September 30, 1993, Valero sold the common stock of RGVG to Southern Union.) The City seeks monetary damages and injunctive relief on the theory that non-LDC owned pipelines were not authorized under the franchise with RGVG and were otherwise unlawful without the consent of, and the payment of compensation to, the City. The City also claims that when RGVG began to operate pipelines it did not own, such activities were not within the franchise and not otherwise consented to by the City. Consequently, the City contends that all non-LDC owned pipelines (which includes all of Valero Transmission, L.P.'s (now known as PG&E Texas Pipeline, L.P.) transmission and gathering lines in City rights-of-way) are "trespassing," and the Valero defendants must agree to a franchise or face removal by injunction. Further, the City contends that it is entitled to compensation for the past presence of such pipelines in city property without consent, and for the use of such pipelines to facilitate the past and present sales of gas, both for resale and to direct end-users, by any person or entity other than the LDC. Additionally, the City contends that RGVG has breached the franchise agreement by failing to pay all franchise fees owed because it did not include in the "gross sales" figure such incidental revenues as bad check fees, late payment charges, hook-up and disconnect fees, and transportation revenues. The City seeks to assert against the Valero defendants derivative liability for all of RGVG's acts and omissions. The latest pleading seeks actual damages in excess of $15 million, unspecified punitive damages, and injunctive relief against six Valero entities: Valero Energy Corporation (now known as GTT), Valero Transmission Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now known as PG&E Natural Gas Company), Reata Industrial Gas Company (now known as Valero Gas Marketing Company), 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.), and two SU entities. Trial was originally set in the Edinburg matter for September 9, 1996, but did not commence due to the disqualification on August 21, 1996, of the original judge. The new judge has set a jury trial for June 15, 1998. 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 Valero Gas Marketing Company), 92nd State District Court of Hidalgo County, Texas. A lawsuit filed by the City of Mercedes on April 16, 1997, is currently pending against Valero Gas Marketing Company and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.). On September 4, 1997, 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 defendants, gas marketers, have never owned or operated any pipelines. Plaintiff asserts these marketing companies have operated as "ghost pipelines" that have "used" public property without consent or franchise from the cities in which the defendants have sold gas. Plaintiff alleges that state law requires the defendants to have specific prior city consent by ordinance in order to transact business within or through city limits. The plaintiff alleges various tort and statutory claims against the defendants for failure to secure such consent. Plaintiff has requested a damage award, but has not specified an amount. Defendants' motion to transfer venue to Bexar County, Texas, is currently pending. On September 10, 1997, defendants also filed a motion to disqualify or recuse the presiding judge of the 92nd State District Court. This motion was granted on November 26, 1997. A new judge has not been appointed yet. If a class is certified, defendants anticipate that they will challenge such certification. 47 Other Texas Franchise Fee Litigation In addition to the three cases described above, involving the cities of Edinburg, Mercedes, San Benito, Primera, and Port Isabel, there are five lawsuits involving claims of a similar nature. In 1996, the South Texas cities of Alton and Donna also independently intervened as plaintiffs in the Edinburg lawsuit filed in the 92nd State District Court in Hidalgo County. Subsequently, in July 1996, these lawsuits were severed from the Edinburg lawsuit. The claims asserted by the cities of Alton and Donna are substantially similar to the Edinburg litigation claims. Damages are not quantified. In December 1996, two additional lawsuits were filed in South Texas making allegations substantially similar to those in the City of Edinburg litigation: City of La Joya v. Rio Grande Valley Gas Company, Valero Energy Corporation, Southern Union Company, et al., 92nd State District Court, Hidalgo County, Texas (filed December 27, 1996), and 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, Southern Union Company, et al., 93rd State District Court, Hidalgo County, Texas (filed December 27, 1996). The City of La Joya filed its lawsuit on its own behalf and as a putative class representative on behalf of all similarly situated cities against the same defendants sued in the Edinburg case. The same Southern Union entities in the Edinburg suit have also been named in this suit. 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, is also currently pending. Finally, on April 17, 1997, a petition was filed by the South Texas city of Weslaco. (City of Weslaco v. Reata Industrial Gas, L.P., et al., 92nd State District Court, Hidalgo County, Texas). Weslaco sued Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now known as Valero Gas Marketing Company), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy L.P.) The causes of action alleged are identical to those alleged in the City of Mercedes case. Defendants' motion to transfer venue to Bexar County, Texas is currently pending. Defendants have also filed a motion to disqualify or recuse the presiding judge, which is also pending. In 1996, the Texas city of Pharr sought and obtained class certification in a lawsuit styled City of Pharr, on behalf of itself and other Similarly Situated Entities v. Rio Grande Valley Gas Company, et al, 92nd Judicial District Court, Hidalgo County, Texas. By definition, the Pharr class consists only of those Texas cities, excluding Edinburg and McAllen, that have, or have had, natural gas franchises with RGVG or SU. The Pharr class was certified as to only two claims: breach of contract and declaratory relief dealing with the rights, status and legal relationship between plaintiff, the class members and the LDC regarding payment of franchise fees and use of granted easements. On December 30, 1997, the Pharr class certification order was affirmed on interlocutory appeal. In conjunction with this appeal, the appellate court specifically considered whether any of the Valero entities (now PG&E Gas Transmission, Texas Corporation entities) is a party to the Pharr class action and expressly found that such entities are not parties to that class action. Recently, however, Pharr class counsel has represented to various Texas courts that these entities were added to the Pharr class action as of December 9, 1997. As of February 25, 1998, none of these entities has been formally served in the Pharr class action, nor has counsel to these entities been furnished with a copy of the pleadings. However, the court's docket sheet shows a supplemental pleading was filed on or about December 12, 1997, which purports to add as defendants to the Pharr class action the same twenty-nine PG&E Corporation entities that are defendants in the San Benito litigation described above. The PG&E Corporation entities intend to defend vigorously against any attempt to add them as defendants in the Pharr class action, as well as against any attempt to modify the Pharr class definition in an effort to assert claims against the PG&E Corporation entities. 48 PG&E Corporation believes that the ultimate outcome of the Texas franchise fee cases described above will not have a material adverse impact on its financial position. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Not applicable. 49 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 1997 POSITION ---- ------------ -------- R. D. Glynn, Jr...... 55 Chairman of the Board, Chief Executive Officer, and President S. W. Gebhardt....... 46 Senior Vice President, President and Chief Executive Officer, PG&E Energy Services Corporation T. W. High........... 50 Senior Vice President, Administration and External Relations J. F. Jenkins-Stark.. 46 Senior Vice President, President and Chief Executive Officer, PG&E Gas Transmission Corporation J. P Kearney......... 49 Senior Vice President, President and Chief Executive Officer, U.S. Generating Company L. E. Maddox......... 42 Senior Vice President, President and Chief Executive Officer, PG&E Energy Trading Corporation M. E. Rescoe......... 45 Senior Vice President, Chief Financial Officer, and Treasurer G. R. Smith.......... 49 President and Chief Executive Officer, Pacific Gas and Electric Company G. B. Stanley........ 51 Senior Vice President, Human Resources B. R. Worthington.... 48 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 J. F. Jenkins-Stark.. Senior Vice President June 1, 1997 to current President and Chief June 1, 1997 to current Executive Officer, PG&E Gas Transmission Corporation
50
NAME POSITION PERIOD HELD OFFICE ---- -------- ------------------ Senior Vice President August 1, 1993 to May 30, 1997 and General Manager, Gas Supply Business Unit, Pacific Gas and Electric Company Vice President and January 15, 1992 to July 31, 1993 Treasurer, Pacific Gas and Electric Company J. P. Kearney........ Senior Vice President September 1997 to current President and Chief February 1989 to current Executive Officer, U.S. Generating 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.......... (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) Senior Vice President B. R. Worthington.... and General Counsel June 1, 1997 to current General Counsel December 18, 1996 to May 31, 1997 Senior Vice President and General Counsel, Pacific Gas and Electric Company June 1, 1995 to June 30, 1997 Vice President and General Counsel, Pacific Gas and Electric Company December 21, 1994 to May 31, 1995 Chief Counsel-Corporate, Pacific Gas and Electric Company January 10, 1991 to December 20, 1994
"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 1997 POSITION ---- ------------ -------- G. R. Smith.......... 49 President and Chief Executive Officer K. M. Harvey......... 39 Senior Vice President, Chief Financial Officer and Treasurer E. J. Macias......... 43 Senior Vice President and General Manager, Generation, Transmission, and Supply Business Unit R. J. Peters......... 47 Vice President and General Counsel J. K. Randolph....... 53 Senior Vice President and General Manager, Distribution and Customer Service Business Unit D. D. Richard, Jr.... 47 Senior Vice President, Governmental and Regulatory Relations G. M. Rueger......... 47 Senior Vice President and General Manager, Nuclear Power Generation Business Unit
51 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
52 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 60 under the heading "Quarterly Consolidated Financial Data (Unaudited)" in the 1997 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 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 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 16 under the heading "Selected Financial Data" in the 1997 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, 1997, was 3.19. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the year ended December 31, 1997, was 2.96. 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 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 17 through 30 under the heading "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the 1997 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 concerning PG&E Corporation's and Pacific Gas and Electric Company's market risk is set forth on page 28 in the table providing information about debt obligations and rate reduction bonds under the heading "Cash Flows From Financing Activities--Utility," and on page 30 under the heading "Price Risk Management" in the 1997 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Information responding to Item 8 is contained in the 1997 Annual Report to Shareholders on pages 31 through 61 under the respective headings for each of PG&E Corporation and Pacific Gas and Electric Company, "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement 53 of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities," "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. None. 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 50 through 52 in Part I of this report. Other information responding to Item 10 is included on pages 2 through 5 under the heading "Election of Directors of PG&E Corporation and Pacific Gas and Electric Company" and page 35 under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the 1998 Joint Proxy Statement relating to the 1998 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 page 8 under the heading "Compensation of Directors" and on pages 28 through 33 under the heading "Executive Compensation" (excluding the sections thereunder entitled "Nominating and Compensation Committee Report on Compensation," "Comparison of One-Year Total Shareholder Return," and "Comparison of Five-Year Cumulative Total Shareholder Return") in the 1998 Joint Proxy Statement relating to the 1998 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 10 and 11 under the heading "Security Ownership of Management" and on page 34 under the heading "Principal Shareholders" in the 1998 Joint Proxy Statement relating to the 1998 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 9 under the heading "Certain Relationships and Related Transactions" in the 1998 Joint Proxy Statement relating to the 1998 Annual Meetings of Shareholders, which information is hereby incorporated by reference. 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 1997 Annual Report to Shareholders, are incorporated by reference in this report: Statements of Consolidated Income for the Years Ended December 31, 1997, 1996, and 1995, for each of PG&E Corporation and Pacific Gas and Electric Company. 54 Statements of Consolidated Cash Flows for the Years Ended December 31, 1997, 1996, and 1995, for each of PG&E Corporation and Pacific Gas and Electric Company. Consolidated Balance Sheets at December 31, 1997, and 1996, for each of PG&E Corporation and Pacific Gas and Electric Company. Statements of Consolidated Common Stock Equity, Preferred Stock and Preferred Securities for the Years Ended December 31, 1997, 1996, and 1995, for each of PG&E Corporation and 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 60 of this Form 10-K. 3. Consolidated financial statement schedules: I--Condensed Financial Information of Parent for the Year Ended December 31, 1997. II--Consolidated Valuation and Qualifying Accounts of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 1997, 1996 and 1995. 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 effective as of January 1, 1998. 3.3 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 28, 1997 (Pacific Gas and Electric Company's Form 10-Q for quarter ended June 30, 1997 (File No. 1-2348), Exhibit 3.1). 3.4 By-Laws of Pacific Gas and Electric Company as of January 1, 1998. 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. 55 *10.3 Agreement regarding certain payments between U.S. Generating Company and Joseph Kearney. (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1997 (File No. 1-12609), Exhibit 10.2.) Filed only as an exhibit to the Annual Report on Form 10-K filed by PG&E Corporation under Commission File Number 1-12609. Confidential treatment of information omitted from this exhibit has been granted by the Commission until December 31, 1999. Omitted information has been filed separately with the Commission. *10.4 PG&E Corporation Deferred Compensation Plan for Directors. *10.5 PG&E Corporation Deferred Compensation Plan for Officers. *10.6 The Pacific Gas and Electric Company Savings Fund Plan for Non-Union Employees, as amended and restated effective as of October 1, 1997. *10.7 Short-Term Incentive Plan for Officers of Pacific Gas and Electric Company, effective January 1, 1996 (Pacific Gas and Electric Company's Form 10-K for fiscal year 1995 (File No. 1- 2348), Exhibit 10.7). *10.8 The Pacific Gas and Electric Company Retirement Plan applicable to non-union employees, as amended October 15, 1997, effective January 1, 1998. *10.9 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company, as amended through October 16, 1991 (Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.11). *10.10 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). *10.11 Pacific Gas and Electric Company Executive Flexible Perquisites Program (Pacific Gas and Electric Company's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16). *10.12 The 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). *10.13 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998. *10.14 Executive Compensation Insurance Indemnity in respect of Deferred Compensation Plan for Directors, Deferred Compensation Plan for Officers, Supplemental Executive Retirement Plan and Retirement Plan for Non-Employee Directors (Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.19). *10.15 PG&E Corporation Long-Term Incentive Program, as amended and restated effective as of January 1, 1998, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan. *10.16 PG&E Corporation Executive Stock Ownership Program, effective January 1, 1998. - -------- * 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. 56 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. 1997 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company (portions of the 1997 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition," "Report of Independent Public Accountants," and for each of PG&E Corporation and Pacific Gas and Electric Company, "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)" included only) (except for those portions which are expressly incorporated herein by reference, such 1997 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 Act of 1935 under Rule 2 by filing Form U-3A-2 dated February 27, 1998, pages 1 through 33 (File No. 1-12609). 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, 1997, for PG&E Corporation. 27.2 Financial Data Schedule for the year ended December 31, 1997, 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 as indicated and are hereby incorporated by reference. All exhibits filed herewith or incorporated by reference are filed with respect to both PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No. 1-2348), unless otherwise noted. Exhibits will be furnished to security holders of PG&E Corporation or Pacific Gas and Electric Company upon written request and payment of a fee of $0.30 per page, which fee covers only the registrants' reasonable expenses in furnishing such exhibits. The registrants agree to furnish to the Commission upon request a copy of any instrument defining the rights of long-term debt holders not otherwise required to be filed hereunder. (B) REPORTS ON FORM 8-K Reports on Form 8-K(/1/) during the quarter ended December 31, 1997, and through the date hereof: 1. October 16, 1997 Item 5. Other Events -- Performance Incentive Plan--Year-to-Date Financial Results 57 2. November 24, 1997 Item 5. Other Events A. Electric Industry Restructuring B. Gas Accord 3. December 19, 1997 Item 5. Other Events A. Electric Industry Restructuring B. CPUC Regulatory Proceedings C. Common Stock Repurchase Authorization 4. January 22, 1998 (As amended by Form 8-K/A dated February 5, 1998.) Item 5. Other Events A. Performance Incentive Plan--Year-to-Date Financial Results B. 1997 Consolidated Earnings (unaudited) C. Accelerated Stock 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) 58 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, 1998. PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY (Registrant) (Registrant) /s/ GARY P. ENCINAS /s/ GARY P. ENCINAS By _________________________________ By _________________________________ (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 Chairman of the Board of March 5, 1998 Directors, Chief Executive Officer, and *GORDON R. SMITH President (PG&E Corporation) President and Chief Executive Officer (Pacific Gas and Electric Company) B. PRINCIPAL FINANCIAL OFFICERS MICHAEL E. RESCOE /s/ MICHAEL E. RESCOE March 5, 1998 Senior Vice President, Treasurer, and Chief Financial Officer (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, 1998 (PG&E Corporation) Vice President and Controller (Pacific Gas and Electric Company) D. DIRECTORS *RICHARD A. CLARKE *H. M. CONGER *DAVID A. COULTER *C. LEE COX *WILLIAM S. DAVILA *ROBERT D. GLYNN, JR. *DAVID M. LAWRENCE *RICHARD B. MADDEN *MARY S. METZ Directors of PG&E Corporation and *REBECCA Q. MORGAN Pacific Gas and Electric March 5, 1998 Company, *CARL E. REICHARDT except as noted *JOHN C. SAWHILL *GORDON R. SMITH (Director of Pacific Gas and Electric Company, only) *BARRY LAWSON WILLIAMS
/s/ GARY P. ENCINAS *By ________________________________ (Gary P. Encinas, Attorney-in-Fact) 59 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 Annual Report on Form 10-K, and have issued our report thereon dated February 9, 1998. 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) of this Annual Report on 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 basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic 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 basic consolidated financial statements taken as a whole. /s/ ARTHUR ANDERSEN LLP _______________________ ARTHUR ANDERSEN LLP San Francisco, California February 9, 1998 60
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED BALANCE SHEET December 31, 1997 ------------- (In millions) Assets: Cash and cash equivalents................................ $ 1 Other current assets..................................... 149 ------ Total current assets................................. 150 Investments in subsidiaries.............................. 9,600 Other deferred charges................................... 1 ------ Total Assets......................................... $9,751 ====== Liabilities and Stockholders' Equity: Current Liabilities Accounts payable Related parties.................................... $ 635 Other.............................................. 10 Accrued taxes........................................ 46 Dividends payable.................................... 118 ------ Total current liabilities............................ 809 Noncurrent Liabilities................................... 1 Stockholders' Equity Common stock......................................... 6,366 Reinvested earnings.................................. 2,575 ------ Total stockholders' equity........................... 8,941 ------ Total Liabilities and Stockholders' Equity........... $9,751 ====== CONDENSED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1997 1997 ---------- (In millions, except per share amounts) Equity in earnings of subsidiaries....................... $ 743 Operating expenses....................................... (21) Interest expense......................................... (23) ------ Income Before Income Taxes............................... 699 Income taxes............................................. (17) ------ Net Income............................................... $ 716 ====== Weighted Average Common Shares Outstanding............... 410 Earnings Per Common Share................................ $ 1.75 ======
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT (CONTINUED) CONDENSED STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1997 1997 ---------- (in millions) Cash Flows From Operating Activities Net income............................................... $ 716 Adjustments to reconcile net income to net cash provided by operating activities: Dividends received from consolidated subsidiaries.. 763 Other-net.......................................... (167) ------- Net cash provided by operating activities................ $ 1,312 Cash Flows From Investing Activities..................... (150) Cash Flows From Financing Activities Common stock repurchased........................... (804) Dividends paid..................................... (367) Other-net.......................................... 10 ------- Net cash used by financing activities.................... (1,161) Net Change in Cash and Cash Equivalents.................. 1 Cash and Cash Equivalents at January 1................... 0 ------- Cash and Cash Equivalents at December 31................. $ 1 =======
PG&E CORPORATION SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995 Column A Column B Column C Column D Column E Additions --------------------- Balance Charged at to Costs Charged Balance Beginning and to Other at End of Description of Period Expenses Accounts Deductions Period ------------ --------- ---------- --------- ------------ --------- (in thousands) VALUATION AND QUALIFYING ACCOUNTS DEDUCTED FROM ASSETS: 1997: Allowance for uncollectible accounts............... $57,904 $42,500 $ 0 $ 27,492(2) $72,912 ======= ======= ======= ========= ======= 1996: Reserve for deferred project costs................. $ 5,710 $ -- $ -- $ 5,710(1) $ 0 ======= ======= ======= ========= ======= Allowance for uncollectible accounts............... $35,520 $55,566 $ 1,836 $ 35,018(2) $57,904 ======= ======= ======= ========= ======= Reserve for land costs............................. $ 4,444 $ -- $ -- $ 4,444(1) $ 0 ======= ======= ======= ========= ======= 1995: Reserve for impairment of oil and gas properties....................................... $ 4,341 $ -- $ -- $ 4,341(3) $ 0 ======= ======= ======= ========= ======= Reserve for deferred project costs................. $25,800 $ -- $ -- $ 20,090(1) $ 5,710 ======= ======= ======= ========= ======= Allowance for uncollectible accounts............... $29,769 $50,327 $ -- $ 44,576(2) $35,520 ======= ======= ======= ========= ======= Reserve for land costs............................. $ 5,960 $ -- $ -- $ 1,516(1) $ 4,444 ======= ======= ======= ========= =======
(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 noncurrents assets. (2) Deductions consist principally of write-offs, net of collections of receivables previously written off. (3) Deductions consist principally of write-offs of expired leaseholds on reserved property. Deduction in 1995 results from sale of oil and gas properties. PACIFIC GAS AND ELECTRIC COMPANY SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995
Column A Column B Column C Column D Column E Additions --------------------- Balance Charged at to Costs Charged Balance Beginning and to Other at End of Description of Period Expenses Accounts Deductions Period ------------ --------- ---------- --------- ------------ --------- (in thousands) VALUATION AND QUALIFYING ACCOUNTS DEDUCTED FROM ASSETS: 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) $ 0 ======= ======= ======= ========= ======= Allowance for uncollectible accounts............... $35,520 $55,566 $ 1,836 $ 35,018(2) $57,904 ======= ======= ======= ========= ======= Reserve for land costs............................. $ 4,444 $ -- $ -- $ 4,444(1) $ 0 ======= ======= ======= ========= ======= 1995: Reserve for impairment of oil and gas properties....................................... $ 4,341 $ -- $ -- $ 4,341(3) $ 0 ======= ======= ======= ========= ======= Reserve for deferred project costs................. $25,800 $ -- $ -- $ 20,090(1) $ 5,710 ======= ======= ======= ========= ======= Allowance for uncollectible accounts............... $29,769 $50,327 $ -- $ 44,576(2) $35,520 ======= ======= ======= ========= ======= Reserve for land costs............................. $ 5,960 $ -- $ -- $ 1,516(1) $ 4,444 ======= ======= ======= ========= =======
(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. (3) Deductions consist principally of write-offs of expired leaseholds on reserved property. Deduction in 1995 results from sale of oil and gas properties. EXHIBIT INDEX 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 effective as of January 1, 1998. 3.3 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 28, 1997 (Pacific Gas and Electric Company's Form 10-Q for quarter ended June 30, 1997 (File No. 1-2348), Exhibit 3.1). 3.4 By-Laws of Pacific Gas and Electric Company as of January 1, 1998. 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. 1 *10.3 Agreement regarding certain payments between U.S. Generating Company and Joseph Kearney. (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1997 (File No. 1-12609), Exhibit 10.2.) Filed only as an exhibit to the Annual Report on Form 10-K filed by PG&E Corporation under Commission File Number 1-12609. Confidential treatment of information omitted from this exhibit has been granted by the Commission until December 31, 1999. Omitted information has been filed separately with the Commission. *10.4 PG&E Corporation Deferred Compensation Plan for Directors. *10.5 PG&E Corporation Deferred Compensation Plan for Officers. *10.6 The Pacific Gas and Electric Company Savings Fund Plan for Non-Union Employees, as amended and restated effective as of October 1, 1997. *10.7 Short-Term Incentive Plan for Officers of Pacific Gas and Electric Company, effective January 1, 1996 (Pacific Gas and Electric Company's Form 10-K for fiscal year 1995 (File No. 1- 2348), Exhibit 10.7). *10.8 The Pacific Gas and Electric Company Retirement Plan applicable to non-union employees, as amended October 15, 1997, effective January 1, 1998. *10.9 Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company, as amended through October 16, 1991 (Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.11). *10.10 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). *10.11 Pacific Gas and Electric Company Executive Flexible Perquisites Program (Pacific Gas and Electric Company's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16). *10.12 The 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). *10.13 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998. *10.14 Executive Compensation Insurance Indemnity in respect of Deferred Compensation Plan for Directors, Deferred Compensation Plan for Officers, Supplemental Executive Retirement Plan and Retirement Plan for Non-Employee Directors (Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.19). *10.15 PG&E Corporation Long-Term Incentive Program, as amended and restated effective as of January 1, 1998, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan. *10.16 PG&E Corporation Executive Stock Ownership Program, effective January 1, 1998. - -------- * 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. 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. 1997 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company (portions of the 1997 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition," "Report of Independent Public Accountants," and for each of PG&E Corporation and Pacific Gas and Electric Company, "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)" included only) (except for those portions which are expressly incorporated herein by reference, such 1997 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 Act of 1935 under Rule 2 by filing Form U-3A-2 dated February 27, 1998, pages 1 through 33 (File No. 1-12609). 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, 1997, for PG&E Corporation. 27.2 Financial Data Schedule for the year ended December 31, 1997, 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 as indicated and are hereby incorporated by reference. All exhibits filed herewith or incorporated by reference are filed with respect to both PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No. 1-2348), unless otherwise noted. Exhibits will be furnished to security holders of PG&E Corporation or Pacific Gas and Electric Company upon written request and payment of a fee of $0.30 per page, which fee covers only the registrants' reasonable expenses in furnishing such exhibits. The registrants agree to furnish to the Commission upon request a copy of any instrument defining the rights of long-term debt holders not otherwise required to be filed hereunder. (B) REPORTS ON FORM 8-K Reports on Form 8-K(/1/) during the quarter ended December 31, 1997, and through the date hereof: 1. October 16, 1997 Item 5. Other Events -- Performance Incentive Plan--Year-to-Date Financial Results 3 EX-3.2 2 BYLAWS OF PG&E CORPORATION AMENDED AS OF 01-01-98 EXHIBIT 3.2 BYLAWS OF PG&E CORPORATION AMENDED AS OF JANUARY 1, 1998 ----------------------------- 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. The Board of Directors shall consist of fourteen (14) 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. 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. 2 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. 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 3 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. 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. 4 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 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. 5 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, 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. 6 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 CO AMENDED AS OF 1/1/98 EXHIBIT 3.4 BYLAWS OF PACIFIC GAS AND ELECTRIC COMPANY AMENDED AS OF JANUARY 1, 1998 ----------------------------- 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 shall consist of fifteen (15) 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. 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. [2] 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 [3] 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. [4] 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 [5] 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. [6] EX-10.2 4 GAS ACCORD SETTLEMENT AGREEMENT EXHIBIT 10.2 =============================================================================== Subject to Rule 51 of the CPUC Rules of Practice and Procedure, Rule 601 et seq. of the FERC Rules of Practice, Rule 408 of the Federal Rules of Evidence, and Section 1152 of the California Evidence Code =============================================================================== [GAS ACCORD LOGO] THE GAS ACCORD SETTLEMENT AGREEMENT ------------------------------------ I. INTRODUCTION A. PROPOSAL FOR A NEW GAS MARKET STRUCTURE FOR NORTHERN CALIFORNIA The Gas Accord is a proposal to significantly restructure the way PG&E provides natural gas service to California consumers by increasing competition and customer choice. In part, the Gas Accord is a response to signals from regulators and the market that the time has come for such changes. The Gas Accord is also a vision of how the natural gas industry in northern California should be structured as we enter the next century. The Gas Accord consists of three broad initiatives. First, the Accord unbundles PG&E's gas transmission and a portion of storage services, places PG&E at risk for these costs, and changes the terms of service and the rate structure for gas transportation so that customers' rates more accurately reflect the facilities used to serve them. PG&E's service area is served by an integrated high-pressure transmission system that resembles an interstate pipeline system more than a typical local distribution company (LDC) system. The Accord unbundles the transmission system, and requires PG&E to operate and provide service on that system similar to an interstate pipeline. PG&E will continue to provide distribution service, much as it does today. Second, the Accord changes PG&E's role in procuring gas supplies for core customers in order to increase customer choice. It reduces PG&E's role in core procurement, and reduces PG&E's holdings of interstate transportation capacity. It also provides for negotiations between PG&E and California gas producers for a mutual release of supply contracts with PG&E. PG&E's core procurement department will continue to hold a portion of storage capacity to ensure system reliability and a defined standard of customer service reliability, but customers will be free to seek commodity and transmission services from alternative suppliers. As part of this Agreement, the Core Procurement Incentive Mechanism agreed to by PG&E and DRA in 1996 must be implemented for an initial period through 1997, followed by the revised incentive mechanism described in the Gas Accord for the period thereafter. The Gas Accord period will extend from the date of implementation, which PG&E is asking to be July 1, 1997, through December 31, 2002. Third, the Gas Accord settles all major outstanding gas regulatory issues. Neither PG&E, the CPUC, nor market participants can expend the energy and resources to proceed with the Gas Accord while at the same time arguing about whether PG&E acted reasonably under the old rules. The changes proposed herein are reasonable and bold responses to several forces for change that have manifested themselves since gas restructuring began in California, about ten years ago. On the regulatory side, the CPUC has initiated programs to segment the noncore from the core market, with rights accorded to noncore customers to obtain transmission service and commodity supplies separately from bundled PG&E service. Core customer representatives are now advocating an increase in the competitive choices available to them. In addition, the CPUC has changed the way it regulates both Southern California gas utilities, approving performance-based regulation for each utility's gas procurement. The CPUC also has called for an OII/OIR for the purpose of further restructuring the California natural gas industry on at least two occasions, most recently in a decision (D.94- 02-042) approving interim rates for PG&E's Pipeline Expansion Project. The market, too, has signaled a desire for change. Customers have sought more options for natural gas transportation and sources of supply. Marketers and producers have stated there are obstacles to selling directly to core customers, and there have been proposals to build competitive pipelines into PG&E's service area. All of these demonstrate that PG&E's current transportation and service structure is outdated. For these reasons, further changes are inevitable. PG&E could resist and watch these changes occur piecemeal, to the possible disadvantage of its customers and shareholders; however, this Gas Accord, negotiated with the market participants, offers a better prospect for a rational result. All participants in the Accord process -- market participants, the CPUC, and PG&E -- have significant interests in the process of change. It is vital that this process result in a fair resolution of past issues and a fair opportunity to compete in the new world of unbundled competitive gas markets. Unbundling of services will increase market participation. Each competitive market -- transmission, procurement, and other services --inevitably will lead to the development of new services and increased choices for consumers. As these markets become contested by new service providers, the freedom to compete in each on an equal basis must be granted to all parties, including PG&E. The Accord will move PG&E and the marketplace toward this vision. The Accord is a negotiated compromise on a number of issues related to many proceedings. If not accepted by the Commission, the Accord shall not be admissible in evidence in this or any other proceeding. Nothing contained herein shall be deemed to constitute an admission or an acceptance by any party of any fact, principle, or position contained herein. The Accord is to be treated as an entire package and not as a collection of separate agreements on discrete proceedings, nor is the restructuring proposal separable from the resolution of past issues. To accommodate the interests of different parties on diverse issues, changes, concessions, or compromises in one section of the Accord necessitated changes, concessions, or compromises in other sections. -2- In an August 16, 1995, Assigned Commissioner's Ruling on the Gas Accord process, Assigned Commissioner Fessler stated: I encourage all affected parties to participate in settlement discussions, and I encourage PG&E to include all gas market participants in its negotiations. I look with disfavor on parties that decline fair opportunities to participate in settlement discussions, then criticize agreements reached in their absence. (August 16, 1995, ACR, p. 5). The Gas Accord negotiations have met the Assigned Commissioner's standard for wide participation, and the Accord presents a new, more competitive structure for the natural gas marketplace in northern California that is broadly supported by the market participants. The settling parties encourage the Commission to adopt and implement the Gas Accord. B. ELEMENTS OF THE AGREEMENT 1. Unbundle the rates and service options for transmission system service from distribution system service. The transmission system is defined as PG&E's backbone and local gas transmission lines, including gathering and Stanpac facilities. The local transmission system includes distribution feeder mains (DFMs). A map of PG&E's system is included at the end of this Section. 2. Charge transmission, storage, and distribution rates to those customers who use these facilities pursuant to contractually-defined terms of service. 3. Provide balancing service through a single integrated gas system for both transmission level and distribution level customers. PG&E proposes initially to continue a monthly balancing service, with imbalance trading, tighter tolerance bands and monthly cash-out provisions. 4. Establish transmission system services that eliminate the crossover ban and the backbone credit. 5. Offer various paths over the transmission system. Each path requires a separate contract. See Section II for more information on the definition of the paths and applicable delivery and receipt points. These paths include: -3- a. Malin to On-system for the Core; b. Malin to On-system; c. Topock to On-system; d. California Production and Storage to On-system; e. Malin to Off-system; f. Topock to Off-system; g. California Production, Storage, Market Center/Hub Services, and On- system Delivery Points to Off-system; and h. G-XF Firm Service. On-system is defined as any point at which deliveries are made to, or for ultimate delivery to, PG&E's distribution facilities, PG&E's storage facilities, a third party's storage facilities located in PG&E's service territory, or end-use or wholesale loads located in PG&E's service territory. Off-system is defined as any point of interconnection for delivery outside of PG&E's service territory. 6. Provide new services over these paths using (a) Line 300 capacity, and (b) capacity consisting of that portion of Line 400 capacity not reserved for the core and that portion of Line 401 capacity not reserved under long-term firm contracts with existing firm Expansion shippers. This combined Malin capacity is to be redesignated by the Commission as non-Expansion capacity, which shall be subject to phased- in rates and shall not be subject to the tariff or contract provisions and rights that apply to the Line 401 capacity reserved under long-term Expansion contracts. 7. For ratemaking purposes, phase-in the embedded cost of 375 MMcf/d (381 Mdth/d) of Line 401 capacity into the Line 400 capacity not reserved for the core over the period from 1997 through 2002. The phase-in will begin at 200 MMcf/d (203 Mdth/d). This phase-in schedule is consistent with historical Line 401 on-system usage and projected on-system noncore demand growth. This will determine the Malin to on-system path costs. (See Section II.I.3 for the complete phase-in schedule.) 8. Provide to the retail core 600 MMcf/d (609 Mdth/d) and to core wholesale 6.5 MMcf/d (6.6 Mdth/d) of Malin to on-system vintage firm capacity, at Line 400 embedded cost (vintaged rates). Any additional capacity from Malin used by the retail core or wholesale customers must be on the Malin to on-system path. 9. Honor the service commitments set forth in existing long-term transmission service agreements for the period of the Accord or the remaining term of each such -4- agreement, whichever applies. These commitments are addressed below in Section II.F. 10. Provide parking and lending services at all interstate interconnection points and at Kern River Station. These services shall be provided using transmission and storage capacity as it becomes available. 11. Continue operational integration of PG&E's gas storage facilities with PG&E's transmission facilities. PG&E will reserve firm storage capacity for pipeline balancing services and PG&E's Core Procurement Department will contract for a major portion of PG&E firm storage capacity on behalf of the retail core. The remaining storage capacity will be marketed in an unbundled storage program. 12. Unless otherwise stated in this document, the principles and specific elements of the Accord, the resulting Accord rates (and their underlying assumptions) and the revenue treatment for Accord services are fixed and not subject to challenge or change in any regulatory forum during the Gas Accord period. Consequently, the parties will not challenge any assumption that is set by this Accord, and that if altered, would result in a shift of revenue responsibility between core and noncore customers and/or between customers and PG&E shareholders. Furthermore, any issue settled as part of the Gas Accord described in Section V, Litigation Resolution, will not be subject to litigation in any regulatory forum. -5- This page left deliberately blank for the map to be inserted -6- II. TRANSMISSION AND STORAGE SERVICES A. NEW TRANSMISSION SERVICES The services offered over the backbone portions of the new transmission paths (paths a through g, listed in Section I.B.5 above) are described below. Contracts will set the terms of service, including service priority. Local transmission costs are included in a separate local transmission charge, which will be collected from all on-system end- users. The pre-existing transmission services are described in Section II.B, below. The following five transmission services will have all terms and conditions set by tariff. 1. Firm Annual On-system (AFT) a. Definition: Firm service on the transmission system with deliveries on-system. b. Minimum Term: One year. c. Rate: Straight Fixed Variable (SFV) or Modified Fixed Variable (MFV), at the shipper's option for the backbone component. See rates in Section VI. No discounts. 2. Firm Seasonal (SFT) a. Definition: Firm seasonal service on the transmission system. b. Conditions: Paths to on-system destinations only. Maximum term limited to two years. c. Minimum Term: Three consecutive months in one season. d. Winter Season: November through March. e. Summer Season: April through October. f. Rate: SFV or MFV, at the shipper's option for the backbone component. See rates in Section VI. No discounts. 3. As-available On-system (AA) a. Definition: As-available service on the transmission system with deliveries on-system. b. Minimum Term: One day. c. Rate: Volumetric for the backbone component. See rates in Section VI. No discounts. -7- 4. Firm Annual Off-system (AFT-Off) a. Definition: Firm service on the transmission system with deliveries off-system. b. Minimum Term: One year. c. Rate: Straight Fixed Variable (SFV) or Modified Fixed Variable (MFV), at the shipper's option for the backbone component. If a shipper elects SFV rate design, the shipper can also specify an alternate delivery point on-system. If a shipper elects MFV, delivery must be off-system only. See rates in Section VI. No discounts . 5. As-available Off-system (AA-Off) a. Definition: As-available service on the transmission system with deliveries off-system. b. Minimum Term: One day. c. Rate: Volumetric for the backbone component. See rates in Section VI. No discounts. The following four transmission services are negotiable, as indicated. 6. Negotiated Firm Service On-system (NFT) a. Definition: Firm service on the transmission system with deliveries on-system. b. Minimum Term: Negotiable. c. Rate: Negotiable, above a marginal-cost-based floor consistent with negotiated term. Maximum rate for the backbone component of each path is 120 percent of the firm annual rate for that path. d. Take Requirement: Negotiable. e. Sections IX and X of General Order No. 96-A are waived by the Commission. 7. Negotiated As-available On-system (NAA) a. Definition: As-available service on the transmission system with deliveries on-system. b. Minimum Term: Negotiable. -8- c. Rate: Negotiable, above a marginal-cost-based floor consistent with the negotiated term. Maximum rate for the backbone component of each path is 120 percent of the As-available rate for that path. d. Take Requirement: Negotiable. e. Sections IX and X of General Order No. 96-A are waived by the Commission. 8. Negotiated Firm Service Off-system (NFT-Off) a. Definition: Firm service on the transmission system with deliveries off-system. b. Minimum Term: Negotiable. c. Rate: Negotiable, above a marginal-cost-based floor consistent with negotiated term. Maximum rate for the backbone component of each path is 120 percent of the firm annual rate for that path. d. Take Requirement: Negotiable. e. Sections IX and X of General Order No. 96-A are waived by the Commission. 9. Negotiated As-available Off-system (NAA-Off) a. Definition: As-available service on the transmission system with deliveries off-system. b. Minimum Term: Negotiable. c. Rate: Negotiable, above a marginal-cost-based floor consistent with the negotiated term. Maximum rate for the backbone component of each path is 120 percent of the As-available rate for that path. d. Take Requirement: Negotiable. e. Sections IX and X of General Order No. 96-A are waived by the Commission. 10. PG&E may also offer other customer-specific negotiated contracts. Negotiated transmission service contracts under NFT and NAA will not require submission to the CPUC for approval; however, any other negotiated transmission service contracts will require submission to the CPUC for approval. -9- 11. The following table summarizes which new transmission services are available to the transmission paths described in Section I.B.5.
Available Path Services ---- --------- a. Malin to On-system for Core AFT b. Malin to On-system AFT, SFT, AA, NFT, NAA c. Topock to On-system AFT, SFT, AA, NFT, NAA, d. California Production and AFT, SFT, AA, NFT, Storage to On-system NAA, e. Malin to Off-system AFT-Off, AA-Off, NFT-Off, NAA-Off f. Topock to Off-system AFT-Off, AA-Off, NFT-Off, NAA-Off g. California Production, Storage, AFT-Off, AA-Off, Services and Market Center/Hub On-system NFT-Off, NAA-Off Delivery Points to Off-system
B. PRE-EXISTING TRANSMISSION SERVICES 1. G-XF Firm Service a. Definition: Firm service on Line 401 under the G-XF rate. b. Minimum Term: Thirty years. c. Rate: Incremental rates based on a capital cost for Line 401 of $736 million, using utility capital structure and the operating expenses and cost allocation methodologies set forth in PG&E's PEPR Application. d. Take Requirement: As negotiated. e. Other terms and conditions: Delivery point as set forth in Exhibit A to each firm contract; Uniform Terms of Service rights apply only to firm G-XF service; backbone credit and crossover ban are eliminated. f. Sections IX and X of General Order No. 96-A may apply. -10- 2. Expedited Application Docket (EAD) Agreements a. Definition: Firm service on Line 300 and from California gas production to the burnertip, under individually negotiated contracts approved by the CPUC under the provisions of Decision 92- 11-052. b. Minimum Term: As set forth in each contract. c. Rate: Volumetric negotiated rate, as set forth in each contract. d. Take Requirement: As set forth in each contract. e. Other terms and conditions: As set forth in each contract. f. Sections IX and X of General Order No. 96-A may apply. 3. Enhanced Oil Recovery (EOR) Agreements a. Definition: Interruptible service for Enhanced Oil Recovery customers pursuant to Decisions 85-12-102 and 87-05-046. b. Minimum Term: As set forth in each contract. c. Rate: Volumetric negotiated rate, as set forth in each contract. d. Take Requirement: None e. Other terms and conditions: As set forth in each contract. f. Sections IX and X of General Order No. 96-A apply. 4. Expedited Direct Connection Docket (EDCD) Agreements a. Definition: Agreements for direct connection service on PG&E's Line 401 approved pursuant to the CPUC's Expedited Direct Connection Docket. b. Term: The remaining term of the direct connection agreement. c. Rate: The rate established in the direct connection agreement. If this agreement does not specify a rate, then the rate will be established under one of the new transmission service rates. d. Other terms and conditions: Per the direct connection agreement, or if unspecified in that agreement, the applicable Gas Accord tariffs. 5. Other Existing Agreements a. Negotiable Interruptible Agreements -11- PG&E has a number of negotiable interruptible transportation agreements with terms that may extend into the Accord period. PG&E will continue to honor the terms and conditions, including the rate, negotiated for the original term of these contracts. b. Crockett Cogeneration Crockett cogeneration has a negotiated contract which provides for transportation service at volumetric rates. PG&E will continue to honor the terms and conditions, including the rate, negotiated for the original term of this contract. If any terms and conditions are unspecified by the existing contract agreement, then the applicable Gas Accord tariffs will apply. C. STORAGE SERVICES 1. Storage Capacity Allocated To Core Customers, Including Core Transport Customers a. Core service is allocated a portion of storage capacity to support the obligation to maintain highly reliable service under cold conditions. See Section II.E.5 for allocations. b. Core aggregators, on behalf of their core transport customers, will be allocated a pro rata share of the total core reservation based on the winter season throughput of their core customers. c. Costs for storage allocated to core customers, including core transport customers, will remain bundled in all core rates. d. Any storage capacity that is not needed for core reliability may be brokered. e. PG&E and core aggregators, on behalf of core customers, may elect to purchase more storage through the unbundled storage program. 2. Storage Capacity Allocated to Pipeline Balancing Services a. A portion of storage capacity is needed to support the balancing services. See Section II.E.5 for the allocation. b. Storage costs allocated to balancing services remain bundled in transmission rates. 3. Unbundled Storage Program a. PG&E will offer storage services to the market from its integrated storage facilities through the unbundled storage program. The storage services will be -12- offered from the capacity remaining, after the allocations for balancing provisions and storage for the core market. b. Firm Storage Service (FS) i. Definition: Firm storage service. ii. Minimum Term: One year iii. Rate: Sub-functions are capacity (combined injection and inventory) and withdrawal. Each sub-function is further divided into a reservation charge (fixed) component and a volumetric charge (variable) component. iv. Conditions: Requires injection during the defined summer storage season. v. Features: Imbalance trading and inventory transfers are available. c. Negotiated Firm Storage Service (NFS) i. Definition: Firm storage service; customers may purchase inventory, injection, and withdrawal separately. ii. Minimum Term: One month iii. Rate: The flexibility inherent in this storage offer could result in stranded facilities and PG&E requires the opportunity to collect the value of its storage services. Rates are negotiable above a short-run marginal price floor and capped at the price which will collect 100 percent of PG&E's total revenue requirement for the unbundled storage program for each of the three storage subfunctions (e.g., inventory, injection, or withdrawal). iv. Features: Imbalance trading, inventory transfers, and counter- cyclical operations are available. v. Sections IX and X of General Order No. 96-A are waived by the Commission. d. Negotiated As-available Storage Injection and Withdrawal Service (NAS) i. Definition: As-available storage service only available to customers with firm storage inventory. ii. Minimum Term: One day iii. Rate: Volumetric only rate design. The flexibility inherent in this storage offer could result in stranded facilities and PG&E requires the opportunity to collect the value of its storage services. Rates are negotiable above a marginal price floor and capped at the price which will collect 100 percent of PG&E's -13- total revenue requirement for the unbundled storage program for each of the three storage subfunctions (e.g., inventory, injection, or withdrawal). iv. Sections IX and X of General Order No. 96-A are waived by the Commission. 4. PG&E may also offer other customer-specific negotiated contracts. Negotiated storage service contracts under NFS and NAS will not require submission to the CPUC for approval; however, any other negotiated storage service contracts will require submission to the CPUC for approval. 5. Depending on market interest, PG&E is free to develop and offer additional storage services in the future. D. OTHER SERVICES 1. Parking (PARK) Services offered are identical to those approved by the CPUC on June 26, 1996 (Advice 1949-G). a. Definition: As-available short-term parking service, using PG&E's transmission and storage system. b. Term: One day to one year. c. Rate: Negotiable, above a minimum transaction fee and capped at the daily and/or annual cost to cycle gas using Firm Storage Service. d. Terms and Conditions: Gas is parked and unparked at the same location. e. Priority: Lowest priority As-available service. 2. Lending (LEND) Services offered are identical to those approved by the CPUC on June 26, 1996 (Advice 1949-G). a. Definition: As-available short-term loan of gas using PG&E's transmission and storage system. b. Term: One day to one year. c. Rate: Negotiable, above a minimum transaction fee and capped at the daily and/or annual cost to cycle gas using Firm Storage Service. d. Terms and Conditions: Gas is loaned and repaid at the same location. e. Priority: Lowest priority As-available service. 3. PG&E may also offer other customer-specific negotiated contracts. Negotiated service contracts under PARK and LEND will not require submission to the CPUC -14- for approval; however, any other negotiated service contracts will require submission to the CPUC for approval. 4. Other Depending on market interest, PG&E is free to develop and offer various additional services in the future. E. GENERAL TERMS AND CONDITIONS 1. These general terms and conditions will apply to PG&E's intrastate transmission and storage systems, and to third party storage providers located in PG&E's service territory who have an operating agreement and who have inter-connecting facilities with PG&E. Subscription to these services does not, in itself, subject the subscriber to CPUC jurisdiction. 2. With the unbundling of transmission services, the crossover ban and the backbone credit are eliminated. The following sections in PG&E's existing tariffs are removed along with other references and definitions as may be applicable: Rule 21, Section H, "Scheduling Priority at Malin, Oregon"; Rule 21, Section I, "Self Identification of Malin, Oregon Receipts"; and Rule 22, "Backbone Credit Eligibility Criteria." -15- 3. Receipt Points By Path a. The receipt points by path are as follows:
Path Receipt Points - ----- -------------- Malin to On-system for the Core Malin Malin to On-system Malin Topock to On-system Topock, Daggett, and Kern River Station California Production and Storage to On-system PG&E interconnections with California gas production within PG&E's service territory, PG&E's storage facilities, or a third party's storage facilities located in PG&E's service territory. Malin to Off-system Malin Topock to Off-system Topock, Daggett, and Kern River Station California Production, Storage, Market Center/Hub PG&E interconnections with California gas Services, and On-system Delivery Point Pools to production within PG&E's service territory, Off-system PG&E's storage facilities, a third party's storage facilities located in PG&E's service territory, PG&E's Market Center/Hub Services, or on-system delivery point pools. G-XF Firm Service Malin
b. Alternate Receipt Points Alternate receipt points are allowed only within the transmission path contracted for by a shipper. c. New Receipt Points New receipt points may be requested from time to time by shippers. 4. Delivery Points a. On-system Deliveries On-system is defined as any point at which deliveries are made to, or for ultimate delivery to, PG&E's distribution facilities, PG&E's storage facilities, a third party's storage facilities located in PG&E's service territory, or end-use or wholesale loads located in PG&E's service territory. -16- b. Off-system Deliveries Any interconnection for delivery outside of PG&E's service territory, including Topock, Daggett, Kern River Station, Malin, etc. c. G-XF Firm Service Delivery points are as specified in each shipper's FTSA (Exhibit A). 5. Initial Allocation of Firm Intrastate Transmission Capacity a. Total intrastate capacity currently available for firm transmission services is:
MMcf/d Mdth/d ------------------ ------------------ Malin: 1,803 1,830 Topock: 1,140 1,174 CaliGas 200 192
The Malin capacity consists of 990 MMcf/d (1,005 Mdth/d) from Line 400 and 813 MMcf/d (825 Mdth/d) from Line 401. b. PG&E's retail core initially will be allocated the following quantities of firm transmission capacity:
Malin to Topock to On-system On-system California --------- --------- ---------- Annual MMcf/d 600 150 50 Mdth/d 609 155 48
c. PG&E's retail core will also hold additional seasonal winter capacity as follows:
Malin to Topock to On-system On-system California --------- --------- ---------- November and March MMcf/d 0 150 0 Mdth/d 0 155 0 December to February MMcf/d 0 450 0 Mdth/d 0 464 0
d. The retail core capacity reservation on the Topock to on-system path (Line 300) and the California production path can be modified in ensuing BCAPs to account for changes in core requirements due to factors such as core aggregation, the termination of PG&E's California gas contracts, and the migration of core -17- customers to noncore status. These modifications will not take place prior to 2000. e. Capacity of up to 6.5 MMcf/d (6.6 Mdth/d) is available on the Malin to on-system path for existing wholesale customers on behalf of their core load. f. New services over the Malin 517 Mdth/d) not reserved under paths will use capacity long-term firm contracts with consisting of that portion of existing firm Expansion Line 400 capacity (383.5 shippers. This combined MMcf/d; 389 Mdth/d) not capacity is to be redesignated reserved for the core, by the Commission as including wholesale, and that non-Expansion capacity, which portion of Line 401 capacity shall be subject to "phased-in" (509 MMcf/d; rates and shall not be subject to the tariff or contract provisions and rights (including but not limited to the firm Expansion shippers' "Uniform Terms of Service" rights) that apply to the Line 401 Expansion capacity reserved under long-term contracts. g. PG&E will conduct an open season among all creditworthy parties to award remaining intrastate firm transmission service for at least the minimum term and at the full tariff rate under the AFT, AFT-Off, or SFT service. Firm capacity will first be awarded under the AFT and AFT-Off service. Any remaining firm capacity will then be awarded under the SFT service. h. If a particular path is oversubscribed in the open season, PG&E will award available firm capacity based on PG&E's determination of the highest economic value of each bid to PG&E's gas transmission department, as determined by PG&E. 6. Allocation of Storage Capacity a. The following quantities of firm storage capacity will be allocated to PG&E's retail core customers, including core transport:
Inventory Injection Withdrawal --------- ---------- ---------- 32.Bcf 93 - 209 MMcf/d 951 - 1,228 MMcf/d 33.5 MMdth 95 - 213 Mdth/d 970 - 1,253 Mdth/d
-18- b. The following quantities of firm storage capacity will be allocated to system load balancing:
Inventory Injection Withdrawal --------- --------- ----------- 2.2 Bcf 50 MMcf/d 70 MMcf/d 2.24 MMdth 51 Mdth/d 71 Mdth/d
c. The following quantities of storage capacity will be allocated to the unbundled storage program:
Inventory Injection Withdrawal --------- --------- ---------- 4.7 Bcf 13 - 30 MMcf/d 136 - 175 MMcf/d 4.79 MMdth 13 - 30 Mdth/d 139 - 179 Mdth/d
Volumes are subject to change pursuant to operating conditions. Future fluctuations or changes in PG&E's injection and/or withdrawal capabilities during the Gas Accord period will be assigned or absorbed by the unbundled storage program, except for changes in storage capabilities required on behalf of core customers served by PG&E. d. PG&E will conduct an open season among all creditworthy parties to award remaining firm storage service for at least the minimum term and at the full tariff rate for Firm Storage Service. e. If Firm Storage Service is oversubscribed in the open season, PG&E will award available firm storage capacity based on PG&E's determination of the highest economic value of each bid to PG&E's gas transmission department, as determined by PG&E. 7. Subsequent Allocation of Intrastate Transmission and Storage Capacity a. After the open season for transmission and storage capacity, any remaining capacity will be available for subscription under the Firm, Negotiated Firm, or As-available services on an on-going basis. b. Customers may request negotiated rates at less than maximum rates. PG&E will not be required to sell capacity to any shipper at less than the full tariff rate; however, at PG&E's sole option, capacity may be awarded based on offers that represent the highest economic value to PG&E, as determined by PG&E. 8. Contract Assignment -19- a. Unless the shipper's contract states otherwise, all transmission and storage contracts are assignable. Such assignments may consist of all or part of the shipper's contract quantity and all or part of the shipper's remaining contract term. b. Contract assignments are subject to the following requirements: i. Assignors must notify PG&E in advance of their assignments. ii. The assignee must satisfy PG&E's creditworthiness requirements described in Section II.E.9. Alternatively, the assignor may, at its option, waive the creditworthiness requirements applicable to the assignee, in which case the assignor shall be secondarily liable for non-performance by the assignee. If an assignor exercises this option, it must demonstrate to PG&E's satisfaction that it remains creditworthy itself. c. To encourage assignments and development of an active secondary market, PG&E will maintain a posting board similar to PG&E's existing "Energy Marketplace" that contract holders may use, at their option. PG&E is willing to work with others to establish new or modify existing mechanisms, including electronic bulletin boards, that encourage development of an active secondary market. 9. Creditworthiness a. An entity requesting service must demonstrate creditworthiness before receiving service. Additionally, an entity receiving service under a long-term (one year or longer) contract may be subject to periodic re- evaluations of its creditworthiness. b. An entity requesting service must provide the following to PG&E in order for PG&E to evaluate its creditworthiness: i. Most recent annual report; ii. Most recent SEC Form 10-K; iii. If SEC Form 10-K is unavailable, substitute audited annual financial statements (including a balance sheet, income statement, and cash flow statement), o r iv. If audited financial statements are unavailable, substitute unaudited financial statements (including a balance sheet, income statement, and cash flow statement) accompanied by an attestation by the providing entity's Chief Financial Officer that the information reflected in the unaudited statements is true and correct and a fair representation of the entity's financial condition; -20- v. Most recent quarterly or monthly financial statements (including a balance sheet, income statement, cash flow statement, and contingencies). c. PG&E will use the items above, in conjunction with the entity's service request or service level, to determine the maximum amount of credit PG&E can offer the entity. d. If an entity is unable to demonstrate creditworthiness through the materials listed in Section b, PG&E may request additional evidence of creditworthiness, in which event the entity may elect to provide one of the following: i. an irrevocable letter of credit in form, substance and amount satisfactory to PG&E; ii. a guarantee, in form and substance satisfactory to PG&E, executed by a person PG&E deems to be creditworthy, of the entity's performance of its obligations to PG&E; or iii.such other form of security as the entity may agree to provide and as may be acceptable to PG&E. e. PG&E will treat all financial statements provided to it as confidential. f. PG&E will continue to oversee aggregators' creditworthiness, pursuant to PG&E's Gas Rule 23 - Gas Aggregation Service for Core Transport Customers. 10. Priority of Service a. The current Receipt Point Capacity Allocation rules will change to reflect the following priorities. b. Scheduling Priority at Transmission Receipt Points (in the following order) i. Firm Intrastate Transmission: All firm service at all receipt points on a defined transmission path is treated equally (pro rata allocation of nominations if necessary). ii. As-available Intrastate Transmission: Scheduled according to contract price. c. Scheduling Priority at Transmission Delivery Points (in the following order): i. Firm Intrastate Transmission: All firm service at a given delivery point is treated equally (pro rata allocation of nominations if necessary). ii. As-available Intrastate Transmission: Scheduled according to contract price. -21- d. Scheduling Priority To Storage for Injection i. Transportation priority to storage is determined by the underlying intrastate transmission contract. ii. Injection priority at PG&E's storage interconnection is determined by the storage contract: * PG&E Firm Storage Service: All firm service treated equally (pro rata allocation of nominations if necessary). * PG&E As-available Storage Service: Scheduled according to contract price. e. Scheduling Priority From Storage for Withdrawal i. Transportation priority from storage to the delivery point is determined by the underlying intrastate transportation contract. ii. Withdrawal priority at PG&E's storage interconnection is determined by the storage contract. * PG&E Firm Storage Service: All firm service treated equally (pro rata allocation of nominations if necessary). * PG&E As-available Storage Service: Scheduled according to contract price. f. Over-Nomination Provision PG&E will develop a tariff provision to discourage nominations in excess of actual available supply (over-nomination) at a constrained receipt or delivery point. 11. Local Constraints a. PG&E will take whatever steps it determines are operationally necessary in the event a constraint on local transmission or distribution threatens service to customers. This includes curtailment of noncore customers. b. To the extent feasible, PG&E will use the transmission system diversion procedures to prioritize noncore customers in the affected service area. c. In the event of an Emergency Flow Order (EFO) due to a local constraint, EFO penalties may apply, but involuntary diversion penalties will not apply. 12. Service Reliability and Diversion Procedures -22- a. When operational conditions exist such that supply is insufficient to meet demand and delivery to end-users is threatened, the diversion of supply may be used to ensure continued gas delivery to core end-users. EFO provisions will apply under these conditions (see Section II.E.13). If a noncore end-user's supply is diverted, either voluntarily or involuntarily, then that end-user must curtail its use of natural gas. If a core end-user's supply is diverted, then that customer must pay any penalties if it continues to use gas, as referenced later in this Section. b. The following diversion procedures will apply to ensure service reliability to core end-users. PG&E's core procurement department and core aggregators, on behalf of core customers, will use: i. their own firm capacity, to the extent possible; ii. any available As-available capacity on the system at any receipt point; and iii.available voluntary diversion of supply from noncore end-users or other transmission system shippers, at prices not to exceed the cost of involuntary diversion. c. Involuntary diversion of gas supply on the transmission system will be used as a last resort to ensure service reliability for core end-users. Firm transportation to off-system is not subject to diversion. Diversion will occur in the following order: i. Noncore supply scheduled under As-available transportation is diverted in order of contract transmission price and on a pro rata basis for all volumes with the same price. However, scheduled deliveries from storage using As-available transmission will be treated as the highest priority noncore firm transmission. ii. Firm transportation to on-system noncore end-users. d. Those receiving involuntarily diverted supply will be assessed a $50/Dth diversion usage charge in addition to a $50/Dth EFO curtailment noncompliance penalty, for a total noncompliance charge of $100/Dth. These revenues will be used first to pay diversion credits to those whose gas supply is involuntarily diverted. The remaining revenues will be returned to all customers in the customer class charge. e. Firm transportation service customers whose gas supply is involuntarily diverted will receive a $50/Dth diversion credit. f. As-available transmission service customers whose gas supply is involuntarily diverted will receive a diversion credit based on the current market price of the diverted supply. -23- 13. Balancing Service a. Basic Service i. Balancing service will be provided on a monthly basis through a single integrated gas system for both transmission-level and distribution-level customers. ii. All customers shall exercise best efforts to have daily gas receipts match daily gas usage. iii.Monthly imbalances can be carried forward one month, not to exceed plus or minus five percent of the usage in the month in which the imbalance occurred, except as noted in items a.iv and d, below. iv. If at any time the aggregate imbalance on PG&E's system (excluding the operation of the storage reserved for balancing) has exceeded plus or minus three percent of that month's aggregate deliveries (excluding gas scheduled for subsequent delivery off-system) for two months in the preceding 12 month period, then the imbalance carry-over allowance will be decreased one percent after a minimum of 30 days notice to the market. This provision can be used to lower the imbalance carry-over allowance no more than once in any 12 month period. The carry-over allowance will not be set below three percent without CPUC approval. All references in the Gas Accord to a five percent carry-over allowance and to the tiers for monthly imbalance cash-outs are intended and understood to be subject to change by operation of this provision. v. Operational Flow Order (OFO) and Emergency Flow Order (EFO) provisions will be used to manage operational imbalances when necessary. b. Customer Imbalances i. Imbalances generally will be maintained at the delivery point. For deliveries made to on-system end-users, the end-user will be responsible for imbalances. For deliveries to storage and to off- system points, the transmission shipper will be responsible for imbalances. ii. End-user imbalance accounts may be assigned to a third party. iii.A third party may aggregate imbalance accounts. c. Imbalance Trading i. Monthly imbalance quantities may be traded with another entity. -24- ii. Imbalance quantities can only be traded with other imbalance quantities that occurred during the same calendar month. Trading between on- and off-system imbalances is not allowed. iii.Any imbalance trade must move the trader's imbalance quantity toward zero, unless the imbalance resulting from the trade is within the range of plus or minus three percent. iv. Imbalance trading into and out of storage will be available. Firm storage customers may use a PG&E (or other on-system storage provider's storage account subject to having an appropriate operational balancing agreement between PG&E and the other storage provider) to trade transportation imbalances, during the imbalance trading period, within operational limits. d. Imbalance Charges and Cash-Out i. Automatic cash-out of all commodity and transmission imbalances outside of allowed carry-forward quantity each month will occur. In-kind imbalance deliveries will not be included. Imbalance cash -outs will have a commodity and a transmission component. Monthly imbalance cash-out occurs after imbalance trading for the month is complete. ii. Commodity cash-out prices for each month for each interconnect are based on the higher (for under-deliveries) or lower (for over- deliveries) of the following gas price indexes at PG&E interconnects (e.g. Malin, Topock) from public sources (e.g. Bloomberg, Gas Daily): * Monthly index price; * Under-deliveries: average of the five highest daily index prices during the month; * Over-deliveries: average of the five lowest daily index prices during the month. iii.The commodity cash-out index price for imbalances less than or equal to ten percent will weight the appropriate interconnect indices by the supply mix of all gas received by PG&E for on-system customers during the month in which the imbalance occurred. Imbalances greater than ten percent will be cashed-out based upon an index equal to the highest interconnect index price for under- deliveries and the lowest interconnect index price for over- deliveries, regardless of PG&E's supply mix. iv. The commodity cash-out index price will be adjusted by the following percentages, according to the level of the actual monthly imbalance: -25-
Monthly Imbalance Over-delivery (OD) Under-delivery (UD) Level Purchase Dollars Sale Dollars - ----- ---------------- ------------ +/-5% to +/-10% 95% weighted OD index 105% weighted UD index >+/-10% 50% lowest index 150% highest index
v. Transmission service cash-out prices are based on the volumetric component of PG&E's standard tariff firm (MFV) and As-available transmission services. Over-deliveries will receive a transmission service credit based on the volumetric component of the appropriate firm transportation rate. Under-deliveries will be charged the appropriate rate for As-available service. The appropriate rate is determined by weighting the path specific rates by the supply mix of all gas received by PG&E for on-system customers during the month. vi. PG&E gas purchases and/or sales associated with cash-outs will be accounted for separately from the core portfolio purchases. vii.The intent of imbalance cash-outs is to create an economic disincentive for incurring cash-out imbalances. PG&E will file to revise the imbalance charges and cash-out options if the Gas Accord provisions do not accomplish this. e. Operational Flow Order Provisions i. System-wide, local, or customer-specific OFO provisions may be called to order out-of-tolerance customers to balance supply and demand daily, when operationally necessary. OFO provisions will require daily balancing and impose penalties for noncompliance. ii. OFOs may be called if pipeline inventory exceeds or is forecast to exceed desired pipeline inventory by 200 MMcf/d, or is below or is forecast to be below desired pipeline inventory by 150 MMcf/d. Desired pipeline inventory in the winter is typically 4.2 Bcf and in the summer is typically 4.15 Bcf. iii.PG&E will use multi-stage OFO provisions, which would provide a daily tolerance band ranging from plus or minus 25 percent to zero percent of actual daily usage. iv. Multi-stage OFO non-compliance penalty provisions would range from $1/Dth to $25/Dth. The amount of the penalty will be announced prior to the enactment of each stage. The penalty will start at $1/Dth and only increase during an event if the response to the OFO is inadequate. Subsequent levels will be $5/Dth and $25/Dth, as needed to maintain pipeline system integrity. A specific customer may start at an elevated penalty level if that customer has a history of non-compliance. -26- v. An OFO will normally be ordered with at least twelve hours notice prior to the beginning of the gas day, or as necessary as dictated by operating conditions. Penalties will not be imposed with less than twelve hours notice. vi. For each noncore end-user without telemetering, compliance with an OFO will be determined by comparing the end-user's supply against a 5:00 p.m. day-before PG&E forecast of the end-user's usage. f. Emergency Flow Order Provisions i. Emergency Flow Order conditions are defined to exist when a forecast or actual supply and/or capacity shortage threatens to affect the delivery to end-users. ii. EFOs will have a zero percent tolerance (supply must be greater than or equal to usage) and a $50/Dth noncompliance penalty. iii.For each noncore end-user without telemetering, compliance with an EFO will be determined by comparing the end-user's supply against a 5:00 p.m. day-before PG&E forecast of the end-user's usage. iv. If an involuntary supply diversion is called in conjunction with an EFO, an additional $50/Dth diversion usage charge will apply for a total potential noncompliance penalty of $100/Dth. v. An EFO would normally be ordered following an OFO, but could also occur under an emergency operational condition. There is no required notice period for EFOs, however, PG&E will attempt to provide as much notification to customers as possible. vi. PG&E reserves the right to implement other measures to ensure system integrity should the EFO actions not alleviate the emergency condition. g. Other Operational Balancing Issues i. Transmission-level end-users and distribution-level noncore end- users will be required to have daily metering. ii. Telemetering will be installed on noncore customers' meters where it is cost-effective. These costs will not change the rates established by the Gas Accord. iii.PG&E reserves the right to propose other measures to ensure system integrity should the OFO and/or EFO provisions not prove to be adequate. iv. A load profile modeling tool will be developed to determine daily usage for PG&E's core procurement customers and core transport customers served by -27- core aggregators in order to remove PG&E's core portfolio from providing a system balancing function, and to be able to hold PG&E's core procurement department to the same balancing and OFO provisions to which others are held. v. The normal nomination deadline will be shifted to one day prior to gas flow at all receipt points where the upstream operator(s) will accommodate the shift. vi. PG&E will allow same-day nominations, if necessary, and if upstream and downstream operator(s) are able to accommodate the practice. 14. Transmission Level End-Use Service a. To be eligible for transmission-level end-use service, an end-user must: i. Be a noncore customer; ii. Be physically connected to the transmission system or have an annual load in excess of 3 million therms/year; and iii.Elect to receive transmission level end-use service. b. All on-system transmission-level end-users must pay local transmission charges. c. All other end-users will be served at distribution tariff rates. d. The definition of a noncore customer may be revisited in BCAPs during the Accord period. 15. Negotiated Contracts a. Standard tariff rates and terms are available to all customers. b. PG&E may distinguish between parties in offering negotiated rates by evaluating differences in circumstances and conditions, including but not limited to differences occurring upstream, downstream or at the customer's location, affecting either cost of service or the entities' market alternatives. Such negotiations will be conducted without undue preference or undue discrimination. c. Negotiated rates for transmission and storage service shall not be less than PG&E's short-run marginal cost of providing the service. Negotiated transmission rates under NFT and NAA will be capped at 120 percent of the tariffed rate for the particular service on the particular path. Negotiated storage rates (NFS and NAS) will be capped at the price which will provide PG&E the opportunity to recover its total embedded cost revenue requirement for the unbundled storage program for each of the three storage subfunctions (e.g., inventory, injection, or withdrawal). -28- d. To the extent that PG&E negotiates a transmission contract for its Malin to on-system path with an on-system end-user, and the negotiated backbone rate component offered is below the analogous Topock to on- system path rate, e.g., seasonal firm, PG&E agrees to offer to that end-user the same negotiated rate for a Topock to on-system path contract, to the extent that capacity is available . e. Negotiated rates for parking and lending services shall not be less than PG&E's short-run marginal cost of providing the service. These rates will be capped at a daily and/or annual cost to cycle gas using firm storage service. f. PG&E will issue monthly reports to CPUC covering all negotiated contracts, including those negotiated under NFT, NAA, NFS, and NAS, but excluding PARK and LEND. PG&E will make the report available upon request. Customer names, including PG&E's affiliates and other departments, will not be disclosed in the report. However, the report will indicate whether a particular transaction was with an affiliate. The report will show the negotiated contract rates. g. The CPUC's complaint procedure will be available to address any undue discrimination claims. h. PG&E may also offer other customer-specific negotiated contracts. Negotiated transmission and storage service contracts under NFT, NAA, NFS, and NAS will not require submission to the CPUC for approval; however, any other negotiated transmission or storage service contracts will require submission to the CPUC for approval. 16. Affiliate and Intracompany Transactions a. PG&E will treat PG&E's affiliates and core procurement and UEG departments without undue preference or undue discrimination. b. PG&E will not disclose specific shipper information to PG&E's affiliates or core procurement and UEG departments without that shipper's permission, except as needed to serve the shipper. c. PG&E will provide nonpublic information about the intrastate transmission system to all entities, including PG&E's affiliates and core procurement and UEG departments, without undue preference or undue discrimination. d. PG&E will develop specific standards of conduct for affiliate transactions to be included in its Accord tariffs. F. SPECIAL AGREEMENTS 1. Firm Expansion Agreements -29- a. As set forth in Section I.B.6, the 304 MMcf/d of Line 401 capacity remains initially dedicated to firm G-XF service, consistent with the Firm Transportation Service Agreements (FTSAs) previously approved by the CPUC for service to the firm Expansion shippers. The G-XF rate will continue to apply to this capacity and to service provided to these shippers for the remainder of the 30-year term of these agreements, as set forth in part (b.ii), below, except that each shipper may elect one of the options set forth in parts (b.i) and (c), below, and, by virtue of that election, alter the rate, term, and terms and conditions of service. The other 509 MMcf/d of Line 401 firm capacity is redesignated as firm capacity available for subscription under the new transmission services described in Section II.A. b. Options for Service: Firm Expansion shippers may elect -------------------- one of the following options for restructuring their contractual commitments. The shippers may elect either of the following two options at any time up to 45 calendar days following CPUC approval of this Settlement Agreement. i. Accord Service: A shipper may convert its firm Expansion --------------- contract to Firm Annual Off-System service (AFT-Off) under the Accord for Malin to off-system service. The rate, terms and conditions of this service are delineated in Section II.A.4. These include a Line 401 capital cost of $736 million, and an on-system delivery option if the shipper elects SFV rate design. Features specially applicable to converting Expansion shippers are the following: * the term of the replacement contract is the full remainder of the shipper's 30-year term under its FTSA; * UTS and all other Expansion-related contract and tariff rights must be irrevocably waived; * the contract for new service is pro forma (no negotiated agreements) and service is henceforth provided under AFT-Off and superseding tariff(s); * the shipper's capacity is redesignated as non-Expansion capacity, as discussed in Section I.B.6; and * PG&E will offer consideration as payment for the shipper's waiver of UTS rights. ii. G-XF Firm Service: Those firm Expansion shippers that do ------------------ not elect one of the other options set forth herein will continue to receive service under G-XF, as described below: * Rates are based on a $736 million capital cost, using PG&E's proposed cost of capital and utility capital structure; * Rates remain incremental and are based on the operating expenses and cost allocation methodologies proposed by PG&E in its PEPR Application; * The G-XF firm service continues to apply, but is modified to reflect the revenue requirement assumptions above, and the backbone credit and crossover ban are eliminated; -30- * UTS and all other contract rights remain applicable only to firm G-XF service; and * Delivery points are as set forth in Exhibit A to each shipper's FTSA. c. Other Options: PG&E is also offering the following three options to ------------- firm Expansion shippers. The following descriptions set forth PG&E's vision of these options, but each option will be negotiated with any interested shipper, and specific terms and conditions may vary as a result of those negotiations. The shippers may elect one of these options by executing the appropriate agreement with PG&E on or before the earlier of (1) December 1, 1996, or (2) the date the CPUC approves this Accord Settlement Agreement. i. Negotiated Contract Amendments: A shipper may elect either a ------------------------------ discounted rate (to be negotiated with PG&E), which is fixed for the term of the Gas Accord, or a market index rate, which would fluctuate during the term of the Gas Accord within a negotiated floor and ceiling based on differentials between Southwest and Canadian prices. Service under either rate option, once agreed to, will be provided under G-XF, as modified by the Gas Accord. At the end of the Gas Accord term, and for the remainder of the shipper's 30-year contract term, rates will be set based on a Line 401 capital cost of $736 million. Beginning on the date the contract amendment is executed, the shipper must waive its UTS provision for the remainder of its 30-year contract term. ii. Contract buyout: A shipper may terminate its contract --------------- obligations either by making a single payment to PG&E or accelerating payment of demand charges by means of a higher negotiated rate for a specified negotiated term. In either case, PG&E intends that the payment shall be of a sum less than the full NPV of the remainder of the shipper's 30-year contract term. Upon payment of the full negotiated buyout amount, the shipper's contract with PG&E for Expansion transportation service, and all rights and obligations under that contract, shall terminate, and the capacity released thereby shall be redesignated as non- Expansion capacity and shall become part of the pool of capacity used to provide Accord transmission services. If a shipper elects the accelerated payment option, service for the term of such payment will be provided under G-XF, as modified by the Gas Accord, and the shipper must waive its UTS provision immediately. iii. Equity Purchase: A shipper may convert its firm service to an --------------- equity interest in Line 401 at a purchase price to be negotiated with PG&E. Under this option, the shipper would purchase a share of Line 401 at least equal to the firm Maximum Daily Quantity (MDQ) set forth in Exhibit A to the shipper's FTSA. 2. EAD Contracts -31- The EAD contracts provide the equivalent of contract rights as firm transportation service (AFT) on the Topock to on-system path, but at the contract volumetric rate. The EAD customers will have the option of continuing to receive the same bundled transportation service, or taking service under a Gas Accord contract. Service under Gas Accord contracts will contribute to any use-or-pay obligations under the EAD contract. Because of the unique terms and conditions in the various EAD contracts, individual discussions are needed as to how specific contract provisions will be implemented in the Gas Accord contract environment. 3. EOR Contracts In Decisions 85-12-102 and 87-05-046, the Commission established a long-term transportation program and set the criteria for Enhanced Oil Recovery (EOR) contracts. Existing EOR contracts will be treated based on the Commission's decisions during the Accord period, or until the expiration date of such contracts, whichever is earlier. Future EOR service will be provided based on the terms and conditions of Accord services. 4. EDCD Agreements In Decision 94-12-061, the Commission established the Expedited Direct Connection Docket (EDCD) for case-by-case approval of direct connection service on PG&E's Line 401. PG&E has one EDCD application (A.96-04-007) pending before the Commission and may file additional applications. To the extent these applications are approved before the Gas Accord is implemented, the underlying agreements shall continue in effect during the Gas Accord until they expire. Otherwise, new services are provided consistent with the Accord services. 5. Other Existing Agreements a. Negotiated Interruptible Agreements PG&E has a number of negotiable interruptible transportation agreements with terms that may extend into the Accord period. PG&E will continue to honor the terms and conditions, including the rate, negotiated for the original term of these contracts. Because the underlying tariff (G-ITS) will be eliminated upon Accord implementation, these terms and conditions will be carried out through an NAA contract. b. Crockett Cogeneration -32- Crockett cogeneration has a negotiated contract which provides for transportation service at volumetric rates. PG&E will continue to honor the terms and conditions, including the rate, negotiated for the original term of this contract. If any terms and conditions are unspecified by the existing contract agreement, then the applicable Gas Accord tariffs will apply. 6. SMUD a. Background Sacramento Municipal Utility District (SMUD), as the largest municipal utility in the state, is in a unique position and the Accord proposes a unique solution to meet its needs. PG&E and SMUD have agreed, subject to completing definitive agreements and obtaining CPUC approval, that PG&E will sell to SMUD a qualified equity interest in Line 300 and Line 401 backbone facilities. This transaction along with the Interim and Contingent Rate discussed below, would settle SMUD's BCAP Phase II issues. The details of the transaction will be part of a Section 851 filing seeking CPUC approval of the asset sale. b. Interim and Contingent Rate Should the above asset transfers not occur before the Gas Accord becomes effective, there will be an interim rate, which is also a contingent rate in the event that the Section 851 filing is not approved as filed. This rate will include a $0.123 per Dth discount (escalated for inflation over time) from the local transmission charge component of the otherwise applicable tariff rates for gas delivered and received by SMUD or its affiliate to support its electric utility operations. This rate treatment will terminate upon closing of SMUD's purchase of a qualified, equity interest in Lines 300 and 401. G. GENERAL DESCRIPTION OF TRANSMISSION AND UNBUNDLED STORAGE PROGRAM RATES 1. Unbundle transmission and a portion of storage from distribution services. 2. Establish transmission, distribution, and storage rates based on cost of service. 3. Make transmission and storage service available to all entities, including end-users, shippers, producers and marketers. 4. Collect social, environmental, and transition costs and balancing accounts from on-system end-use volumes. 5. Backbone rates associated with service to storage are paid upon injection. For on-system deliveries, the remaining transmission rates are paid upon withdrawal. 6. New Transmission Rates -33- a. Differentiate transmission rates by path to reflect facilities used to provide service. b. Establish two-part firm rates (reservation and usage charges) and one-part As-available rates (volumetric or usage charges). c. Establish a customer access charge to cover the costs of meters and service drops, meter reading, billing and payment processing where applicable. 7. Pre-existing Transmission Rates For those services with pre-existing contracts discussed in Section II.F, charge the rates shown in Section II.B. 8. Storage Rates for the Unbundled Storage Program a. Establish two-part (reservation and volumetric) rates for both the capacity (injection and inventory) and withdrawal subfunctions for Firm Storage Service. b. Negotiated storage rates may be based on three subfunctions (inventory, injection, and withdrawal) and may be either one-part or two-part rates. H. TRANSMISSION AND UNBUNDLED STORAGE PROGRAM RATES 1. New Transmission Rates a. Four rate components will be applicable to on-system transmission service. A backbone transmission charge, a local transmission charge, a customer class charge, and a customer access charge. Shippers delivering on-system will be charged the backbone transmission charge, and corresponding end-users will be charged the local transmission charge, the customer class charge and customer access charge. b. The backbone transmission charge, the local transmission charge, and the transmission-level customer access charge, will not change from the rate set forth in this Accord, except pursuant to the z-factor. c. New off-system transmission service under the Accord includes a backbone transmission charge, and a customer access charge where applicable. The backbone transmission and customer access charges are guaranteed except for the z-factor. d. Backbone Transmission Charge -34- i. The backbone transmission charge is designed to collect backbone transmission revenues and is applicable to all transmission customers. ii. The retail core market receives 600 MMcf/d (609 Mdth/d) and the core wholesale market receives up to 6.5 MMcf/d (6.6 Mdth/d) of Malin to on-system firm intrastate capacity at vintaged rates. iii. The Malin to on-system rate is based on an intrastate capacity phase-in, over the period from 1997 through 2002 of 375 MMcf/d (381 Mdth/d) of Line 401 and the portion of Line 400 embedded costs not allocated to the retail core and core wholesale. e. The local transmission charge collects local transmission costs and is applicable to all on-system end-users. f. The customer class charge includes social, environmental and transition costs, balancing account balances and all other non-base revenue requirements. Some of the costs included in this charge are CARE, CEE programs, hazardous substance, and ITCS costs. It is generally applicable to all on-system end-users. g. The customer access charge includes the cost of meters and service drops, meter reading, billing and payment processing, and is applicable to the customers to whom PG&E provides these services (see Section II.I.10). h. Transmission rates for AFT, SFT, and AA are shown in Section VI. 2. Pre-existing Transmission Rates Pre-existing services and contracts are discussed in Sections II.B and II.F. 3. Storage Rates for the Unbundled Storage Program a. Rates for storage services are based on the costs of storage injection, inventory and withdrawal. b. Firm Storage i. Rates are subfunctionalized by a capacity (combined injection and inventory) charge and withdrawal charge. ii. Capacity and withdrawal charges are recovered through a reservation (fixed) and volumetric (variable) component. c. Negotiated Firm and As-available services are negotiable above a price floor representing PG&E's short-run marginal cost of providing the service. -35- d. Negotiated Firm rates can be recovered through a volumetric-only charge or a reservation and volumetric charge. e. Negotiated As-available Storage Injection and Withdrawal rates are recovered through a volumetric charge only. f. Negotiated storage rates (NFS and NAS) are capped at the price which will collect 100 percent of PG&E's total embedded cost revenue requirement for the unbundled storage program for each of the three storage subfunctions (e.g., inventory, injection, or withdrawal). The flexibility inherent in this storage offer could result in stranded facilities and PG&E requires the opportunity to collect the value of its storage services. g. Firm storage rates for the unbundled storage program are shown in Section VI. I. COST BASIS AND RATE DESIGN 1. The Backbone Component of New Transmission Path Rates a. Except for certain services and contracts described in Section II.F, all on-system rates include a backbone transmission component that varies by path, and a common backbone component. The common backbone component includes the costs of backbone facilities used by all on- system paths, and gathering mains. b. The incremental Line 401 costs used in developing the Malin to on- and off-system rates are based on the Pipeline Expansion assumptions shown in Section II.I.3. Off-system rates do not include any common backbone component. c. Malin to on-system rates for the core (including core wholesale) are based on a prorated portion of vintaged Line 400 and Line 2, and the common backbone component. d. Malin to on-system rates for all customers except retail core and core wholesale include the cost of the portions of Line 400 and Line 2 not reserved for the core, the common backbone component, and a phased-in portion of Line 401 costs as described in Section II.I.3. e. Both the Topock to on-system and the Topock to off-system rates include the cost of Line 300 and the common backbone component. Capital costs of $42 million for NOx-related retrofits needed to meet NOx emission standards are included in the Line 300 revenue requirement. To the extent PG&E's expenditures exceed the $42 million, PG&E will be at risk for recovery of these expenditures during the Gas Accord period, but does not waive the right to seek recovery after that. f. California production to on-system rates include 40 percent of the average backbone transmission costs and the common backbone component. California -36- production to off-system rates assume Line 401 will be used, and the rate is equal to the Line 401 to off-system rate. g. The on-system and off-system rates are guaranteed for the Accord period, subject to change pursuant only to the z-factor provision of Section II.I.7. 2. The Storage Costs in the Unbundled Storage Program a. The storage costs allocated to the unbundled storage program represent 12.5 percent of the inventory, injection, and withdrawal storage costs remaining after the allocation for load balancing requirements. b. The maximum rates for Negotiated Firm Storage and Negotiated As- available Storage are based on a rate design assuming an average injection period of 30 days and an average withdrawal period of seven days. The rates assume full collection of the total unbundled storage program revenue requirement in each individual subfunction. c. The minimum rates for Negotiated Firm Storage and Negotiated As-available Storage are based on the marginal price floor to provide the service. 3. Revenue Requirement Assumptions a. Gas Department (excluding Pipeline Expansion) i. Initial base revenue requirements for calculating 1997 rates match PG&E's 1996 GRC. ii. Cost of capital and capital structure are based on the 1996 Cost of Capital proceeding's authorized cost of capital for the gas department. iii. Gas department common costs are allocated to backbone transmission, local transmission and distribution based on plant and labor. b. Development of the Line 401 Revenue Requirement i. Base revenue requirements are calculated using the proposed litigation resolution figure of $736 million of capital costs discussed in Section V. Operating expenses and the methods used to allocate costs and calculate taxes and the revenue requirement match PG&E's current position in the Pipeline Expansion Project Reasonableness (PEPR) Case. ii. Cost of capital and capital structure matches PG&E's gas department cost of capital as authorized in the 1996 Cost of Capital Decision 95-11-062, with no premium on the return on equity. -37- iii. No common costs, except those included in the PEPR Case, are included. The cost allocation methods match those used in the PEPR Case. The allocation of original facilities to the Expansion increases to the amount proposed by PG&E in the PEPR Case. c. Line 401 Cost Phase-in to On-system Rates Each year a portion of the Line 401 revenue requirement will be included in the Malin to on-system rate. The portion is calculated using the firm Expansion capacity of 813 MMcf/d (825 Mdth/d). The Line 401 revenue requirement phased-in each year will be based on depreciated plant. The following table summarizes the amount of capacity used to determine the phased-in costs:
Capacity 1997 1998 1999 2000 2001 2002 ---- ---- ---- ---- ---- ---- Incremental 200 50 50 25 25 25 (MMcf/d) Cumulative 200 250 300 325 350 375 (MMcf/d) Cumulative 208 254 305 330 355 381 (Mdth/d)
4. Load Factor and Rate Cap Assumptions a. Firm annual on-system backbone transmission charges are based on an annual average capacity factor of 87.5 percent. Malin to on-system capacity increases each year consistent with the cost phase-in. Seasonal firm and As-available rates are set at 120 percent of the annual firm rates. As-available rates are set at 110 percent of the annual firm rates through March 31, 1998, and at 120 percent thereafter. The load factors used in setting backbone transmission rates remain constant through the Gas Accord period. The core's Topock to On-system path charge for firm seasonal capacity will be calculated at 110 percent of the firm annual price for the period through March 1998. b. The Malin to off-system firm rates are calculated using incremental Line 401 costs and a 95 percent load factor. The Malin to off-system As-available rates are set at 110 percent of firm rates through March 31, 1998, and at 120 percent thereafter. c. On-system California production and storage to off-system rates are equal to the Malin to off-system rates. 5. Balancing Account Treatment a. There will be no balancing account treatment for backbone or local transmission revenues, or for parking or lending service revenues. -38- b. The current storage program has a contractual operating period from April 1 through March 31. Therefore, PG&E will not offer firm storage service until April 1, 1998, and PG&E will continue to honor storage contracts for the 1997/1998 storage season. PG&E may begin offering as-available storage service upon implementation of all other services if capacity is available. Balancing account treatment for the current storage program will continue through March 31, 1998. Any outstanding balance plus interest will be allocated to core and noncore customers on an equal cents per therm basis. PG&E will absorb 100 percent of the core share. 6. Shrinkage (compressor fuel, and lost and unaccounted for gas) In-kind shrinkage will be charged to all gas shipped on the PG&E transmission system on a postage-stamp basis. Additional shrinkage will be charged for distribution service, also on a postage-stamp basis. The Malin to off-system shrinkage rate is the rate adopted in Decision 94-02-042. The shrinkage rate for all other transmission paths is developed using rates authorized in PG&E's BCAP Decision 95-12-053 and is subject to change in subsequent BCAPs. Transmission shrinkage will be charged for all deliveries into storage, but not for deliveries out of storage. Path Shrinkage Rate ---- -------------- Malin to Off-system 1.11% All Other Transmission Paths 1.72% 7. Rate Adjustments a. The Line 400 component of Malin rates escalates at 2.5 percent annually. b. Line 401 costs used to establish the phase-in component of the Malin to on-system rates and the Malin to off-system rates are adjusted in accordance with PG&E's Pipeline Expansion Rate Case methodology and the litigation resolution agreement in Section V. c. Line 300 rates escalate at 2.5 percent annually, plus the revenue requirement associated with the $42 million of capital cost additions for NOx-related retrofits needed to meet NOx emission standards. d. Storage and parking and lending rates escalate at 2.5 percent annually. e. The guaranteed rates may be adjusted by a z-factor to reflect extraordinary costs or savings. The z-factor is limited to known changes due to governmental action. An example of a government action would include changes to the federal or state income tax rate. The z- factor mechanism would not replace either the current CEMA or the Hazardous Substance incentive mechanism, both of which would remain in effect. -39- f. The following z-factor sharing mechanism (costs or savings) is adopted for cost responsibility per each extraordinary event:
z-Factor Cost (Savings) Cost Per Event Responsibility ----------------------- -------------- $0 - $5 million 100% PG&E (greater than) $5 - $10 million 50/50 sharing (greater than) $10 million 100% customers
8. Local Transmission Charge a. The charge includes the cost of local transmission facilities. b. The local transmission charge is paid by all on-system end-users. This charge is non-bypassable. c. The local transmission charge varies by core and noncore customer class. Local transmission costs are allocated to core and noncore based on LRMC methodology from PG&E's BCAP Decision 95-12-053. d. Local transmission rates escalate at 2.5 percent annually. e. The local transmission charge will have no balancing account protection. f. The rates are guaranteed for the Accord period, subject only to the z-factor provisions of Section II.I.7. g. Local transmission rates are shown in Section VI. 9. Customer Class Charge a. The customer class charge is designed to collect social, environmental and transition costs, balancing account balances, and all other non- base revenue requirements. Some of the costs included in this charge are CARE, CEE programs, hazardous substance, and ITCS costs. b. The core customer class charge does not include ITCS. PG&E will absorb all of the core portion of the ITCS charges as defined herein, less brokering revenues, plus interest, from the beginning of the ITCS account, as part of the litigation resolution described in Section V. The customer class charge includes a "true-up" of ITCS costs collected from core customers prior to Accord implementation. c. The noncore customer class charge includes only 50 percent of the noncore ITCS costs, less brokering revenues, plus interest, from the beginning of the ITCS account. PG&E will absorb the remaining 50 percent of the noncore ITCS costs, as part of the litigation resolution described in Section V. -40- d. The customer class charge does not include any component for recovery of the backbone credit. PG&E will absorb 100 percent of the Backbone Credit Account. PG&E will not provide any shipper with a backbone credit after the Gas Accord is approved, as part of the litigation resolution described in Section V. e. Initial customer class charges have been allocated to customer classes and will be collected in rates as determined in PG&E's 1996 GRC and PG&E's BCAP Decision 95-12-053. These charges will be periodically adjusted based on the regulatory proceedings associated with each account and continue to be subject to balancing account treatment. f. PG&E will collect the existing balance in the Noncore Fixed Cost Account (NFCA), but will not record any activity to the account other than amortization revenue and interest after implementation of the Gas Accord. g. Customer class charges will be paid by on-system end-users only. However, loads subject to Line 401 direct connect agreements or EOR contracts will neither pay, nor be allocated, customer class charges while the direct connect agreements or contracts are in effect. h. Forecast customer class charges are shown in Section VI. 10. Customer Access Charge a. End-users who are directly connected to the transmission system will pay a customer access charge each month. The purpose of the customer access charge is to assess the end-user a fee for the cost of providing and maintaining the individual end-user's service connection to the transmission system. b. For industrial end-users, the customer access charges will be the same as the current industrial customer charge. With the current industrial customer charge, each end-user is placed in one of six tiers depending on the end-user's specific annual volumetric usage. There is a specific monthly charge associated with each tier. Distribution industrial customers will have the same initial customer access charge as part of their distribution rates. c. The UEG and cogenerator customer access charges will be based on the annual scaled marginal customer cost revenues adopted in BCAP Decision 95-12-053. For UEG, the customer access charge is a monthly charge. For cogeneration end-users, the customer access charge will be a volumetric adder, calculated such that the UEG-cogeneration rate parity is maintained. For cogeneration end-users currently on Schedule G-CGS, the volumetric adder will equal UEG customer access charges for twelve months divided by the UEG average annual forecasted throughput adopted in BCAP Decision 95-12-053. For cogeneration end-users currently on Schedule G-EPO, the volumetric adder will equal the UEG monthly -41- customer charge divided by UEG actual monthly throughput, lagged by sixty days. d. For wholesale customers, the customer access charge for each month of 1997 will equal the scaled annual marginal customer cost revenues adopted in BCAP Decision 95-12-053 for each specific wholesale customer divided by twelve. e. Customer access charges escalate at 2.5 percent per year annually. f. Current customer access charges are shown in Section VI. g. Customer access charges for transmission level customers are guaranteed for the Accord period, subject only to z-factor changes described in Section II.I.7. 11. Cogeneration Rate Parity a. On-system cogeneration tariff transmission rates will be available to all cogenerators, including EPO3 cogenerators, from PG&E's transmission department. For each path and service, cogenerator rates will be set equal to the average Utility Electric Generation (UEG) rate for that path and service. UEG negotiated rates received from PG&E's transmission department will be included in the rate calculations on a weighted average,/1/ path specific, service- - specific/2/ basis. PG&E will develop, in cooperation with - cogenerators, a-mechanism to incorporate UEG negotiated rates into cogeneration rates. b. In the event that the current methodology used to determine payments to EPO3 cogenerators changes so that it is no longer based on actual UEG natural gas costs, PG&E will negotiate with EPO3 customers in good faith to develop a method for calculating EPO3 natural gas transmission service rates which maintains the linkage between EPO3 cogenerators' transmission rates and their electricity payments. Such resulting rates would be subject to CPUC approval and will apply only until the expiration of the EPO3 payment option. - ------------------- /1/ That is, the firm service rate for cogenerators will be calculated using - any-negotiated rates for firm service for UEG weighted by volume; similarly, the As-available service rate for cogenerators will be calculated using any negotiated rates for As-available service for UEG weighted by volume. /2/ For purposes of this paragraph, the term "service specific" shall refer - to-either firm service or As-available service (including negotiable rate, non- negotiable rate and other variations of such service) and indicates the distinction between firm and As-available as separate services. -42- c. Transportation services provided to the UEG by entities other than PG&E's transmission department will not be included in the cogeneration rate calculations. The UEG includes only PG&E-owned utility fossil-fired generation facilities. If the UEG does not take any service from PG&E's transmission department on a particular path for a particular service, the on-system cogeneration tariff rates for that path and service will equal the otherwise-applicable cogeneration tariff rates for that path and service. d. On-system cogeneration transmission rates will be available only to cogeneration end-users for their own usage up to the authorized cogenerator gas allowance./3/ If the cogeneration rate parity statute - (Public Utilities Code Section 454.4) is amended or repealed so that "rate parity" is no longer required by statute,/4/ and if the CPUC - for whatever reason no longer requires such rate parity, then there will be no separate transmission tariff rates applicable to cogeneration end-users. For purposes of this paragraph, PG&E shall be free at any time (following the amendment or repeal of the cogeneration rate parity statute so that "rate parity" is no longer required by statute) to file a superseding tariff for cogenerators with the CPUC, which filing may be the occasion for the CPUC to reevaluate the requirement for such rate parity. Cogenerators expressly retain the right to oppose such a filing by PG&E./5/ - e. An on-system cogenerator's monthly bill for non-discounted tariff service provided by PG&E's transmission department shall be the minimum of the bill calculated using the transmission rates described above, and the bill calculated using the otherwise-applicable tariff transmission rates for that path and service. f. During open seasons for intrastate transmission capacity, PG&E will notify on-system cogenerators of UEG's elections for service from PG&E's transmission department three business days prior to the date that cogenerators must make their service elections. PG&E will also notify on-system cogenerators of UEG's other elections for service from PG&E's transmission department as they may occur - ----------------------- /3/ The cogenerator gas allowance is not to be determined by the Gas Accord, - except that it will remain within 10 percent of 0.09683 th/kWh. /4/ The Gas Accord does not restrict either PG&E or cogenerators from seeking - legislative changes to P.U. Code Section 454.4, but the parties shall support the provisions of the Gas Accord before the CPUC. /5/ The provisions of this section are not intended to limit parties' - abilities to address before the CPUC any issue they think appropriate dealing with the divestiture of PG&E generation units. This could include discussion of any cogeneration rate parity topics as they might relate in any way to divested units. -43- from time to time. This will apply only to UEG service agreements whose durations are more than 30 days. -44- III. DISTRIBUTION SERVICES A. SERVICES FOR NONCORE END-USERS 1. Distribution transportation service: Noncore customers connected to PG&E's distribution system may arrange for transmission, storage, and supply services separately. These customers receive noncore distribution service from PG&E. 2. Core subscription: Noncore customers may have PG&E arrange for their supply and transmission service under core subscription service, described in Section IV.M. 3. Residual load service: PG&E will propose a residual load service in the next BCAP. B. SERVICE FOR CORE END-USERS 1. PG&E will continue to provide bundled service for coreend-users. See Section IV for changes that may affect core service. 2. PG&E will also provide core transport service for core end-users. See Section IV for a discussion of core aggregation. C. RATES AND COST ALLOCATION 1. Distribution Revenue Requirement Assumptions a. The initial natural gas distribution revenue requirement will match PG&E's 1996 GRC Decision 95-12-055, consistent with the transfer of DFMs to local transmission. Customer access charges for transmission-level end-users have been moved from the distribution revenue requirement to the customer access charge. b. The distribution revenue requirement in future years of the Gas Accord will be based on cost of service or Performance Based Regulation (PBR), whichever is applicable. For the purposes of calculating the illustrative rates shown in Table 16 in Section VI, the revenue requirement escalates at 2.5 percent per year. 2. Distribution Cost Allocation a. The initial distribution revenue requirement will be allocated to end-users on an Equal Percent of Marginal Cost (EPMC) basis, using distribution and customer marginal cost revenues consistent with PG&E's BCAP Decision 95-12-053. b. PG&E will continue to have BCAPs and GRCs or successor proceedings to update the allocations of costs. The methodology for allocating the distribution revenue requirement between core and noncore will not be changed for the term of the Gas Accord, although the allocation itself may change due to, among other -45- things, changes to throughput forecasts or marginal costs. The allocation of revenues within the core will be addressed in future BCAPs. 3. Distribution Throughput a. Distribution throughput for noncore end-users has been modified to reflect loads served directly from the transmission system, as well as end-users connected to the distribution system but classified as transmission customers. b. Core and noncore throughput forecasts will be addressed in future BCAPs or PBRs. 4. Balancing Account Treatment a. PG&E's core procurement department's cost of intrastate backbone and local transmission service for the core will receive 100 percent balancing account treatment for the costs incurred, either through the Core Fixed Cost Account (CFCA) or the Purchased Gas Account (PGA). b. The core distribution revenue requirement will continue to receive 100 percent balancing account treatment. c. Balancing account treatment (Noncore Fixed Cost Account) for prospective noncore distribution revenues will be eliminated. 5. Shrinkage a. Noncore customers and core transport customers will continue to deliver in-kind shrinkage. Bundled core end-users and core subscription customers will continue to pay shrinkage as part of their procurement rate. b. Shrinkage will be charged on the distribution system on a postage- stamp basis for all gas deliveries. Distribution shrinkage is in addition to any shrinkage applied on the transmission system. c. Distribution shrinkage is calculated using percentages authorized in PG&E's most recent BCAP Decision 95-12-053, as follows: the core distribution shrinkage rate (including core transport) is 3.31 percent, and the noncore distribution shrinkage rate is 0.21 percent. These percentages are subject to change in future BCAPs. The core shrinkage subaccount will continue as currently authorized. 6. Distribution Rates and Rate Design -46- a. Forecast distribution rates and illustrative intrastate bundled core transportation rates are shown in Section VI. b. The initial core commercial winter distribution rate component will remain at 135 percent of the summer distribution rate component. For core commercial customers taking bundled service from PG&E, intrastate transmission costs will be allocated into the season in which they are incurred, and storage costs will be included in winter season rates only. Commodity costs will not be included in any seasonal rate differential calculation. c. The initial noncore winter distribution rate component will be 135 percent of the summer distribution rate component. d. Future distribution rate design, rates, residential tier differentials, and core deaveraging, among other things, will be determined in future BCAPs. Parties also reserve the right to propose other cost-based core cost allocation and rate design changes in future BCAPs. 7. Cogeneration Rate Parity a. Consistent with the CPUC's cogeneration rate parity policy, distribution level cogenerators will not have a distribution component in their rate. The resulting "cogeneration shortfall" will be a part of the customer class charge, and will be collected from cogeneration and UEG end-users, for their own usage up to the authorized cogenerator gas allowance. b. If the cogeneration rate parity statute is amended or repealed so that "rate parity" is no longer required by statute, and if the CPUC for whatever reason no longer requires such rate parity, then distribution level cogenerators will be served under the otherwise applicable distribution rate, and there will be no separate cogeneration class. c. PG&E shall be free at any time (following the amendment or repeal of the cogeneration rate parity statute so that "rate parity" is no longer required by statute) to file a superseding tariff for cogenerators with the CPUC, which filing may be the occasion for the CPUC to reevaluate the requirement for such rate parity. Cogenerators expressly retain the right to oppose such a filing by PG&E. 8. Discounting a. Distribution service may be discounted to prevent uneconomic bypass of PG&E's distribution system and to encourage business retention and business attraction. b. PG&E may negotiate discounts with distribution-level noncore end- users to prevent uneconomic bypass of PG&E's distribution and transmission systems, and to encourage business retention and business attraction. -47- c. Any negotiated discounts with core end-users for distribution service will require CPUC approval prior to going into effect. d. If the purpose of a noncore discount negotiation is to attract or retain both transmission and distribution load, any discount will be "split" between transmission and distribution services proportional to the revenue to each system at full tariff prices. The noncore end-use customer would receive the transmission portion of the discount in a bill credit, or through local transmission or customer access charges. e. If a negotiated distribution service benefits only the distribution system, any discount will be reflected only in distribution rates. f. PG&E will have the option in BCAP proceedings of demonstrating the reasonableness of any discounted distribution contracts that will continue into the prospective period. If the Commission finds the discounts to be reasonable, PG&E will be allowed to recover the forecasted revenue shortfalls during the prospective period. g. Negotiated contracts and affiliate transactions rules which will apply to transmission services will also apply to distribution services. (See Sections II.E.15 and II.E.16.) -48- IV. PG&E'S FUTURE ROLE IN CORE PROCUREMENT A. OVERVIEW PG&E proposes to reduce costs to customers and to expand core customer choices by: 1. Encouraging greater customer choice among gas suppliers; 2. Reducing PG&E's regulated sales of gas to core customers; 3. Reducing PG&E's interstate pipeline capacity holdings for the core; 4. Establishing operational principles that provide market flexibility while ensuring safe and reliable service; 5. Implementing appropriate incentive mechanisms; and 6. Negotiating with California producers for a mutual release of PG&E's gas purchase contracts and reducing gas gathering costs through the disposal of assets. B. CORE PROCUREMENT ADVISORY GROUP 1. Significantly reducing PG&E's role in the core procurement market requires significant expansion of the current core gas transportation program. This program now serves only about three percent of the core load in PG&E's service area, and well under one percent of core customers. 2. To determine the changes that should be made to the program, PG&E invited all Gas Accord parties to participate in the Core Procurement Advisory Group (CPAG). The focus of the CPAG was the development of recommendations that would accomplish two primary objectives: a. Make the program consistent with the proposed Gas Accord framework; and b. Remove barriers, from both the customers' and aggregators' perspectives, to increasing program participation. 3. Approximately 50 parties joined PG&E and identified over 40 separate issues that needed to be resolved. Two working groups were established to conduct the detailed negotiations necessary to resolve these issues and balance the widely diverse interests of the parties. 4. After the initial package of recommendations was developed, three new CPAG working groups were established to facilitate implementation of the CPAG recommendations: -49- a. Market Test: The Market Test work group will participate in the ----------- development and performance of market research and affinity- group marketing field tests that are required to enhance core aggregation in PG&E's service area. b. Tariff Revisions: The Tariff Revision work group will assist as ---------------- PG&E's tariffs are revised to incorporate the CPAG recommendations that are ultimately approved in the Gas Accord proceeding. c. Load Forecast and Determination Model: The Load Forecast and ------------------------------------- Determination Model work group will participate in the development of a model that will be used for core load balancing purposes. 5. The agreements below reflect the approved package of CPAG recommendations. The core aggregation agreements are intended to apply to PG&E's service area. They are not intended to set precedents for any other utility service area, or for noncore service. Additional information about the detail behind these proposals can be found in the CPAG agreement. C. PG&E'S AND AGGREGATORS' ROLES IN THE CHANGING CORE GAS SALES MARKET 1. As part of its compliance filing following approval of the Gas Accord, PG&E will file tariffs to lift the ten percent cap on PG&E's core gas aggregation program. 2. Aggregators have the obligation to make and pay for all necessary arrangements to deliver gas to PG&E to match the use of their customers. 3. PG&E has the obligation to operate the gas system safely and efficiently and to purchase gas supplies for customers not served by aggregators. 4. PG&E's remaining core gas procurement role will be as a regulated utility supplier within PG&E's service area during the Gas Accord period. 5. The CPAG will explore, through market research efforts, several ways to attract small and highly seasonal customers to core transportation service and to reduce transaction costs for aggregators to serve them. 6. PG&E and the aggregators will each be responsible for dealing with their own customers' payment problems. The allocation of costs to serve slow- and non-paying customers will be reexamined when PG&E's core gas sales market share drops to 80 percent. 7. The costs of social and environmental programs such as CARE, clean air vehicles and customer energy efficiency will continue to be recovered from all on-system end-users through the customer class charge component of the transportation rates. 8. CARE core transportation customers will receive the full CARE benefits regardless of their choice of gas supplier. -50- D. REDUCING PG&E'S INTERSTATE PIPELINE CAPACITY PG&E will adjust its core capacity holdings of firm interstate pipeline capacity as follows: 1. PG&E's contract with El Paso will terminate at the end of 1997. As part of the current El Paso general rate case (FERC Docket Nos. RP95- 363-000, et al.), PG&E's termination of this contract, as well as other utility contract step-downs and the related costs, are addressed in a settlement filed with the FERC on March 15, 1996. The parties agree that any costs paid by PG&E resulting from the FERC- approved settlement will be treated as one component of the overall interstate pipeline reservation charges; and therefore, will be allocated to core and noncore customers using the allocation methodology for interstate pipeline reservation charges adopted in PG&E's BCAP Decision 95-12-053. 2. PG&E reserves the right to subscribe to additional interstate capacity in the future, with costs assigned to PG&E's core procurement customers. 3. Other reductions may be made by PG&E (as allowed by PG&E's interstate capacity contracts) as core aggregators' share of the core market increases. E. PG&E'S CORE PROCUREMENT DEPARTMENT INTRASTATE PIPELINE AND STORAGE CAPACITY 1. PG&E's core procurement department will hold intrastate transportation capacity on behalf of its core and core subscription customers. The following initial firm reservation of intrastate transportation capacity will be made for the retail core: a. PG&E's retail core initially will be allocated the following quantities of firm transmission capacity:
Malin to Topock to On-system On-system California --------- ---------- ---------- Annual MMcf/d 600 150 50 Mdth/d 609 155 48
b. PG&E's retail core will also hold additional seasonal winter capacity as follows: -51-
Malin to Topock to On-system On-system California --------- --------- ---------- November and March MMcf/d 0 150 0 Mdth/d 0 155 0 December to February MMcf/d 0 450 0 Mdth/d 0 464 0
2. The initial firm allocation of Malin capacity for the retail core will be priced at vintaged rates. 3. PG&E's core procurement department will continue to be allocated firm rights to a portion of storage capacity on behalf of the core market, as specified in Section II.E.5. The core's storage and other costs related to maintaining the safe and reliable operation of the gas system will be included in core rates. F. CORE AGGREGATORS' HOLDINGS OF INTERSTATE CAPACITY 1. PG&E will make two filings to unbundle interstate transmission costs from core transport rates within 30 days after a comprehensive Gas Accord agreement is signed. a. The first filing will address unbundling prior to January 1, 1998. This filing will: i. unbundle PGT and El Paso capacity; ii. impose a surcharge on core transport rates until January 1, 1998, not to exceed $0.19/Dth, to cover any resulting transition costs; iii. continue the present treatment of ANG and NOVA costs; and iv. implement the rate credit described in Section IV.G.6. b. The second filing will address unbundling after January 1, 1998, when PG&E's El Paso contract will expire. This filing will: i. continue unbundling of PGT capacity; and ii. provide that, once the core transport share of PGT core capacity exceeds the point where PG&E's remaining PGT core capacity matches its upstream rights on ANG and NOVA, approximately 40 MMcf/d, core aggregators taking a share of PGT core capacity will have the right, but not the obligation, to accept a proportionate share of ANG and NOVA capacity, to the extent it is available, for additional PGT capacity reservations. iii. provide that, to the extent that core aggregators taking a share of PGT core capacity choose not to take a proportionate share of ANG and NOVA -52- capacity, PG&E will have the right to offer to assign the capacity to other shippers for one month up to the duration of PG&E's contracts with ANG and NOVA. This may result in core aggregator's not having access to this capacity in the future. If PG&E chooses not to make such an offer, or is not successful in finding shippers for the full amount offered, PG&E will broker the capacity. iv. provide that, 50 percent of the difference between the cost of PG&E's contractual obligations for the proportionate share of ANG and NOVA capacity offered to, but not taken, by core aggregators, and the revenues collected by PG&E as a result of brokering efforts for that capacity will be allocated to the transportation rates paid by PG&E's core transport customers. PG&E's shareholders will be at risk for the remaining 50 percent. 2. Core aggregators will choose their own interstate pipeline capacity mix. Each month, core aggregators will have a preferential right (but not the obligation) to acquire a portion of PG&E's interstate capacity holdings to serve their core customers. 3. If core aggregators choose not to acquire PG&E's firm capacity rights, or if this capacity is marketed at less than as-billed rates, unrecovered pipeline reservation fees will become a transition cost, subject to the $0.19/Dth cap in Section IV.F.1.a.ii above until January 1, 1998. 4. Beginning January 1, 1998, any pipeline transition costs resulting from existing PGT commitments on behalf of core transport customers will be allocated to all core customers for the term of the Gas Accord. This provision will be reexamined if transition costs exceed $5 million per year. G. CORE AGGREGATORS' HOLDINGS OF INTRASTATE CAPACITY AND STORAGE 1. Intrastate transmission costs will be unbundled from core aggregation customers' rates effective with the Accord. 2. For the initial two years of the Gas Accord, aggregators must hold firm intrastate transmission capacity rights during the winter season equal to a proportional share of PG&E's initial core reservation during the five winter months, excluding the California on-system reservation. Thereafter, aggregators who perform reliably will have no firm requirements. 3. Aggregators may choose the transmission path of their reservation. They are entitled, though not obligated, to subscribe to a proportional share of the vintage-priced Malin to on-system core reservation and/or a proportional share of the Topock to on-system reservation. 4. Aggregators may also use the following alternatives to meet their firm intrastate transmission requirements: -53- a. Standard agreements to use other firm holders' rights when needed; b. California gas supplies; or c. Firm storage capacity in addition to their assigned capacity, if available. 5. Aggregators will continue to be assigned a proportional share of PG&E's core storage reservation based on the winter season throughput of the core transport customers (consistent with CPUC Decision 95-07- 048), with the obligation to fill it and maintain minimum inventory levels for reliability purposes. However, to the extent possible without compromising the reliability functions of storage for core customers, aggregators will have the right to use storage balances above each aggregator's minimum level described in PG&E's G-CT tariff to cure imbalances, to make same-day injection and withdrawal nominations, and to sell or trade gas in storage. 6. Within three years after the Gas Accord is implemented, PG&E will file with the CPUC an examination of storage unbundling for core transportation customers in light of the then-existing market. 7. In recognition of the fact that aggregators have settled for less service unbundling than they preferred, and to encourage participation in the core transportation program, PG&E's shareholders will fund a $0.095/Dth credit to core transport rates until January 1, 1998. H. CORE AGGREGATION REGULATORY ISSUES 1. The PG&E core procurement brokerage fee will be set at $0.024/Dth and will be subject to balancing-account recovery. This fee will be reviewed when PG&E's market share drops to 80 percent. 2. In compliance with the provisions of California Public Utilities Code Sections 6350 - 6354, PG&E will continue to collect city/county franchise fees for service provided by aggregators based on its own weighted-average cost of gas (WACOG). PG&E will seek legislative changes to allow similar treatment for utility users' taxes. 3. Billing and metering costs will remain bundled. PG&E will install additional metering at the request/expense of aggregators and their customers, and will provide a credit if PG&E equipment can be removed as a result. 4. PG&E will continue to oversee aggregators' creditworthiness, pursuant to PG&E's Gas Rule 23, Gas Aggregation Service for Core Transport Customers. 5. Aggregators will continue to be required to sign a core transport agreement with PG&E. Aggregator-customer contracts are strictly between the parties. -54- 6. Customers must sign a PG&E agreement for service from an aggregator for an initial term of 12 months. PG&E will conduct market research to see if this requirement is a significant barrier to program participation. 7. In order to prevent slamming (unauthorized switching of a customer from one aggregator to another), written consent will continue to be required from customers who want to change their gas aggregators. 8. Aggregators may obtain PG&E customer information required to select and serve their customers (such as balances owed and customer-service details) when authorization is given by the customer. 9. PG&E will provide aggregators with a list of qualified gas-supply businesses owned by minorities, women, and disabled veterans that may be used when purchasing gas supplies. PG&E will also provide gas- supply businesses owned by minorities, women, and disabled veterans with a list of qualified core aggregators and other information needed to participate in PG&E's core gas transportation program. 10. The minimum size for a core transport group will be lowered from 250,000 therms per year to 120,000 therms per year. 11. After three years, PG&E will file a core transport program status report with the CPUC, and PG&E will hold a workshop to address any difficulties that have arisen with respect to PG&E's core gas transportation program. 12. The modifications for core aggregation are designed so that they do not have a significant adverse impact on PG&E's remaining core procurement customers. I. CORE AGGREGATION AND CUSTOMER INFORMATION 1. Customers of aggregators may continue to select a consolidated payment option, where aggregators in compliance with PG&E's Gas Rule 23 creditworthiness standards collect and forward to PG&E appropriate transportation revenues from their customers, as long as the payments to PG&E are on time. 2. PG&E and the aggregators will work together to develop a common Electronic Data Interface (EDI) protocol, which all aggregators will then be required to use, to streamline data and monetary transfers necessary to serve their customers. 3. PG&E will continue to promote the core transportation program to customers through periodic bill inserts and provision of aggregator lists upon customer request. PG&E will also promote the core transportation program to its own employees through an internal education program. -55- 4. PG&E will conduct a market test to see if outreach efforts through affinity groups (e.g., city governments, schools, churches) are effective in increasing program knowledge and participation and reducing aggregators' transaction costs. 5. PG&E call centers will be equipped to handle calls about the core transportation program. 6. PG&E will provide aggregators with a bill insert that they may use to ensure that their customers know to call PG&E for service- or safety- related questions. Aggregators will refer all such calls that they receive from their customers to PG&E. J. CUSTOMER AGGREGATION SERVICE AND OPERATIONAL ISSUES 1. PG&E will provide aggregators with a new Core Load Forecasting and Determination Service. This service will feature 24- and 48-hour forecasts and day-after estimated ("determined") use, based on each aggregator's customer mix. 2. The sum of the daily determined use figures will be used to calculate monthly imbalance volumes and penalties. 3. The difference between the monthly sum of the daily determined use figures and the prorated monthly metered use for each aggregator's customers will be the "operating imbalance." The operating imbalance will be disposed of during the next month. However, operating imbalances of more than 10 percent of monthly use can be disposed of over two months. 4. By 5:00 p.m. on the day before an Operational Flow Order or Emergency Flow Order, PG&E will provide an additional forecast to aggregators for their customers' next-day usage. Aggregators will be required to balance against that forecast during the OFO or EFO. 5. When an aggregator collects PG&E transportation revenue from customers under the "consolidated payment" option, PG&E will hold the aggregator responsible for late payment or non-payment to PG&E if the customer can demonstrate that it has paid the aggregator in full and on time. PG&E will not hold the customer responsible . 6. The following recommendations were made in order to provide clear, prompt, and responsive information to address customer concerns: a. PG&E and the aggregators will negotiate the establishment of joint communications protocols, to allow seamless call and information transfers. b. PG&E and the aggregators will negotiate an industry "decision tree" for screening customer inquiries, to determine the party responsible for responding to the customer. K. CORE WHOLESALE CUSTOMERS -56- 1. Wholesale customers have the obligation to plan to meet their own core loads. 2. Existing wholesale customers, Palo Alto and Coalinga, will have a one-time option at the implementation of the Gas Accord to subscribe, on behalf of their core customers, for up to 6.5 MMcf/d (6.6 Mdth/d) of firm capacity on the Malin to on-system path at vintaged rates. 3. Existing wholesale customers will have the right to a share of storage capacity. They will get first priority from the storage capacity allocated to the Unbundled Storage Program, equal to their proportional share of the core load. They must reserve inventory, injection, and withdrawal proportionately together and they will pay the equivalent core rate for storage. Any storage cost will be added to the wholesale customer's transportation rate. They will have the same storage rights as other entities serving core customers and they may contract for storage through the Unbundled Storage Program to serve their noncore customers. L. PROCUREMENT INCENTIVE MECHANISMS 1. For the period June 1, 1994, through December 31, 1997, PG&E will recover procurement and transportation costs consistent with the revised CPIM mechanism negotiated with DRA in 1996, and submitted as testimony by PG&E on April 23, 1996, in Application 94-12-039. As a result, this will resolve core procurement reasonableness for such period. Further, as part of such testimony, PG&E will forego its right to seek recovery of the reservation charges associated with the 150 MMcf/d Transwestern core reservation for the periods 1992-1997. 2. A post-1997 procurement incentive mechanism will be based on the following parameters: a. The pre-1998 CPIM agreement with DRA will be used as a model for the new incentive mechanism. b. The mechanism will be modified to include intrastate core capacity use (both firm and as-available). -57- c. The mechanism will be modified to allow for the opportunity to recover the cost of Transwestern reservation charges for 150 MMcf/d, as well as other Southwest interstate capacity requirements that the core may require. d. PG&E will develop a procedure to recover the costs associated with diversion and balancing penalties in rates that may occur under extreme weather or other extraordinary circumstances. e. Based on the above parameters, PG&E and DRA will agree on the detailed substance of their post-1997 mechanism and amend this Gas Accord Settlement filing with the CPUC. M. CORE SUBSCRIPTION 1. Operations a. Core and core subscription customers will be served by PG&E through a single supply portfolio. b. Capacity reservations, nominations, and balancing will take place for the portfolio as a whole. c. Core subscription customers will be assumed to use a proportional share of reserved interstate, Canadian and intrastate capacity. d. Core subscription customers will be assumed to use a proportional share of the core portfolio's flowing supplies. e. Transmission service priority for core subscription customers under emergency conditions will be the same as the priority of firm intrastate transmission service. 2. Pricing a. Core subscription rates will be volumetric. b. The intrastate transmission capacity charges for core subscription will be based on the transmission rates for the noncore market. That is, core subscription will not receive vintaged Malin to on-system prices. Core subscription revenues above the core subscription's proportionate share of the core portfolio's intrastate capacity costs will be returned to core customers served from the portfolio. c. The PGT capacity costs for core subscription will be set at a weighted average (based on the available capacity) of the FTS-1 "Noncore" and the FTS-1 "Expansion Shipper" reservation rates, as specified in PGT's FERC-approved tariffs. Core subscription revenues above the core subscription's proportionate share of the core portfolio's PGT capacity costs will be returned to core customers served from the portfolio. -58- d. The cost of southwest pipeline capacity for core subscription is set at its cost. e. The Canadian capacity charges for core subscription will be at the as-billed rate. f. There will be a surcharge on core subscription rates of $0.07/Dth beginning January 1, 1998, to fund activities associated with program phase-out. Unspent revenues from the surcharge remaining after the core subscription program is discontinued will be returned to the core subscription customers which initially paid the surcharge. g. Each core subscription customer will be responsible for any customer-specific penalties for failing to curtail use when requested by PG&E under the involuntary diversion provisions. Core subscription customers will not be responsible for any involuntary diversion penalties incurred by the core portfolio. h. Except as just described, the core subscription rate will include core subscription's pro rata share of all core portfolio costs. Among other things, this includes Southwest interstate and Canadian capacity costs, as well as any imbalance charges, voluntary diversion payments, and costs or credits associated with the risk-sharing provisions of the core procurement incentive mechanism. i. The core subscription rate will be set monthly based on a forecast of the core portfolio costs. j. The core subscription monthly commodity price will be set at the forecasted average cost of core portfolio flowing supplies (no gas out of storage), adjusted as necessary to reflect any prior months' forecast error in the core portfolio commodity cost. k. The core subscription rate will also be adjusted as necessary to reflect any prior period forecast errors associated with Canadian, interstate and intrastate capacity (net of brokering revenues). l. Adopted shrinkage costs will be collected from core subscription customers. m. Balancing account treatment for core subscription commodity, interstate and Canadian capacity, and shrinkage will be eliminated prospectively. n. The core subscription rate will include a component to amortize the accrued balances from the current balancing accounts. o. PG&E's noncore brokerage fee will remain at $0.0382 per decatherm, with balancing account treatment. Balances will continue to be allocated equal cents per therm to all noncore customers. 3. Eligibility for Core Subscription Service -59- Any noncore customer on PG&E's system, excluding UEG, is eligible for core subscription service. 4. Core Subscription Service Phaseout a. Core subscription service is to expire within three years after implementation of the Gas Accord. At that time, customers wishing to remain PG&E procurement customers must elect to become core customers. b. Parties may propose cost-based rate design changes in a future BCAP to mitigate the price impact on such customers who choose core status. c. PG&E will conduct a marketing campaign to ensure that core subscription customers are aware of the competitive procurement alternatives available to them. The cost of the marketing campaign will be offset against the revenues from the $0.07/Dth surcharge. 5. Contract Terms a. One-year term. b. Current contracts will remain in effect until their expiration on July 1, 1997, except that current core subscription customers will be allowed to change suppliers before the expirations of their current contracts. c. If the core subscription program participation (numbers of customers or contracted load) increases by more than ten percent (35 customers or 4 MMcf/d), the parties will confer to consider possible responses. N. CHANGING PG&E'S ROLE IN NORTHERN CALIFORNIA GAS PRODUCTION 1. PG&E has had a strong presence in the northern California gas production industry both as the largest purchaser of gas and the largest gas gatherer. The Gas Accord proposes to reshape that role and seeks approval of the principles advocated here. Many of the implementation details that underlie these changes will of necessity be part of separate proceeding(s). PG&E and California producers intend to provide for efficient operation of the facilities used to bring California gas to market and to extend the economic life of California gas production. 2. PG&E proposes several principles that would apply to northern California gas production. They are: a. The mutual release of all California production gas procurement contracts held by PG&E. -60- b. PG&E will support the formation of a non-utility cooperative run and managed by an association of producers (the Cooperative) or of a utility corporation run and managed by an association of producers (the Utility) to purchase and operate the gas gathering system. The Utility or Cooperative shall protect producer interests through an opportunity to participate in ownership and in governance; to have access to information; and to participate in profits, if any. PG&E's support is limited to a gas gathering entity. PG&E will not seek to spin-down the gathering facilities to an unregulated affiliate. c. The sale of as many of the gas gathering facilities as possible to the Cooperative or the Utility, or to individual producers who are served by those facilities. Assets presently designated as gathering that are needed to provide safe and reliable transmission or distribution service will be retained and redesignated. PG&E will identify and connect producers on redesignated portions of the gathering system to the Utility/Cooperative gathering system(s) to assure access to market. d. Should the Cooperative or the Utility not be formed or not purchase all the facilities, PG&E shall divest as many facilities as possible to producers where those facilities are only used by those producers. e. If gathering facilities cannot be divested at a fair market price, PG&E will continue to own and maintain those facilities while recovering the ongoing costs of such facilities directly from producers that use them through a gathering charge. The level of the gathering charges will not exceed the difference between the California path rate and the lowest noncore transmission path connected to interstate gas supplies. f. Where the Utility, the Cooperative, or individual producers acquire or provide their own gathering, the California path rate will be reduced by a cost-based credit. The cost-based credit shall be volumetric and shall be afforded to producers on a basis that reflects facilities acquired and costs avoided. g. Approval of the sale of gas gathering facilities is pursuant to Section 851 of the California Public Utilities Code, on such terms and conditions as are mutually acceptable to the parties. To the extent there is a gain-on-sale related to the disposition of gathering facilities, the gains will be shared 95 percent ratepayer and 5 percent shareholder. To the extent there is a loss-on-sale, PG&E's shareholders will absorb 100 percent of the losses. In determining whether or not a gain- or loss-on-sale has occurred, PG&E will use a net book value based on the depreciation methodology outlined in Decision 89-12-016, the gas gathering decision. Gains would be included in an interest bearing balancing account, reflected in rates in the appropriate rate proceeding. Any environmental clean-up necessary for the sale will be recoverable via the Hazardous Substance Mechanism balancing account or through the appropriate mechanism as may be authorized by the Commission. -61- h. Approval and implementation of a standard California Production Balancing Agreement to meet one of PG&E's goals of improving the efficient use of its gas transportation system by reducing delays caused by adjustments when wellhead meter data do not match scheduled volumes. This will be effected by filing a pro forma agreement in an advice filing, subject to protest by producers. i. Cooperate with the California gas producer community to develop options that will allow gas gatherers access to pipeline pressure data to maximize gathering system operational flexibility and to assist with the management of production imbalances. j. Approval and implementation of a standard California Production Interconnection and Operating Agreement to apply consistent requirements whenever facilities owned by producers, by the Utility, or by the Cooperative are interconnected with PG&E's system for the purpose of gas transportation and authorization of an operations and maintenance fee, where applicable. Both will be effected through an advice filing, subject to protest by producers. k. Any California-produced gas that PG&E buys outside of its existing contracts will meet the same quality standards as all other transported California-produced gas. PG&E will endeavor to continue its historic practice of transporting low-Btu gas to the extent physically possible, based on historical volumes. California produced gas that does not meet PG&E's minimum heating value requirement and/or gas quality specifications as set forth in PG&E's Rule 21 that is sold directly to end-use customers of PG&E is exempt from the residual load service tariff. l. Should the Utility form for the purpose of acquiring and operating the gas gathering system, PG&E will support a filing for "light-handed" regulation for the Utility by the commission. "Light-handed regulation" shall be consistent with protecting producer interests through the provision of gathering services at the lowest reasonable cost; participation in ownership; participation in governance; access to information; assurances against discrimination; and participation in profits. PG&E's support for "light-handed" regulation is limited to a gas gathering entity. 3. The implementation of the Gas Accord could affect the employees of PG&E. With respect to PG&E's International Brotherhood of Electrical Workers (IBEW) workforce, PG&E will work with the IBEW to minimize the impact on employees. In the event that PG&E sells gas gathering facilities, as discussed above, and the sale results in the need to reduce the workforce, PG&E may offer a Voluntary Severance Incentive, a Voluntary Retirement Incentive, retraining, and other employee options, subject to negotiation with the IBEW local 1245. -62- V. LITIGATION RESOLUTION A. OBJECTIVES To resolve the outstanding proceedings relating to PG&E's natural gas operations as a means of transitioning to a restructured, more competitive gas business. Settlement of all these cases and the outstanding issues in these cases pursuant to the provisions below is a prerequisite to implementation of the Gas Accord. B. REGULATORY CASES ADDRESSED BY THE ACCORD 1. The Gas Accord settles and resolves the outstanding gas issues in the following proceedings, except as otherwise noted in this document: a. PG&E's 1992 through 1995 gas reasonableness cases, Applications 93-04-011, 94-04-002, 95-04-002, and 96-04-001; b. All issues in Phases 1, 2, and 3 of the combined Pipeline Expansion Project Reasonableness/Interstate Transition Cost Surcharge proceeding, and also the alleged Rule 1 violation, covered in Applications 92-12-043, 93-03-038, 94-05-035, 94-06- 034, 94-09-056, and 94-06-044; c. All issues regarding the reasonableness of noncore capacity brokering from January 1, 1996, through December 31, 1997. (Noncore and core capacity brokering for 1993-1994 is addressed in 1.b above. Noncore capacity brokering for 1995 is addressed in 1.a above. Core capacity brokering practices from June 1, 1994, to December 31, 1997, are addressed through PG&E's revised CPIM); d. All issues in the Core Procurement Incentive Mechanism case, Application 94-12-039; e. The EAD shortfall issues addressed in Applications 92-07-047, 92-07-049, 95-02-008, and 95-02-010; f. Phase 2 of PG&E's BCAP Application 94-11-015; and g. All issues pertaining to the reasonableness, restructuring, and revision of PG&E's transmission, storage, and core procurement practices, rates, and services in various statewide rulemaking and investigation dockets, R.88-08-018, R.90-02-008, R.92-12-016, and I.92-12-017. 2. PG&E has omitted the Canadian procurement (including the effects on northwest, geothermal and QF purchases), Canadian Decontracting and Restructuring, ANG and NOVA capacity, Affiliate Investigations, CIG sequencing, UEG curtailment, and Southwest procurement (including the Satrap investigation) issues in the 1991-1994 gas reasonableness cases from the list of financial concessions. These issues have -63- been settled separately through May 1994, and the settlements have been filed with the CPUC. Therefore, they are not included in the financial concessions being considered as part of the Gas Accord. C. SETTLEMENT OF REGULATORY CASES AND PG&E FINANCIAL CONCESSIONS 1. Transwestern Pipeline Capacity Charges - Core 150 MMcf/d Contract ----------------------------------------------------------------- (A.93-04-011, 94-04-002, 94-12-039, 95-04-002, 96-04-001, and PG&E's application covering reasonableness for 1996 and 1997, when filed) PG&E will not seek to recover any pipeline demand charges associated with the core portion of the Transwestern contract from the initiation of the contract through December 31, 1997, consistent with PG&E's revised CPIM submitted on April 23, 1996. (See Section IV.L.) For the period after 1997, PG&E will recover Transwestern demand charges for the balance of the Transwestern contract term in accordance with a successor CPIM which will be implemented January 1, 1998. Accordingly, if the Gas Accord, including PG&E's revised CPIM, is approved, PG&E will withdraw any appeal of Decision 95-12-046. 2. ANG and NOVA Pipeline Capacity Charges -------------------------------------- (A.94-12-039, 95-04-002, 96-04-001, and PG&E's application covering reasonableness for 1996 and 1997, when filed) For the period from June 1, 1994, through December 31, 1997, PG&E will recover core ANG and NOVA capacity demand charges in accordance with PG&E's revised CPIM. (See Section IV.L.) For the period after 1997, PG&E will recover ANG and NOVA demand charges for the balance of the ANG and NOVA contract terms at full ABR in accordance with a successor CPIM which will be implemented January 1, 1998. 3. Transwestern Pipeline Capacity -- UEG 50 MMcf/d Contract -------------------------------------------------------- (A.93-04-011, 94-04-002, 95-04-002, and 96-04-001) PG&E agrees to resolve the UEG Transwestern Capacity of 50 Mdth/d as follows: PG&E will not seek to recover from ratepayers the reservation charges associated with the 50 Mdth/d of UEG Transwestern capacity incurred through July 31, 1993. Recovery of reservation charges from August 1993 through implementation of the Power Exchange (PX) will be determined by comparing UEG's monthly commodity and volumetric interstate transportation costs associated with UEG's 50 Mdth/d of Transwestern capacity contract to a market benchmark based on California border indices. The benchmark will be calculated by multiplying an average of Topock gas price indices by the volumes transported by UEG for the month on the 50 Mdth/d of Transwestern capacity. The difference between the benchmark and the UEG commodity and the volumetric interstate transportation costs will be the amount of Transwestern reservation costs PG&E will be allowed to recover. The average border price will be determined by a simple average of 30 day Topock gas price indices from the following publications: Gas Daily, Natural Gas Weekly and Natural Gas Intelligence Gas Price Index. Recovery of reservation charges after implementation -64- of the PX will not be through the proposed Competitive Transition Charge (CTC) mechanism. PG&E is entitled to all revenue from brokering UEG Transwestern capacity generated through the period of the contract. For the period prior to December 31, 1995, PG&E would recover $3.7 million of its total Transwestern capacity costs plus brokering revenues. The appropriate adjustments will be made to PG&E's ECAC balancing account to reflect this agreement. It is further agreed that this agreement will set no precedent for the treatment of other capacity reservations that the UEG may incur from time to time. 4. Pipeline Expansion Project Reasonableness (PEPR)/Interstate ----------------------------------------------------------- Transition Cost Surcharge (ITCS) Proceeding ------------------------------------------- (A.92-12-043, 93-03-038, 94-05-035, 94-06-034, 94-09-056, 94-06-044, and 96-04-001) Implementation of the terms and agreements of the Gas Accord, as proposed, settles all contested issues associated with Phases 1, 2, and 3, of the PEPR/ITCS case, and also Rule 1 allegations. a. ITCS Account (Core portion) --------------------------- PG&E will absorb 100 percent of the core portion of ITCS charges as currently defined, less brokering revenues, plus interest, from the inception of the ITCS account. Any ITCS costs that were recovered in rates from the core will be returned to the core. Consequently: i. PG&E will not be responsible for any proposed additional Northern California ITCS costs or other penalties or remedies alleged in the PEPR/ITCS proceeding for the period addressed in such proceeding or subsequent periods; and ii. No other ITCS, capacity assignments, revenue requirements, or similar "stranded costs" or penalties should be shifted to Northern California ratepayers or PG&E shareholders from Southern California, as alleged in the PEPR/ITCS proceeding, the SoCalGas BCAP (Application 96-03-031), and other proceedings. b. ITCS Account (Noncore portion) ------------------------------ PG&E will absorb 50 percent of the noncore portion of ITCS charges as currently defined, less brokering revenues, plus interest, from the inception of the ITCS account. PG&E's liability is limited to 50 percent, and therefore, includes any rate reduction approved by the CPUC in response to Advice Letter 1952-G Consequently: -65- i. PG&E will not be responsible for any proposed additional Northern California ITCS costs or other penalties or remedies alleged in the PEPR/ITCS proceeding for the period addressed in such proceeding or subsequent periods; ii. No other ITCS, capacity assignments, revenue requirements, or similar "stranded costs" or penalties should be shifted to Northern California ratepayers or PG&E shareholders from Southern California, as alleged in the PEPR/ITCS proceeding, the SoCalGas BCAP (Application 96-03-031), and other proceedings. iii. PG&E shall be entitled to recovery of 50 percent of ITCS charges through gas transportation rates. No ITCS charges shall be recovered through electric rates except those paid by PG&E's UEG as a noncore gas customer. c. Pipeline Expansion Rates ------------------------ PG&E agrees that, for ratemaking purposes, the initial capital cost of the PG&E portion of the PG&E/PGT Pipeline Expansion Project will be $736 million. In recalculating rates using the lower Line 401 capital costs, PG&E will use the Company's utility corporate cost of capital and capital structure. The rates and terms of service for the Malin to on- and off-system paths, which include a Line 401 component, and the major assumptions used in deriving the Line 401 component, are as specified in Sections II.I and IV. The rates and terms of service for G-XF firm service are as specified in Section II.B.1. Other options available to firm Expansion shippers are described in Section II.F.1.c. d. Backbone Credit --------------- PG&E agrees not to collect in future rates the balance of the Backbone Credit Memorandum Account. As of the date the Gas Accord is approved by the CPUC, PG&E will not provide a backbone credit to any shipper and will remove the backbone crediting provisions from its tariffs. The Backbone Credit Memorandum Account will be terminated as of the date the Gas Accord is approved. 5. EAD Contracts ------------- (A.92-07-047, 92-07-049, 95-02-008, and 95-02-010) For the period from the contracts' inception dates until the date the Gas Accord rate structure is implemented, PG&E will collect 75 percent of EAD revenue shortfalls by operation of the Noncore Fixed Cost Account. This covers all EAD contracts, except those with Gaylord and Posco, approved in Decisions 95-06-022 and 95-06-023, respectively. With respect to those contracts, PG&E will be at risk for 100 percent of EAD shortfall revenue. During the Gas Accord period, PG&E will not collect any EAD revenue shortfalls in rates. The Commission will not take any further action in and will close this consolidated proceeding. 6. BCAP Phase II ------------- -66- (A.94-11-015) In PG&E's 1995 BCAP, SMUD proposed an unbundled backbone transmission rate. Decision 95-12-053, recognizing that there were issues that needed to be addressed prior to adopting such a rate, established a second phase in the BCAP. The Decision also recognized that these issues could potentially be resolved in the Accord, and therefore encouraged parties to enter into negotiations as part of the Accord process. Subsequent to the issuance of Decision 95-12-053, PG&E and SMUD have reached preliminary agreement for service that better meets SMUD's needs, as discussed in Section II.F.6. Subject to timely completing the definitive agreements and securing CPUC approval, this arrangement will resolve SMUD's Phase II BCAP issues. The Gas Accord provides the framework necessary for PG&E to negotiate to resolve any remaining concerns of other parties. 7. Remaining Reasonableness Issues ------------------------------- (A.93-04-011, 94-04-002, 95-04-002, and 96-04-001) All core procurement cost recovery after May 1994 shall be in accordance with PG&E's revised CPIM. All other issues outstanding in reasonableness proceedings are deemed settled and no party shall seek or recommend any disallowance, sanction, or penalty associated any gas reasonableness issue, named or unnamed for years 1992 through 1995. 8. 1988 - 1990 Gas Reasonableness Issues ------------------------------------- (A.91-04-003) If the Gas Accord Settlement is finally adopted by the Commission, or adopted with modifications acceptable to PG&E and DRA, PG&E will permanently forego recovering from its ratepayers any of the disallowance ordered by Decision 94-03-050, which has been (or will be) refunded to ratepayers, notwithstanding the outcome of its pending lawsuit in Federal District court (Civil No. C-94-4381 WHO). In the event the Federal District Court issues a decision prior to a Commission decision on the Gas Accord, PG&E will not execute any court judgment or otherwise seek recovery of the disallowance and associated refunds ordered as a result of Decision 94-03-050, unless in PG&E's reasonable judgment, failure to do so would prejudice PG&E's right to said recovery. In the event PG&E seeks recovery of a refund in order to preserve its rights pending a Commission decision on the Accord, PG&E agrees to once again refund the disallowance to ratepayers upon final approval of the Gas Accord Settlement. The UEG and noncore will receive their portion of the 1988-1990 disallowance ordered by Decision 94-03-050 upon approval of the refund plan pending before the Commission. The UEG's portion of the 1988-1990 disallowance ordered by Decision 94-03-050 will be credited directly to the ECAC balancing account and will not be refunded to electric customers directly. This treatment will not have an effect on PG&E's electric rate freeze, and will be subject to the same provisions as other ECAC balances. -67- As part of the overall Gas Accord Settlement, the remaining phase III C issues in Application 91-04-003 associated with the 1988-1990 disallowance (BCAP Phase II) are resolved for $3.7 million inclusive of any interest through 1995. PG&E will credit its ECAC balancing account $3.7 million effective December 31, 1995. Interest would accrue from that date forward. This treatment will not have an effect on PG&E's electric rate freeze, and will be subject to the same provisions as other ECAC balances. -68- VI. VI. ACCORD RATES TABLE 1 ILLUSTRATIVE RATE PROJECTIONS UNDER THE GAS ACCORD -- ON-SYSTEM ($/DTH)
1997 1998 1999 2000 2001 2002 AVG (1997-02) Core (Bundled) - --------------------------- Residential 5.61 5.62 5.75 5.79 5.93 6.07 5.79 Small Commercial 5.65 5.66 5.80 5.83 5.97 6.11 5.84 Large Commercial 3.93 3.92 4.02 4.01 4.11 4.21 4.03 Noncore (Firm Topock) - --------------------------- Distribution 1.14 1.11 1.11 1.10 1.12 1.15 1.12 Transmission 0.48 0.45 0.43 0.40 0.41 0.42 0.43 UEG 0.42 0.39 0.38 0.36 0.36 0.37 0.38 COG 0.42 0.39 0.38 0.36 0.36 0.37 0.38 Coalinga 0.47 0.44 0.43 0.41 0.42 0.42 0.43 Palo Alto 0.42 0.40 0.38 0.36 0.37 0.38 0.39 Noncore (Firm Malin) - --------------------------- Distribution 1.23 1.21 1.21 1.20 1.22 1.24 1.22 Transmission 0.57 0.54 0.53 0.50 0.51 0.51 0.53 UEG 0.51 0.49 0.48 0.45 0.46 0.46 0.48 COG 0.51 0.49 0.48 0.45 0.46 0.46 0.48 Coalinga 0.56 0.54 0.53 0.51 0.51 0.52 0.53 Palo Alto 0.52 0.49 0.48 0.46 0.47 0.47 0.48 Noncore (Firm California Gas) - --------------------------- Distribution 1.10 1.06 1.06 1.04 1.07 1.09 1.07 Transmission 0.44 0.40 0.38 0.35 0.35 0.36 0.38 UEG 0.37 0.34 0.32 0.30 0.31 0.31 0.33 COG 0.37 0.34 0.32 0.30 0.31 0.31 0.33 Coalinga 0.43 0.39 0.37 0.35 0.36 0.37 0.38 Palo Alto 0.38 0.35 0.33 0.31 0.31 0.32 0.33
Notes: a) Some portions of these rates are guaranteed. b) Core rates are bundled and include average backbone transmission costs, local transmission, distribution, storage, customer class charge, and a forecast of procurement and interstate pipeline demand charges. c) Noncore rates include backbone transmission, local transmission, customer class charges, customer access charges and distribution charges. -69- TABLE 2 FIRM BACKBONE CHARGE -- ANNUAL RATES (AFT) MFV RATE DESIGN ON-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002 Malin to On-System - Core - ----------------------- Reservation Charge ($/Dth/mo) 2.20 2.23 2.27 2.32 2.36 2.41 Usage Charge ($/Dth) 0.041 0.042 0.043 0.043 0.044 0.045 Total ($/Dth@Full 0.113 0.115 0.118 0.119 0.122 0.124 Contract) Malin to On-System - ----------------------- Reservation Charge ($/Dth/mo) 3.95 4.21 4.43 4.52 4.61 4.69 Usage Charge ($/Dth) 0.108 0.114 0.119 0.118 0.117 0.115 Total ($/Dth@Full 0.238 0.253 0.265 0.267 0.269 0.269 Contract) Topock to On-System - ----------------------- Reservation Charge ($/Dth/mo) 3.16 3.45 3.69 3.81 3.86 3.91 Usage Charge ($/Dth) 0.041 0.042 0.043 0.044 0.045 0.046 Total ($/Dth@Full 0.145 0.155 0.164 0.169 0.172 0.175 Contract) California Gas and On-System Storage to On-System - ----------------------- Reservation Charge ($/Dth/mo) 2.00 2.11 2.20 2.26 2.29 2.33 Usage Charge ($/Dth) 0.036 0.038 0.039 0.039 0.039 0.039 Total ($/Dth@Full 0.102 0.107 0.111 0.113 0.114 0.116 Contract)
Notes: a) These rates are only the backbone transmission charge component of the transmission service. They exclude local transmission charges, customer class charges, customer access charges, distribution charges, storage charges, and shrinkage charges. b) On-system backbone transmission charges are based on an 87.5% load factor. c) The "Total" rows represent the average backbone transmission charge incurred by a firm shipper that uses its full contract quantity at a 100% load factor. d) Customers delivering gas to storage facilities pay the applicable backbone transmission on-system rate from Malin, Topock or California production. e) Core and core wholesale are assigned 606.5 MMcf/d (615.6 Mdth/d) of capacity on Line 400 at vintaged rates. These rates are shown under "Malin to On-System - Core". Any additional usage from Malin by core or core wholesale must be on the "Malin to on-system path". f) These rates are subject to change during the Accord period pursuant only to the z-factor provisions of Section II.I.7. Malin to on-system charges include a phase-in of Line 401 costs as described in Section II.I.3. g) Gathering facilities are assumed to be fully depreciated by January 1, 1997. Gathering O&M expenses are included as part of the common backbone component. AFT continued next page -70- TABLE 3 FIRM BACKBONE TRANSPORTATION -- ANNUAL RATES (AFT) SFV RATE DESIGN ON-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002 Malin to On-System Core - ---------------------- Reservation Charge ($/Dth/mo) 3.19 3.24 3.30 3.37 3.44 3.52 Usage Charge ($/Dth) 0.008 0.008 0.009 0.009 0.009 0.009 Total ($/Dth@Full 0.113 0.115 0.117 0.120 0.122 0.125 Contract) Malin to On-System - ---------------------- Reservation Charge ($/Dth/mo) 7.01 7.48 7.83 7.90 7.95 7.96 Usage Charge ($/Dth) 0.007 0.007 0.007 0.007 0.007 0.007 Total ($/Dth@Full 0.237 0.253 0.264 0.267 0.268 0.269 Contract) Topock to On-System - ---------------------- Reservation Charge ($/Dth/mo) 4.31 4.63 4.89 5.03 5.11 5.19 Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004 Total ($/Dth@Full 0.146 0.156 0.165 0.169 0.172 0.175 Contract) California Gas and On-System Storage to On-System - ---------------------- Reservation Charge ($/Dth/mo) 3.02 3.18 3.30 3.36 3.39 3.43 Usage Charge ($/Dth) 0.003 0.003 0.003 0.003 0.003 0.003 Total ($/Dth@Full 0.102 0.107 0.112 0.113 0.115 0.116 Contract)
Notes: a) These rates are only the backbone transmission charge component of the transmission service. They exclude local transmission charges, customer class charges, customer access charges, distribution charges, storage charges, and shrinkage charges. b) On-system backbone transmission charges are based on an 87.5% load factor. c) The "Total" rows represent the average backbone transmission charge incurred by a firm shipper that uses its full contract quantity at a 100% load factor. d) Customers delivering gas to storage facilities pay the applicable backbone transmission on-system rate from Malin, Topock or California production. e) Core and core wholesale are assigned 606.5 MMcf/d (615.6 Mdth/d) of capacity on Line 400 at vintage rates. Any additional usage from Malin by core or core wholesale must be on the Malin to on-system path. f) These rates are subject to change during the Accord period pursuant only to the z-factor provisions of Section II.I.7. Malin to on-system charges include a phase-in of Line 401 costs as described in Section II.I.3. g) Gathering facilities are assumed to be fully depreciated by January 1, 1997. Gathering O&M expenses are included as part of the common backbone component. -71- TABLE 4 FIRM BACKBONE TRANSPORTATION CHARGES -- SEASONAL RATES (SFT) MFV RATE DESIGN ON-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002 Malin to On-System - ---------------------- Reservation Charge ($/Dth/mo) 4.74 5.06 5.31 5.43 5.53 5.63 Usage Charge ($/Dth) 0.129 0.137 0.143 0.142 0.140 0.138 Total ($/Dth@Full Contract) 0.285 0.303 0.318 0.320 0.322 0.323 Topock to On-System - ---------------------- Reservation Charge ($/Dth/mo) 3.79 4.14 4.42 4.57 4.63 4.69 Usage Charge ($/Dth) 0.050 0.051 0.052 0.053 0.054 0.055 Total ($/Dth@Full Contract) 0.175 0.187 0.197 0.203 0.206 0.209 California Gas and On-System Storage to On-System - ---------------------- Reservation Charge ($/Dth/mo) 2.40 2.53 2.64 2.71 2.75 2.79 Usage Charge ($/Dth) 0.044 0.046 0.047 0.047 0.047 0.047 Total ($/Dth@Full Contract) 0.123 0.129 0.134 0.136 0.137 0.139
Notes: a) Firm Seasonal rates are 120% of Firm Annual rates. b) These rates are only the backbone transmission charge component of the transmission service. They exclude local transmission charges, customer class charges, customer access charges, distribution charges, storage charges, and shrinkage charges. c) The "Total" rows represent the average backbone transmission cost incurred by a firm shipper that uses its full contract quantity at a 100% load factor. d) Customers delivering gas to storage facilities pay the applicable backbone transmission on-system rate from Malin, Topock or California production. e) These rates are subject to change during the Accord period pursuant only to the z-factor provisions of Section II.I.7. Malin to on-system rates include phase-in of Line 401 costs as described in Section II.I.3. f) Gathering facilities are assumed to be fully depreciated by January 1, 1997. Gathering O&M expenses are included as part of the common backbone component. g) For the period July 1997 through March 1998, core will receive seasonal service (SFT) from Topock at a rate that is 110% of annual firm rates (AFT). SFT continued next page -72- TABLE 5 FIRM BACKBONE TRANSPORTATION CHARGES -- SEASONAL RATES (SFT) SFV RATE DESIGN ON-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002 Malin to On-System - ---------------------- Reservation Charge ($/Dth/mo) 8.41 8.97 9.39 9.48 9.53 9.55 Usage Charge ($/Dth) 0.008 0.008 0.008 0.009 0.009 0.009 Total ($/Dth@Full Contract) 0.285 0.303 0.317 0.321 0.322 0.323 Topock to On-System - ---------------------- Reservation Charge ($/Dth/mo) 5.17 5.55 5.86 6.04 6.13 6.23 Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.005 0.005 Total ($/Dth@Full Contract) 0.174 0.187 0.197 0.203 0.207 0.210 California Gas and On-System Storage to On-System - ---------------------- Reservation Charge ($/Dth/mo) 3.62 3.81 3.96 4.03 4.07 4.11 Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004 Total ($/Dth@Full Contract) 0.123 0.129 0.134 0.136 0.138 0.139
Notes: a) Firm Seasonal rates are 120% of Firm Annual rates. b) These rates are only the backbone transmission charge component of the transmission service. They exclude local transmission charges, customer class charges, customer access charges, distribution charges, storage charges, and shrinkage charges. c) The "Total" rows represent the average backbone transmission cost incurred by a firm shipper that uses its full contract quantity at a 100% load factor. d) Customers delivering gas to storage facilities pay the applicable backbone transmission on-system rate from Malin, Topock or California production. e) These rates are subject to change during the Accord period pursuant only to the z-factor provisions of Section II.I.7. Malin to on-system rates include a phase-in of Line 401 costs described in Section II.I.3. f) Gathering facilities are assumed to be fully depreciated by January 1, 1997. Gathering O&M expenses are included as part of the common backbone component. g) For the period July 1997 through March 1998, core will receive seasonal service (SFT) from Topock at a rate that is 110% of annual firm rates (AFT). -73- TABLE 6 AS-AVAILABLE BACKBONE TRANSPORTATION (AA) ON-SYSTEM DELIVERIES
1997 1998 1998 1999 2000 2001 2002 1/1-3/31 4/1-12/31 Malin to On-System - ----------------- Usage Charge ($/Dth) 0.261 0.278 0.303 0.317 0.320 0.322 0.323 Topock to On-System - ----------------- Usage Charge ($/Dth) 0.160 0.171 0.187 0.197 0.203 0.206 0.209 California Gas to On-System - ----------------- Usage Charge ($/Dth) 0.112 0.118 0.129 0.134 0.136 0.138 0.139 On-System Storage to On-System - ----------------- Usage Charge ($/Dth) 0.000 0.000 0.000 0.000 0.000 0.000 0.000
Notes: a) As-Available rates are 110% of Firm-Annual rates through March 31, 1998, and 120% thereafter. b) These rates are only the backbone transmission charge component of the transmission service. They exclude local transmission charges, customer class charges, customer access charges, distribution charges, storage charges, and shrinkage charges. c) Customers delivering gas to storage facilities pay the applicable backbone transmission on-system rate from Malin, Topock or California production. d) Consistent with current CPUC rules, there will not be a transmission charge for transmission from storage unless firm transmission capacity is required to schedule the movement of the natural gas from the storage facility. e) These rates are subject to change during the Accord period pursuant only to the z-factor provisions of Section II.I.7. Malin to on-system rates include a phase-in of Line 401 costs described in Section II.I.3. f) Gathering facilities are assumed to be fully depreciated by January 1, 1997. Gathering O&M expenses are included as part of the common backbone component. -74- TABLE 7 FIRM BACKBONE TRANSPORTATION CHARGES -- ANNUAL RATES (AFT-OFF) MFV RATE DESIGN OFF-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002 Malin to Off-System - ---------------------- Reservation Charge ($/Dth/mo) 5.52 5.46 5.39 5.32 5.25 5.18 Usage Charge ($/Dth) 0.216 0.205 0.195 0.185 0.175 0.165 Total ($/Dth@Full 0.397 0.384 0.372 0.360 0.348 0.335 Contract) Topock to Off-System - ---------------------- Reservation Charge ($/Dth/mo) 3.16 3.45 3.69 3.81 3.86 3.91 Usage Charge ($/Dth) 0.041 0.042 0.043 0.044 0.045 0.046 Total ($/Dth@Full 0.145 0.155 0.164 0.169 0.172 0.175 Contract) California Gas and On-System Storage to Off-System - ---------------------- Reservation Charge ($/Dth/mo) 5.52 5.46 5.39 5.32 5.25 5.18 Usage Charge ($/Dth) 0.216 0.205 0.195 0.185 0.175 0.165 Total ($/Dth@Full 0.397 0.384 0.372 0.360 0.348 0.335 Contract)
Notes: a) These rates are only the backbone transmission charge component of the transmission service. They exclude local transmission charges, customer class charges, customer access charges, distribution charges, storage charges, and shrinkage charges. b) Except for Malin to off-system, and California gas to off-system, backbone transmission rates are based on an 87.5% load factor. c) The "Total" rows represent the average backbone transmission cost incurred by a firm shipper that uses its full contract quantity at a 100% load factor. d) Malin to off-system charges are based on Line 401's embedded costs and a 95% load factor. e) These rates are subject to change during the Accord period pursuant only to the z-factor provisions of Section II.I.7. f) Gathering facilities are assumed to be fully depreciated by January 1, 1997. Gathering O&M expenses are included as part of the common backbone component. g) California gas and storage to off-system are assumed to flow on Line 401, and are priced at the Line 401 rate. AFT-Off continued next page -75- TABLE 8 FIRM BACKBONE TRANSPORTATION CHARGES -- ANNUAL RATES (AFT-OFF) SFV RATE DESIGN OFF-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002 Malin to Off-System - ---------------------- Reservation Charge ($/Dth/mo) 11.66 11.28 10.91 10.55 10.19 9.83 Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004 Total ($/Dth@Full 0.387 0.375 0.363 0.351 0.339 0.327 Contract) Topock to Off-System - ---------------------- Reservation Charge ($/Dth/mo) 4.31 4.63 4.89 5.03 5.11 5.19 Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004 Total ($/Dth@Full 0.146 0.156 0.165 0.169 0.172 0.175 Contract) California Gas and On-System Storage to Off-System - ---------------------- Reservation Charge ($/Dth/mo) 11.66 11.28 10.91 10.55 10.19 9.83 Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004 Total ($/Dth@Full 0.387 0.375 0.363 0.351 0.339 0.327 Contract)
Notes: a) These rates are only the backbone transmission charge component of the transmission service. They exclude local transmission charges, customer class charges, customer access charges, distribution charges, storage charges, and shrinkage charges. b) Except for Malin to off-system, and California gas to off-system, backbone transmission rates are based on an 87.5% load factor. c) The "Total" rows represent the average backbone transmission cost incurred by a firm shipper that uses its full contract quantity at a 100% load factor. d) Malin to off-system charges are based on the embedded cost of Line 401 and a 95% load factor. e) These rates are subject to change during the Accord period pursuant only to the z-factor provisions of Section II.I.7. f) Gathering facilities are assumed to be fully depreciated by January 1, 1997. Gathering O&M expenses are included as part of the common backbone component. g) California gas and storage to off-system are assumed to flow on Line 401, and are priced at the Line 401 rate. -76- TABLE 9 AS-AVAILABLE BACKBONE TRANSPORTATION (AA-OFF) OFF-SYSTEM DELIVERIES
1997 1998 1998 1999 2000 2001 2002 1/1-3/31 4/1-12/31 Malin to Off-System - ----------------- Usage Charge ($/Dth) 0.437 0.424 0.462 0.447 0.433 0.418 0.403 Topock to Off-System - ----------------- Usage Charge ($/Dth) 0.160 0.171 0.187 0.197 0.203 0.206 0.209 California Gas and On-System Storage to Off-System - ----------------- Usage Charge ($/Dth) 0.437 0.424 0.462 0.447 0.433 0.418 0.403
Notes: a) These rates are only the backbone transmission charge component of the transmission service. They exclude local transmission charges, customer class charges, customer access charges, distribution charges, storage charges, and shrinkage charges. b) As-Available rates are 110% of Firm-Annual rates through March 31, 1998, and 120% thereafter. c) Gathering facilities are assumed to be fully depreciated by January 1, 1997. Gathering O&M expenses are included as part of the common backbone component. d) California gas and storage to off-system is assumed to flow on Line 401, and is priced at the Line 401 rate. -77- TABLE 10 FIRM TRANSPORTATION -- EXPANSION SHIPPERS -- ANNUAL RATES (G-XF) MFV RATE DESIGN OFF-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002 Malin to Off-System - ---------------------- Reservation Charge ($/Dth/mo) 5.52 5.46 5.39 5.32 5.25 5.18 Usage Charge ($/Dth) 0.216 0.205 0.195 0.185 0.175 0.165 Total ($/Dth@Full 0.397 0.384 0.372 0.360 0.348 0.335 Contract)
Notes: a) These rates are only the backbone transmission charge component of the transmission service. They exclude local transmission charges, customer class charges, customer access charges, distribution charges, storage charges, and shrinkage charges. b) The "Total" rows represent the average backbone transmission cost incurred by a firm shipper that uses its full contract quantity at a 100% load factor. c) G-XF charges are based on the embedded cost of Line 401 and a 95% load factor. d) These rates are subject to change during the Accord period pursuant only to the z-factor provisions of Section II.I.7. -78- TABLE 11 FIRM TRANSPORTATION -- EXPANSION SHIPPERS -- ANNUAL RATES (G-XF) SFV RATE DESIGN OFF-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002 Malin to Off-System - ---------------------- Reservation Charge ($/Dth/mo) 11.66 11.28 10.91 10.55 10.19 9.83 Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004 Total ($/Dth@Full 0.387 0.375 0.363 0.351 0.339 0.327 Contract)
Notes: a) These rates are only the backbone transmission charge component of the transmission service. They exclude local transmission charges, customer class charges, customer access charges, distribution charges, storage charges, and shrinkage charges. b) The "Total" rows represent the average backbone transmission cost incurred by a firm shipper that uses its full contract quantity at a 100% load factor. c) G-XF charges are based on the embedded cost of Line 401 and a 95% load factor. d) These rates are subject to change during the Accord period pursuant only to the z-factor provisions of Section II.I.7. -79- TABLE 12 STORAGE RATES
FIRM STORAGE SERVICE (FS) CAPACITY Withdrawal ------------- ----------------- RESERVATION CHARGES Annual Reservation Charge $0.746/Dth $9.651/Dth/day VARIABLE CHARGES Variable Charge $0.039/Dth $0.039/Dth NEGOTIATED FIRM STORAGE (NFS) INJECTION INVENTORY Withdrawal ------------- ------------ --------------- MAXIMUM RATE Volumetric Rate 8.149/Dth $1.144/Dth $4.923/Dth NEGOTIATED AS-AVAILABLE STORAGE (NAS) MAXIMUM RATE Volumetric Rate $8.149/Dth $4.923/Dth
Notes: a) Rates for storage services are based on the costs of storage injection, inventory and withdrawal. b) Firm Storage rates are subfunctionalized by a capacity (combined injection and inventory) charge and withdrawal charge. The capacity charge is calculated assuming recovery of both the injection and inventory revenue requirement over the annual inventory design capacity allocated to the unbundled storage program. The withdrawal charge is calculated based on recovery of the withdrawal revenue requirement over the daily withdrawal design capacity allocated to the unbundled storage program. c) Firm Storage capacity and withdrawal charges are recovered through a reservation (fixed) and volumetric (variable) component. d) Negotiated Firm rates may be one-part rates (volumetric) or two-part rates (reservation and variable), as negotiated between parties. The volumetric equivalent is shown above. e) Negotiated As-available Storage Injection and Withdrawal rates are recovered through a volumetric charge only. f) The flexibility inherent in this storage offer could result in stranded facilities and PG&E requires the opportunity to collect the value of the storage services. Negotiated rates (NFS and NAS) are capped at the price which will collect 100 percent of PG&E's total revenue requirement for the unbundled storage program under all three subfunctions (e.g. inventory, injection, or withdrawal.) The maximum rates are based on a rate design assuming an average injection period of 30 days and an average withdrawal period of 7 days. g) Negotiated Firm and As-available services are negotiable above a price floor representing PG&E's marginal cost of providing the service. h) Rates will be implemented for the unbundled storage program in April 1,1998. i) The maximum annual charge for parking and lending is based on the annual cost of cycling one Dth of Firm Storage Gas assuming the full 214 day injection season and 151 day withdrawal season. The annual cycle cost is $0.89 per Dth. -80- TABLE 13 LOCAL TRANSMISSION RATES ($/DTH)
1997 1998 1999 2000 2001 2002 Core .254 .260 .267 .273 .280 .287 Noncore .131 .135 .138 .141 .145 .149
Notes: a) These rates are subject to change during the Accord period pursuant only to the z-factor provisions of Section II.I.7. b) Rates for 1998-2002 escalate at 2.5 percent. c) First year rates are based on 1996 GRC revenue requirement, 1995 BCAP cost allocation and throughput, and 57.8% of BCAP adopted APD adjustment. -81- TABLE 14 ILLUSTRATIVE CUSTOMER CLASS CHARGES ($/DTH)
1997 1998 1999 2000 2001 2002 Residential .353 .224 .223 .121 .119 .118 Small Commercial .404 .276 .276 .174 .175 .175 Large Commercial .300 .200 .201 .099 .099 .100 Industrial Distribution .207 .149 .122 .083 .084 .085 Industrial Transmission .174 .127 .100 .061 .062 .062 UEG .132 .093 .066 .039 .039 .039 Cogeneration .132 .093 .066 .039 .039 .039 Wholesale Coalinga .145 .100 .072 .045 .045 .045 Palo Alto .136 .094 .066 .039 .039 .039
Notes: a) Customer class charges include no ITCS for core, and 50% of ITCS for noncore, as described in Section IV.B.4. Core rates include a refund of ITCS costs recovered prior to 1997. b) Rates for 1997 consistent with 1995 BCAP decision. Rates for 1998-2002 do not escalate at 2.5%. Instead they represent forecasts of individual balancing accounts. Actual rates will be determined in BCAPs or successor proceedings. c) The UEG and cogeneration customer class charges include costs associated with cogeneration rate parity. See section III.C.5. -82- TABLE 15 (REVISED--9/11/96) 1997 CUSTOMER ACCESS CHARGE FOR ON-SYSTEM CUSTOMERS DIRECTLY CONNECTED TO THE TRANSMISSION SYSTEM ($/MONTH)
1997 1998 1999 2000 2001 2002 Industrial (Therms/Month) - ------------ 10.49 10.75 11.02 11.30 11.58 11.87 Tier 1 0 to 5,000 82.66 84.73 86.84 89.02 91.24 93.52 Tier 2 5,001 to 10,000 313.58 321.42 329.45 337.69 346.13 354.79 Tier 3 10,001 to 50,000 826.61 847.28 868.46 890.17 912.42 935.23 Tier 4 50,001 to 200,000 1,183.50 1,213.09 1,243.41 1,274.50 1,306.36 1,339.02 Tier 5 200,001 to 1,000,000 3,440.30 3,526.31 3,614.47 3,704.83 3,797.45 3,892.38 Tier 6 1,000,001 and above 113,083 115,910 118,808 121,778 124,822 127,943 UEG Cogeneration ($/Dth) .00710 .00728 .00746 .00765 .00784 .00803 WHOLESALE - ------------ 908.67 931.39 954.67 978.54 1,003.00 1,028.08 Coalinga 3,882.42 3, 979.48 4,078.96 4,180.94 4,285.46 4,392.60 Palo Alto
Notes: a) Customer access charges escalate at 2.5% per year. -83- TABLE 16 FORECAST DISTRIBUTION RATES ($/DTH)
1997 1998 1999 2000 2001 2002 Residential 2.53 2.59 2.66 2.72 2.79 2.86 Small Commercial 2.53 2.59 2.66 2.72 2.79 2.86 Large Commercial .94 .96 .99 1.01 1.04 1.06 Industrial .656 .672 .689 .706 .724 .742 Distribution
Notes: a) Core and noncore rates are distribution only. b) Commercial and industrial rates shown are average distribution rates. Commercial and industrial distribution rates will be seasonally differentiated and include a monthly customer charge. c) Illustrative rates, based on 2.5% escalation, are shown. Actual rates will be determined in BCAPs or successor proceedings. d) There is no cogeneration rate shown, since cogenerators receive rate parity with UEG, which is transmission level service. e) All rates exclude procurement and interstate transmission. -84- TABLE 17 ILLUSTRATIVE BUNDLED 1997 CORE TRANSPORTATION RATES ($/DTH)
LARGE RESIDENTIAL SMALL COMMERCIAL COMMERCIAL AVERAGE CORE Intrastate Backbone .148 .148 .130 .147 Transmission Intrastate Local .254 .254 .254 .254 Transmission Customer class charge .353 .404 .300 .363 Distribution 2.53 2.53 .945 2.45 Storage .115 .115 .102 .115 Procurement 1.92 1.92 1.92 1.92 Interstate Transmission .292 .281 .281 .289 ------------------------------------------------------------------------------------- Total 5.61 5.65 3.93 5.53
Note: a) Average backbone transmission rate based on expected core deliveries from Line 400, Line 300 and California gas production, based on the capacity assignments discussed in Section I.E. b) Average core storage rates are based on core capacity reservations set forth in Section II.E. -85- TABLE 18 (REVISED--9/11/96) 1997 SEASONAL VOLUMETRIC RATES FOR DISTRIBUTION SERVICE CUSTOMERS ($/th)
SUMMER VOLUMETRIC WINTER AVERAGE WINTER TO RATE VOLUMETRIC RATE VOLUMETRIC RATE SUMMER RATIO Small Commercial $.166 $.250 $.212 1.50 Large Commercial $.065 $.110 $.089 1.70 Industrial $.048 $.064 $.056 1.35 Distribution
Notes: a) Rates exclude monthly customer charge. -86- EX-10.4 5 DEFERRED COMPENSATION PLAN FOR NON EMPLOYEE DIRECT EXHIBIT 10.4 PG&E CORPORATION DEFERRED COMPENSATION PLAN FOR NON-EMPLOYEE DIRECTORS (As Amended and Restated Effective as of December 17, 1997) 1. Establishment and Purpose ------------------------- The is the controlling and definitive statement of the PG&E Corporation Deferred Compensation Plan for Non-Employee Directors ("Plan"). The Plan was originally adopted on December 18, 1996, by the Board of Directors of PG&E Corporation to provide Directors of PG&E Corporation an opportunity to defer payment of their Meeting Fees and Retainer Fees. The Plan is also intended to establish a method of paying Meeting Fees and Retainer Fees which will assist the Corporation in attracting and retaining persons of outstanding achievement and ability as members of the Board of Directors of the Corporation. 2. Definitions ----------- (a) "Beneficiary" means the person, persons, or entity designated by the Director to receive payment of the Director's Deferred Compensation Account in the event of the death of the Director. (b) "Board" and "Board of Directors" means the Board of Directors of the Corporation. (c) "Committee" shall mean the Nominating and Compensation Committee of the Board. (d) "Corporation" means PG&E Corporation, a California corporation. (e) "Deferred Compensation Account" means the bookkeeping account established pursuant to Section 6 on behalf of each Director who elects to participate in the Plan. (f) "Deferred Election Form" means a participation form to be supplied by the Secretary of the Corporation. (g) "Director" means a member of the Board of Directors who is not an employee of the Corporation or any subsidiary thereof. (h) "Director's Termination Date" shall mean the effective date of the Director's resignation from the Board of Directors of the Corporation. (i) "Meeting Fee" means the amount of compensation paid by the Corporation to a Director for his or her attendance and services at a meeting of the Board of Directors or any committee thereof. A Meeting Fee shall not include (i) any Retainer Fee, (ii) any reimbursement by the Corporation of expenses incurred by a Director incidental to attendance at a meeting of the Board of Directors or of a committee thereof or of any other expense incurred on behalf of the Corporation, or (iii) any amount payable with respect to services rendered prior to January 1, 1997. (j) "Plan" shall mean the PG&E Corporation Deferred Compensation Plan for Non-Employee Directors. (k) "Retainer Fee" means the amount of compensation paid by the Corporation to a Director for retaining his or her services during a calendar quarter. A Retainer Fee shall not include (i) any Meeting Fee, (ii) any reimbursement by the Corporation of expenses incurred by a Director incidental to attendance at a meeting of the Board of Directors or of a committee thereof or of any other expense incurred on behalf of the Corporation, or (iii) any amount payable with respect to services rendered prior to January 1, 1997. (l) "Year" shall mean the calendar year. 3. Eligibility ----------- Each Director who receives a Meeting Fee or Retainer Fee for service on the Board of Directors shall be eligible to participate in the Plan. 4. Participation ------------- In order to commence participation in the Plan in 1997, a Director must file a deferral election with the Secretary of the Corporation prior to January 1, 1997. In order to commence participation in the Plan for calendar quarters commencing on or after April 1, 1997, a Director must file a Deferral Election Form with the Secretary of the Corporation prior to the first day of the calendar quarter for which participation is to become effective. Notwithstanding the foregoing, in the case of a newly elected Director, an election to participate shall be effective for the calendar quarter in which the Director is first elected if it is filed before the date the Director first receives a Meeting Fee or Retainer Fee (but in no event later than one month following the date of election). A participating Director may defer: (a) All Retainer Fees only; or (b) All Meeting Fees only; or (c) All Retainer Fees and all Meeting Fees. The Retainer Fees and Meeting Fees deferred under (a), (b), or (c), above, shall be net of any amounts which a Director has authorized the Corporate Secretary to transmit to the Corporation's Dividend Reinvestment and Common Stock Purchase Plan. Partial deferral of Retainer Fees or Meeting Fees is not permitted. Payment to the Director of deferred compensation may, at the election of the participating Director, be paid in a lump sum or in a series of ten or less approximately equal annual installments. Payment to the Director may commence in the Year following the Director's Termination Date or in such earlier year as the Director may specify on the Deferral Election Form. 2 5. Deferral Election ----------------- A Director who elects to participate in the Plan shall file an executed Deferral Election Form with the Secretary of the Corporation indicating the compensation to be deferred, the time and form of distribution, and the Beneficiary designations described in Section 9. The Director's deferral election shall become effective and apply with respect to Meeting Fees and Retainer Fees earned for the first calendar quarter after the Deferral Election Form is filed with the Secretary of the Corporation and all subsequent calendar quarters until revoked (by electing not to further defer either Meeting Fees or Retainer Fees) or modified by the Director. The Director shall notify the Secretary of the Corporation in writing of any such revocation or modification, which shall apply solely to amounts deferred with respect to calendar quarters following the calendar quarter in which the revocation or modification is received by the Secretary of the Corporation. Notwithstanding the foregoing, the Director's designation as to time and form of distribution to the Director of deferred compensation may not be revoked or modified by the Director either as to amounts already deferred or as to amounts to be deferred in the future. 6. Credits to Deferred Compensation Account ---------------------------------------- Upon receipt of a duly filed Deferral Election Form, the Corporation shall establish a Deferred Compensation Account to which shall be credited an amount equal to the Meeting Fees and/or Retainer Fees which would have been payable currently to the Director but for the terms of the deferral election. Retainer Fees and Meeting Fees shall be credited to the Director's Deferred Compensation Account as of the following dates: (a) The deferred Retainer Fee for each calendar quarter shall be credited to such Account as of the first day of such calendar quarter; and (b) The deferred Meeting Fee shall be credited to such Account as of the first business day following the date of the meeting for which the Meeting Fee was earned. 7. Interest During Deferral Period ------------------------------- At such time as participant elects to participate in the Plan, he shall also elect to have his account balances credited to the Utility Bond Fund or to the PG&E 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 a participant may not reallocate Phantom Stock Fund units and the earnings thereon which were credited to a participant's Deferred Compensation Account in connection with the termination of the PG&E Corporation Retirement Plan for Non- Employee Directors. 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 under 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. 3 (a) Utility Bond Fund ----------------- On the first 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. 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 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 Phantom Stock Fund ----------------------- Deferrals and transfers into this Fund shall be converted into units representing a share of PG&E Corporation stock, where the value of a unit is 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-day period preceding the date of deferral or transfer into this Fund. Thereafter, the value of a unit shall fluctuate with the value of a share of PG&E Corporation common stock. Each time that the Corporation pays a dividend on its stock, an amount equal to such dividend, multiplied by the number of PG&E Phantom Stock Fund units held in a participant's account, shall be credited to a participant's account and converted into additional units. 8. Form and Time of Payment to a Director of Deferred Compensation Account ----------------------------------------------------------------------- Payment to a Director of his or her Deferred Compensation Account shall be made in cash prior to January 31 in each Year in which payment is to be made in accordance with the Director's deferral election; provided, however, that amounts attributable to Phantom Stock Fund units and the earnings thereon which were credited to a participant's Deferred Compensation Account in connection with the termination of the PG&E Corporation Retirement Plan for Non-Employee Directors may not be distributed from the Plan until the latter of the participant's retirement from the Board, or age 65. 9. Effect of Death of Participant ------------------------------ Upon the death of a Director 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 Director. Such distribution shall be made at the time or times specified as part of the Beneficiary designation of the Director's deferral election (but, in no event shall such distribution be made later than ten years after the death of the Director or in more than ten approximately equal annual installments). The Committee, however, reserves the right to determine in its sole discretion that payment shall be made at a different time or times (but no later than ten years after the death of the Director). If the designated Beneficiary does not survive the Director or dies before receiving payment in full of the Director's Deferred Compensation Account, payment of the remaining balance shall be made as soon as practicable in a lump sum to the estate of the last to die of the Director or the designated Beneficiary. All Beneficiary designations (including selection of the timing and manner of payments to any Beneficiary) may be revoked or modified at the Director's option. The Director shall notify the Secretary of the Corporation in writing of any such revocation or modification. 4 10. Participant's Rights Unsecured ------------------------------ The interest under the Plan of any participating Director and such Director'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 no Director shall have an interest in or claim against any specific asset of the Corporation pursuant to the Plan. 11. Statement of Deferred Compensation Account ------------------------------------------ The Secretary of the Corporation shall provide to each participating Director an annual statement of his or her Deferred Compensation Account no later than January 31 each year. 12. Nonassignability of Interests ----------------------------- The interests and property rights of any Director 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 12 shall be void. 13. Administration of the Plan -------------------------- The Plan shall be administered by the Committee. In addition to the powers and duties otherwise set forth in the Plan, the Committee 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 Committee's interpretation and construction of the Plan shall be conclusive and binding on all persons. 14. Amendment or Termination of the Plan ------------------------------------ The Board of Directors may amend, suspend, or terminate the Plan at any time. In the event of such termination, the Deferred Compensation Accounts of participating Directors shall be paid at such times and in such forms as shall be determined pursuant to Section 8, unless the Board of Directors shall prescribe a different time or times for payments of such Accounts. 5 EX-10.5 6 DEFERRED COMPENSATION PLAN FOR OFFICERS EXHIBIT 10.5 PG&E CORPORATION DEFERRED COMPENSATION PLAN FOR OFFICERS 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) unused 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 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) SALARY, or (iii) PERFORMANCE UNITS 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 unused PERQUISITE ALLOWANCES may be filed at any time. 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 unused 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 grant. SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS and -3- any dividends earned thereon remain unvested until the third anniversary of the date on which they are credited to an OFFICER'S DEFERRED COMPENSATION ACCOUNT. Unvested SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS and any dividends earned thereon shall be forfeited if an OFFICER'S stock ownership falls below the levels set forth in the Executive Stock Ownership Guidelines. Upon retirement or death of a participant, unvested SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS and any dividends credited thereon shall immediately vest and shall be payable in accordance with the terms of the PLAN. 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, unused 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. The participant's deferral election of SALARY shall continue from YEAR to YEAR until terminated or modified by written notice to the PLAN ADMINISTRATOR. Deferral elections of INCENTIVE PLAN AWARDS, PERFORMANCE UNITS, SAVINGS FUND PLAN EXCESS BENEFITS, and unused 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. Notice of termination or modification of SALARY, INCENTIVE PLAN AWARDS, and/or PERFORMANCE UNITS deferral 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. In no event shall any notice of termination or modification affect amounts deferred prior to the effective date of such notice. 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. 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. Deferred INCENTIVE PLAN AWARDS shall be credited to the participant's DEFERRED -4- COMPENSATION ACCOUNT on the first of the month following the announcement of the granting of the participant's individual INCENTIVE PLAN AWARD. SAVINGS FUND PLAN EXCESS BENEFITS shall be credited to the participant's DEFERRED COMPENSATION ACCOUNT as of January 1 following the YEAR to which such Excess Benefits are attributable. PERQUISITE ALLOWANCES shall be credited to the participant's DEFERRED COMPENSATION ACCOUNT as soon as practicable after receipt of a DEFERRAL ELECTION FORM specifying the dollar amount to be deferred. PERFORMANCE UNITS and INCENTIVE PLAN AWARDS shall be credited to the participant's DEFERRED COMPENSATION ACCOUNT as of the first business day following the date of payment. SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall be credited to the participant's DEFERRED COMPENSATION ACCOUNT immediately upon the date of grant. Each SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM shall be equal to a share of PG&E Corporation common stock. The initial value of a SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM 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-day period preceding the date that the SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM is credited to a participant's DEFERRED COMPENSATION ACCOUNT. Each time that the CORPORATION pays a dividend on its stock, an amount equal to such dividend, multiplied by the number of a participant's SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall be credited to the participant's account and converted into additional SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS. The number of additional SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall be calculated by dividing the aggregate amount of credited dividends by 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 a period of five trading days ending on the eight day of the month, or, if such day is not a business day, on the business day next preceding the eighth. Thereafter, the value of a SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM shall fluctuate with the value of a share of PG&E Corporation common stock. 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 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 SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS and earnings and dividends 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. -5- (a) Utility Bond Fund ----------------- On the first 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 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 Phantom Stock Fund ----------------------- Deferrals and reallocations from the Utility Bond Fund to the PG&E Phantom Stock Fund shall be converted into units representing a share of PG&E Corporation common stock. The initial value of a 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-day period preceding the date that (i) deferrals are credited to a participant's account in the PG&E Phantom Stock Fund, or (ii) the PLAN ADMINISTRATOR receives a reallocation request. Each time that the CORPORATION pays a dividend on its stock, an amount equal to such dividend, multiplied by the number of units credited to a participant's account, shall be credited to the participant's account and converted into additional units. The number of additional units shall be calculated by dividing the aggregate amount of credited dividends by 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 a period of five trading days ending on the eight day of the month, or, if such day is not a business day, on the business day next preceding the eighth. Thereafter, the value of a unit shall fluctuate with the value of a share of PG&E Corporation common stock. 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 1954, as amended. -6- 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 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. Notwithstanding the foregoing, deferrals attributable to SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall only be paid 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 PREMIUMS following a participant's retirement or, if earlier, death or termination of employment. Payment to a participant of his or her DEFERRED COMPENSATION ACCOUNT shall be made in January of each YEAR in which payment is to be made in accordance with the participant's deferral election. All payments from the DEFERRED COMPENSATION ACCOUNT shall be subject to all tax withholdings or other reductions which may be required by law. 10. 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 in a lump sum to the BENEFICIARY designated by the OFFICER on the DEFERRAL ELECTION FORM. 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 PREMIUMS 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 PREMIUMS) 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. 11. 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 -7- 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. 12. 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 Phantom Stock Fund units, the amount of SPECIAL INCENTIVE STOCK OWNERSHIP 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. 13. 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 13 shall be void. 14. 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. 15. 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. Adopted pursuant to the delegation contained in the Resolution of the Board of Directors of PG&E Corporation dated June 18, 1997. By: /s/ Robert D. Glynn, Jr. ______________________________ Robert D. Glynn, Jr. President and Chief Executive Officer PG&E Corporation -8- 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 -9- EX-10.6 7 SAVINGS FUND PLAN FOR NON-UNION EMPLOYEE EXHIBIT 10.6 THE PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN FOR NON-UNION EMPLOYEES _________________________________________ This is the controlling and definitive statement of the Pacific Gas and Electric Company Savings Fund Plan for Non-Union EMPLOYEES /1/ in effect on and after October 1, 1997. The PLAN, which covers ELIGIBLE EMPLOYEES of the COMPANY and other EMPLOYERS, is a further revision of the one originally placed in effect by the COMPANY as of April 1, 1959. It has since been amended from time to time. The PLAN as amended may be further amended retroactively in order to meet applicable rules and regulations of the Internal Revenue Service, the United States Department of Labor and all other applicable rules and regulations. The PLAN is maintained for the exclusive benefit of participants or their BENEFICIARIES, and contributions or benefits under the PLAN do not discriminate in favor of HIGHLY COMPENSATED EMPLOYEES. ELIGIBILITY AND PARTICIPATION ----------------------------- 1. Eligibility ----------- A non-union EMPLOYEE becomes an ELIGIBLE EMPLOYEE upon commencement of employment. Once eligibility occurs it continues as long as the EMPLOYEE remains a non-union EMPLOYEE and SERVICE continues. 2. Participation ------------- To become a participant, an ELIGIBLE EMPLOYEE must provide NOTICE to the PLAN ADMINISTRATOR of the ELIGIBLE EMPLOYEE'S election to participate and to be bound by the terms of the PLAN. Through such NOTICE, the ELIGIBLE EMPLOYEE shall: (a) authorize the EMPLOYER to reduce his COVERED COMPENSATION by a stated percentage and to contribute such amount to the PLAN as a SECTION 401(k) (b) elect to make NON-SECTION 401(k) CONTRIBUTIONS, if any, to the PLAN; and (c) instruct the PLAN ADMINISTRATOR as to the manner in which EMPLOYEE contributions and matching EMPLOYER CONTRIBUTIONS are to be invested. - ------------------ /1/ Words in all capitals are defined in Section 30. CONTRIBUTIONS ------------- 3. EMPLOYEE Contributions ---------------------- To become a contributing participant, an ELIGIBLE EMPLOYEE must make SECTION 401(k) CONTRIBUTIONS, NON-SECTION 401(k) CONTRIBUTIONS, or a combination of both to the PLAN through payroll deduction. All contributions withheld by the EMPLOYER from COVERED COMPENSATION are paid over to the TRUSTEE, unconditionally credited to the participant's account and invested in accordance with the participant's instructions. (a) SECTION 401(k) CONTRIBUTIONS. A SECTION 401(k) CONTRIBUTION is an election to defer the receipt of a specified whole percentage of COVERED COMPENSATION which would otherwise be currently payable to a participant. The EMPLOYER shall reduce the participant's COVERED COMPENSATION by an amount equal to the percentage of the SECTION 401(k) CONTRIBUTION elected by the participant. Under current law, SECTION 401(k) CONTRIBUTIONS deferred by a participant under the PLAN are not subject to federal or state income tax until actually withdrawn or distributed from the PLAN. (b) FLEXDOLLARS. By giving NOTICE, a participant in the COMPANY'S Flex Plan may elect to have any unused FLEXDOLLARS contributed to this PLAN. Any FLEXDOLLARS contributed to this PLAN shall be deemed SECTION 401(k) CONTRIBUTIONS and shall be subject to all restrictions and limitations applicable to SECTION 401(k) CONTRIBUTIONS. FLEXDOLLAR contributions shall not be eligible for matching EMPLOYER CONTRIBUTIONS as described in Section 4. (c) NON-SECTION 401(k) CONTRIBUTIONS. NON-SECTION 401(k) CONTRIBUTIONS differ from SECTION 401(k) CONTRIBUTIONS in that a participant has already paid taxes on the amounts contributed to the PLAN. All EMPLOYEE Contributions made to the PLAN as it existed prior to October 1, 1984, are considered to be NON-SECTION 401(k) CONTRIBUTIONS and are so recorded in the accounts maintained by the PLAN ADMINISTRATOR. NON-SECTION 401(k) CONTRIBUTIONS must be made in whole percentages of COVERED COMPENSATION, and the sum of all SECTION 401(k) CONTRIBUTIONS and NON-SECTION 401(k) CONTRIBUTIONS made by a participant may not exceed 15 percent of the participant's COVERED COMPENSATION. (d) CHANGING CONTRIBUTIONS. By giving NOTICE to the PLAN ADMINISTRATOR, a participant may direct the PLAN ADMINISTRATOR to cease or resume making contributions, or to change the rate of contributions. Any such change shall become effective within 30 days of receipt by the PLAN ADMINISTRATOR of such NOTICE. -2- 4. Employer Contributions ---------------------- (a) Each and every time that participants make Section 401(k) or non- section 401(K) CONTRIBUTIONS to the PLAN eligible for matching EMPLOYER CONTRIBUTIONS, the COMPANY shall make a matching EMPLOYER CONTRIBUTION to the PLAN in cash or in whole shares of COMMON STOCK, or partly in both. Matching EMPLOYER CONTRIBUTIONS shall be limited to an amount equal to three-quarters of the aggregate participant contributions eligible for matching EMPLOYER CONTRIBUTIONS under the provisions of Subsection 4(a)(1). The COMPANY shall charge to each EMPLOYER its appropriate share of matching EMPLOYER CONTRIBUTIONS. (1) SECTION 401(k) and NON-SECTION 401(k) CONTRIBUTIONS Eligible for Matching EMPLOYER CONTRIBUTIONS. Although a participant may elect to defer up to 15 percent of COVERED COMPENSATION to the PLAN, the maximum amount of a participant's contributions eligible for matching EMPLOYER CONTRIBUTIONS shall be one of the following percentages of COVERED COMPENSATION: a) up to 3 percent, with at least one but less than three years of SERVICE; or b) up to 6 percent, with at least three years of SERVICE. c) for a participant who is absent from work and receiving temporary compensation under any state Worker's Compensation Law or under the COMPANY'S LONG TERM DISABILITY PLAN, the larger of: i) the maximum percentage calculated under (a) or (b), whichever is applicable; or ii) the dollar amount which was eligible for matching EMPLOYER CONTRIBUTIONS immediately before the participant's absence began. (b) Investment of EMPLOYER CONTRIBUTIONS. All EMPLOYER CONTRIBUTIONS made to the PLAN shall be invested by the TRUSTEE in accordance with a participant's INVESTMENT FUND directions. 5. Rollover Contributions ---------------------- (a) With the approval of the Plan Administrator, an Eligible Employee may make a rollover to the Plan in cash an amount which constitutes all or part of an eligible rollover distribution (as defined in Section 402(c)(4) of the Code). However, a direct or indirect transfer to this Plan from another qualified plan will not be permitted if such transfer would subject this Plan to the qualified joint and survivor rules of Code Section 401(a)(11) -3- (b) The Employer, the Plan Administrator and the Trustee have no responsibility for determining the propriety of, proper amount or time of, or status as a tax-free transaction of any transfer under Subsection (a) above. (c) The Plan administrator shall develop such procedures, and may require such information from the individual who is requesting to make a rollover to the Plan, as necessary or desirable in order to determine that the proposed rollover will meet the requirements of this Section 5. (d) A rollover will be credited to the participant's account and will be recorded separately as a Rollover Contribution by the Plan Administrator as soon as practicable following the receipt thereof by the Trustee. (e) The Plan Administrator in its discretion may direct the return to the participant (or the transfer to another trustee or custodian designated by the participant) of any Rollover Contribution and any earnings thereon to the extent the Plan Administrator determines that such return may be necessary to insure the continued qualification of this Plan under Section 401(a) of the Code. (f) Rollover Contributions shall not be eligible for matching Employer Contributions as described in Section 4. 6. Limitations ----------- (a) Average Deferral Percentage Limitation. In any PLAN YEAR, the average rate of SECTION 401(k) CONTRIBUTIONS as a percentage of compensation for all participating HIGHLY COMPENSATED ELIGIBLE EMPLOYEES shall not exceed the larger of: (1) the average rate of SECTION 401(k) CONTRIBUTIONS as a percentage of compensation for all other participating ELIGIBLE EMPLOYEES multiplied by 1.25 percent; or (2) the lesser of: a) the average rate of SECTION 401(k) CONTRIBUTIONS as a percentage of compensation for all other participating ELIGIBLE EMPLOYEES multiplied by 2; or b) the average rate of SECTION 401(k) CONTRIBUTIONS as a percentage of compensation for all other participating ELIGIBLE EMPLOYEES plus 2 percentage points, or such lesser amount as the Secretary of the Treasury may prescribe in order to prevent the multiple use of this alternative limitation with respect to any HIGHLY COMPENSATED participant. If multiple use of the alternative limitation occurs with respect to the Average Deferral Percentage Limitation and Average Contribution Percentage Limitation in this PLAN, it will be corrected by reducing the actual contribution percentage of HIGHLY COMPENSATED participants in the manner described in Section 6(c), below. -4- The average rate of SECTION 401(k) CONTRIBUTIONS for a PLAN YEAR for a designated group of ELIGIBLE EMPLOYEES shall be the average of the ratios, calculated separately for each participating ELIGIBLE EMPLOYEE in the group, of the amount of SECTION 401(k) CONTRIBUTIONS made by each EMPLOYEE for the PLAN YEAR, to the EMPLOYEE'S compensation for such PLAN YEAR. As used in this subsection, compensation shall mean compensation paid by an EMPLOYER to the participant during the PLAN YEAR which is required to be reported as wages on the participant's form W-2 and shall also include compensation which is not currently includable in the participant's gross income by reason of the application of CODE Sections 125 and 402(e)(3). For purposes of this subsection, the ratio of the amount of SECTION 401(k) CONTRIBUTIONS to a participant's compensation for any participant who is HIGHLY COMPENSATED for the PLAN YEAR and who is eligible to have elective deferrals or qualified employer deferral contributions allocated to his account under two or more plans or arrangements described in Section 401(k) of the CODE that are maintained by an employer or affiliated employer shall be determined as if all such SECTION 401(k) CONTRIBUTIONS, elective deferrals and qualified employer deferral contributions were made under a single arrangement. For purposes of determining the ratio of the amount of SECTION 401(k) CONTRIBUTIONS to a participant's compensation for a participant who is HIGHLY COMPENSATED by reason of being one of the ten highest-paid EMPLOYEES or a 5 percent owner of the controlled group of corporations, as defined in Section 414 of the CODE, the SECTION 401(k) CONTRIBUTIONS and compensation of such participant shall include the SECTION 401(k) CONTRIBUTIONS and compensation of the participant's family members, as defined in Section 414 of the CODE, and such family members shall be disregarded in determining the average rate of SECTION 401(k) CONTRIBUTIONS for non-HIGHLY COMPENSATED participants. The determination and treatment of SECTION 401(k) CONTRIBUTIONS of any participant shall satisfy such other requirements as may be prescribed by the Secretary of the Treasury. (b) Average Contribution Percentage Limitation. In any PLAN YEAR, the average rate of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as a percentage of compensation for all participating HIGHLY COMPENSATED ELIGIBLE EMPLOYEES shall not exceed the larger of: (1) the average rate of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as a percentage of compensation for all other participating ELIGIBLE EMPLOYEES multiplied by 1.25; or (2) the lesser of: a) the average rate of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as a percentage of compensation for all other participating ELIGIBLE EMPLOYEES multiplied by 2; or -5- b) the average rate of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS for all other participating ELIGIBLE EMPLOYEES plus 2 percentage points, or such lesser amount as the Secretary of the Treasury may prescribe in order to prevent the multiple use of this alternative limitation with respect to any HIGHLY COMPENSATED participant. If multiple use of the alternative limitation occurs with respect to the Average Deferral Percentage Limitation and Average Contribution Percentage Limitation in this PLAN, it will be corrected by reducing the actual contribution percentage of HIGHLY COMPENSATED participants in the manner described in Section 6(c), below. The average rate of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS for a PLAN YEAR for a designated group of ELIGIBLE EMPLOYEES shall be the average of the ratios, calculated separately for each participating ELIGIBLE EMPLOYEE in the group, of the amount of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS made by and on behalf of each EMPLOYEE for the PLAN YEAR, to the EMPLOYEE'S compensation for such PLAN YEAR. As used in this subsection, compensation shall mean compensation paid by an EMPLOYER to the participant during the PLAN YEAR which is required to be reported as wages on the participant's form W-2 and shall also include compensation which is not currently includable in the participant's gross income by reason of the application of CODE Sections 125 and 402(e)(3). For purposes of this subsection, the ratio of the amount of NON- SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS to a participant's compensation for any participant who is HIGHLY COMPENSATED for the PLAN YEAR and who is eligible to have elective deferrals or qualified employer deferral contributions allocated to his account under two or more plans or arrangements described in Section 401(k) of the CODE that are maintained by an employer or affiliated employer shall be determined as if all such NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS, elective deferrals and qualified employer deferral contributions were made under a single arrangement. For purposes of determining the ratio of the amount of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS to a participant's compensation for a participant who is HIGHLY COMPENSATED by reason of being one of the ten highest-paid EMPLOYEES or a 5 percent owner of the controlled group of corporations, as defined in Section 414 of the CODE, the NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS and compensation of such participant shall include the NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS and compensation of the participant's family members, as defined in Section 414 of the CODE, and such family members shall be disregarded in determining the average rate of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS for non-HIGHLY COMPENSATED participants. The determination and treatment of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS of any participant shall satisfy such other requirements as may be prescribed by the Secretary of the Treasury. -6- (c) In the event that the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, in its sole and absolute discretion, determines that the rate of SECTION 401(k) CONTRIBUTIONS, and/or the rate of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS will exceed either or both of the maximum limitations contained in subsections 6(a) and 6(b), the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall instruct the PLAN ADMINISTRATOR to reduce the rate of contributions made by HIGHLY COMPENSATED participants so that the limitations will be met. The PLAN ADMINISTRATOR shall first determine the maximum average rate of contributions which can be made by the HIGHLY COMPENSATED participants. The contributions made by HIGHLY COMPENSATED participants shall then be reduced, on a prospective basis, until the limitations are met. Any necessary reduction shall be made by first reducing the highest rate of SECTION 401(k) CONTRIBUTIONS or NON- SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as may be appropriate, currently authorized by participants, with such rate to be reduced in one percent increments until the maximum permissible average rate of contributions is met. Notwithstanding any other provision of the PLAN, if, as of the end of a PLAN YEAR, the PLAN fails to meet either or both of the tests described in subsections 6(a) or 6(b), the PLAN ADMINISTRATOR shall, on or before December 31 of the following PLAN YEAR distribute to each HIGHLY COMPENSATED participant, beginning with the participant having the higher ratio, such excess portion of the participant's SECTION 401(k) CONTRIBUTIONS, and/or NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS (and any income allocable to such portion), until the PLAN satisfies both of the tests. Distributions made to satisfy the limitations described in subsection 6(b) shall include both NON-SECTION 401(k) CONTRIBUTIONS and related matching EMPLOYER CONTRIBUTIONS in accordance with the requirements of Treasury Regulation SECTION 1.401(m)-l(e)(4). If there is a loss allocable to such excess amount, the amount of the distribution shall in no event be less than the lesser of the (i) participant's account or (ii) the participant's SECTION 401(k) CONTRIBUTIONS, or NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS, as appropriate, for the PLAN YEAR. For the PLAN YEARS 1987, 1988, 1989, 1990 and 1991 only, the PLAN ADMINISTRATOR may elect to make qualified non-elective employer contributions within the meaning of Section 401(m)(4)(c) of the CODE, on behalf of such non-HIGHLY COMPENSATED participants who are EMPLOYEES of Pacific Service Employees Association as will cause the PLAN to meet the appropriate limits set forth in subsections 6(a) and 6(b). For purposes of PLAN withdrawals qualified non-elective employer contributions shall be treated as SECTION 401(k) CONTRIBUTIONS. For purposes of determining whether the PLAN meets either or both of the limits set forth in subsections 6(a) and 6(b), the PLAN ADMINISTRATOR may elect to make the look-back year calculation as provided in Regulation 1.414(q)-ITA-14(b)(1) for any determination year on the basis of the calendar year ending with the applicable determination year. -7- (d) Annual Section 401(k) Limitation. Effective as of January 1, 1987, no participant shall be permitted to make Section 401(k) CONTRIBUTIONS to the PLAN during any PLAN YEAR in excess of $7,000, multiplied by the adjustment factor prescribed by the Secretary of the Treasury under Section 415(d) of the CODE for years beginning after December 31, 1987, as applied to elective deferrals. A participant who is unable to make SECTION 401(k) CONTRIBUTIONS which would have been eligible for matching EMPLOYER CONTRIBUTIONS because of the limitation contained in this subsection 6(d), shall be entitled to make NON-SECTION 401(k) CONTRIBUTIONS in an amount equal to the amount of SECTION 401(k) CONTRIBUTIONS that could have been made but for the subsection 6(d) limitation. Such NON-SECTION 401(k) CONTRIBUTIONS shall be eligible for matching EMPLOYER CONTRIBUTIONS as though they were SECTION 401(k) CONTRIBUTIONS, subject to the limitations contained in Section 6. (e) Section 415 Limitation. Anything herein to the contrary notwithstanding, in no event shall the annual additions to a participant's accounts in a YEAR exceed the lesser of (1) 25 percent of the participant's compensation (as defined in subparagraph 6(e)(1), below) for the YEAR or (2) $30,000, or, if greater, one- fourth of the defined benefit dollar limitation set forth in Section 415(b)(1) of the CODE as in effect for the PLAN YEAR. For purposes of applying the limitations of Section 415 of the CODE, the annual additions which must be kept within the limits set forth above, shall mean the sum credited to a participant's account for any PLAN YEAR of (i) EMPLOYER CONTRIBUTIONS and SECTION 401(k) CONTRIBUTIONS, (ii) NON-SECTION 401(k) CONTRIBUTIONS, and (iii) any amounts allocated to an individual medical account, as defined in Sections 415(l)(2) and 419A(d)(2) of the CODE. The compensation limitation percentage referred to above shall not apply to (i) any contribution for medical benefits, as defined in Section 419A(f)(2) of the CODE, after a participant's separation from SERVICE which is otherwise treated as an annual addition, or (ii) any amount which is otherwise treated as an annual addition under Section 415(l)(1) of the CODE. (1) Solely for purposes of applying the Section 415 limitations, compensation shall include all of a participant's wages, salaries, fees for professional service, and other amounts received for personal services actually rendered in the course of employment with an EMPLOYER (including, but not limited to, commissions paid to salesmen, compensation for services on the basis of a percentage of profits, commissions on insurance premiums, tips, and bonuses). For purposes of applying the Section 415 limitations, compensation shall not include any of the following: a) Contributions made by an EMPLOYER to a plan of deferred compensation to the extent that, before the application of the Section 415 limitations to that plan, the contributions are not includable in the gross income of the participant for the taxable year in which contributed. Any distributions from a plan of deferred compensation are not considered as compensation for Section 415 purposes, regardless of whether such amounts are includable in the gross income of the EMPLOYEE when distributed. However, any amounts received by a participant pursuant to an unfunded, nonqualified plan may be considered as -8- compensation for Section 415 purposes in the year such income is includable in the gross income of the EMPLOYEE. b) Amounts realized from the exercise of a nonqualified stock option, or when restricted stock (or property) held by a participant either becomes freely transferable or is no longer subject to a substantial risk of forfeiture. c) Amounts realized from the sale, exchange, or other disposition of stock acquired under a qualified stock option. d) Other amounts which receive special tax benefits such as premiums for group term life insurance (but only to the extent that the premiums are not includable in the gross income of the participant). In the event that the annual additions to a participant's accounts would exceed the Section 415 Limitations, the PLAN ADMINISTRATOR shall first reduce the participant's NON- SECTION 401(k) CONTRIBUTIONS until the Section 415 limitations are met. (f) If a participant of this PLAN is also a participant in the COMPANY'S RETIREMENT PLAN, Section 415 of the CODE imposes a combined benefit limitation. Contributions to this PLAN will nevertheless be permitted to the maximum extent permitted by Section 415 of the CODE and the terms of the PLAN. If the combined maximum benefit permitted would be exceeded, the benefit from the COMPANY'S RETIREMENT PLAN shall be reduced so that the limitation will be met. The combined maximum benefit for a participant shall be determined pursuant to the provisions of Section 415(e) of the CODE. At the election of the PLAN ADMINISTRATOR, special transitional rules may apply for both the defined benefit fraction and the defined contribution fraction for EMPLOYEES who were participants as of December 31, 1982. (g) Top Heavy Provisions. In the event that the PLAN is or becomes "Top Heavy", as that term is defined in Section 416(g) of the CODE, the provision contained in Special Provision A shall supersede any conflicting provision of the PLAN. (h) For purposes of determining all benefits under the PLAN, for PLAN YEARS beginning after 1988 and before 1994, the maximum compensation of each EMPLOYEE that may be taken into account each PLAN YEAR shall not exceed $200,000 (as adjusted by the Secretary of the Treasury under Section 401(a)(17) of the CODE. For purposes of determining all benefits under the PLAN, for PLAN YEARS beginning after 1993, the maximum compensation of each EMPLOYEE that may be taken into account each PLAN YEAR shall not exceed $150,000 (as adjusted by the Secretary of the Treasury under Section 401(a)(17) of the CODE). In determining the compensation of a HIGHLY COMPENSATED EMPLOYEE for purposes of this limitation, the rules of Section 414(q)(6) of the CODE shall apply, except that the term "family" shall include only the spouse of the EMPLOYEE and any lineal descendants of the -9- EMPLOYEE who have not attained age 19 before the close of the YEAR. If the aggregate compensation of family members exceeds the applicable compensation limit of compensation as limited by Section 401(a)(17) of the CODE, then the amount of compensation considered under the PLAN for each family member is proportionately reduced so that the total equals the applicable compensation limitation under Section 401(a)(17) of the CODE. SELECTION OF INVESTMENT FUNDS ----------------------------- 7. (a) SECTION 401(k) CONTRIBUTIONS, NON-SECTION 401(k) CONTRIBUTIONS, and EMPLOYER CONTRIBUTIONS. By giving NOTICE, a participant shall instruct the PLAN ADMINISTRATOR to invest his SECTION 401(k) CONTRIBUTIONS, NON-SECTION 401(k) CONTRIBUTIONS, and EMPLOYER CONTRIBUTIONS in one or more INVESTMENT FUNDS. The minimum amount which can be invested in any single INVESTMENT FUND shall be one percent of a participant's current contributions to the PLAN. A participant may elect to invest more than the minimum amount in any INVESTMENT FUND, provided that any such increase must be in increments of one percent. (b) CHANGE OF INVESTMENT FUND ALLOCATIONS. By giving NOTICE to the PLAN ADMINISTRATOR, a participant may (1) change the percentage levels of future contributions which are to be allocated to any INVESTMENT FUND or FUNDS or, (2) change the INVESTMENT FUNDS in which his future contributions are to be invested. Each election regarding investment of future contributions shall be effective with the next deposit of contributions. THE INVESTMENT FUNDS -------------------- 8. PG&E Corporation Common Stock Fund ---------------------------------- This FUND is invested primarily in common stock of PG&E Corporation/2/, with a small portion invested in cash or cash equivalents. The FUND also holds COMMON STOCK and the earnings thereon attributable to EMPLOYER CONTRIBUTIONS and participant contributions made to the Basic Fund of the PLAN as it existed prior to April 1, 1983, as well as all COMMON STOCK which has been transferred to this PLAN from the TRASOP and PAYSOP Plan. All cash dividends received by the TRUSTEE on COMMON STOCK are reinvested in the FUND. (a) Investment Generally. Whenever the TRUSTEE invests cash in COMMON STOCK, the EMPLOYEE BENEFIT FINANCE COMMITTEE shall direct the - ------------------ /2/ Prior to January 1, 1997, this FUND was invested primarily in the common stock of the Pacific Gas and Electric Company. Effective January 1, 1997, all PG&E common stock was converted to common stock of PG&E Corporation by operation of the formation of PG&E Corporation. -10- TRUSTEE to purchase the COMMON STOCK either (i) at a public sale on a recognized stock exchange, (ii) directly from PG&E Corporation at a price equal to that day's closing price for COMMON STOCK on the New York Stock Exchange, or (iii) from a private source at a price no higher than the price that would have been payable under (i). (b) Voting of COMMON STOCK. Each and every time common shareholders of PG&E Corporation who are not participants in the PLAN are entitled to vote COMMON STOCK, participants shall have an absolute right to vote COMMON STOCK. Whenever participants are given the opportunity to vote COMMON STOCK, the TRUSTEE shall inform each participant of all relevant material received by the TRUSTEE with a written request for confidential voting instructions. The TRUSTEE is required to vote the COMMON STOCK credited to a participant's account as the participant directs. If the participant does not give such instructions within the required time, the TRUSTEE may not vote any --- COMMON STOCK credited to a participant's account. (c) Cost of UNITS. The cost of a UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the COMMON STOCK FUND. (d) Value of UNITS. The value of a UNIT is the value of the COMMON STOCK held in the FUND at the closing price on the New York Stock Exchange plus the cash held in the FUND, as determined by the TRUSTEE each BUSINESS DAY, less any fees or other expenses which are charged to the FUND which shall reduce the earnings of that fund, divided by the number of UNITS. Each payment into the COMMON STOCK FUND of contributions shall increase, and each payment out of the COMMON STOCK FUND shall decrease, the number of UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. 9. United States Bond Fund ----------------------- This FUND was maintained for the purpose of investing EMPLOYEE contributions in United States BONDS. This FUND also holds all BONDS attributable to participant contributions made to the Basic Fund of the PLAN as it existed prior to April 1, 1983. Income from BONDS is reflected in the greater redemption values of the BONDS. BONDS held in this FUND cannot be transferred to another INVESTMENT FUND under the transfer provisions of Section 18. Effective July 1, 1991, the U.S. BOND FUND no longer accepts EMPLOYEE contributions. BONDS purchased to date with EMPLOYEE contributions will continue to be held in the PLAN until a distribution is requested by the EMPLOYEE in accordance with current PLAN provisions. 10. Large Company Stock Index Fund (LCSF) ------------------------------ This FUND is maintained for the purpose of investing in a diversified portfolio consisting principally of common stock of large US companies and securities convertible into -11- common stock. However, at no time shall the LCSF be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the LCSF INVESTMENT MANAGER. The LCSF INVESTMENT MANAGER directs the day-to-day investment of the FUND. Contributions to this FUND are paid over to the TRUSTEE and invested in accordance with instructions received from the LCSF INVESTMENT MANAGER. A participant's account is credited with the number of LCSF UNITS purchased with contributions allocated to his account. (a) Cost of LCSF UNITS. The cost of a LCSF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the LCSF. (b) Value of LCSF UNITS. The value of a LCSF UNIT is the value of the FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the FUND), divided by the number of LCSF UNITS. Each payment into the FUND of contributions shall increase, and each payment out of the FUND shall decrease, the number of FUND UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of the payment. 11. Small Company Stock Index Fund (SCSF) ------------------------------------- This FUND is maintained for the purpose of investing in a diversified portfolio consisting principally of common stock of small capitalization US companies and securities convertible into common stock. However, at no time shall the SCSF be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the SCSF INVESTMENT MANAGER. The SCSF INVESTMENT MANAGER directs the day-to-day investment of the FUND. Contributions to this FUND are paid over to the TRUSTEE and invested in accordance with instructions received from the SCSF INVESTMENT MANAGER. A participant's account is credited with the number of SCSF UNITS purchased with contributions allocated to his account. (a) Cost of SCSF UNITS. The cost of a SCSF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the SCSF. (b) Value of SCSF UNITS. The value of a SCSF UNIT is the value of the FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the FUND), divided by the number of SCSF UNITS. Each payment into the FUND of contributions shall increase, and each payment out of the FUND shall decrease, the number of FUND UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of the payment. -12- 12. International Stock Index Fund (ISF) ------------------------------------ This FUND is maintained for the purpose of investing in a diversified portfolio consisting principally of non-US common stock and securities convertible into common stock. However, at no time shall the ISF be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the ISF INVESTMENT MANAGER. The ISF INVESTMENT MANAGER directs the day-to-day investment of the FUND. Contributions to this FUND are paid over to the TRUSTEE and invested in accordance with instructions received from the ISF INVESTMENT MANAGER. A participant's account is credited with the number of ISF UNITS purchased with contributions allocated to his account. (a) Cost of ISF UNITS. The cost of a ISF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the ISF. (b) Value of ISF UNITS. The value of a ISF UNIT is the value of the FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the FUND), divided by the number of ISF UNITS. Each payment into the FUND of contributions shall increase, and each payment out the FUND shall decrease, the number of FUND UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of the payment. 13. Stable Value Fund (SVF) ----------------------- This FUND is designed to provide participants with preservation of principal while earning a stable and consistent rate of return. The FUND is made up of investment contracts with a diversified group of insurance companies, banks, and other financial institutions which provide for credited interest rates and terms that are negotiated at the time of purchase. Contributions made to the SVF are invested in a portfolio of investment contracts. The SVF INVESTMENT MANAGER directs the day-to-day investment of the FUND. The blended interest earned on all contracts held in the portfolio is posted daily to the participant's account. (a) COST OF SVF UNITS. The cost of a SVF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the SVF. (b) VALUE OF SVF UNITS. The value of a SVF UNIT is the value of the SVF assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the SVF), divided by the number of SVF UNITS. Each payment into the SVF of contributions shall increase, and payments out of the SVF shall decrease, the number of SVF UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. -13- 14. Bond Index Fund (BIF) --------------- The BIF is maintained for the purpose of investing in a diversified portfolio consisting principally of marketable fixed-income securities. At no time shall the BIF be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the BIF INVESTMENT MANAGER. The BIF INVESTMENT MANAGER directs the day-to-day investment of the BIF. Contributions to the BIF are paid over to the TRUSTEE and invested in accordance with instructions received from the BIF INVESTMENT MANAGER. A participant's account is credited with the number of BIF UNITS purchased with contributions allocated to his account. (a) Cost of BIF UNITS. The cost of a BIF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the FUND. (b) Value of BIF UNITS. The value of a BIF UNIT is the value of the BIF assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the BIF), divided by the number of BIF UNITS. Each payment into the BIF of contributions shall increase, and each payment out of the BIF shall decrease, the number of BIF UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. 15. Conservative Asset Allocation Fund (CAAF) ----------------------------------------- The FUND is maintained for the purpose of investing in a diversified portfolio with a primary emphasis on bonds and a secondary emphasis on stocks. This Fund has an allocation to each of the following Funds: the Small Company Stock Index Fund (SCSF), the Large Company Stock Index Fund (LCSF), the International Stock Index Fund (ISF), and the Bond Index Fund (BIF). At no time shall the CAAF be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the CAAF INVESTMENT MANAGER. The CAAF INVESTMENT MANAGER directs the day-to-day investment of the FUND. Contributions to this FUND are paid over to the TRUSTEE and invested in accordance with instructions from the CAAF INVESTMENT MANAGER. A participant's account is credited with the number of CAAF UNITS purchased with contributions allocated to his account. (a) Cost of CAAF UNITS. The cost of an CAAF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the CAAF. (b) Value of CAAF UNITS. The value of a CAAF UNIT is the value of the FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the FUND), divided by the number of -14- CAAF UNITS. Each payment into the FUND of contributions shall increase, and each payment out of the FUND shall decrease, the number of FUND UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. 16. Moderate Asset Allocation Fund (MAAF) ------------------------------------- The FUND is maintained for the purpose of investing in a diversified portfolio with an emphasis on stocks and bonds. This Fund has an allocation to each of the following Funds: the Small Company Stock Index Fund (SCSF), the Large Company Stock Index Fund (LCSF), the International Stock Index Fund (ISF), and the Bond Index Fund (BIF). However, at no time shall the MAAF be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the MAAF INVESTMENT MANAGER. The MAAF INVESTMENT MANAGER directs the day-to-day investment of the FUND. Contributions to this FUND are paid over to the TRUSTEE and invested in accordance with instructions from the MAAF INVESTMENT MANAGER. A participant's account is credited with the number of MAAF UNITS purchased with contributions allocated to his account. (a) Cost of MAAF UNITS. The cost of an MAAF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the MAAF. (b) Value of MAAF UNITS. The value of a MAAF UNIT is the value of the FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the FUND), divided by the number of MAAF UNITS. Each payment into the FUND of contributions shall increase, and each payment out of the FUND shall decrease, the number of FUND UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. 17. Aggressive Asset Allocation Fund (AAAF) --------------------------------------- The FUND is maintained for the purpose of investing in a diversified portfolio with a primary emphasis on stocks and a secondary emphasis on bonds. This Fund has an allocation to each of the following Funds: the Small Company Stock Index Fund (SCSF), the Large Company Stock Index Fund (LCSF), the International Stock Index Fund (ISF), and the Bond Index Fund (BIF). However, at no time shall the AAAF be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the AAAF INVESTMENT MANAGER. The AAAF INVESTMENT MANAGER directs the day-to-day investment of the FUND. Contributions to this FUND are paid over to the TRUSTEE and invested in accordance with instructions from the AAAF INVESTMENT MANAGER. A participant's account is credited with the number of AAAF UNITS purchased with contributions allocated to his account. -15- (a) Cost of AAAF UNITS. The cost of an AAAF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the AAAF. (b) Value of AAAF UNITS. The value of a AAAF UNIT is the value of the FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the FUND), divided by the number of AAAF UNITS. Each payment into the FUND of contributions shall increase, and each payment out of the FUND shall decrease, the number of FUND UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. 18. Transfer of Investment Fund Balances ------------------------------------ (a) By giving NOTICE to the PLAN ADMINISTRATOR, a participant may elect to transfer any portion of the contributions held in his account, plus the earnings thereon, from any INVESTMENT FUND to another INVESTMENT FUND or FUNDS. A transfer shall be effective and shall be valued on the day it is made, if such day is a BUSINESS DAY, and the participant provides NOTICE of such transfer prior to the closing time of the New York Stock Exchange. All other transfers shall be effective and valued as of the next BUSINESS DAY. Upon receipt of a transfer NOTICE, the TRUSTEE shall value the UNITS to be transferred from the FUND and convert the UNITS to cash. The FUND account of the participant shall be debited with the number of UNITS transferred from that FUND and the TRUSTEE shall purchase with the cash proceeds realized from the converted UNITS, UNITS in the appropriate FUND or FUNDS, as designated by the participant. The cost of the UNITS purchased shall be the value of the FUND UNITS as determined on the date of transfer, and the number of UNITS purchased shall be credited to the appropriate INVESTMENT FUND account of the participant. (b) COMMON STOCK FUND -- Overall Limitation. Anything herein to the contrary notwithstanding, if, as of any single month, the TRUSTEE is required, as a result of the transfer provisions of this Section 18, to sell on the open market more than one percent of the number of outstanding shares of COMMON STOCK, then the TRUSTEE shall immediately so advise the EMPLOYEE BENEFIT FINANCE COMMITTEE. The EMPLOYEE BENEFIT FINANCE COMMITTEE may, in its sole discretion, limit, prorate, or temporarily suspend further sales of COMMON STOCK by the PLAN or take whatever steps necessary to ensure an orderly market in COMMON STOCK. The percentage limitation set forth in this subsection shall be applied to the excess of shares sold on the open market less shares purchased to meet Section 18 requirements for the applicable period. -16- PARTICIPANT'S INTEREST IN THE PLAN ---------------------------------- 19. Participant Accounts -------------------- The PLAN ADMINISTRATOR maintains a separate account for each PLAN participant which records the participant's interest in each of the INVESTMENT FUNDS, together with EMPLOYER CONTRIBUTIONS made on his behalf. Each account is charged with participant transfers and withdrawals and credited with its appropriate share of FUND income. The account maintained by the PLAN ADMINISTRATOR for each participant also records separately the participant's SECTION 401(k) CONTRIBUTIONS and NON-SECTION 401(k) CONTRIBUTIONS, the UNITS purchased therewith, and the earnings thereon. All Basic Contributions and Supplemental Contributions made to the PLAN as it existed prior to October 1, 1984, are recorded as NON-SECTION 401(k) CONTRIBUTIONS on the records maintained by the PLAN ADMINISTRATOR. Whenever UNITS attributable to a participant's SECTION 401(k) CONTRIBUTIONS are transferred to another FUND OR FUNDS, the resulting UNITS are also recorded as attributable to SECTION 401(k) CONTRIBUTIONS. Similarly, UNITS attributable to NON-SECTION 401(k) CONTRIBUTIONS which are transferred to another FUND or FUNDS are also recorded as NON-SECTION 401(k) CONTRIBUTIONS. A participant is at all times fully vested in his own contributions and all EMPLOYER CONTRIBUTIONS credited to his account, together with income attributable thereto. 20. Account Statements ------------------ As soon as practicable after the end of each CALENDAR QUARTER, all participants will receive from the ADMINISTRATOR a statement of their interest in the PLAN. PLAN WITHDRAWALS ---------------- 21. Withdrawal During Service ------------------------- Except as provided in this Section, withdrawals of any part of a participant's interest in the PLAN are not permitted as long as SERVICE continues. A participant may never replace in the TRUST FUND any UNITS or cash which have been withdrawn. By submitting a withdrawal Form, a participant may make withdrawals as provided below. (a) SECTION 401(k) CONTRIBUTIONS. (1) A participant may withdraw all or part of the UNITS, including income thereon and including additional UNITS attributable thereto, bought with the participant's SECTION 401(k) CONTRIBUTIONS upon the occurrence of any of the following events: a) the participant is disabled and is receiving benefits under the LONG TERM DISABILITY PLAN; or b) the participant has attained age 59 1/2. -17- (2) A participant may withdraw an amount equal to his SECTION 401(k) CONTRIBUTIONS, as we ll as any income and UNITS attributable to income accrued thereon prior to January 1, 1989, upon receipt of satisfactory proof by the PLAN ADMINISTRATOR that the withdrawal is required to meet immediate and heavy financial needs of the participant which constitute a valid hardship as defined under the CODE and regulations issued by the Secretary of the Treasury. A request for a withdrawal for one of the following reasons will be deemed to be on account of a valid hardship: a) To cover medical expenses (as defined in Section 213(d) of the CODE) of the participant, the participant's spouse or dependents (as defined in Section 152 of the CODE); b) The purchase of a participant's principal place of residence, but not including mortgage payments; c) To meet tuition payments for the next semester or quarter of post-secondary education for the participant, his spouse, children or dependents; or d) To prevent the eviction of the participant from his principal place of residence, or to prevent a foreclosure of the mortgage on the participant's principal place of residence. A request for a withdrawal under this subsection 21(a)(2) will not be deemed to be for immediate and heavy financial needs unless the participant represents that the need cannot be met from the following resources: a) through reimbursement or compensation by insurance or otherwise, b) by reasonable liquidation of the participant's resources, c) by cessation of contributions to the PLAN, or d) by other distributions, withdrawals or nontaxable loans from any plans maintained by an EMPLOYER, or by borrowing from commercial sources on reasonable commercial terms. For purposes of this Subsection 21(a)(2), a participant's resources shall be deemed to include any assets of his spouse and minor children that are reasonably available to the participant. In addition, withdrawals under Subsection 21(a)(2) may not exceed the amount actually required to meet the participant's immediate financial needs. (3) A participant who withdraws UNITS under Subsection 21(a) will automatically be suspended from the PLAN and will not be permitted to resume making contributions to the PLAN for six months following the date upon which the withdrawal Form is processed by the PLAN ADMIN- -18- ISTRATOR. After suspension ends, contributions may be resumed by giving NOTICE to the PLAN ADMINISTRATOR. (b) NON-SECTION 401(k) CONTRIBUTIONS. A participant may at any time elect to withdraw all or any part of the UNITS including income thereon and including additional UNITS attributable thereto, bought with the participant's NON-SECTION 401(k) CONTRIBUTIONS to the PLAN. Such an election will not cause suspension from the PLAN. (c) EMPLOYER CONTRIBUTIONS. (1) A participant may withdraw all or any part of the UNITS, including the income attributable thereto, bought with EMPLOYER CONTRIBUTIONS which were made to the PLAN at anytime prior to the second YEAR preceding the current YEAR. For example, UNITS, including the income attributable thereto, purchased with EMPLOYER CONTRIBUTIONS made in 1981 and prior years may be withdrawn in 1984 or anytime thereafter. Such an election will not cause suspension from the PLAN. (2) UNITS, including the income attributable thereto, bought with EMPLOYER CONTRIBUTIONS which would not be withdrawable under Subsection 21(c)(1), shall nonetheless be withdrawable upon the occurrence of any of the following events: a) the participant is disabled and is receiving benefits under the LONG TERM DISABILITY PLAN; b) the participant attains 59-1/2; or c) the participant has requested and is entitled to receive a hardship distribution which meets the requirements of Subsection 21(a)(2) but only if all amounts distributable under Subsection 21(a) have been exhausted. Anything herein to the contrary notwithstanding, if as of any single month, the TRUSTEE is required as a result of the withdrawal provisions of this Subsection 21(c), to sell on the open market more than one percent of the outstanding shares of COMMON STOCK, then the TRUSTEE shall immediately so advise the EMPLOYEE BENEFIT FINANCE COMMITTEE. The EMPLOYEE BENEFIT FINANCE COMMITTEE may, in its sole discretion, limit, prorate, or temporarily suspend further sales of COMMON STOCK by the PLAN or take whatever steps necessary to ensure an orderly market in COMMON STOCK. A participant shall submit the appropriate Form to the SAVINGS FUND PLAN directing the PLAN ADMINISTRATOR as to the amount of the withdrawal. Distribution will be made as soon as practicable after receipt of the withdrawal Form. Upon each withdrawal, the UNITS credited to the appropriate FUND or FUNDS will be reduced by the number of UNITS withdrawn. Withdrawals from the BOND FUND can only be made in United States BONDS. Withdrawals from the COMMON STOCK FUND may be made in cash or whole shares of stock at the -19- election of the participant. Withdrawals of LCSF, SCSF, ISF, SVF, BIF, CAAF, MAAF or AAAF UNITS will be made in cash at the then current value of the UNITS; or, at the election of the participant, the UNITS will be transferred to the COMMON STOCK FUND pursuant to Section 18 and distribution will be made in whole shares of COMMON STOCK. (d) ROLLOVER CONTRIBUTIONS. A participant may at any time elect to withdraw all or any part of the UNITS including income thereon bought with the participant's Rollover Contributions to the PLAN. Such an election will not cause suspension from the PLAN. (e) ORDERING OF WITHDRAWALS. Whenever the PLAN ADMINISTRATOR is required to make a distribution under this Section 21 or Section 22, the PLAN ADMINISTRATOR shall first withdraw UNITS and earnings thereon attributable to a participant's NON-SECTION 401(k) CONTRIBUTIONS made prior to 1987, followed by UNITS and earnings thereon attributable to NON-SECTION 401(k) CONTRIBUTIONS made after 1986, followed by Units and earnings thereon attributable to Rollover Contributions, followed by UNITS withdrawable under Subsection 21(c)(1) followed by UNITS withdrawable under Subsection 21(c)(2), but only if available for withdrawal under that subsection, followed by UNITS and earnings thereon attributable to a participant's SECTION 401(k) CONTRIBUTIONS, but only to the extent that such UNITS can be withdrawn by the participant under Subsection 21(a). 22. Termination of Participation ---------------------------- Participation in the PLAN ends as of the date that a participant ceases to be an ELIGIBLE EMPLOYEE. Although a former participant may elect to have an account balance held in the PLAN under Section 23 after participation ends, a former participant may not contribute to the PLAN, except that contributions to the PLAN will be accepted with respect to retroactive wage payments. A former participant who has an account balance in the PLAN may make withdrawals from the account balance, and transfer from one or more FUNDS to another FUND or FUNDS pursuant to the terms of the PLAN. Upon the death of a participant, the PLAN ADMINISTRATOR shall distribute the participant's account balance to the participant's BENEFICIARY within a reasonable time but not later than 60 days after receipt of a completed withdrawal form or 180 days after the PLAN ADMINISTRATOR receives NOTICE of the participant's death. If the BENEFICIARY does not complete a withdrawal form within the time periods set forth above, the distribution shall be in cash and paid directly to the BENEFICIARY. 23. Distribution of Plan Benefits ----------------------------- (a) Upon termination of participation, a distribution shall be made of the balances allocated to a participant's accounts if the value of the participant's account is $3,500 or less. Such distribution shall be made no later than the 60th day following the close of the PLAN YEAR in which participation terminates, unless the participant elects to receive distribution at an earlier date. If the value of a participant's account exceeds $3,500, distribution will be made upon receipt by -20- the PLAN ADMINISTRATOR of the written distribution request of the participant. Distribution will therefore be made within 60 days of the receipt of such distribution request. Any provision of the PLAN notwithstanding, if participation continues beyond the end of the YEAR in which the participant attains age 70-1/2, distribution of the participant's entire interest in the PLAN shall be made no later than April 1 of the YEAR following the YEAR in which the participant attains age 70-1/2. All distributions due under the PLAN shall be payable only out of the PLAN's assets as directed by the ADMINISTRATOR. Unless a cash distribution is requested the TRUSTEE will distribute a certificate for the whole shares of COMMON STOCK, the United States BONDS, and the TRUSTEE'S check for the then current value of all other UNITS credited to the participant's account, plus any uninvested cash. Alternatively, at the direction of the participant, FUND UNITS other than U.S. SAVINGS BONDS UNITS may be transferred to the COMMON STOCK FUND pursuant to Section 18 and distribution will be made in whole shares of COMMON STOCK. If a participant elects a cash distribution, upon receipt of the appropriate Form requesting such distribution, the TRUSTEE will distribute the then current value of the INVESTMENT FUND UNITS and uninvested cash. Until the TRUSTEE converts INVESTMENT FUND UNITS to cash, all UNITS shall continue to share in investment gains and losses. Distributions from the BOND FUND can only be made in United States BONDS. (b) Any provision of the PLAN notwithstanding: Unless the participant otherwise elects, distribution to such participant shall be made (or shall commence) not later than the 60th day after the close of the PLAN YEAR in which occurs the latest of the following events: (1) The participant attains age 65; (2) The participant attains the 10th anniversary of the date on which he or she became a participant under the PLAN; or (3) The participant's termination of employment with the EMPLOYER. (c) Distributions hereunder will be made in accordance with Section 401(a)(9) of the CODE and the regulations thereunder, including Treasury regulation Section 1.401(a)(9)-2, which are incorporated by reference herein. 24. Direct Rollovers ---------------- Notwithstanding any provision of the PLAN to the contrary that would otherwise limit a participant's election under this section, effective January 1, 1993, a participant or BENEFICIARY who is a surviving spouse may elect, at the time and in the manner prescribed by the PLAN ADMINISTRATOR, to have any portion of an eligible rollover distribution, as defined below, paid directly to an eligible retirement plan, as defined below, specified by the participant or BENEFICIARY who is a surviving spouse in a direct -21- rollover. Any taxable portion of an eligible rollover distribution that is not transferred directly to an eligible retirement plan will be subject to mandatory federal income tax withholding. (a) An eligible rollover distribution shall mean any distribution of all or any portion of the balance to the credit of the participant, except that an eligible rollover distribution does not include any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the participant or the joint lives (joint life expectancies) of the participant and his or her designated BENEFICIARY, or for a specified period of 10 years or more; any distribution to the extent such distribution is required under Section 401(a)(9) of the CODE; and the portion of any distribution that is not includable in gross income (determined without regard to the exclusion for net unrealized appreciation with respect to employer securities). (b) An eligible retirement plan shall mean an individual retirement account described in Section 408(a) of the CODE, an individual retirement annuity described in Section 408(b) of the CODE, an annuity plan described in Section 403(a) of the CODE, or a qualified trust described in Section 401(a) of the CODE, that accepts the participant's eligible rollover distribution. However, in the case of an eligible rollover distribution to the surviving spouse, an eligible retirement plan is an individual retirement account or individual retirement annuity. ADMINISTRATIVE PROVISIONS ------------------------- 25. Company's Powers and Duties --------------------------- The COMPANY, acting through its BOARD OF DIRECTORS or Executive Committee, reserves to itself the exclusive power to amend, suspend or terminate the PLAN as provided below and to appoint and remove from time to time: (a) The individuals comprising the EMPLOYEE BENEFIT FINANCE COMMITTEE; (b) The individuals comprising the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE; and (c) The EMPLOYERS whose EMPLOYEES may participate in the PLAN. All powers and duties not reserved to the COMPANY are delegated to the EMPLOYEE BENEFIT FINANCE COMMITTEE and to the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE. Action of either committee shall be by vote of a majority of the members of the committee at a meeting, or in writing without a meeting and evidenced by the signature of any member who is so authorized by the committee. The COMPANY indemnifies each member of each committee against any personal liability or expense arising out of any action or inaction of the committee or of any member of the committee or of such individual, except that due to his own willful misconduct. -22- 26. Funding and Investment Provisions --------------------------------- The EMPLOYEE BENEFIT FINANCE COMMITTEE appointed by the COMPANY'S BOARD OF DIRECTORS to serve at its pleasure has the express powers and duties described in this section. (a) Appointments. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole power and duty from time to time to appoint and remove the TRUSTEE, the INVESTMENT MANAGER, actuaries, accountants and such other advisors and consultants as may be needed for the proper financial administration and investment of the assets of the PLAN. Supplementing such appointments, the EMPLOYEE BENEFIT FINANCE COMMITTEE may enter into appropriate agreements with each TRUSTEE, INVESTMENT MANAGER or other advisors appointed under this paragraph and delegate to them appropriate powers and duties. The EMPLOYEE BENEFIT FINANCE COMMITTEE may appoint and delegate to one or more individuals the power and duty to handle the day-to-day financial administration of the PLAN. Such individuals need not be members of the committee and shall serve at the pleasure of the committee. (b) Investment Policy. The funding policy is set forth in Sections 3 and 4. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole power and duty to establish the investment policy and to review and revise it from time to time as the committee shall determine in its sole discretion. A copy of the current investment policy will be available for participants' review in the ADMINISTRATOR'S office. Any revision of the investment policy shall not be an amendment of the PLAN. 27. Administration -------------- The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, appointed by the COMPANY'S BOARD OF DIRECTORS to serve at its pleasure, is the ADMINISTRATOR of the PLAN and is responsible for the overall administration of the PLAN. The ADMINISTRATOR has the sole power and duty to establish, and from time to time revise, such rules and regulations as may be necessary to administer the PLAN in a nondiscriminatory manner for the exclusive benefit of participants and all other persons entitled to benefits under the PLAN. The ADMINISTRATOR shall also maintain such records and make such computations, interpretations and decisions as may be necessary or desirable for the proper administration of the PLAN. The ADMINISTRATOR shall maintain for participants' inspection copies of the PLAN, TRUST AGREEMENT, investment policy, each agreement with an INVESTMENT MANAGER, the latest annual report, PLAN description and summary description and any amendments or changes in any of these documents. On written request, participants may obtain from the ADMINISTRATOR a copy of any of these documents at a cost established by the ADMINISTRATOR from time to time. The ADMINISTRATOR may appoint and delegate to one or more individuals the power and duty to handle the day-to-day administration of the PLAN. Such individuals need not be members of the committee and shall serve at the pleasure of the committee. -23- The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall serve as the final review committee under the PLAN, to determine conclusively for all parties any and all questions arising from the administration of the PLAN and shall have sole and complete discretionary authority and control to manage the operation and administration of the PLAN, including, but not limited to, the determination of all questions relating to eligibility for participation and benefits, interpretation of all PLAN provisions, determination of the amount and kind of benefits payable to any participant or BENEFICIARY, and construction of disputed or doubtful terms. Such decisions shall be conclusive and binding on all parties and not subject to further review. 28. Claims and Appeals Procedure ---------------------------- If a claim is denied in whole or in part, the ADMINISTRATOR shall furnish to the claimant a written notice setting forth: (a) Specific reason(s) for the denial, (b) The PLAN provision(s) on which the denial is based, (c) A description of any material or information, if any, necessary for the claimant to perfect the claim, and an explanation of why such material or information is necessary, and (d) Information concerning the steps to be taken if claimant wishes to submit a claim for review. The above information shall be furnished to the claimant within 90 days after the claim is received by the ADMINISTRATOR. If a claimant is not satisfied with the written NOTICE described in the preceding paragraph, such claimant may request a full and fair review by so notifying the ADMINISTRATOR in writing within 90 days after receiving such notice. If a review is requested the claimant shall also be entitled, upon written request, to review pertinent documents and to submit issues and comments in writing. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall furnish the claimant with a written final decision within 60 days after receipt of the request for review. 29. Qualified Domestic Relations Orders ----------------------------------- The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall apply the provisions of this section with regard to a Domestic Relations Order (as defined below) to the extent not inconsistent with Section 414(p) of the CODE. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall establish procedures, consistent with Section 414(p) of the CODE, to determine the qualified status of any Domestic Relations Order, to administer distributions under any Qualified Domestic Relations Order (as defined below), and to provide to the Participant and the Alternate Payee(s) (as defined below) all notices required under Section 414(p) of the CODE with respect to any Domestic Relations Order. -24- Within a reasonable period of time after the receipt of a Domestic Relations Order (or any modification thereof), the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall determine whether such order is a Qualified Domestic Relations Order. For purposes of this section: (a) Alternate Payee shall mean any spouse, former spouse, child, or other dependent of a participant who is recognized by a Domestic Relations Order as having a right to receive all, or a portion of, the benefits payable under the PLAN with respect to such Participant. (b) Domestic Relations Order shall mean any judgment, decree, or order (including approval of a property settlement agreement) which: (1) relates to the provision of child support, alimony payments, or marital property rights to a spouse, former spouse, child, or other dependent of a participant; and (2) is made pursuant to a state domestic relations law (including a community property law). (c) Qualified Domestic Relations Order shall mean a Domestic Relations Order which meets the requirements of Section 414(p)(1) of the CODE. 30. Lost Participant or Beneficiary ------------------------------- If, after three years, the ADMINISTRATOR cannot locate a participant or BENEFICIARY who is entitled to a distribution from an account, the UNITS, cash or COMMON STOCK in the account shall be applied to reduce the amount of future EMPLOYER CONTRIBUTIONS payable to the PLAN. A participant or BENEFICIARY who is entitled to a distribution from an account which has previously been applied to reduce EMPLOYER CONTRIBUTIONS under this Section 30 shall, upon filing a written claim, have the account reinstated in full and upon such reinstatement shall receive a distribution of the balance in the reinstated account, with interest at the prevailing legal rate accrued from the date his account was applied to reduce EMPLOYER CONTRIBUTIONS. 31. Benefits Are Not Assignable --------------------------- Except as may be required by law, a participant's interest in the PLAN and that of a participant's BENEFICIARY or spouse shall not be subject in any manner to assignment, anticipation, alienation, sale, transfer, pledge, encumbrance or charge, whether voluntary or involuntary, and any attempt to so assign, anticipate, sell, transfer, pledge, encumber or charge the same shall be void. -25- 32. Facility of Payment ------------------- If the ADMINISTRATOR determines that any individual entitled to any payment under the PLAN is physically or mentally incompetent and no guardian or conservator has been appointed to receive such payment, the ADMINISTRATOR may cause all payments thereafter becoming due to such individual to be applied for and on behalf of and for the benefit of such individual. Payments made pursuant to this provision shall completely discharge the EMPLOYER, the ADMINISTRATOR, the TRUSTEE and all fiduciaries of all further responsibility with respect to such individual. 33. Future of the Plan ------------------ If participation in the PLAN is ended because a substantial portion of an EMPLOYER'S property is sold or otherwise disposed of or because an EMPLOYER withdraws from the PLAN, a participant's interest is determined in accordance with the provisions of the next paragraphs as if the PLAN itself has been terminated. The COMPANY hopes and expects to continue this PLAN indefinitely, but because future conditions cannot be foreseen, its BOARD OF DIRECTORS necessarily reserves the right to amend or terminate the PLAN at any time. However, no amendment, merger or consolidation of the PLAN may be made which would reduce the right that any individual may then have with respect to the PLAN's assets then being held under the PLAN or permit any funds to revert to an EMPLOYER or to be used for any purpose except for the exclusive benefit of participants, spouses and BENEFICIARIES. If the PLAN is terminated, all contributions to the PLAN shall cease but the PLAN shall continue to operate in all other respects until all of the TRUST assets have been distributed in accordance with the provisions of the PLAN in effect on the date of its termination. In the event of a merger or consolidation with, or transfer of assets or liabilities to any other plan, if such other plan is then terminated, participant shall receive a benefit immediately after such merger, consolidation, or transfer which is equal to or greater than the benefit which participant would have received had the PLAN terminated immediately prior to such merger, consolidation, or transfer. 34. Definitions ----------- AAAF: The Aggressive Asset Allocation ----- Fund. Aggressive Asset Allocation Fund: A fund invested in a diversified --------------------------------- portfolio with a primary emphasis on stocks and a secondary emphasis on bonds. (See Section 17) Administrator: Employee Benefit Administrative -------------- Committee, Market Street, 3d Floor, Mail Code N3X, P.O. Box 770000, San Francisco, California 94177 BIF: The Bond Index Fund. ---- -26- Beneficiary: The person or persons entitled to ------------ receive any distribution due under the Plan in the event of a participant's death. For a married participant, the participant's spouse shall automatically be the Beneficiary unless the participant, with the written consent of his spouse, elects to designate another person or persons to be Beneficiary. The consent of the spouse shall be in writing, shall acknowledge the effect of the consent, and shall be witnessed by a notary public or Plan representative. A participant designates a Beneficiary on a Designation of Beneficiary Form available from the Plan Administrator. In the event an unmarried participant does not designate a Beneficiary, the participant's estate shall be deemed to be the Beneficiary. Board of Directors: The Board of Directors of Pacific ------------------- Gas and Electric Company. Bond Fund: A fund invested in United States ---------- Savings Bonds. (See Section 9) Bond Index Fund: A fund invested in marketable ---------------- fixed-income securities. (See Section 14) Bonds: Series "EE" Savings Bonds issued ------ by the United States Treasury. If the issuance of Series "EE" Bonds is discontinued, Bonds will refer to any other Bond issued by the United States Treasury which the Employee Benefit Finance Committee selects for purchase under the Plan. Business Day: Any day that the New York Stock ------------- Exchange is open for business. CAAF: The Conservative Asset Allocation ----- Fund. Calendar Quarter: The three month period commencing ----------------- on January 1, April 1, July 1 or October 1. Code: The Internal Revenue Code of 1986, ----- as amended from time to time. Company: Pacific Gas and Electric Company. -------- Common Stock: The common stock issued by PG&E ------------- Corporation. -27- Common Stock Fund: A fund invested in the common stock ------------------ issued by PG&E Corporation. (See Section 8) Conservative Asset Allocation Fund: A fund invested in a diversified ----------------------------------- portfolio with a primary emphasis on bonds and a secondary emphasis on stocks. (See Section 15) Covered Compensation: Earnings from an Employer, including --------------------- straight-time pay for hours worked, shift and nuclear premiums at the straight-time rate, straight-time pay for temporary upgrades, vacation pay (including vacation pay upon retirement), inclement weather pay, sick leave pay, holiday pay, differential pay for military training, pay for other time off with permission carrying full pay, temporary compensation under any state Worker's Compensation Law, payments under the Long Term Disability Plan, or supplemental benefits for industrial injury. Covered Compensation shall not include pay or shift and nuclear premiums for more than 40 hours per week, overtime bonuses, vacation or holiday pay requests other special fees or allowances, per diem allowances, payments, other than temporary compensation, made under any Workers' Compensation Law, voluntary wage benefit or state disability plans, or any other benefit plan. For Plan Years beginning after 1988 and before 1994, the maximum Covered Compensation of each Employee that may be taken into account each Plan Year shall not exceed $200,000 (as adjusted by the Secretary of the Treasury under Section 401(a)(17) of the Code. For Plan Years beginning after 1993, the maximum Covered Compensation of each Employee that may be taken into account each Plan Year shall not exceed $150,000 (as adjusted by the Secretary of the Treasury under Section 401(a)(17) of the Code). In determining the Covered Compensation of a Highly Compensated Employee for purposes of this limitation, the rules of Section 414(q)(6) of the Code shall apply, except that the term "family" shall include only the spouse of the Employee and any lineal descendants of the Employee who have not attained age 19 before the close of the Year. If the aggregate Covered Compensation of family members exceeds the applicable compensation limit as -28- limited by Section 401(a)(17) of the Code, then the amount of Covered Compensation considered under the Plan for each family member is proportionately reduced so that the total equals the applicable compensation limitation under Section 401(a)(17) of the Code. Eligible Employee: One entitled to become a ------------------ contributing participant, provided, however, a "leased employee," as defined in Section 414(n)(2) of the Code shall not be entitled to become an Eligible Employee Employee: An Employee of an Employer who is --------- not represented by a union. Employee Benefit Administrative Committee: The Employee Benefit ------------------------------- Administrative Committee referred to in Section 27. Employee Benefit Finance Committee: The Employee Benefit Finance ----------------------------------- Committee referred to in Section 26. Employer: Pacific Gas and Electric Company, --------- Pacific Service Employees Association, and any other company, association, or credit union designated by the Board of Directors as eligible to participate in this Plan as an Employer. Employer Contributions: Any contributions to the Plan by ----------------------- Company. FlexDollars: Amounts which a participant elects ------------ pursuant to the Company's Flex Plan to contribute as Section 401(k) Contributions. Rules governing FlexDollars are contained in the Company's Flex Plan; rules governing the treatment of FlexDollars under this Plan are contained in Subsection 3(b). Fund: The Company Stock Fund, The Bond ----- Fund, the Bond Index Fund, the Large Company Stock Index Fund, the Small Company Stock Index Fund, the International Stock Index Fund, the Stable Value Fund, the Conservative Asset Allocation Fund, the Moderate Asset Allocation Fund and the Aggressive Asset Allocation Fund or any of them. -29- Highly Compensated: Whether an Eligible Employee is ------------------- Highly Compensated shall be determined using the simplified method under Code Section 414(q)(12) as described in applicable Treasury regulations or other guidance issued by the Internal Revenue Service. Investment Fund: The Company Stock Fund, The Bond ---------------- Fund, the Bond Index Fund, the Large Company Stock Index Fund, the Small Company Stock Index Fund, the International Stock Index Fund, the Stable Value Fund, the Conservative Asset Allocation Fund, the Moderate Asset Allocation Fund and the Aggressive Asset Allocation Fund or any of them. Investment Manager: STABLE VALUE FUND. PRIMCO Capital ------------------- Management, Inc., 101 South Fifth Street, Louisville, Kentucky 40202, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. BOND INDEX FUND. State Street Bank and Trust, Two International Place, Boston, MA 02110, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. LARGE COMPANY STOCK INDEX FUND. State Street Bank and Trust, Two International Place, Boston, MA 02110, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. SMALL COMPANY STOCK INDEX FUND. State Street Bank and Trust, Two International Place, Boston, MA 02110, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. INTERNATIONAL STOCK INDEX FUND. State Street Bank and Trust, Two International Place, Boston, MA 02110, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. -30- CONSERVATIVE ASSET ALLOCATION FUND. State Street Bank and Trust, Two International Place, Boston, MA 02110, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. MODERATE ASSET ALLOCATION FUND. State Street Bank and Trust, Two International Place, Boston, MA 02110, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. AGGRESSIVE ASSET ALLOCATION FUND. Stat Street Bank and Trust, Two International Place, Boston, MA 02110, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. Long Term Disability Plan: Part B of the Group Life Insurance -------------------------- and Long term Disability Plan of Pacific Gas and Electric Company as amended January 1, 1991. MAAF: The Moderate Asset Allocation Fund. ----- Moderate Asset Allocation Fund: A fund invested in a diversified ------------------------------- portfolio with an emphasis on stocks and bonds. (See Section 16) Non-Section 401(k) Contributions: Employee contributions to the Plan --------------------------------- as described in Subsection 3(c) and all Employee Contributions made prior to October 1, 1984. Non- Section 401(k) Contributions are made with after-tax dollars. Notice: Any method of communication, whether ------- electronic, telephonic, written or other, provided that the Plan Administrator has communicated in writing to participants any such method and its format as appropriate and acceptable. Plan: This Company's Savings Fund Plan for ----- Non-Union Employees, as amended, revised and set forth herein. Retirement Plan: The Company's Retirement Plan as ---------------- revised from time to time. -31- Rollover Contribution: An amount contributed by a ---------------------- participant which originated from another employer's qualified plan which is eligible for rollover under Section 402(c)(4) of the Code. Savings Fund Plan Office: 245 Market Street, 3d Floor ------------------------- Mail Code N3X P.O. Box 770000 San Francisco, CA 94177 Section 401(k) Contributions: Amounts deferred from a ----------------------------- Participant's Covered Compensation as described in Subsection 3(a). Section 401(k) Contributions are made with pre-tax dollars. Service: The period of time commencing with -------- the first day of employment or reemployment for an Employer and ending on participant's Severance from Service Date. If an Employee with less than one year of Service is rehired after a period of severance which extends for 12 months or more, the Employee shall be treated as a new Employee for all purposes, and the Service and compensation before the Severance from Service Date shall not be recognized for any purpose of the Plan. Participants who have a period of severance after they have completed at least one year of Service and who are later rehired, immediately become Eligible Employees entitled to contribute in accordance with their total years of Service. Service shall also include all years of Service with: (a) Any corporation which is a member of the same controlled group of corporations as the Company or of any other Employer (within the meaning of Section 414(b) of the Code); (b) Any trade or business under the common control of the Company or of any other Employer (within the meaning of Section 414(c) of the Code); (c) Any service organization which is a member of the same affiliated service group as the Company or of any other Employer (within the meaning of -32- Section 414(m) of the Code). Severance From Service Date: A. The date on which an Employee ---------------------------- quits, retires, is discharged or dies; or B. The first anniversary of the first date of a period in which a participant remains absent from work for an Employer for any reason other than resignation, retirement, discharge, or death. C. For the purpose of determining the Severance from Service Date, the following periods shall not be considered as absences from work for an Employer: (1) Absence on a leave of absence authorized by an Employer. (2) Absence because of illness or injury as long as the participant is entitled to receive sick leave pay or is entitled to receive benefits under the provisions of the Voluntary Wage Benefit Plan, a state disability plan, the Long Term Disability Plan, or a Workers' Compensation Law. (3) Absence for military service or service in the Merchant Marines so long as reemployment rights are protected by law. (4) Absence caused by layoff for lack of work of less than 12 continuous months for a Participant who has less than five years of service, or 24 continuous months for a Participant who has five or more years of service. Stable Value Fund: A fund invested in fixed rate, ------------------ fixed term investment contracts. (See Section 13) SVF: The Stable Value Fund. ---- -33- Trust: The Trust into which all ------ contributions are deposited and from which all distributions are made. Trustee: State Street Bank and Trust -------- Company, 225 Franklin Street, Boston, Massachusetts 02101, or such other bank or trust company selected by the Employee Benefit Finance Committee which agrees to act as Trustee or successor Trustee of the Trust pursuant to the Trust Agreement. Trust Agreement: The agreement between the Company ---------------- and the Trustee. Unit: A measurement of participant's ----- interest in the Investment Funds. For purposes of the Bond Fund, a unit shall be a United States Bond. Year: The calendar year beginning ----- January 1 and ending December 31. -34- SPECIAL PROVISION A TOP HEAVY PROVISIONS -------------------- (a) General Rule ------------ For any PLAN YEAR for which this PLAN is a "top-heavy plan" as defined in subsection (g) below, any other provisions of this PLAN to the contrary notwithstanding, this PLAN shall be subject to the following provisions: (1) The minimum contribution provisions of subsection (b). (2) The limitation on contribution set by subsection (d). (b) Minimum Contribution Provisions ------------------------------- Each participant who (i) is a non-key EMPLOYEE (as defined in subsection (i) below) and (ii) is employed on the last day of the PLAN YEAR, even if such individual is excluded from the PLAN for failing to make mandatory contributions to the PLAN, shall be entitled to have contributions allocated to his account of not less than three percent (the "minimum contribution percentage") of the participant's compensation (within the meaning of Section 415 of the CODE). In determining the minimum contribution percentage to be allocated to an EMPLOYEE'S account, a key EMPLOYEE'S SECTION 401(k) CONTRIBUTIONS shall be considered as an EMPLOYER CONTRIBUTION. However, SECTION 401(k) CONTRIBUTIONS on behalf of EMPLOYEES other than key EMPLOYEES will not be considered as EMPLOYER CONTRIBUTIONS. The minimum contribution percentage set forth above shall be reduced for any PLAN YEAR in which the percentage at which contributions are made (or required to be made) under the PLAN for the PLAN YEAR for the key EMPLOYEE for whom such percentage is the highest for such PLAN YEAR is less than three percent. For this purpose, the percentage with respect to a key EMPLOYEE (as defined in subsection (g) below) shall be determined by dividing the contributions (including forfeitures and SECTION 401(k) CONTRIBUTIONS) made for such key EMPLOYEES by so much of his total compensation for the PLAN YEAR. Contributions taken into account under the immediately preceding sentence shall include contributions under this PLAN and under all other defined contribution plans required to be included in an aggregation group (as defined in subsection (f)(2) below) but shall not include any plan required to be included in such aggregation group if such plan enables a defined contribution plan required to be included in such group to meet the requirements of the CODE prohibiting discrimination as to contributions or benefits in favor of EMPLOYEES who are officers, shareholders or the highly-compensated or prescribing the minimum participation standards. Contributions taken into account under this subsection (b) shall not include any contributions under the Social Security Act or any other Federal or State law. -35- (c) Limitations on Contributions ---------------------------- In the event that the EMPLOYER also maintains a defined benefit PLAN providing benefits on behalf of participants in this PLAN, one of the two following provisions shall apply: (1) If for the PLAN YEAR this PLAN would not be a "top-heavy PLAN" as defined in subsection (a)(2) above if "90 percent" were substituted for "60 percent," then subsection (b) shall apply for such PLAN YEAR as if amended so that "four percent" were substituted for "three percent". (2) If for the PLAN YEAR this PLAN would continue to be a "top-heavy PLAN" as defined in subsection (f) below if "90 percent" were substituted for "60 percent," then the denominator of both the defined contribution PLAN fraction and the defined benefit PLAN fraction shall be calculated as set forth in Section 415 (e) of the CODE for the limitation year ending in such PLAN YEAR by substituting "1.0" for "1.25" in each place such figure appears, except with respect to any individual for whom there are no EMPLOYER CONTRIBUTIONS allocated or any accruals for such individual under the defined benefit PLAN. Furthermore, the transitional rule set forth in Section 415 (e) of the CODE shall be applied by substituting "$41,500" for "$51,875". (d) Coordination with Other Plans ----------------------------- In the event that another defined contribution or defined benefit plan maintained by the EMPLOYER provides contributions or benefits on behalf of participants in this PLAN, such other plan shall be treated as a part of this PLAN pursuant to applicable principles (such as Rev. Rul. 81-202 or any successor ruling or regulations) in determining whether this PLAN satisfies the requirements of subsection (b), (c) and (d). Such determination shall be made upon the advice of counsel by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE. (e) Top-Heavy Plan Definition ------------------------- This PLAN shall be a "top-heavy plan" for any PLAN YEAR if, as of the determination date (as defined in subsection (f)(1) below), the aggregate of the accounts under the PLAN and any required aggregation group or permissive aggregation group of plans for participants (including former participants) who are key EMPLOYEES (as defined in subsection (g) below but not including accounts of individuals excluded under section 416(g)(4)(E) of the CODE) exceeds 60 percent of the present value of the aggregate of the accounts for all participants, excluding former key EMPLOYEES, or if this PLAN is required to be in an aggregate group (as defined in subsection (f)(3) below) which for such PLAN YEAR is a top-heavy group (as defined in subsection (f)(4) below). (1) "Determination date" means for any PLAN YEAR the last day of the immediately preceding PLAN YEAR. (2) "Valuation date" means the last day of each PLAN YEAR. -36- (3) "Aggregation group" means the group of plans, if any, that includes both the group of plans that are required to be aggregated and the group of plans that are permitted to be aggregated. (A) The group of plans that are required to be aggregated (the "required aggregation group") includes (i) Each plan of the EMPLOYER (as defined in subsection (i) below) in which a key EMPLOYEE is a participant, including collectively-bargained plans, and (ii) Each other plan, including collectively-bargained plans of the EMPLOYER (as defined in subsection (i) below) which enables a plan in which a key EMPLOYEE is a participant to meet the requirements of the CODE prohibiting discrimination as to contributions or benefits in favor of EMPLOYEES who are officers, shareholders or the highly-compensated or prescribing the minimum participation standards. (B) The group of plans that are permitted to be aggregated (the "permissive aggregation group") includes the required aggregation group plus one or more plans of the EMPLOYER (as defined in subsection (i) below) that is not part of the required aggregation group and that the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE certifies as constituting a plan within the permissive aggregation group. Such plan or plans may be added to the permissive aggregation group only if, after the addition, the aggregation group as a whole continues not to discriminate as to contributions or benefits in favor of officers, shareholders or the highly-compensated and to meet the minimum participation standards under the CODE. (4) "Top-heavy group" means the aggregation group, if as of the applicable determination date, the sum of the present value of the cumulative accrued benefits for key EMPLOYEES under all defined benefit plans included in the aggregation group plus the aggregate of the accounts of key EMPLOYEES under all defined contribution plans included in the aggregation group exceeds 60% of the sum of the present value of the cumulative accrued benefits for all EMPLOYEES, excluding former key EMPLOYEES, under all such defined benefit plans plus the aggregate accounts for all EMPLOYEES, excluding former key EMPLOYEES, under such defined contribution plans. If the aggregation group that is a top- heavy group is a required aggregation group, each plan in the group will be top heavy. If the aggregation group that is a top-heavy group is a permissive aggregation group, only those plans that are part of the required aggregation group will be treated as top-heavy. If the aggregation group is not a top-heavy group, no plan within such group will be top-heavy. (5) In determining whether this PLAN constitutes a "top-heavy plan," the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (or its agent) shall make the following adjustments in connection therewith: -37- (A) When more than one plan is aggregated, the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall determine separately for each plan as of each plan's determination date the present value of the accrued benefits or account balance. The results shall then be aggregated separately by adding the results of each plan as of the determination dates for such plans that fall with the same calendar year. (B) In determining the present value of the cumulative accrued benefit or the amount of the account of any EMPLOYEE, such present value or account shall include the amount in dollar value of the aggregate distributions made to such EMPLOYEE under the applicable plan during the five-year period ending on the determination date, unless reflected in the value of the accrued benefit or account balance as of the most recent valuation date. Such amounts shall include distributions to EMPLOYEES which represented the entire amount credited to their accounts under the applicable plan. (C) Further, in making such determination, in any case where an individual is a "non-key EMPLOYEE" as defined in subsection (h) below, with respect to an applicable plan, but was a key EMPLOYEE with respect to such plan for any prior PLAN YEAR, any accrued benefit and any account of such EMPLOYEE shall be altogether disregarded. For this purpose, to the extent that a key EMPLOYEE is deemed to be a key EMPLOYEE if he or she met the definition of key EMPLOYEE within any of the four preceding PLAN YEARS, this provision shall apply following the end of such period of time. (f) Key EMPLOYEE ------------ The term "key EMPLOYEE" means any EMPLOYEE or former EMPLOYEE under this PLAN who, at any time during the PLAN YEAR containing the determination date or during any of the four preceding PLAN YEARS, is or was one of the following: (1) An officer of the EMPLOYER having an annual compensation greater than 50 percent of the amount in effect under Section 415(b)(1)(A) of the CODE for such PLAN YEAR. Whether an individual is an officer shall be determined by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE on the basis of all the facts and circumstances, such as an individual's authority, duties and term of office, not on the mere fact that the individual has the title of officer. For any such PLAN YEAR, these shall be treated as officers no more than the lesser of: (A) 50 EMPLOYEES, or (B) the greater of three EMPLOYEES or 10 percent of the EMPLOYEES. For this purpose, if there are more than 50 officers, the 50 highest- paid officers shall be the key EMPLOYEES. (2) One of the ten EMPLOYEES owning (or considered as owning, within the meaning of the constructive ownership rules of the CODE) the largest interests in the EMPLOYER (as defined in subsection (i)). An EMPLOYEE who has some ownership interest is considered to be one of the top ten owners unless at least ten other EMPLOYEES own a greater interest than that EMPLOYEE. However, an -38- EMPLOYEE will not be considered a top ten owner for a PLAN YEAR if the EMPLOYEE earns an amount equal to or less than the maximum dollar limitation on contributions and other annual additions to a participant's account in a defined contribution PLAN under the CODE as in effect for the calendar year in which the determination date falls. (3) Any person who owns (or is considered as owning within the meaning of the constructive ownership rules of the CODE) more than five percent of the outstanding stock of the EMPLOYER or stock possessing more than five percent of the combined total voting power of all stock of the EMPLOYER. (4) A one percent owner of the EMPLOYER having an annual compensation from the EMPLOYER of more than $150,000, and who owns more than one percent of the outstanding stock of the EMPLOYER or stock possessing more than one percent of the combined total voting power of all stock of the EMPLOYER. For purposes of this subsection, compensation means all items includable as compensation for purposes of applying the limitations on contributions and other annual additions to a participant's account in a defined contribution plan and the maximum benefit payable under a defined benefit plan under the CODE. For purposes of parts (1), (2), (3) and (4) of this definition, a BENEFICIARY of a key EMPLOYEE shall be treated as a key EMPLOYEE. For purposes of parts (3) and (4), each EMPLOYER is treated separately (without regard to the definition in subsection (i)) in determining ownership percentages; but, in determining the amount of compensation, the definition of EMPLOYER in subsection (i) is taken into account. (g) Non-key EMPLOYEE ---------------- The term "non-key EMPLOYEE" means any EMPLOYEE (and any beneficiary or an EMPLOYEE) who is not a key EMPLOYEE. (h) Employer -------- The term "employer" as defined in Section 34 of this PLAN. -39- ------------------------- I, Leslie H. Everett, do hereby certify that I am the Vice President and Corporate Secretary of the PACIFIC GAS AND ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of California, and that the above and foregoing is a full, true and correct copy of the Pacific Gas and Electric Company SAVINGS FUND PLAN FOR NON-UNION EMPLOYEES as the same exists at the date of this certification. WITNESS my hand and the seal of the said corporation hereunto affixed this day of Leslie H. Everett Vice President and Corporate Secretary of PACIFIC GAS AND ELECTRIC COMPANY -40- EX-10.8 8 RETIREMENT PLAN EXHIBIT 10.8 THE PACIFIC GAS AND ELECTRIC COMPANY RETIREMENT PLAN PART I ------ TABLE OF CONTENTS ----------------- RETIREMENT PLAN ---------------
Page ---- 1. INTRODUCTION...................................................1 2. ELIGIBILITY AND PARTICIPATION..................................2 3. SERVICE........................................................2 4. BREAK IN SERVICE AND REEMPLOYMENT..............................2 5. NORMAL RETIREMENT DATE.........................................3 6. BASIC PENSION BENEFIT FORMULA..................................3 7. EARLY RETIREMENT PENSION BENEFIT FORMULA.......................4 8. PENSIONS WHERE EMPLOYMENT ENDS BEFORE AGE 55...................5 9. DEFERRED RETIREMENT............................................5 10. FORMS OF PENSION...............................................6 11. SPOUSE'S PENSION...............................................7 12. WITHDRAWAL OF PARTICIPANT CONTRIBUTIONS ON TERMINATION OF EMPLOYMENT..................................................9 13. DEATH BENEFITS.................................................9 14. FACILITY OF PAYMENT............................................9 15. BENEFITS ARE NOT ASSIGNABLE...................................10 16. EMPLOYER CONTRIBUTIONS........................................10 17. COMPANY'S POWERS AND DUTIES...................................10 18. FUNDING AND INVESTMENT PROVISIONS.............................11 19. ADMINISTRATION................................................11 20. CLAIMS PROCEDURE..............................................12 21. QUALIFIED DOMESTIC RELATIONS ORDERS...........................12 22. AMENDMENT, TERMINATION, AND MERGER............................13 23. DEFINITIONS AND CROSS-REFERENCES..............................13 SPECIAL PROVISIONS A, B, C, D, E, F, G, H, I, J, K, L, M AND N..20-76
-1- RETIREMENT PLAN --------------- 1. Introduction ------------ This is the controlling and definitive statement of the Pacific Gas and Electric Company Retirement PLAN /1/ which, with certain exceptions, is effective on and after January 1, 1996, for EMPLOYEES who are employed by Pacific Gas and Electric Company and other EMPLOYERS. This PLAN is a further revision of the PLAN, originally placed in effect by the COMPANY January 1, 1937, which has been amended from time to time in the intervening years. Rights of PARTICIPANTS in this PLAN will not be less than rights of PARTICIPANTS under COMPANY'S PLAN as it existed before 1996. The purpose of this PLAN is to distribute the corpus and income of accumulated PENSION trust funds in accordance with the PLAN. Under no circumstances shall contributions or benefits under this PLAN discriminate in favor of a "highly compensated EMPLOYEE," as that term is defined using the simplified method under CODE Section 414(q)(12) as described in applicable Treasury regulations or other guidance issued by the Internal Revenue Service. Forfeitures of nonvested accrued benefits under the PLAN shall not be applied to increase benefits any EMPLOYEE could otherwise receive under the terms of the PLAN. Except for pension adjustments provided for in Special Provision G, PARTICIPANTS who retire or terminate employment before the effective date of any amendment are not affected or benefited by such amendments. Since final regulations governing many statutory requirements of the Employee Retirement Income Security Act of 1974 (ERISA) have not yet been issued, the COMPANY reserves the right to retroactively modify the final language of the revised PLAN to conform to these requirements. As provided for in Section 414(f) of the CODE, the PLAN has elected to be treated as a single employer plan. This PLAN consists of Part I and Part II. Part I applies solely to EMPLOYEES not covered by a collective bargaining agreement, and Part II applies solely to EMPLOYEES whose benefits are the subject of collective bargaining with a union representing EMPLOYEES of the COMPANY. /2/ - --------------------------- /1/ Words in all capitals are defined in Section 23. /2/ For PLAN YEARS prior to January 1, 1995, only management EMPLOYEES were PARTICIPANTS in Part I of the PLAN; prior to January 1, 1995, weekly-paid, non-union EMPLOYEES participated in Part II. -1- PART I ------ 2. Eligibility and Participation ----------------------------- An EMPLOYEE automatically becomes a PARTICIPANT in the PLAN on the first day of work for an EMPLOYER, and participation continues until the PARTICIPANT's SERVICE is terminated. 3. Service ------- (a) The SERVICE of a PARTICIPANT on any date shall consist of the sum of the following: (1) Any CREDITED SERVICE as of December 31, 1975, as defined under the PLAN prior to the January 1, 1976, amendment and reproduced in Special Provision F, and (2) The elapsed time from the first day of employment with an EMPLOYER (but not earlier than January 1, 1976) to the PARTICIPANT's SEVERANCE FROM SERVICE DATE, excluding any periods of BREAK IN SERVICE and any SERVICE cancelled by the operation of Sections 4 and 13. (b) For EMPLOYEES who attain PART-TIME status at any time on or after January 1, 1991, service benefit accruals will be based on the following SERVICE: (1) Paragraph (a) of this Section will apply to all SERVICE prior to January 1, 1991; (2) All SERVICE after December 31, 1990 in which the EMPLOYEE is designated as a PART-TIME EMPLOYEE shall be prorated for purposes of benefit accruals based on the ratio of actual straight-time hours worked in the calendar year to the full-time hourly equivalent (2,080 per calendar year) rounded to the nearest month. 4. Break in Service and Reemployment --------------------------------- Upon reemployment with an EMPLOYER after a BREAK IN SERVICE, prior SERVICE earned under the PLAN will be treated for eligibility, vesting and/or benefit accrual as follows: (a) If a PARTICIPANT has a BREAK IN SERVICE starting on or after January 1, 1989, the SERVICE of such PARTICIPANT prior to the BREAK IN SERVICE will be cancelled unless such prior SERVICE was at least five years or, in the event that such prior SERVICE was less than five years, if the period of the BREAK IN SERVICE was less than the prior SERVICE. (b) If a PARTICIPANT has a BREAK IN SERVICE starting on or after January 1, 1985, but before January 1, 1989, the SERVICE of such PARTICIPANT prior to the BREAK IN SERVICE will be cancelled unless such prior SERVICE was at least 10 years or, in the event that such prior SERVICE was less than 10 years, such prior SERVICE will be cancelled if the period of the BREAK IN SERVICE is equal to or exceeds the greater of (i) five years or (ii) the period of SERVICE prior to the BREAK IN SERVICE. (c) If a PARTICIPANT has a BREAK IN SERVICE starting on or after January 1, 1976, but before January 1, 1985, the SERVICE of such PARTICIPANT prior to the BREAK IN SERVICE will be cancelled unless such prior SERVICE was at least 10 years or, in the event that such prior SERVICE was less than 10 years, if the period of the BREAK IN SERVICE was less than the prior SERVICE. If the PARTICIPANT's contributions to the PLAN have been withdrawn, -2- restoration of the PARTICIPANT's prior SERVICE will be in accordance with the provisions of Section 12. (d) EMPLOYEES who were PARTICIPANTS in the PLAN prior to January 1, 1976, and whose prior SERVICE would not be restored under the provisions of (a) of this Section, but would have been restored under the provisions of the PLAN prior to the January 1, 1976, amendment, shall continue to be eligible to have their prior SERVICE restored under the rules of the PLAN prior to the January 1, 1976, amendment. Such rules are set forth in Special Provision E. 5. Normal Retirement Date ---------------------- NORMAL RETIREMENT DATE is the first day of the month following a PARTICIPANT's 65th birthday. 6. Basic Pension Benefit Formula ----------------------------- A PARTICIPANT whose SERVICE continues to NORMAL RETIREMENT DATE or beyond/3/ is entitled to a BASIC PENSION payable on ACTUAL RETIREMENT DATE and on the first day of each month thereafter as long as the PARTICIPANT lives./4/ (a) The monthly amount of the BASIC PENSION for a PARTICIPANT whose entire SERVICE is accrued as a PARTICIPANT in Part I of this PLAN shall be a monthly amount equal to 1.6 percent of the PARTICIPANT's average BASIC MONTHLY SALARY for the final 36 consecutive months of SERVICE,/5/ multiplied by the number of whole and fractional years of SERVICE. The amount so determined shall take the place of all other retirement income to which a PARTICIPANT might otherwise have been entitled under any suspended plan of an EMPLOYER or predecessor company. (b) The monthly amount of the BASIC PENSION for a PARTICIPANT whose classification is changed and who has accrued SERVICE under both Part I and Part II of this PLAN shall be the larger of (1) or (2) below: (1) The amount produced by computing all years of SERVICE pursuant to the applicable formula for the new classification. (2) The amount equal to the sum of (i) a pension benefit for SERVICE prior to the change in classification, computed pursuant to the applicable formula for the PARTICIPANT's old classification in effect at the time of the change in classification; and (ii) a pension benefit for SERVICE after the change in classification, computed pursuant to the formula applicable for the PARTICIPANT's new job classification. Each portion of the BASIC PENSION calculated under (i) and (ii) above shall be subject to all the applicable reductions imposed in PART I and PART II with respect to age and early retirement, joint pensions, marital pensions, and the election of an alternative spouse's pension. - --------------------------- /3/ See Section 9 for the conditions under which this may occur. /4/ See Section 10 for the conditions under which other forms of pension may be substituted for the BASIC PENSION. /5/ A married PARTICIPANT'S EARLY RETIREMENT PENSION shall be in the form of a MARITAL PENSION, computed as provided in Section 10b. In lieu of a MARITAL PENSION, a PARTICIPANT may elect any of the alternative forms of the EARLY RETIREMENT PENSION described in Section 10b. and subject to the rules contained therein. -3- (c) The monthly amount of the BASIC PENSION for a PARTICIPANT receiving LONG TERM DISABILITY PLAN benefits on ACTUAL RETIREMENT DATE shall be computed under (1) or (2) below, as applicable: (1) For EMPLOYEES receiving LONG TERM DISABILITY PLAN benefits on January 1, 1988, a monthly benefit equal to 1.6 percent of the larger of (i) the PARTICIPANT'S BASIC MONTHLY SALARY for the last month of active SERVICE or (ii) the PARTICIPANT'S LONG TERM DISABILITY PLAN benefit for the month immediately preceding ACTUAL RETIREMENT DATE. The result obtained in (i) or (ii) shall be multiplied by the number of whole or fractional years of SERVICE. (2) For EMPLOYEES who start receiving LONG TERM DISABILITY PLAN benefits after January 1, 1988, a monthly benefit equal to 1.6 percent of the larger of (i) the average BASIC MONTHLY SALARY for the final consecutive 36 months of active SERVICE or (ii) the PARTICIPANT'S LONG TERM DISABILITY PLAN benefit for the month immediately preceding ACTUAL RETIREMENT DATE. The result obtained in (a) or (b) shall be multiplied by the number of whole and fractional years of SERVICE. 7. Early Retirement Pension Benefit Formula ---------------------------------------- If a PARTICIPANT's SERVICE ends after the first day of the month following said PARTICIPANT's 55th birthday, and before NORMAL RETIREMENT DATE or death, the PARTICIPANT shall elect to receive either: (a) A BASIC PENSION computed as provided in Section 6, or a MARITAL PENSION computed as provided in Section 10b., whichever is applicable, payable beginning with NORMAL RETIREMENT DATE; or (b) An EARLY RETIREMENT PENSION with payments to begin on the PARTICIPANT's EARLY RETIREMENT DATE and to continue on the first day of each month thereafter so long as PARTICIPANT lives. EARLY RETIREMENT DATE is the date selected by the PARTICIPANT for commencement of payment of retirement benefits. This date must be the first day of any month after the termination of SERVICE and before the PARTICIPANT's 65th birthday. To elect an EARLY RETIREMENT PENSION, PARTICIPANT must notify the EMPLOYER in writing at least 30 days before the EARLY RETIREMENT DATE the PARTICIPANT selects. The monthly amount of the PARTICIPANT's EARLY RETIREMENT PENSION/6/ will be as follows: (1) If PARTICIPANT has less than 15 years of SERVICE on the EARLY RETIREMENT DATE, the amount of the BASIC PENSION shall be reduced by one-fourth of one percent for each month (three percent per year) between PARTICIPANT's NORMAL RETIREMENT DATE and PARTICIPANT's EARLY RETIREMENT DATE; or (2) If PARTICIPANT has at least 15 but less than 30 years of SERVICE and is 62 years of age or older on the EARLY RETIREMENT DATE, the amount shall be the PARTICIPANT's BASIC PENSION computed to the PARTICIPANT's EARLY RETIREMENT DATE; or - --------------------------- /6/ A married PARTICIPANT'S EARLY RETIREMENT PENSION shall be in the form of a MARITAL PENSION, computed as provided in Section 10b and Section 7. In lieu of a MARITAL PENSION, a PARTICIPANT may elect any of the alternative forms of the EARLY RETIREMENT PENSION described in Section 10b. and subject to the rules contained therein. -4- (3) If PARTICIPANT has at least 15 but less than 25 years of SERVICE and is less than 62 years of age on the EARLY RETIREMENT DATE, the amount of the BASIC PENSION shall be reduced by one-fourth of one percent for each month (three percent per year) by which PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's 62nd birthday, and further reduced by 1/12th of one percent for each month (one percent per year) by which PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's 60th birthday; or (4) If PARTICIPANT has at least 25 but less than 30 years of SERVICE and is less than 62 years of age on the EARLY RETIREMENT DATE, the amount of the BASIC PENSION shall be reduced by one-fourth of one percent for each month (three percent per year) by which PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's 62nd birthday; or (5) If a PARTICIPANT has at least 30 years of SERVICE and is less than 60 years of age on the EARLY RETIREMENT DATE, the amount of the BASIC PENSION shall be reduced by one- half of one percent for each month (up to a maximum of 12 months or six percent) by which PARTICIPANT'S EARLY RETIREMENT DATE precedes PARTICIPANT's 60th birthday, and further reduced by one-fourth of one percent for each month (three percent per year) by which PARTICIPANT'S EARLY RETIREMENT DATE precedes PARTICIPANT's 59th birthday; or (6) If PARTICIPANT has at least 30 years of SERVICE and is 60 years of age or older on the EARLY RETIREMENT DATE, the amount shall be the PARTICIPANT's BASIC PENSION computed to the PARTICIPANT's EARLY RETIREMENT DATE. (7) If a PARTICIPANT has at least 35 years of SERVICE and is 55 years of age or older on EARLY RETIREMENT DATE, and such PARTICIPANT was formerly a PARTICIPANT on December 31, 1994, in Part II of the PLAN, the amount shall be the PARTICIPANT'S BASIC PENSION computed to the PARTICIPANT'S EARLY RETIREMENT DATE. See Special Provision B for a table of EARLY RETIREMENT reductions. 8. Pensions Where Employment Ends Before Age 55 -------------------------------------------- Until January 1, 1989, a PARTICIPANT with at least 10 years of SERVICE will be designated as a former EMPLOYEE rather than a retired EMPLOYEE if such PARTICIPANT's SERVICE ends before the first day of the month which follows the PARTICIPANT's 55th birthday. Effective January 1, 1989, any PARTICIPANT with at least five years of SERVICE will be designated as a former EMPLOYEE if such PARTICIPANT's SERVICE ends before the first day of the month which follows the PARTICIPANT's 55th birthday. Such former EMPLOYEE has a vested right to receive a PENSION with the same rights of election and in the same amounts as provided in Section 7, provided that the earliest election date for commencement of PENSION payments is the first day of the month after the PARTICIPANT's 55th birthday and the latest shall be April 1 of the year following the year in which the PARTICIPANT attains age 70 1/2. Such a PARTICIPANT is also entitled to the elections provided in Sections 10 (Forms of Pension), 12 (Withdrawal of Participant Contributions on Termination of Employment), 13 (Death Benefits in Certain Cases), and 15 (Facility of Payment). 9. Deferred Retirement ------------------- An EMPLOYEE may continue in employment beyond the NORMAL RETIREMENT DATE only at the request of an EMPLOYER or as may be required by law. A PARTICIPANT whose employment continues -5- beyond NORMAL RETIREMENT DATE shall not be entitled to a pension until PARTICIPANT's ACTUAL RETIREMENT DATE. Any provision of the PLAN notwithstanding, distributions from the PLAN shall comply with the requirements of CODE Section 401(a)(9) and the regulations thereunder. The amount of the PENSION payable shall be the PENSION benefit accrued as of the April 1 following the end of the year in which the EMPLOYEE attains age 70 1/2, adjusted for any elections made by the PARTICIPANT and any forms of PENSION required under Section 10. Pursuant to CODE Section 401(a)(9)(A)(ii), if an EMPLOYEE continues employment beyond the end of the year in which the EMPLOYEE attains age 70 1/2, a PENSION shall be distributed, commencing not later than April 1 of the calendar year following the calendar year in which the EMPLOYEE attains age 70 1/2, over the life of the EMPLOYEE or over the joint lives of the EMPLOYEE and the EMPLOYEE'S SPOUSE or other JOINT PENSIONER. If an EMPLOYEE dies after the distribution of the EMPLOYEE'S interest in the PLAN has begun, then, in accordance with CODE Section 401(a)(9)(B)(i), the remaining portion of the EMPLOYEE'S accrued PENSION benefit, if any, will be distributed at least as rapidly as under the method of distributions being used as of the date of his or her death. If an EMPLOYEE dies before the ACTUAL RETIREMENT DATE, then the EMPLOYEE'S SPOUSE may elect to postpone receiving distributions under the SPOUSE'S PENSION, but postponement of receipt of benefits shall not extend beyond the date that the EMPLOYEE would have attained age 70 1/2. Death benefits provided under the PLAN shall be no more than incidental, within the meaning of the CODE, to the PLAN'S primary purpose of providing retirement benefits to EMPLOYEES. 10. Forms of Pension ---------------- (a) Joint Pension With Non-Spouse ----------------------------- For a PARTICIPANT who is unmarried on the ACTUAL RETIREMENT DATE, the normal form of a PENSION shall be a BASIC PENSION or an EARLY RETIREMENT PENSION which terminates on the PARTICIPANT'S death. A MARITAL PENSION, as described in 10(b) below, is the normal form of PENSION for PARTICIPANTS who are married on the ACTUAL RETIREMENT DATE. However, any PARTICIPANT, whether married or unmarried, who wishes to have the PENSION continued in whole or in part after the PARTICIPANT'S death for the life of a non-spouse JOINT PENSIONER, may elect to have the applicable normal form of PENSION paid as a JOINT PENSION by giving the EMPLOYER at least 30 days' advance written notice prior to the PARTICIPANT'S ACTUAL RETIREMENT DATE. If such an election is made, the PARTICIPANT will receive a reduced BASIC or EARLY RETIREMENT PENSION for life and, upon the PARTICIPANT'S death, the non-spouse JOINT PENSIONER designated by the PARTICIPANT will receive that proportion of such reduced PENSION, up to 100 percent, which the PARTICIPANT has elected, for the remainder of the JOINT PENSIONER'S life. Non-spouse JOINT PENSIONS shall be determined in accordance with an actuarial formula which is set forth in Special Provision C. (b) Joint Pension With Spouse ------------------------- For a PARTICIPANT who is married on the ACTUAL RETIREMENT DATE, the normal form of PENSION shall be a MARITAL PENSION, reducing the amount of the PARTICIPANT'S BASIC PENSION and providing that on the PARTICIPANT'S death one-half of such MARITAL PENSION will be continued to the SPOUSE for the remainder of the SPOUSE'S life. -6- In lieu of the MARITAL PENSION, a married PARTICIPANT, by making a QUALIFIED ELECTION prior to ACTUAL RETIREMENT DATE, may elect one of the following options: (1) a JOINT PENSION with SPOUSE which provides that an amount equal to either 25, 75 or 100 percent of a reduced BASIC or EARLY RETIREMENT PENSION will, upon the PARTICIPANT'S death, be continued for the remainder of the SPOUSE'S life, or (2) a SPECIAL JOINT PENSION with SPOUSE which provides an amount of one-half or 100 percent of a reduced BASIC or EARLY RETIREMENT PENSION that, upon the PARTICIPANT'S death, will be continued for the remainder of the SPOUSE'S life. However, if the SPOUSE predeceases the PARTICIPANT, future PENSION payments will be restored to the amount of the full BASIC or EARLY RETIREMENT PENSION that the PARTICIPANT would be entitled to receive if no SPECIAL JOINT PENSION with SPOUSE had been elected. MARITAL PENSIONS and JOINT PENSIONS with SPOUSE shall be determined in accordance with an actuarial formula which is set forth in Special Provision D. Special Provision D also includes tables of factors which apply to typical options which may be elected. SPECIAL JOINT PENSIONS with SPOUSE shall also be determined in accordance with the actuarial formula which is set forth in Special Provision D, but actuarially adjusted further to reflect the value of the restoration feature. Provision D also includes tables of the factors which apply to SPECIAL JOINT PENSION options that may be elected. (c) Basic or Early Retirement Pension Terminating Upon The Death Of The ------------------------------------------------------------------- Participant ----------- Under this option, no additional PENSION payments are made to anyone after the PARTICIPANT'S death. (d) Conditions Applicable To All Forms Of Pensions ---------------------------------------------- The CONSENT of the SPOUSE is required whenever a QUALIFIED ELECTION is made which would provide benefits to a surviving SPOUSE less than those provided by a MARITAL PENSION. The SPOUSE of a PARTICIPANT may not receive a benefit under any provisions of this Section if a larger SPOUSE'S PENSION is payable under Section 11. 11. Spouse's Pension ---------------- (a) If a married PARTICIPANT dies while employed by an EMPLOYER and prior to the ACTUAL RETIREMENT DATE, or within 30 days thereafter, the PARTICIPANT's surviving SPOUSE will be eligible to receive a SPOUSE's PENSION if, at the time of the PARTICIPANT'S death, (i) the PARTICIPANT was at least 55 years of age, or (ii) the sum of the PARTICIPANT's age and years of SERVICE equaled 70 or more. (69.5 or more is rounded to 70.) The amount of the SPOUSE's PENSION is one-half of the PENSION that the PARTICIPANT would have been entitled to receive, and will be calculated as if: (1) the PARTICIPANT had elected a BASIC PENSION under Section 10(b)(3), (2) the first day of the month following the PARTICIPANT's death had been the PARTICIPANT's ACTUAL RETIREMENT DATE, and -7- (3) The PARTICIPANT had in fact retired on that date without reduction for early retirement. However, if the SPOUSE is more than 10 years younger than the PARTICIPANT, the amount of the SPOUSE's PENSION shall be reduced 1/20th of one percent for each full month in excess of 120 months' difference in their ages, except that such reduction shall not result in a SPOUSE's PENSION lower than would have been payable if the PARTICIPANT had retired as of the date of death and elected an optional form providing for continuation of 50 percent to a named JOINT PENSIONER with SPOUSE the same sex and age of the SPOUSE, under the provisions of Section 10(b)(1). The SPOUSE's PENSION is payable to the PARTICIPANT's surviving SPOUSE on the first day of the month following the PARTICIPANT's death and the first day of each month thereafter so long as the SPOUSE lives. (b) The surviving SPOUSE of a PARTICIPANT or of a former EMPLOYEE who dies prior to actual retirement date shall be entitled to receive a SPOUSE's PENSION under this Section 11(b) if, at the time of the death of the PARTICIPANT or former EMPLOYEE, (i) the PARTICIPANT or former EMPLOYEE had at least five years of SERVICE, and (ii) the surviving SPOUSE does not qualify for a SPOUSE's PENSION under Section 11(a), above. A SPOUSE's PENSION under this Section 11(b) shall be payable on the first day of the month following the later of (i) the date of death or (ii) the month in which the deceased PARTICIPANT or former EMPLOYEE would have attained his 55th birthday. By submitting an election form to the PLAN ADMINISTRATOR, a SPOUSE may elect to begin receiving a SPOUSE's PENSION at a specified later date. Unless a vested PARTICIPANT or vested former EMPLOYEE and his or her SPOUSE have elected otherwise pursuant to a QUALIFIED ELECTION, if a PARTICIPANT dies on or before age 55, the PARTICIPANT'S or FORMER EMPLOYEE'S surviving SPOUSE (if any) will receive the same benefit that would have been payable if the PARTICIPANT or former EMPLOYEE had: (1) separated from SERVICE on the date of death (or date of separation from SERVICE, if earlier), (2) survived to age 55, (3) retired with a MARITAL PENSION at age 55, (4) died on the day of retirement, and begun to receive benefit payments at the date as of which the PARTICIPANT or former EMPLOYEE would have attained age 55. Unless a surviving SPOUSE elects otherwise, the surviving SPOUSE will begin to receive payments at the date as of which the PARTICIPANT or former EMPLOYEE would have attained age 55. Benefits commencing after this date will be the ACTUARIAL EQUIVALENT of the benefit to which the surviving SPOUSE would have been entitled if benefits had commenced at this date. A PARTICIPANT's SPOUSE may not receive both a SPOUSE's PENSION under this Section and a MARITAL or JOINT PENSION under Section 10. If the PARTICIPANT dies within 30 days after the PARTICIPANT's ACTUAL RETIREMENT DATE, the SPOUSE will receive the larger of the monthly Pensions under this Section and Section 3.10, but not both. -8- 12. Withdrawal of Participant Contributions on Termination of Employment -------------------------------------------------------------------- A PARTICIPANT's contributions to the PLAN may not be withdrawn prior to ACTUAL RETIREMENT DATE or other termination of SERVICE. After a PARTICIPANT's SERVICE is terminated, the PARTICIPANT, by written notice to the PARTICIPANT's EMPLOYER at least 30 days before the date the PENSION begins, may elect to have such CONTRIBUTIONS PLUS INTEREST returned. If a PARTICIPANT elects to withdraw such CONTRIBUTIONS PLUS INTEREST, the PENSION the PARTICIPANT would otherwise be entitled to at the NORMAL or EARLY RETIREMENT DATE shall be reduced by an amount that reflects the actuarial value of the contributions withdrawn. The factors used to reduce the PENSION of a PARTICIPANT who has withdrawn his contributions shall comply with CODE Sections 411(a)(7)(D) and 411(c)(2)(B) and are contained in the table set forth in Special Provision I. 13. Death Benefits -------------- If a PARTICIPANT with contributions on deposit in the PLAN dies before receiving payments from the PLAN equal to the amount of the PARTICIPANT's CONTRIBUTIONS PLUS INTEREST, the difference between the payments made and the CONTRIBUTIONS PLUS INTEREST will be paid to the named BENEFICIARY, unless a PENSION is payable to the PARTICIPANT's surviving SPOUSE or JOINT PENSIONER. If a PENSION is payable after such PARTICIPANT's death, and if upon the death of the SPOUSE or JOINT PENSIONER the total combined amount paid to the PARTICIPANT and the SPOUSE or JOINT PENSIONER does not equal the amount of the PARTICIPANT's CONTRIBUTIONS PLUS INTEREST, the difference between the total amount paid and the PARTICIPANT's CONTRIBUTIONS PLUS INTEREST will be paid to the BENEFICIARY of the SPOUSE or JOINT PENSIONER. 14. Facility of Payment ------------------- (a) If the present value of all PENSION benefits payable under the PLAN to any individual is less than $3,500.00 as of the date of SEVERANCE FROM SERVICE or ACTUAL RETIREMENT DATE, the equivalent value shall be paid in a lump sum, as directed by the ADMINISTRATOR. For PARTICIPANTS terminating before age 55, present value means the ACTUARIAL EQUIVALENT of the normal retirement benefit commencing at NORMAL RETIREMENT DATE. For PARTICIPANTS retiring at or after age 55, present value means the ACTUARIAL EQUIVALENT of the early, normal or deferred retirement benefit commencing at ACTUAL RETIREMENT DATE. In determining the present value, the PLAN ADMINISTRATOR shall use the Unisex Mortality Table for 1984 (UP-84) and the interest rates set, as of the first day of the PLAN YEAR in which the lump sum payment is made, by the Pension Benefit Guaranty Corporation for the purpose of determining the present value of a lump sum distribution on PLAN termination. (b) If the ADMINISTRATOR determines that any individual entitled to any payment under the PLAN is physically or mentally incompetent to handle the payment and no guardian or conservator has been appointed to receive such payment, the ADMINISTRATOR may cause all payments thereafter becoming due to such individual to be applied for and on behalf of and for the benefit of such individual. Payments made pursuant to this provision shall completely discharge the EMPLOYER, the ADMINISTRATOR, the Trustee, and all fiduciaries of all further responsibility with respect to such individual. (c) If the distributee of any eligible rollover distribution (as defined below) elects to have the distribution paid directly to an eligible retirement plan (as defined below), and if the distributee specified, according to the manner specified by the PLAN, the eligible retirement plan to which such distribution is to be paid, then the distribution shall be made in the form of a direct trustee-to- -9- trustee transfer to the eligible retirement plan specified by the distributee. The trustee-to-trustee transfer shall be made available only if the distribution from the PLAN would be subject to federal income taxation. The term "eligible rollover distribution" shall mean any distribution to a PARTICIPANT or former EMPLOYEE of all or part of the balance to the credit of the PARTICIPANT or former EMPLOYEE in the PLAN. The term shall not, however, include any distribution which is one of a series of "substantially equal periodic payments" (as defined at CODE Section 402(c)(4)(A), or any distribution that is required under CODE Section 401(a)(9). The term "eligible retirement plan" means an individual retirement account described in CODE Section 408(a), an individual retirement annuity described in CODE Section 408(b) (other than an endowment contract), an annuity plan described in CODE Section 403(a), or a qualified defined contribution plan, the terms of which permit the acceptance of rollover distributions. 15. Benefits Are Not Assignable --------------------------- Except as may be required by law, a PARTICIPANT's interest in the PLAN, either before or after retirement, and that of a PARTICIPANT's SPOUSE, JOINT PENSIONER, or BENEFICIARY shall not be subject to assignment, anticipation, sale, transfer, pledge, encumbrance, or charge, whether voluntary or involuntary, and any attempt to so assign, anticipate, sell, transfer, pledge, encumber, or charge shall be void. 16. Employer Contributions ---------------------- The COMPANY shall contribute to the PLAN such amount of EMPLOYER CONTRIBUTIONS as the EMPLOYEE BENEFIT FINANCE COMMITTEE, with the advice of the actuary, shall determine is necessary to keep the PLAN funded in accordance with the Funding Policy and to satisfy any minimum funding standard required by the Internal Revenue SERVICE or the Department of Labor. The EMPLOYEE BENEFIT FINANCE COMMITTEE shall determine and charge to each EMPLOYER its share of the EMPLOYER contributions made by the COMPANY. 17. Company's Powers and Duties --------------------------- The COMPANY, acting through its Board of Directors or Executive Committee, reserves to itself the exclusive power to amend, suspend, or terminate the PLAN as provided below and to appoint and remove from time to time: (a) The individuals comprising the EMPLOYEE BENEFIT FINANCE COMMITTEE; (b) The individuals comprising the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE; (c) The EMPLOYERS whose EMPLOYEES may participate in the PLAN. (d) Except as provided in Section 20, the appropriate committees established by the COMPANY shall serve as the final review committees, under the PLAN, to determine conclusively for all parties any and all questions arising from the administration of the PLAN and shall have sole and complete discretionary authority and control to manage the operation and administration of the PLAN, including, but not limited to, the determination of all questions relating to eligibility for participation and benefits, interpretation of all PLAN provisions, determination of the amount and kind of benefits payable to any PARTICIPANT, SPOUSE or beneficiary, and construction of -10- disputed or doubtful terms. Such decisions shall be conclusive and binding on all parties and not subject to further review. All powers and duties not reserved to the COMPANY are delegated to the EMPLOYEE BENEFIT FINANCE COMMITTEE and to the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE. Action of either committee shall be by vote of a majority of the members of the committee at a meeting, or in writing without a meeting, and evidenced by the signature of any member who is so authorized by the committee. The COMPANY indemnifies each member of each committee against any personal liability or expense arising out of any action or inaction of the committee or of any member of the committee or of such individual, except that due to his own willful misconduct. 18. Funding and Investment Provisions --------------------------------- The EMPLOYEE BENEFIT FINANCE COMMITTEE appointed by the COMPANY's Board of Directors to serve at its pleasure has the express powers and duties described in this Section. (a) Appointments. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole ------------ power and duty from time to time to appoint and remove the Funding Agents, the Investment Manager, actuaries, accountants, and such other advisors and consultants as may be needed for the proper financial administration and investment of the assets of the PLAN. Supplementing such appointments, the EMPLOYEE BENEFIT FINANCE COMMITTEE may enter into appropriate agreements with each Trustee, Investment Manager or other advisors appointed under this paragraph and delegate to them appropriate powers and duties. The EMPLOYEE BENEFIT FINANCE COMMITTEE may appoint and delegate to one or more individuals the power and duty to handle the day-to-day financial administration of the PLAN. Such individuals need not be members of the committee and shall serve at the pleasure of the committee. (b) Funding Policy. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole -------------- power and duty to establish a funding policy and an investment policy and to review and revise it from time to time as the committee shall determine in its sole discretion. All EMPLOYER contributions to the PLAN shall be paid to Funding Agents which may be one or more insurance companies or corporate trustees, or to any combination thereof, as the EMPLOYEE BENEFIT FINANCE COMMITTEE may determine from time to time. These contributions, and all previous contributions of PARTICIPANTS and EMPLOYERS, together with the proceeds of their investment, shall be held and administered by these Funding Agents pursuant to the agreements between the COMPANY and the Funding Agents. All of the PLAN'S assets held by Funding Agents are available to pay benefits on behalf of all PARTICIPANTS covered by this PLAN. 19. Administration -------------- The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, appointed by the COMPANY's Board of Directors to serve at its pleasure, is the ADMINISTRATOR of the PLAN and is responsible for the overall administration of the PLAN. The ADMINISTRATOR has the sole power and duty to establish, and from time to time revise, such rules and regulations as may be necessary to administer the PLAN in a nondiscriminatory manner for the exclusive benefit of PARTICIPANTS and all other persons entitled to benefits under the PLAN. The ADMINISTRATOR shall also maintain such records and make such computations, interpretations, and decisions as may be necessary or desirable for the proper administration of the PLAN. The ADMINISTRATOR may demand such proof of age of any PARTICIPANT, JOINT PENSIONER, or SPOUSE as it considers necessary, and it may adjust any PENSION or other payment or payments thereafter due under the PLAN as it deems appropriate and equitable to correct any factual error or misrepresentation. The ADMINISTRATOR shall maintain for PARTICIPANTS' inspection copies of the PLAN, trust agreement, -11- investment policy, each agreement with an Investment Manager, the latest annual report, PLAN description, and summary description, and any amendments or changes in any of these documents. On written request, PARTICIPANTS may obtain from the ADMINISTRATOR a copy of any of these documents at a cost established by the ADMINISTRATOR from time to time. All expenses of administration may be paid out of the PLAN's assets upon authorization by the appropriate committee, unless paid by the COMPANY. Such expenses shall include any expenses incident to the functioning of the ADMINISTRATOR, including, but not limited to, fees for accountants, actuaries, counsel, investment managers and other specialists and their agents, and other costs of administering the PLAN. 20. Claims Procedure ---------------- If a claim is denied in whole or in part, the ADMINISTRATOR shall furnish to the claimant a written notice setting forth: (a) Specific reason(s) for the denial, (b) The PLAN provision(s) on which the denial is based, (c) A description of any material or information, if any, necessary for the claimant to perfect the claim, and an explanation of why such material or information is necessary, and (d) Information concerning the steps to be taken if claimant wishes to submit a claim for review. The above information shall be furnished to the claimant within 90 days after the claim is received by the ADMINISTRATOR. If a claimant is not satisfied with the written notice described in the preceding paragraph, such claimant may request a full and fair review by so notifying the ADMINISTRATOR in writing within 90 days after receiving such notice. If a review is requested the claimant shall also be entitled, upon written request, to review pertinent documents and to submit issues and comments in writing. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall furnish the claimant with a written final decision within 60 days after receipt of the request for review. 21. Qualified Domestic Relations Orders ----------------------------------- The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall apply the provisions of this section with regard to a Domestic Relations Order (as defined below) to the extent not inconsistent with Section 414(p) of the CODE. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall establish procedures, consistent with Section 414(p) of the CODE, to determine the qualified status of any Domestic Relations Order, to administer distributions under any Qualified Domestic Relations Order (as defined below), and to provide to the PARTICIPANT and the Alternate Payee(s) (as defined below) all notices required under Section 414(p) of the CODE with respect to any Domestic Relations Order. Within a reasonable period of time after the receipt of a Domestic Relations Order (or any modification thereof), the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall determine whether such order is a Qualified Domestic Relations Order. For purposes of this section: -12- (a) Alternate Payee shall mean any SPOUSE, former SPOUSE, child, or other dependent of a PARTICIPANT who is recognized by a Domestic Relations Order as having a right to receive all, or a portion of, the benefits payable under the PLAN with respect to such PARTICIPANT. (b) Domestic Relations Order shall mean any judgment, decree, or order (including approval of a property settlement) which: (1) relates to the provision of child support, alimony payments, or marital property rights to a SPOUSE, former SPOUSE, child, or other dependent of a PARTICIPANT; and (2) is made pursuant to a state domestic relations law (including a community property law). (c) Qualified Domestic Relations Order shall mean a Domestic Relations Order which meets the requirements of Section 414(p)(1) of the CODE. 22. Amendment, Termination, and Merger ---------------------------------- The COMPANY hopes and expects to continue this PLAN indefinitely but, because future conditions cannot be foreseen, its Board of Directors necessarily reserves the right to change, suspend, or terminate the PLAN at any time. However, no change can be made which would adversely affect the rights which any PARTICIPANT, retired EMPLOYEE, former EMPLOYEE, SPOUSE, JOINT PENSIONER, or BENEFICIARY may then have with respect to funds then being held under the PLAN by any Funding Agent or permit any such funds to revert to an EMPLOYER or be used for any purpose except for the exclusive benefit of PARTICIPANTS, Pensioners, and their SPOUSES, JOINT PENSIONERS, and BENEFICIARIES. In the event the PLAN is partially terminated, terminated or suspended, all EMPLOYER contributions with respect to the affected PARTICIPANTS shall cease and the accrued benefits of the affected PARTICIPANTS shall become nonforfeitable. Subject to applicable requirements of notice to the Pension Benefit Guaranty Corporation governing termination of PENSION benefit plans, the funds held under the PLAN by the Funding Agents shall be applied to provide the PENSIONS, benefits and refunds accrued to the date of termination or suspension and to the extent funded. Such provision shall be made in such manner as the ADMINISTRATOR shall direct, including the purchase of paid-up annuities, distribution in installments, or lump- sum distributions and shall be in conformance with the requirements and priorities established by various governmental agencies to oversee PLAN suspensions and terminations. Notwithstanding any contrary provisions of the PLAN, after its termination and after all liabilities for the payment of PENSIONS, benefits and refunds to the date of termination have been satisfied or provided for in accordance with the foregoing, any funds remaining with the Funding Agents shall be returned to the COMPANY. This PLAN shall not be merged into or consolidated with any other PLAN, nor shall any of its assets or liabilities be transferred to any other PLAN, unless each PARTICIPANT in this PLAN would (if such other PLAN then terminated) receive a benefit immediately after the merger, consolidation, or transfer which is equal to or greater than the benefit such PARTICIPANT would have been entitled to receive immediately before the merger, consolidation, or transfer (if this PLAN had then terminated). 23. Definitions and Cross-References -------------------------------- Actual Retirement Date: The date of one of the following, whichever is applicable: - ---------------------- (a) The date on which an EARLY RETIREMENT PENSION begins, or
-13- (b) The PARTICIPANT'S Normal Retirement Date, or (c) If the PARTICIPANT continues in the employ of an EMPLOYER beyond Normal Retirement Date, the first day of the month following termination of SERVICE. Actuarial Equivalent or For purposes of determining actuarially equivalent benefits under Actuarial Equivalence: this PLAN, the provisions of Special Provision D shall apply. - --------------------- Administrator: The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE referred to in - ------------- Section 20, 201 Mission Street, 19th Floor, Mail Code P19A, P.O. Box 770000, San Francisco, California 94177. Basic Monthly Salary: The rate of pay used to calculate the monthly earnings from an - -------------------- EMPLOYER, adjusted to reflect nuclear premium payments, if any, but excluding payments from the LONG TERM DISABILITY PLAN and all other bonuses, premiums, special allowances, overtime pay, or any other payments. For a PARTICIPANT who is paid weekly or bi-weekly, BASIC MONTHLY SALARY shall be equal to the PARTICIPANT'S weekly pay rate multiplied by 4.33, rounded up to the nearest Five Dollars. For purposes of calculating a PARTICIPANT'S accrued benefit under this PLAN, the compensation limitations of CODE Section 401(a)(17) shall be applicable. For purposes of calculating accruals after December 31, 1993, the amount of a PARTICIPANT'S compensation taken into account shall not exceed $150,000, or such greater amount permitted by the Secretary of the Treasury. For purposes of calculating accruals after December 31, 1988, and before January 1, 1994, the amount of compensation taken into account shall not exceed $200,000, or such greater amount permitted by the Secretary of the Treasury. Unless otherwise provided under this PLAN, each CODE Section 401(a)(17) employee's accrued benefit under this PLAN will be the greater of the accrued benefit determined for the employee under 1 or 2 below: 1. The employee's accrued benefit determined with respect to the benefit formula applicable for the PLAN YEAR beginning on or after January 1, 1994, as applied to the employee's total years of SERVICE taken into account under the PLAN for the purposes of benefit accruals, or 2. The sum of: (a) the employee's accrued benefit as of the last day of the last PLAN YEAR beginning before January 1, 1994, frozen in accordance with CODE Section 1.401(a)(4)-13, and (b) the employee's accrued benefit determined under the benefit formula applicable for the PLAN YEAR beginning on or after January 1, 1994, as
-14- applied to the employee's years of service credited to the employee for PLAN YEARS beginning on or after January 1, 1994, for purposes of benefit accrual. A CODE Section 401(a)(17) employee means an employee whose current accrued benefit as of a date on or after the first day of the first PLAN YEAR beginning on or after January 1, 1994, is based on compensation for a year beginning prior to the first day of the first PLAN YEAR beginning on or after January 1, 1994, that exceeded $150,000. Basic Pension: The PENSION due at the later of NORMAL RETIREMENT DATE or ACTUAL - ------------- RETIREMENT DATE and unreduced because of marital status. See Sections 6 and 10b. Beneficiary: The individual or individuals or intervivos trust or trusts that - ----------- a PARTICIPANT, SPOUSE, or JOINT PENSIONER designates to receive any death benefits due pursuant to Section 13. Such designation must be made on forms provided by the EMPLOYER and filed with the ADMINISTRATOR. A PARTICIPANT, or the PARTICIPANT'S SPOUSE (if receiving a SPOUSE's PENSION), may change the designated Beneficiary from time to time by filing an appropriate written notice with the ADMINISTRATOR. In the absence of a designation, the Beneficiary shall be the estate of the person entitled to make the designation. There were no employee contributions after December 31, 1972. Therefore, EMPLOYEES who first became Participants in the PLAN after said date were not required or permitted to name a Beneficiary. Break in Service: A BREAK IN SERVICE occurs 12 months after the SEVERANCE FROM - ---------------- SERVICE DATE if during such 12-month period an EMPLOYEE does not work for an EMPLOYER. Once a Break in Service occurs, it continues until an EMPLOYEE is reemployed by an EMPLOYER. Code: CODE shall mean the Internal Revenue CODE of 1986, as amended - ---- from time to time. Company: Pacific Gas and Electric Company. - ------- Consent: The CONSENT by a SPOUSE that is required for a QUALIFIED - ------- ELECTION. Any such CONSENT shall be effective only with respect to such SPOUSE. A CONSENT permitting designation by the PARTICIPANT without further CONSENT from the SPOUSE must acknowledge that the SPOUSE has the right to limit CONSENT to a specific BENEFICIARY and also to a specific benefit form, and that the SPOUSE voluntarily elects to relinquish either or both of such rights. A revocation of a prior QUALIFIED ELECTION may be made by a PARTICIPANT without the CONSENT of the SPOUSE at any time prior to the commencement of benefits. An unlimited number of revocations shall be permitted. No CONSENT obtained under this provision shall be valid unless the PARTICIPANT has received proper
-15- NOTICE. Contributions Plus Interest: The cumulative total of contributions made by a PARTICIPANT to - --------------------------- the PLAN under Section 13; paragraph (b) of Special Provision F; and to the COMPANY's Retirement PLAN as it existed before 1969, plus interest at two percent per year on a PARTICIPANT's contributions made after 1953, compounded annually to 1976, together with interest at five percent compounded annually after 1975 on all contributions and previous interest. Credited Service: See Special Provision F. - ---------------- Early Retirement Date: See Section 7. - --------------------- Early Retirement Pension: See Section 7. - ------------------------- Employee: An EMPLOYEE of an EMPLOYER who is not covered by a collective - -------- bargaining agreement. A "leased employee," as defined in Section 414(n) of the CODE, shall not be considered an EMPLOYEE eligible to become a PARTICIPANT in the PLAN. Notwithstanding any other provisions in the PLAN, solely for purposes of CODE Section 414(n)(3), the term EMPLOYEE shall, to the extent required by CODE Section 414, include leased EMPLOYEES. Employee Benefit The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE referred to in Administrative Committee: Section 19. - ------------------------ The Employee Benefit The EMPLOYEE BENEFIT FINANCE COMMITTEE referred to in Section 18. Finance Committee: - ----------------- Employer: Pacific Gas and Electric Company, Pacific Service Employees - -------- Association, and any other company, association, or credit union designated by the Board of Directors as eligible to participate in this PLAN is an EMPLOYER. Joint Pension: See Section 10. - ------------- Joint Pensioner: The individual designated by a PARTICIPANT upon the election of a - --------------- JOINT PENSION who will be entitled upon the PARTICIPANT's death to receive a PENSION, as explained in Section 10. Long Term Disability Plan: Part B of the Pacific Gas and Electric Company's Group Life - ------------------------- Insurance and Long Term Disability Plan. Marital Pension: See Section 10(b). - --------------- Maximum Pension: See Special Provision H. - --------------- Normal Retirement Date: The first of the month following the PARTICIPANT's 65th birthday. - ---------------------- Notice: The NOTICE that is required by this PLAN pursuant to CODE - ------
-16- Section 417 in order to waive the MARITAL PENSION. In the case of MARITAL PENSION, the PLAN shall provide to each PARTICIPANT, and to each vested former EMPLOYEE, no less than 30 days and no more than 90 days prior to the annuity starting date a written explanation of: (i) the terms and conditions of the MARITAL PENSION, (ii) the right to make and the effect of an election to waive the MARITAL PENSION, (iii) the rights of the PARTICIPANT's or the former EMPLOYEE'S SPOUSE, (iv) the right to make an election to waive the MARITAL PENSION and the effect of revoking a previous election to waive the MARITAL PENSION, and (v) the relative values of the various optional forms of benefit under the PLAN. Participant: See Section 2. - ----------- Part-Time Employee: An EMPLOYEE whose regularly scheduled work week is less than 40 - ------------------ hours. Pension: Retirement income payable under the PLAN. - ------- Plan: The Company's Retirement Plan as amended, revised and set forth - ---- herein. Plan Year: The PLAN YEAR shall be the calendar year which shall also be the - --------- limitation year for purposes of applying the annual benefit limitations of CODE Section 415. Qualified Election: An election qualifying under CODE Section 417(a) to waive either, - ------------------ or both, of the 50 percent spousal survivor annuities that are based on the MARITAL PENSION and that are described in Sections 10(b) or 11(b) of the PLAN. Any such waiver shall not be considered a QUALIFIED ELECTION unless: (a) the PARTICIPANT'S SPOUSE furnishes a written CONSENT to the election, (b) the election designates a specific alternate BENEFICIARY, including any class of BENEFICIARIES or any contingent BENEFICIARIES, which may not be changed without spousal CONSENT (or the SPOUSE expressly permits designations by the PARTICIPANT without any further spousal CONSENT, (c) the SPOUSE'S CONSENT acknowledges the effect of the election, and (d) the SPOUSE'S CONSENT is witnessed by a PLAN representative or a notary public. A PARTICIPANT'S waiver of the survivor annuity will not constitute a QUALIFIED ELECTION unless the form of benefit payment may not be changed without spousal CONSENT, or the SPOUSE expressly permits designations by the PARTICIPANT without any further spousal CONSENT. If it is established to the satisfaction of the PLAN representative that such written CONSENT may not be obtained because there is no SPOUSE or the SPOUSE cannot be located, then a waiver will be deemed a QUALIFIED ELECTION. Service: For full-time EMPLOYEES, the period of time commencing with the - ------- first day of work for an EMPLOYER and ending on PARTICIPANT's SEVERANCE FROM SERVICE Date. For
-17- periods of PART-TIME and intermittent employment, SERVICE for purposes of benefit accrual is prorated based on the ratio of actual hours worked in the calendar year to the full-time equivalent (2,080 per calendar year) rounded to the nearest month. Such proration is applicable for any employment period beginning with initiation of PART-TIME or intermittent status on or after January 1, 1991, and ending on the earlier of Participant's return to full time status or the PARTICIPANT'S SEVERANCE FROM SERVICE DATE. The method of computing SERVICE is described in Section 3. Severance from Service Date: (i) The date prior to NORMAL RETIREMENT DATE on which an EMPLOYEE quits, retires, - --------------------------- is discharged or dies, or the ACTUAL RETIREMENT DATE; or (ii) The first anniversary of the first date of a period in which a PARTICIPANT remains absent from work for an EMPLOYER for any reason other than a quit, retirement, discharge, or death. For the purpose of determining the Severance from SERVICE Date, the following periods shall not be considered as absences from work for an EMPLOYER: (a) Absence on a leave of absence authorized by the EMPLOYER. (b) Absence because of illness or injury so long as the PARTICIPANT is entitled to receive sick leave pay or is entitled to receive benefits under the provisions of the Voluntary Wage Benefit Plan, a state disability plan, Part B of the Group Life Insurance and Long Term Disability Plan, or a Workers' Compensation Law. (c) Absence for military service or service in the Merchant Marines so long as reemployment rights are protected by law. (d) Absence caused by layoff for lack of work of less than 12 continuous months for a PARTICIPANT who has less than five years of SERVICE, or 24 continuous months for a PARTICIPANT who has five years or more of SERVICE. Special Joint Pension: See Section 10. - --------------------- Spouse: (a) If a PARTICIPANT dies in SERVICE, SPOUSE shall mean the - ------ PARTICIPANT's wife or husband at the time of the PARTICIPANT's death. (b) If a PARTICIPANT dies after ACTUAL RETIREMENT DATE, SPOUSE shall means the PARTICIPANT's wife or husband at the time of the PARTICIPANT's Actual Retirement.
-18- Spouse's Pension: See Section 11. - ----------------
-19- SPECIAL PROVISION A Payment of all PENSIONS to PARTICIPANTS which commenced before January 1, 1969, under the Retirement Plan of the COMPANY, its Past Service Plan, its Supplemental Benefits and under any applicable retirement plan of a predecessor company shall continue to be made under the PLAN, without regard to the separate sources from which such pensions were previously paid. SPECIAL PROVISION B EARLY RETIREMENT REDUCTIONS IN PERCENTAGE POINTS ------------------------------------------------ Years Of Service At Early Retirement Date -----------------------------------------
Age at Less Than 15 But Less 25 But Less 30 Years Retirement 15 Years Than 25 Years Than 30 Years And Above - ------------ --------- ------------- ------------- --------- 64 3 0 0 0 63 6 0 0 0 62 9 0 0 0 61 12 3 3 0 60 15 6 6 0 59 18 10 9 6 58 21 14 12 9 57 24 18 15 12 56 27 22 18 15 55 30 26 21 18
-20- SPECIAL PROVISION C JOINT PENSION WITH NON-SPOUSE (Entire Provision Amended 1/1/88) The amount of non-spouse JOINT PENSION shall be determined by the use of Actuarial Tables which provide 12%, 16%, 25%, 33-1/3%, 50%, 66-2/3%, 75% and 100% of the JOINT PENSION to a non-spouse JOINT PENSIONER who survives the death of the PARTICIPANT. Partial Actuarial Tables of 50% and 100% have been attached. The following tables illustrate the factors to be applied for typical options which may be elected for 50% and 100%. EXAMPLE: Assume the PARTICIPANT is age 62 and elects a 50% or 100% option with a non-spouse age 50. Also assume that the PARTICIPANT's BASIC PENSION is $1,000 per month. Non- Non- Non-Spouse's Pension Spouse's Option Basic Reduced Spouse's In Event of Option Factor Pension Pension Portion Participant's Death - --------- ------ ------- ------- --------- -------------------- 50% .861 X $1,000. = $861. X .50 = $430.50 100% .756 X $1,000. = $756. X 1.00 = $756.00
Tables for 12%, 16%, 33-1/3%, 66-2/3%, or 75% are available upon request. Tables for Beneficiary's Age at Pensioner's Retirement of less than 25 years or greater than 84 years are also available upon request. -21-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 25 .844 .836 .827 .817 .807 .797 .786 .775 .763 .751 .738 .725 .711 .697 .682 .667 25 26 .847 .838 .829 .819 .809 .799 .788 .777 .765 .753 .740 .727 .713 .699 .684 .669 26 27 .849 .840 .831 .821 .811 .801 .790 .779 .767 .755 .742 .729 .715 .701 .686 .671 27 28 .851 .842 .833 .824 .814 .803 .793 .781 .769 .757 .745 .731 .718 .703 .689 .674 28 29 .853 .844 .835 .826 .816 .806 .795 .784 .772 .760 .747 .734 .720 .706 .691 .676 29 30 .855 .847 .838 .828 .818 .808 .797 .786 .774 .762 .750 .736 .723 .708 .694 .679 30 31 .858 .849 .840 .831 .821 .811 .800 .789 .777 .765 .752 .739 .725 .711 .696 .681 31 32 .860 .852 .843 .833 .824 .813 .803 .792 .780 .768 .755 .742 .728 .714 .699 .684 32 33 .863 .854 .846 .836 .826 .816 .806 .794 .783 .771 .758 .745 .731 .717 .702 .687 33 34 .866 .857 .848 .839 .829 .819 .809 .797 .786 .774 .761 .748 .734 .720 .705 .690 34 35 .868 .860 .851 .842 .832 .822 .812 .801 .789 .777 .764 .751 .737 .723 .708 .693 35 36 .871 .863 .854 .845 .835 .825 .815 .804 .792 .780 .768 .754 .741 .727 .712 .697 36 37 .874 .866 .857 .848 .839 .829 .818 .807 .796 .784 .771 .758 .744 .730 .715 .700 37 38 .877 .869 .860 .851 .842 .832 .821 .811 .799 .787 .775 .761 .748 .734 .719 .704 38 39 .880 .872 .864 .855 .845 .835 .825 .814 .803 .791 .778 .765 .752 .737 .723 .708 39 40 .884 .875 .867 .858 .849 .839 .829 .818 .806 .795 .782 .769 .756 .741 .727 .712 40 41 .887 .879 .870 .862 .852 .843 .832 .822 .810 .798 .786 .773 .760 .746 .731 .716 41 42 .890 .882 .874 .865 .856 .846 .836 .826 .814 .803 .790 .777 .764 .750 .735 .720 42 43 .893 .886 .877 .869 .860 .850 .840 .830 .818 .807 .794 .782 .768 .754 .740 .725 43 44 .897 .889 .881 .873 .864 .854 .844 .834 .823 .811 .799 .786 .773 .759 .744 .729 44 45 .900 .893 .885 .876 .868 .858 .848 .838 .827 .816 .803 .791 .777 .764 .749 .734 45 46 .904 .896 .889 .880 .872 .862 .853 .842 .832 .820 .808 .795 .782 .768 .754 .739 46 47 .907 .900 .892 .884 .876 .867 .857 .847 .836 .825 .813 .800 .787 .774 .759 .744 47 48 .911 .904 .896 .888 .880 .871 .861 .851 .841 .830 .818 .805 .792 .779 .764 .750 48 49 .914 .907 .900 .892 .884 .875 .866 .856 .846 .835 .823 .811 .798 .784 .770 .755 49
-22-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 50 .918 .911 .904 .896 .888 .880 .870 .861 .850 .840 .828 .816 .803 .790 .775 .761 50 51 .921 .915 .908 .900 .892 .884 .875 .866 .855 .845 .833 .821 .808 .795 .781 .767 51 52 .925 .918 .912 .904 .897 .888 .880 .870 .860 .850 .839 .827 .814 .801 .787 .773 52 53 .928 .922 .916 .908 .901 .893 .884 .875 .865 .855 .844 .832 .820 .807 .793 .779 53 54 .932 .926 .919 .913 .905 .897 .889 .880 .870 .860 .849 .838 .826 .813 .799 .785 54 55 .935 .929 .923 .917 .909 .902 .894 .885 .876 .866 .855 .844 .832 .819 .806 .792 55 56 .938 .933 .927 .921 .914 .906 .898 .890 .881 .871 .861 .849 .838 .825 .812 .798 56 57 .942 .936 .931 .925 .918 .911 .903 .895 .886 .876 .866 .855 .844 .831 .819 .805 57 58 .945 .940 .934 .928 .922 .915 .908 .900 .891 .882 .872 .861 .850 .838 .825 .812 58 59 .948 .943 .938 .932 .926 .920 .912 .905 .896 .887 .878 .867 .856 .844 .832 .819 59 60 .951 .947 .942 .936 .930 .924 .917 .910 .902 .893 .883 .873 .863 .851 .839 .826 60 61 .954 .950 .945 .940 .934 .928 .922 .914 .907 .898 .889 .879 .869 .858 .846 .833 61 62 .957 .953 .948 .944 .938 .932 .926 .919 .912 .904 .895 .885 .875 .864 .853 .840 62 63 .960 .956 .952 .947 .942 .937 .931 .924 .917 .909 .901 .891 .882 .871 .860 .848 63 64 .963 .959 .955 .951 .946 .941 .935 .929 .922 .914 .906 .897 .888 .878 .867 .855 64 65 .965 .962 .958 .954 .949 .944 .939 .933 .927 .920 .912 .903 .894 .884 .874 .862 65 66 .968 .965 .961 .957 .953 .948 .943 .938 .931 .925 .917 .909 .900 .891 .881 .870 66 67 .970 .967 .964 .960 .956 .952 .947 .942 .936 .930 .923 .915 .907 .897 .888 .877 67 68 .972 .970 .967 .963 .960 .955 .951 .946 .940 .934 .928 .920 .913 .904 .894 .884 68 69 .975 .972 .969 .966 .963 .959 .955 .950 .945 .939 .933 .926 .918 .910 .901 .891 69 70 .977 .974 .972 .969 .966 .962 .958 .954 .949 .944 .938 .931 .924 .916 .908 .898 70 71 .979 .976 .974 .971 .968 .965 .961 .957 .953 .948 .942 .936 .930 .922 .914 .905 71 72 .980 .978 .976 .974 .971 .968 .965 .961 .957 .952 .947 .941 .935 .928 .920 .912 72 73 .982 .980 .978 .976 .973 .971 .968 .964 .960 .956 .951 .946 .940 .933 .926 .918 73 74 .984 .982 .980 .978 .976 .973 .970 .967 .964 .960 .955 .950 .945 .939 .932 .925 74
-23-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 75 .985 .984 .982 .980 .978 .976 .973 .970 .967 .963 .959 .954 .949 .944 .937 .931 75 76 .987 .985 .984 .982 .980 .978 .976 .973 .970 .966 .963 .958 .954 .948 .943 .936 76 77 .988 .987 .985 .984 .982 .980 .978 .975 .973 .970 .966 .962 .958 .953 .948 .942 77 78 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .966 .962 .957 .952 .947 78 79 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .957 .952 79 80 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .956 80 81 .992 .991 .990 .989 .988 .987 .986 .984 .982 .980 .978 .975 .972 .969 .965 .961 81 82 .993 .992 .991 .991 .990 .988 .987 .986 .984 .982 .980 .978 .975 .972 .968 .964 82 83 .994 .993 .992 .992 .991 .990 .989 .987 .986 .984 .982 .980 .978 .975 .972 .968 83 84 .995 .994 .993 .993 .992 .991 .990 .989 .987 .986 .984 .982 .980 .978 .975 .972 84
-24-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 25 .667 .652 .636 .620 .603 .586 .569 .551 .533 .515 .497 .479 .461 .442 .424 .406 25 26 .669 .654 .638 .622 .605 .588 .571 .553 .535 .517 .499 .481 .462 .444 .426 .407 26 27 .671 .656 .640 .624 .607 .590 .573 .555 .537 .519 .501 .483 .464 .446 .427 .409 27 28 .674 .658 .642 .626 .609 .592 .575 .557 .539 .521 .503 .485 .466 .448 .429 .411 28 29 .676 .661 .645 .628 .612 .595 .577 .560 .542 .524 .505 .487 .468 .450 .431 .413 29 30 .679 .663 .647 .631 .614 .597 .580 .562 .544 .526 .507 .489 .470 .452 .433 .414 30 31 .681 .666 .650 .633 .617 .600 .582 .564 .546 .528 .510 .491 .473 .454 .435 .417 31 32 .684 .669 .653 .636 .619 .602 .585 .567 .549 .531 .512 .494 .475 .456 .437 .419 32 33 .687 .671 .655 .639 .622 .605 .588 .570 .552 .533 .515 .496 .477 .459 .440 .421 33 34 .690 .675 .659 .642 .625 .608 .591 .573 .555 .536 .518 .499 .480 .461 .442 .423 34 35 .693 .678 .662 .645 .628 .611 .594 .576 .558 .539 .520 .502 .483 .464 .445 .426 35 36 .697 .681 .665 .649 .632 .614 .597 .579 .561 .542 .524 .505 .486 .467 .448 .429 36 37 .700 .685 .669 .652 .635 .618 .600 .582 .564 .545 .527 .508 .489 .470 .451 .431 37 38 .704 .688 .672 .656 .639 .621 .604 .586 .567 .549 .530 .511 .492 .473 .454 .434 38 39 .708 .692 .676 .659 .643 .625 .607 .589 .571 .552 .534 .515 .495 .476 .457 .438 39 40 .712 .696 .680 .663 .647 .629 .611 .593 .575 .556 .537 .518 .499 .480 .460 .441 40 41 .716 .700 .684 .668 .651 .633 .616 .597 .579 .560 .541 .522 .503 .483 .464 .444 41 42 .720 .705 .689 .672 .655 .638 .620 .602 .583 .564 .545 .526 .507 .487 .468 .448 42 43 .725 .709 .693 .677 .660 .642 .624 .606 .588 .569 .550 .530 .511 .491 .472 .452 43 44 .729 .714 .698 .681 .664 .647 .629 .611 .592 .573 .554 .535 .515 .495 .476 .456 44 45 .734 .719 .703 .686 .669 .652 .634 .616 .597 .578 .559 .539 .520 .500 .480 .460 45 46 .739 .724 .708 .691 .674 .657 .639 .621 .602 .583 .564 .544 .524 .505 .485 .465 46 47 .744 .729 .713 .697 .680 .662 .644 .626 .607 .588 .569 .549 .529 .509 .489 .469 47 48 .750 .734 .718 .702 .685 .668 .650 .631 .613 .594 .574 .554 .535 .515 .494 .474 48 49 .755 .740 .724 .708 .691 .673 .655 .637 .618 .599 .580 .560 .540 .520 .500 .479 49
-25-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 50 .761 .746 .730 .713 .697 .679 .661 .643 .624 .605 .585 .566 .546 .525 .505 .485 50 51 .767 .752 .736 .720 .703 .685 .667 .649 .630 .611 .591 .572 .551 .531 .511 .490 51 52 .773 .758 .742 .726 .709 .692 .674 .655 .637 .617 .598 .578 .558 .537 .517 .496 52 53 .779 .764 .748 .732 .715 .698 .680 .662 .643 .624 .604 .584 .564 .543 .523 .502 53 54 .785 .770 .755 .739 .722 .705 .687 .669 .650 .631 .611 .591 .571 .550 .529 .508 54 55 .792 .777 .762 .746 .729 .712 .694 .676 .657 .638 .618 .598 .578 .557 .536 .515 55 56 .798 .784 .768 .753 .736 .719 .701 .683 .664 .645 .625 .605 .585 .564 .543 .522 56 57 .805 .790 .775 .760 .743 .726 .709 .691 .672 .653 .633 .613 .592 .571 .550 .529 57 58 .812 .798 .783 .767 .751 .734 .717 .699 .680 .661 .641 .621 .600 .579 .558 .537 58 59 .819 .805 .790 .775 .759 .742 .725 .707 .688 .669 .649 .629 .608 .587 .566 .545 59 60 .826 .812 .798 .783 .767 .750 .733 .715 .696 .677 .658 .638 .617 .596 .575 .553 60 61 .833 .820 .805 .790 .775 .758 .741 .724 .705 .686 .667 .646 .626 .605 .584 .562 61 62 .840 .827 .813 .799 .783 .767 .750 .733 .714 .695 .676 .656 .635 .614 .593 .571 62 63 .848 .835 .821 .807 .792 .776 .759 .742 .724 .705 .685 .665 .645 .624 .602 .581 63 64 .855 .843 .829 .815 .800 .785 .768 .751 .733 .715 .695 .675 .655 .634 .612 .591 64 65 .862 .850 .837 .824 .809 .794 .778 .761 .743 .725 .705 .686 .665 .644 .623 .601 65 66 .870 .858 .845 .832 .818 .803 .787 .770 .753 .735 .716 .696 .676 .655 .634 .612 66 67 .877 .866 .854 .841 .827 .812 .797 .780 .763 .745 .727 .707 .687 .666 .645 .623 67 68 .884 .873 .862 .849 .836 .821 .806 .790 .774 .756 .738 .718 .698 .678 .657 .635 68 69 .891 .881 .870 .858 .845 .831 .816 .801 .784 .767 .749 .730 .710 .690 .668 .647 69 70 .898 .888 .878 .866 .853 .840 .826 .811 .795 .778 .760 .741 .722 .702 .681 .659 70 71 .905 .896 .885 .874 .862 .849 .836 .821 .805 .789 .771 .753 .734 .714 .693 .672 71 72 .912 .903 .893 .882 .871 .859 .845 .831 .816 .800 .783 .765 .746 .727 .706 .685 72 73 .918 .910 .900 .890 .879 .868 .855 .841 .826 .811 .794 .777 .759 .739 .719 .698 73 74 .925 .917 .908 .898 .888 .876 .864 .851 .837 .822 .806 .789 .771 .752 .732 .712 74
-26-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 75 .931 .923 .915 .906 .896 .885 .873 .861 .847 .833 .817 .801 .784 .765 .746 .726 75 76 .936 .929 .921 .913 .904 .893 .882 .870 .858 .844 .829 .813 .796 .778 .759 .740 76 77 .942 .935 .928 .920 .911 .902 .891 .880 .868 .854 .840 .825 .808 .791 .773 .754 77 78 .947 .941 .934 .927 .918 .909 .900 .889 .877 .865 .851 .836 .821 .804 .786 .768 78 79 .952 .946 .940 .933 .925 .917 .908 .898 .887 .875 .862 .848 .833 .817 .800 .782 79 80 .956 .951 .945 .939 .932 .924 .916 .906 .896 .885 .872 .859 .845 .829 .813 .795 80 81 .961 .956 .951 .945 .938 .931 .923 .914 .905 .894 .883 .870 .856 .842 .826 .809 81 82 .964 .960 .955 .950 .944 .937 .930 .922 .913 .903 .892 .881 .868 .854 .839 .823 82 83 .968 .964 .960 .955 .950 .943 .937 .929 .921 .912 .902 .891 .879 .866 .851 .836 83 84 .972 .968 .964 .960 .955 .949 .943 .936 .928 .920 .911 .900 .889 .877 .863 .849 84
-27-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 25 .731 .718 .704 .691 .676 .662 .647 .632 .617 .601 .585 .568 .551 .535 .518 .500 25 26 .734 .721 .707 .694 .679 .665 .650 .635 .619 .603 .587 .571 .554 .537 .520 .503 26 27 .737 .724 .710 .697 .683 .668 .653 .638 .622 .606 .590 .574 .557 .540 .523 .505 27 28 .740 .727 .714 .700 .686 .671 .656 .641 .625 .609 .593 .576 .560 .543 .525 .508 28 29 .744 .731 .717 .703 .689 .675 .660 .644 .629 .613 .596 .580 .563 .545 .528 .511 29 30 .747 .734 .721 .707 .693 .678 .663 .648 .632 .616 .599 .583 .566 .549 .531 .514 30 31 .751 .738 .725 .711 .696 .682 .667 .651 .636 .619 .603 .586 .569 .552 .534 .517 31 32 .755 .742 .728 .715 .700 .686 .671 .655 .639 .623 .607 .590 .573 .555 .538 .520 32 33 .759 .746 .732 .719 .704 .690 .675 .659 .643 .627 .610 .593 .576 .559 .541 .523 33 34 .763 .750 .737 .723 .708 .694 .679 .663 .647 .631 .614 .597 .580 .562 .545 .527 34 35 .768 .754 .741 .727 .713 .698 .683 .667 .651 .635 .618 .601 .584 .566 .549 .531 35 36 .772 .759 .746 .732 .717 .703 .687 .672 .656 .639 .623 .606 .588 .570 .553 .535 36 37 .777 .764 .750 .736 .722 .707 .692 .677 .661 .644 .627 .610 .593 .575 .557 .539 37 38 .781 .768 .755 .741 .727 .712 .697 .681 .665 .649 .632 .615 .597 .579 .561 .543 38 39 .786 .773 .760 .746 .732 .717 .702 .687 .670 .654 .637 .620 .602 .584 .566 .548 39 40 .791 .779 .765 .751 .737 .723 .707 .692 .676 .659 .642 .625 .607 .589 .571 .552 40 41 .797 .784 .771 .757 .743 .728 .713 .697 .681 .665 .648 .630 .612 .594 .576 .557 41 42 .802 .789 .776 .762 .748 .734 .719 .703 .687 .670 .653 .636 .618 .600 .581 .563 42 43 .807 .795 .782 .768 .754 .740 .724 .709 .693 .676 .659 .642 .624 .605 .587 .568 43 44 .813 .800 .788 .774 .760 .746 .731 .715 .699 .682 .665 .648 .630 .611 .593 .574 44 45 .819 .806 .793 .780 .766 .752 .737 .721 .705 .689 .671 .654 .636 .618 .599 .580 45 46 .824 .812 .799 .786 .773 .758 .743 .728 .712 .695 .678 .660 .642 .624 .605 .586 46 47 .830 .818 .806 .793 .779 .765 .750 .734 .718 .702 .685 .667 .649 .631 .612 .593 47 48 .836 .824 .812 .799 .785 .771 .757 .741 .725 .709 .692 .674 .656 .638 .619 .600 48 49 .842 .830 .818 .805 .792 .778 .764 .748 .732 .716 .699 .681 .663 .645 .626 .607 49
-28-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 50 .848 .837 .825 .812 .799 .785 .771 .756 .740 .723 .706 .689 .671 .652 .633 .614 50 51 .854 .843 .831 .819 .806 .792 .778 .763 .747 .731 .714 .697 .679 .660 .641 .622 51 52 .860 .849 .838 .826 .813 .799 .785 .770 .755 .739 .722 .705 .687 .668 .649 .630 52 53 .866 .855 .844 .832 .820 .807 .793 .778 .763 .747 .730 .713 .695 .676 .657 .638 53 54 .872 .862 .851 .839 .827 .814 .800 .786 .771 .755 .738 .721 .703 .685 .666 .646 54 55 .878 .868 .857 .846 .834 .821 .808 .794 .779 .763 .747 .730 .712 .693 .674 .655 55 56 .884 .874 .864 .853 .841 .829 .816 .802 .787 .771 .755 .738 .721 .702 .683 .664 56 57 .890 .880 .870 .860 .848 .836 .823 .810 .795 .780 .764 .747 .730 .712 .693 .673 57 58 .895 .886 .877 .866 .855 .844 .831 .818 .804 .789 .773 .756 .739 .721 .702 .683 58 59 .901 .893 .883 .873 .863 .851 .839 .826 .812 .798 .782 .766 .749 .731 .712 .693 59 60 .907 .898 .890 .880 .870 .859 .847 .834 .821 .806 .791 .775 .758 .741 .722 .703 60 61 .912 .904 .896 .887 .877 .866 .855 .842 .829 .815 .800 .785 .768 .751 .733 .714 61 62 .918 .910 .902 .893 .884 .873 .862 .851 .838 .824 .810 .794 .778 .761 .743 .725 62 63 .923 .916 .908 .900 .890 .881 .870 .859 .846 .833 .819 .804 .788 .772 .754 .736 63 64 .928 .921 .914 .906 .897 .888 .878 .867 .855 .842 .829 .814 .799 .782 .765 .747 64 65 .933 .926 .919 .912 .904 .895 .885 .875 .863 .851 .838 .824 .809 .793 .776 .758 65 66 .937 .931 .925 .918 .910 .902 .892 .882 .872 .860 .847 .833 .819 .803 .787 .770 66 67 .942 .936 .930 .924 .916 .908 .900 .890 .880 .868 .856 .843 .829 .814 .798 .781 67 68 .946 .941 .935 .929 .922 .915 .906 .897 .888 .877 .865 .853 .839 .825 .809 .793 68 69 .950 .946 .940 .934 .928 .921 .913 .905 .895 .885 .874 .862 .849 .835 .820 .804 69 70 .954 .950 .945 .939 .933 .927 .920 .912 .903 .893 .883 .871 .859 .845 .831 .816 70 71 .958 .954 .949 .944 .939 .932 .926 .918 .910 .901 .891 .880 .868 .855 .842 .827 71 72 .962 .958 .953 .949 .944 .938 .932 .925 .917 .908 .899 .889 .878 .865 .852 .838 72 73 .965 .961 .957 .953 .948 .943 .937 .931 .923 .916 .907 .897 .887 .875 .863 .849 73 74 .968 .965 .961 .957 .953 .948 .942 .936 .930 .922 .914 .905 .895 .884 .873 .860 74
-29-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 75 .971 .968 .965 .961 .957 .952 .948 .942 .936 .929 .921 .913 .904 .893 .882 .870 75 76 .974 .971 .968 .965 .961 .957 .952 .947 .941 .935 .928 .920 .912 .902 .892 .880 76 77 .976 .974 .971 .968 .965 .961 .957 .952 .947 .941 .934 .927 .919 .910 .900 .890 77 78 .979 .976 .974 .971 .968 .965 .961 .957 .952 .946 .940 .934 .926 .918 .909 .899 78 79 .981 .979 .976 .974 .971 .968 .965 .961 .956 .952 .946 .940 .933 .926 .917 .908 79 80 .983 .981 .979 .977 .974 .971 .968 .965 .961 .956 .951 .946 .939 .932 .925 .916 80 81 .985 .983 .981 .979 .977 .974 .971 .968 .965 .961 .956 .951 .945 .939 .932 .924 81 82 .986 .985 .983 .981 .979 .977 .975 .972 .968 .965 .961 .956 .951 .945 .939 .931 82 83 .988 .986 .985 .983 .982 .980 .977 .975 .972 .969 .965 .961 .956 .951 .945 .938 83 84 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .958 .951 .945 84
-30-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 25 .500 .483 .466 .449 .432 .414 .397 .380 .364 .347 .331 .315 .299 .284 .269 .254 25 26 .503 .486 .468 .451 .434 .416 .399 .382 .365 .349 .333 .316 .301 .285 .270 .256 26 27 .505 .488 .471 .453 .436 .419 .401 .384 .367 .351 .334 .318 .302 .287 .272 .257 27 28 .508 .491 .473 .456 .438 .421 .403 .386 .369 .353 .336 .320 .304 .288 .273 .258 28 29 .511 .493 .476 .458 .441 .423 .406 .388 .371 .355 .338 .322 .306 .290 .275 .260 29 30 .514 .496 .478 .461 .443 .426 .408 .391 .374 .357 .340 .324 .307 .292 .276 .261 30 31 .517 .499 .481 .464 .446 .428 .411 .393 .376 .359 .342 .326 .309 .294 .278 .263 31 32 .520 .502 .484 .466 .449 .431 .413 .396 .378 .361 .344 .328 .311 .295 .280 .265 32 33 .523 .505 .488 .470 .452 .434 .416 .398 .381 .364 .347 .330 .314 .298 .282 .267 33 34 .527 .509 .491 .473 .455 .437 .419 .401 .384 .366 .349 .332 .316 .300 .284 .269 34 35 .531 .513 .494 .476 .458 .440 .422 .404 .387 .369 .352 .335 .318 .302 .286 .271 35 36 .535 .516 .498 .480 .462 .443 .425 .407 .390 .372 .355 .337 .321 .304 .288 .273 36 37 .539 .520 .502 .484 .465 .447 .429 .411 .393 .375 .357 .340 .323 .307 .291 .275 37 38 .543 .525 .506 .488 .469 .451 .432 .414 .396 .378 .361 .343 .326 .310 .293 .277 38 39 .548 .529 .511 .492 .473 .455 .436 .418 .400 .382 .364 .346 .329 .312 .296 .280 39 40 .552 .534 .515 .496 .478 .459 .440 .422 .403 .385 .367 .350 .332 .315 .299 .283 40 41 .557 .539 .520 .501 .482 .463 .445 .426 .407 .389 .371 .353 .336 .319 .302 .286 41 42 .563 .544 .525 .506 .487 .468 .449 .430 .412 .393 .375 .357 .339 .322 .305 .289 42 43 .568 .549 .530 .511 .492 .473 .454 .435 .416 .397 .379 .361 .343 .326 .309 .292 43 44 .574 .555 .536 .517 .497 .478 .459 .440 .421 .402 .383 .365 .347 .329 .312 .295 44 45 .580 .561 .542 .522 .503 .483 .464 .445 .425 .406 .388 .369 .351 .333 .316 .299 45 46 .586 .567 .548 .528 .509 .489 .469 .450 .431 .411 .392 .374 .355 .337 .320 .303 46 47 .593 .573 .554 .534 .515 .495 .475 .455 .436 .417 .397 .379 .360 .342 .324 .307 47 48 .600 .580 .561 .541 .521 .501 .481 .461 .442 .422 .403 .384 .365 .346 .328 .311 48 49 .607 .587 .567 .548 .528 .507 .487 .467 .447 .428 .408 .389 .370 .351 .333 .315 49
-31-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 50 .614 .594 .575 .555 .534 .514 .494 .474 .454 .434 .414 .394 .375 .356 .338 .320 50 51 .622 .602 .582 .562 .542 .521 .501 .480 .460 .440 .420 .400 .381 .362 .343 .325 51 52 .630 .610 .590 .570 .549 .529 .508 .487 .467 .446 .426 .406 .387 .367 .348 .330 52 53 .638 .618 .598 .577 .557 .536 .515 .495 .474 .453 .433 .413 .393 .373 .354 .335 53 54 .646 .626 .606 .586 .565 .544 .523 .502 .481 .461 .440 .419 .399 .379 .360 .341 54 55 .655 .635 .615 .594 .574 .553 .532 .510 .489 .468 .447 .426 .406 .386 .366 .347 55 56 .664 .644 .624 .603 .582 .561 .540 .519 .497 .476 .455 .434 .413 .393 .373 .353 56 57 .673 .654 .633 .613 .592 .570 .549 .528 .506 .484 .463 .442 .421 .400 .380 .360 57 58 .683 .663 .643 .622 .601 .580 .558 .537 .515 .493 .472 .450 .429 .408 .387 .367 58 59 .693 .673 .653 .632 .611 .590 .568 .546 .524 .502 .481 .459 .437 .416 .395 .374 59 60 .703 .684 .663 .643 .622 .600 .578 .556 .534 .512 .490 .468 .446 .424 .403 .382 60 61 .714 .694 .674 .654 .632 .611 .589 .567 .545 .522 .500 .478 .455 .434 .412 .391 61 62 .725 .705 .685 .665 .644 .622 .600 .578 .556 .533 .510 .488 .465 .443 .421 .400 62 63 .736 .716 .697 .676 .655 .634 .612 .589 .567 .644 .521 .499 .476 .453 .431 .409 63 64 .747 .728 .708 .688 .667 .646 .624 .601 .579 .556 .533 .510 .487 .464 .441 .419 64 65 .758 .740 .720 .700 .679 .658 .636 .614 .591 .568 .545 .522 .498 .475 .452 .430 65 66 .770 .751 .732 .712 .692 .671 .649 .627 .604 .581 .557 .534 .511 .487 .464 .441 66 67 .781 .763 .745 .725 .705 .684 .662 .640 .617 .594 .571 .547 .523 .500 .476 .453 67 68 .793 .775 .757 .738 .718 .697 .676 .653 .631 .608 .584 .560 .537 .513 .489 .465 68 69 .804 .787 .769 .751 .731 .711 .689 .667 .645 .622 .598 .574 .550 .526 .502 .478 69 70 .816 .799 .782 .764 .744 .724 .703 .682 .659 .636 .613 .589 .565 .540 .516 .492 70 71 .827 .811 .794 .777 .758 .738 .718 .696 .674 .651 .628 .604 .580 .555 .531 .506 71 72 .838 .823 .807 .790 .771 .752 .732 .711 .689 .666 .643 .619 .595 .571 .546 .521 72 73 .849 .835 .819 .802 .785 .766 .746 .726 .704 .682 .659 .635 .611 .586 .562 .536 73 74 .860 .846 .831 .815 .798 .780 .761 .741 .720 .698 .675 .651 .627 .603 .578 .553 74
-32-
SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OFSUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 75 .870 .857 .843 .828 .811 .794 .775 .756 .735 .714 .691 .668 .644 .620 .595 .569 75 76 .880 .868 .854 .840 .824 .807 .790 .771 .751 .730 .708 .685 .661 .637 .612 .587 76 77 .890 .878 .865 .852 .837 .821 .804 .785 .766 .746 .724 .702 .679 .654 .630 .605 77 78 .899 .888 .876 .863 .849 .834 .818 .800 .781 .762 .741 .719 .696 .672 .648 .623 78 79 .908 .898 .886 .874 .861 .847 .831 .814 .797 .778 .757 .736 .714 .690 .666 .641 79 80 .916 .907 .896 .885 .873 .859 .844 .828 .811 .793 .774 .753 .731 .709 .685 .660 80 81 .924 .915 .906 .895 .884 .871 .857 .842 .826 .808 .790 .770 .749 .727 .704 .680 81 82 .931 .923 .915 .905 .894 .882 .869 .855 .840 .823 .806 .787 .766 .745 .723 .699 82 83 .938 .931 .923 .914 .904 .893 .881 .868 .853 .838 .821 .803 .784 .763 .741 .718 83 84 .945 .938 .931 .922 .913 .903 .892 .880 .866 .852 .836 .819 .800 .781 .760 .738 84
-33- SPECIAL PROVISION D MARITAL PENSIONS, JOINT PENSIONS WITH SPOUSES AND SPECIAL JOINT PENSIONS WITH SPOUSES MARITAL PENSIONS and JOINT PENSIONS with SPOUSES shall be determined by multiplying factors calculated in accordance with the 1951 Male Group Annuity Table at 5% interest, with the following modifications: (i) PARTICIPANT's mortality rates shall be determined by adding 41% of the rates at PARTICIPANT's ages to 59% of the rates at ages five years lower. (ii) SPOUSE's mortality rates shall be determined by adding 59% of the rates at SPOUSE's ages to 41% of the rates at ages five years lower. (iii) For MARITAL PENSIONS, the factors shall be calculated taking into account only one-half of the costs of the benefits to surviving SPOUSES. (iv) When the proportions of the JOINT PENSIONS to be continued to SPOUSES exceed 50%, the factors shall be calculated in such a way that the values of such JOINT PENSIONS are equal to the values of corresponding MARITAL PENSION. (v) When the proportions of the JOINT PENSIONS to be continued to SPOUSES are less than 50%, the factors shall be calculated taking into account only one-half of the costs to surviving SPOUSES. (vi) Whenever a factor calculated for a MARITAL or JOINT PENSION with SPOUSE is smaller than the corresponding factor for a non- spouse JOINT PENSION, the non-spouse JOINT PENSION factor shall be substituted for the calculated factor. The following tables illustrate the factors to be applied for typical options which may be elected between 25% and 100%. EXAMPLE: Assume the PARTICIPANT is age 62 and Spouse age 60. Also assume that the PARTICIPANT's BASIC PENSION is $1,000 per month.
Spouse's Pension Spouse's Option Basic Reduced Spouse's In Event of Option Factor Pension Pension Portion Participant's Death - --------- ------ -------- -------- -------- -------------------- 25% .976 X $1,000. = $976. X .25 = $244.00 50% .955 X $1,000. = $955. X .50 = $477.50 75% .914 X $1,000. = $914. X .75 = $685.50 100% .876 X $1,000. = $876. X 1.00 = $876.00
SPECIAL JOINT PENSIONS with SPOUSES shall be determined using the same actuarial assumptions described above and are illustrated in the tables following the JOINT PENSION tables. -34- SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 25% OPTION ELECTION -------------------
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----- ---- ---- ----------- 40 .969 .967 .964 .962 .959 .956 .953 .950 .946 .943 .939 .935 .930 .926 .921 .916 40 41 .970 .968 .965 .963 .960 .957 .954 .951 .948 .944 .940 .936 .932 .927 .922 .917 41 42 .971 .969 .966 .964 .961 .958 .955 .952 .949 .945 .941 .937 .933 .929 .924 .919 42 43 .972 .970 .967 .965 .962 .960 .957 .953 .950 .947 .943 .939 .934 .930 .925 .920 43 44 .973 .971 .968 .966 .963 .961 .958 .955 .951 .948 .944 .940 .936 .931 .927 .922 44 45 .974 .972 .969 .967 .965 .962 .959 .956 .953 .949 .946 .942 .937 .933 .928 .923 45 46 .975 .973 .970 .968 .966 .963 .960 .957 .954 .951 .947 .943 .939 .935 .930 .925 46 47 .976 .974 .972 .969 .967 .964 .962 .959 .955 .952 .948 .945 .940 .936 .932 .927 47 48 .977 .975 .973 .970 .968 .966 .963 .960 .957 .953 .950 .946 .942 .938 .933 .928 48 49 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 .948 .944 .939 .935 .930 49 50 .979 .977 .975 .973 .970 .968 .965 .963 .960 .956 .953 .949 .945 .941 .937 .932 50 51 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 .947 .943 .939 .934 51 52 .980 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 .953 .949 .945 .940 .936 52 53 .981 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .954 .951 .947 .942 .938 53 54 .982 .981 .979 .977 .975 .973 .971 .968 .965 .962 .959 .956 .952 .948 .944 .940 54 55 .983 .982 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .954 .950 .946 .942 55 56 .984 .983 .981 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .952. .948 .944 56 57 .985 .984 .982 .980 .979 .977 .975 .972 .970 .967 .964 .961 .958 .954 .950 .946 57 58 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .959 .956 .952 .948 58 59 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .967 .964 .961 .958 .954 .950 59
NOTE: Factors for additional age combinations are available from the Administrator. -35- SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 25% OPTION ELECTION ------------------- (Continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .987 .986 .985 .984 .982 .980 .978 .976 .974 .972 .969 .966 .963 .960 .956 .952 60 61 .988 .987 .986 .985 .983 .981 .980 .978 .976 .973 .971 .968 .965 .962 .958 .954 61 62 .989 .988 .987 .985 .984 .983 .981 .979 .977 .975 .972 .970 .967 .964 .960 .957 62 63 .990 .989 .988 .986 .985 .984 .982 .980 .978 .976 .974 .971 .969 .966 .962 .959 63 64 .990 .990 .988 .987 .986 .985 .983 .981 .980 .978 .975 .973 .970 .967 .964 .961 64 65 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .977 .975 .972 .969 .966 .963 65 66 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .974 .971 .968 .965 66 67 .992 .992 .991 .990 .989 .988 .986 .985 .983 .982 .980 .978 .975 .973 .970 .967 67 68 .993 .992 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 .977 .975 .972 .969 68 69 .994 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 69 70 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 70 71 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 71 72 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 72 73 .995 .995 .995 .994 .993 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 73 74 .996 .995 .995 .994 .994 .993 .992 .992 .991 .990 .989 .987 .986 .984 .982 .980 74
NOTE: Factors for additional age combinations are available from the Administrator. -36- SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 50% OPTION ELECTION -------------------
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .942 .938 .934 .929 .924 .919 .914 .909 .903 .897 .891 .885 .878 .871 .863 .856 40 41 .943 .939 .935 .931 .926 .921 .916 .911 .905 .899 .893 .887 .880 .873 .865 .858 41 42 .945 .941 .937 .933 .928 .923 .918 .913 .907 .901 .895 .889 .882 .875 .868 .860 42 43 .947 .943 .939 .934 .930 .925 .920 .915 .909 .903 .897 .891 .884 .877 .870 .862 43 44 .948 .945 .941 .936 .932 .927 .922 .917 .911 .906 .899 .893 .886 .879 .872 .865 44 45 .950 .946 .942 .938 .934 .929 .924 .919 .914 .908 .902 .895 .889 .882 .875 .867 45 46 .952 .948 .944 .940 .936 .931 .926 .921 .916 .910 .904 .898 .891 .884 .877 .870 46 47 .954 .950 .946 .942 .938 .933 .929 .923 .918 .912 .906 .900 .894 .887 .880 .872 47 48 .955 .952 .948 .944 .940 .935 .931 .926 .920 .915 .909 .903 .896 .889 .882 .875 48 49 .957 .954 .950 .946 .942 .938 .933 .928 .923 .917 .911 .905 .899 .892 .885 .878 49 50 .959 .956 .952 .948 .944 .940 .935 .930 .925 .920 .914 .908 .901 .895 .888 .880 50 51 .961 .957 .954 .950 .946 .942 .938 .933 .928 .922 .917 .911 .904 .898 .891 .883 51 52 .962 .959 .956 .952 .948 .944 .940 .935 .930 .925 .919 .913 .907 .900 .894 .886 52 53 .964 .961 .958 .954 .950 .946 .942 .938 .933 .927 .922 .916 .910 .903 .897 .889 53 54 .966 .963 .960 .956 .953 .949 .945 .940 .935 .930 .925 .919 .913 .906 .900 .893 54 55 .968 .965 .962 .958 .955 .951 .947 .942 .938 .933 .927 .922 .916 .909 .903 .896 55 56 .969 .966 .963 .960 .957 .953 .949 .945 .940 .936 .930 .925 .919 .913 .906 .899 56 57 .971 .968 .965 .962 .959 .955 .952 .947 .943 .938 .933 .928 .922 .916 .909 .902 57 58 .972 .970 .967 .964 .961 .958 .954 .950 .946 .941 .936 .931 .925 .919 .913 .906 58 59 .974 .972 .969 .966 .963 .960 .956 .952 .948 .944 .939 .934 .928 .922 .916 .909 59
NOTE: Factors for additional age combinations are available from the Administrator. -37- SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 50% OPTION ELECTION ------------------- (Continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .976 .973 .971 .968 .965 .962 .959 .955 .951 .946 .942 .937 .931 .926 .919 .913 60 61 .977 .975 .973 .970 .967 .964 .961 .957 .953 .949 .945 .940 .934 .929 .923 .916 61 62 .979 .976 .974 .972 .969 .966 .963 .960 .956 .952 .947 .943 .938 .932 .926 .920 62 63 .980 .978 .976 .974 .971 .968 .965 .962 .958 .955 .950 .946 .941 .936 .930 .924 63 64 .981 .979 .977 .975 .973 .970 .967 .964 .961 .957 .953 .949 .944 .939 .933 .928 64 65 .983 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .952 .947 .942 .937 .931 65 66 .984 .982 .980 .979 .976 .974 .972 .969 .966 .962 .959 .955 .950 .945 .940 .935 66 67 .985 .984 .982 .980 .978 .976 .974 .971 .968 .965 .961 .957 .953 .949 .944 .939 67 68 .986 .985 .983 .982 .980 .978 .975 .973 .970 .967 .964 .960 .956 .952 .947 .942 68 69 .987 .986 .985 .983 .981 .979 .977 .975 .972 .970 .966 .963 .959 .955 .951 .946 69 70 .988 .987 .986 .984 .983 .981 .979 .977 .974 .972 .969 .966 .962 .958 .954 .949 70 71 .989 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 .968 .965 .961 .957 .953 71 72 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .971 .967 .964 .960 .956 72 73 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .970 .967 .963 .959 73 74 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .966 .962 74
NOTE: Factors for additional age combinations are available from the Administrator. -38- SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 75% OPTION ELECTION -------------------
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .890 .883 .875 .868 .859 .851 .842 .833 .824 .814 .803 .793 .782 .771 .760 .748 40 41 .893 .886 .878 .871 .863 .854 .845 .836 .827 .817 .807 .796 .785 .774 .763 .751 41 42 .896 .889 .881 .874 .866 .857 .849 .840 .830 .820 .810 .800 .789 .778 .766 .754 42 43 .899 .892 .885 .877 .869 .861 .852 .843 .834 .824 .814 .803 .792 .781 .770 .758 43 44 .902 .895 .888 .880 .872 .864 .856 .847 .837 .827 .817 .807 .796 .785 .773 .762 44 45 .905 .898 .891 .884 .876 .868 .859 .850 .841 .831 .821 .811 .800 .789 .777 .765 45 46 .908 .901 .894 .887 .879 .871 .863 .854 .845 .835 .825 .814 .804 .792 .781 .769 46 47 .911 .905 .898 .891 .883 .875 .867 .858 .849 .839 .829 .819 .808 .797 .785 .773 47 48 .915 .908 .901 .894 .887 .879 .870 .862 .853 .843 .833 .823 .812 .801 .789 .778 48 49 .918 .911 .905 .898 .890 .883 .874 .866 .857 .847 .837 .827 .816 .805 .794 .782 49 50 .921 .915 .908 .901 .894 .886 .878 .870 .861 .851 .842 .831 .821 .810 .798 .786 50 51 .924 .918 .912 .905 .898 .890 .882 .874 .865 .856 .846 .836 .825 .814 .803 .791 51 52 .927 .922 .915 .909 .902 .894 .887 .878 .869 .860 .851 .840 .830 .819 .808 .796 52 53 .931 .925 .919 .912 .906 .898 .891 .883 .874 .865 .855 .845 .835 .824 .813 .801 53 54 .934 .928 .922 .916 .910 .902 .895 .887 .878 .869 .860 .850 .840 .829 .818 .806 54 55 .937 .932 .926 .920 .913 .906 .899 .891 .883 .874 .865 .855 .845 .834 .823 .811 55 56 .940 .935 .930 .924 .917 .911 .903 .896 .887 .879 .870 .860 .850 .839 .828 .817 56 57 .943 .938 .933 .927 .921 .915 .908 .900 .892 .884 .875 .865 .855 .845 .834 .822 57 58 .946 .942 .936 .931 .925 .919 .912 .905 .897 .888 .880 .870 .860 .850 .839 .828 58 59 .949 .945 .940 .935 .929 .923 .916 .909 .901 .893 .885 .876 .866 .856 .845 .834 59
NOTE: Factors for additional age combinations are available from the Administrator. -39- SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 75% OPTION ELECTION ------------------- (Continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .952 .948 .943 .938 .933 .927 .920 .914 .906 .898 .890 .881 .871 .861 .851 .840 60 61 .955 .951 .946 .942 .936 .931 .925 .918 .911 .903 .895 .886 .877 .867 .857 .846 61 62 .958 .954 .950 .945 .940 .935 .929 .922 .915 .908 .900 .892 .883 .873 .863 .852 62 63 .961 .957 .953 .948 .944 .939 .933 .927 .920 .913 .905 .897 .888 .879 .869 .858 63 64 .963 .960 .956 .952 .947 .942 .937 .931 .925 .918 .910 .902 .894 .885 .875 .865 64 65 .966 .962 .959 .955 .951 .946 .941 .935 .929 .923 .916 .908 .900 .891 .881 .871 65 66 .968 .965 .962 .958 .954 .950 .945 .939 .934 .927 .921 .913 .905 .897 .887 .878 66 67 .971 .968 .964 .961 .957 .953 .948 .943 .938 .932 .925 .918 .911 .902 .894 .884 67 68 .973 .970 .967 .964 .960 .956 .952 .947 .942 .936 .930 .924 .916 .908 .900 .891 68 69 .975 .972 .970 .967 .963 .960 .956 .951 .946 .941 .935 .929 .922 .914 .906 .897 69 70 .977 .975 .972 .969 .966 .963 .959 .955 .950 .945 .940 .933 .927 .920 .912 .903 70 71 .979 .977 .974 .972 .969 .966 .962 .958 .954 .949 .944 .938 .932 .925 .918 .910 71 72 .981 .979 .976 .974 .971 .968 .965 .962 .958 .953 .948 .943 .937 .930 .923 .916 72 73 .982 .980 .978 .976 .974 .971 .968 .965 .961 .957 .952 .947 .942 .936 .929 .922 73 74 .984 .982 .980 .978 .976 .974 .971 .968 .964 .960 .956 .951 .946 .940 .934 .927 74
NOTE: Factors for additional age combinations are available from the Administrator. -40- SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 100% OPTION ELECTION --------------------
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .844 .834 .824 .814 .803 .792 .781 .769 .757 .744 .732 .719 .705 .692 .678 .664 40 41 .847 .838 .828 .818 .807 .796 .785 .773 .761 .748 .736 .723 .709 .696 .682 .668 41 42 .851 .842 .832 .822 .811 .800 .789 .777 .765 .753 .740 .727 .713 .700 .686 .672 42 43 .855 .846 .836 .826 .816 .805 .793 .782 .770 .757 .744 .731 .718 .704 .690 .676 43 44 .860 .850 .841 .831 .820 .809 .798 .786 .774 .762 .749 .736 .722 .709 .695 .680 44 45 .864 .855 .845 .835 .825 .814 .803 .791 .779 .766 .754 .740 .727 .713 .699 .685 45 46 .868 .859 .850 .840 .829 .819 .807 .796 .784 .771 .759 .745 .732 .718 .704 .690 46 47 .873 .864 .854 .844 .834 .824 .812 .801 .789 .776 .764 .750 .737 .723 .709 .695 47 48 .877 .868 .859 .849 .839 .829 .817 .806 .794 .782 .769 .756 .742 .728 .714 .700 48 49 .881 .873 .864 .854 .844 .834 .823 .811 .799 .787 .774 .761 .748 .734 .719 .705 49 50 .886 .877 .868 .859 .849 .839 .828 .817 .805 .793 .780 .767 .753 .739 .725 .711 50 51 .890 .882 .873 .864 .854 .844 .833 .822 .810 .798 .786 .772 .759 .745 .731 .716 51 52 .895 .887 .878 .869 .860 .850 .839 .828 .816 .804 .791 .778 .765 .751 .737 .722 52 53 .899 .892 .883 .874 .865 .855 .845 .834 .822 .810 .797 .784 .771 .757 .743 .728 53 54 .904 .896 .888 .879 .870 .860 .850 .839 .828 .816 .804 .791 .777 .763 .749 .735 54 55 .908 .901 .893 .884 .876 .866 .856 .845 .834 .822 .810 .797 .784 .770 .756 .741 55 56 .913 .906 .898 .890 .881 .872 .862 .851 .840 .829 .816 .804 .791 .777 .763 .748 56 57 .917 .910 .903 .895 .886 .877 .868 .857 .846 .835 .823 .810 .797 .784 .770 .755 57 58 .922 .915 .908 .900 .892 .883 .873 .863 .853 .842 .830 .817 .804 .791 .777 .762 58 59 .926 .919 .912 .905 .897 .888 .879 .870 .859 .848 .837 .824 .811 .798 .784 .770 59
NOTE: Factors for additional age combinations are available from the Administrator. -41- SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 100% OPTION ELECTION -------------------- (Continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .930 .924 .917 .910 .902 .894 .885 .876 .866 .855 .843 .831 .819 .805 .792 .777 60 61 .934 .928 .922 .915 .908 .900 .891 .882 .872 .861 .850 .839 .826 .813 .799 .785 61 62 .938 .933 .926 .920 .913 .905 .897 .888 .878 .868 .857 .846 .834 .821 .807 .793 62 63 .942 .937 .931 .925 .918 .911 .903 .894 .885 .875 .864 .853 .841 .829 .815 .802 63 64 .946 .941 .935 .929 .923 .916 .908 .900 .891 .882 .871 .860 .849 .837 .824 .810 64 65 .950 .945 .940 .934 .928 .921 .914 .906 .897 .888 .878 .868 .857 .845 .832 .819 65 66 .953 .949 .944 .938 .933 .926 .919 .912 .904 .895 .885 .875 .864 .853 .840 .827 66 67 .957 .952 .948 .943 .937 .931 .925 .918 .910 .901 .892 .882 .872 .860 .848 .836 67 68 .960 .956 .951 .947 .942 .936 .930 .923 .916 .908 .899 .890 .879 .868 .857 .844 68 69 .963 .959 .955 .951 .946 .941 .935 .928 .921 .914 .906 .897 .887 .876 .865 .853 69 70 .966 .962 .959 .955 .950 .945 .940 .934 .927 .920 .912 .903 .894 .884 .873 .862 70 71 .969 .965 .962 .958 .954 .949 .944 .939 .932 .926 .918 .910 .901 .892 .881 .870 71 72 .971 .968 .965 .962 .958 .953 .949 .943 .938 .931 .924 .917 .908 .899 .889 .879 72 73 .974 .971 .968 .965 .961 .957 .953 .948 .943 .937 .930 .923 .915 .906 .897 .887 73 74 .976 .974 .971 .968 .965 .961 .957 .952 .947 .952 .936 .929 .921 .913 .904 .895 74
NOTE: Factors for additional age combinations are available from the Administrator. -42- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION -------------------
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 20 .966 .964 .961 .959 .956 .953 .950 .947 .944 .940 .937 .933 .929 .926 .921 .917 20 21 .967 .964 .962 .959 .957 .954 .951 .948 .945 .941 .938 .934 .930 .926 .922 .918 21 22 .967 .965 .963 .960 .957 .955 .952 .949 .945 .942 .938 .935 .931 .927 .923 .919 22 23 .968 .966 .963 .961 .958 .955 .952 .949 .946 .943 .939 .936 .932 .928 .924 .920 23 24 .969 .966 .964 .961 .959 .956 .953 .950 .947 .944 .940 .937 .933 .929 .925 .921 24 25 .969 .967 .965 .962 .960 .957 .954 .951 .948 .944 .941 .937 .934 .930 .926 .921 25 26 .970 .968 .965 .963 .960 .958 .955 .952 .949 .945 .942 .938 .935 .931 .927 .922 26 27 .971 .969 .966 .964 .961 .959 .956 .953 .950 .946 .943 .939 .936 .932 .928 .923 27 28 .971 .969 .967 .965 .962 .959 .957 .954 .950 .947 .944 .940 .936 .933 .929 .924 28 29 .972 .970 .968 .965 .963 .960 .957 .954 .951 .948 .945 .941 .937 .934 .930 .925 29 30 .973 .971 .969 .966 .964 .961 .958 .955 .952 .949 .946 .942 .939 .935 .931 .927 30 31 .974 .972 .969 .967 .965 .962 .959 .956 .953 .950 .947 .943 .940 .936 .932 .928 31 32 .974 .972 .970 .968 .965 .963 .960 .957 .954 .951 .948 .944 .941 .937 .933 .929 32 33 .975 .973 .971 .969 .966 .964 .961 .958 .955 .952 .949 .945 .942 .938 .934 .930 33 34 .976 .974 .972 .970 .967 .965 .962 .959 .956 .953 .950 .947 .943 .939 .935 .931 34 35 .977 .975 .973 .970 .968 .966 .963 .960 .957 .954 .951 .948 .944 .940 .937 .933 35 36 .977 .975 .973 .971 .969 .967 .964 .961 .958 .955 .952 .949 .945 .942 .938 .934 36 37 .978 .976 .974 .972 .970 .968 .965 .962 .960 .957 .953 .950 .947 .943 .939 .935 37 38 .979 .977 .975 .973 .971 .969 .966 .963 .961 .958 .955 .951 .948 .944 .940 .937 38 39 .980 .978 .976 .974 .972 .970 .967 .964 .962 .959 .956 .952 .949 .946 .942 .938 39
NOTE: Factors for additional age combinations are available from the Administrator. -43- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION ------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .980 .979 .977 .975 .973 .970 .968 .966 .963 .960 .957 .954 .950 .947 .943 .939 40 41 .981 .979 .978 .976 .974 .971 .969 .967 .964 .961 .958 .955 .952 .948 .945 .941 41 42 .982 .980 .978 .977 .975 .972 .970 .968 .965 .962 .959 .956 .953 .950 .946 .942 42 43 .983 .981 .979 .977 .975 .973 .971 .969 .966 .963 .961 .958 .954 .951 .947 .944 43 44 .983 .982 .980 .978 .976 .974 .972 .970 .967 .965 .962 .959 .956 .952 .949 .945 44 45 .984 .982 .981 .979 .977 .975 .973 .971 .968 .966 .963 .960 .957 .954 .950 .947 45 46 .985 .983 .982 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .952 .948 46 47 .985 .984 .982 .981 .979 .977 .975 .973 .971 .968 .965 .963 .960 .957 .953 .950 47 48 .986 .984 .983 .981 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 48 49 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 .953 49 50 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .964 .961 .958 .954 50 51 .988 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 51 52 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .961 .957 52 53 .989 .988 .986 .985 .984 .982 .980 .979 .977 .975 .972 .970 .968 .965 .962 .959 53 54 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .960 54 55 .990 .989 .988 .986 .985 .984 .982 .980 .979 .977 .975 .972 .970 .968 .965 .962 55 56 .990 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 56 57 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 57 58 .991 .990 .989 .988 .987 .986 .985 .983 .981 .980 .978 .976 .974 .971 .969 .966 58 59 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 59
NOTE: Factors for additional age combinations are available from the Administrator. -44- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION ------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .992 .991 .990 .989 .988 .987 .986 .985 .983 .981 .980 .978 .976 .974 .972 .969 60 61 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .971 61 62 .993 .992 .991 .991 .990 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .972 62 63 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .983 .981 .979 .977 .975 .973 63 64 .994 .993 .992 .991 .991 .990 .989 .987 .986 .985 .983 .982 .980 .978 .976 .974 64 65 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .978 .976 65 66 .994 .994 .993 .992 .992 .991 .990 .989 .988 .986 .985 .984 .982 .980 .979 .977 66 67 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .980 .978 67 68 .995 .994 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 68 69 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 69 70 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 70 71 .996 .995 .995 .994 .994 .993 .992 .991 .991 .990 .989 .987 .986 .985 .984 .982 71 72 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .985 .983 72 73 .996 .996 .996 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 .987 .985 .984 73 74 .997 .996 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .985 74 75 .997 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 75 76 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 .987 76 77 .997 .997 .997 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 77 78 .997 .997 .997 .996 .996 .996 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 78 79 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .991 .991 .990 .989 79
NOTE: Factors for additional age combinations are available from the Administrator. -45- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION ------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 80 .998 .997 .997 .997 .997 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .990 80 81 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .993 .992 .991 .990 81 82 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .992 .991 82 83 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 83 84 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .993 .992 84 85 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 85 86 .999 .998 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 .994 .993 86 87 .999 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .995 .994 .993 87 88 .999 .999 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 88 89 .999 .999 .999 .998 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 89
NOTE: Factors for additional age combinations are available from the Administrator. -46- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION -------------------
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 20 .917 .913 .908 .903 .898 .893 .888 .882 .876 .870 .864 .857 .850 .843 .836 .828 20 21 .918 .913 .909 .904 .899 .894 .888 .883 .877 .871 .865 .858 .851 .844 .837 .829 21 22 .919 .914 .910 .905 .900 .895 .889 .884 .878 .872 .865 .859 .852 .845 .838 .830 22 23 .920 .915 .911 .906 .901 .896 .890 .885 .879 .873 .866 .860 .853 .846 .838 .831 23 24 .921 .916 .912 .907 .902 .897 .891 .886 .880 .874 .867 .861 .854 .847 .839 .832 24 25 .921 .917 .912 .908 .903 .898 .892 .887 .881 .875 .868 .862 .855 .848 .840 .833 25 26 .922 .918 .913 .909 .904 .899 .893 .888 .882 .876 .869 .863 .856 .849 .841 .834 26 27 .923 .919 .914 .910 .905 .900 .894 .889 .883 .877 .870 .864 .857 .850 .842 .835 27 28 .924 .920 .916 .911 .906 .901 .895 .890 .884 .878 .871 .865 .858 .851 .844 .836 28 29 .925 .921 .917 .912 .907 .902 .896 .891 .885 .879 .873 .866 .859 .852 .845 .837 29 30 .927 .922 .918 .913 .908 .903 .898 .892 .886 .880 .874 .867 .860 .853 .846 .838 30 31 .928 .923 .919 .914 .909 .904 .899 .893 .887 .881 .875 .868 .862 .855 .847 .840 31 32 .929 .925 .920 .915 .911 .905 .900 .895 .889 .883 .876 .870 .863 .856 .849 .841 32 33 .930 .926 .921 .917 .912 .907 .901 .896 .890 .884 .878 .871 .864 .857 .850 .842 33 34 .931 .927 .923 .918 .913 .908 .903 .897 .891 .885 .879 .873 .866 .859 .851 .844 34 35 .933 .928 .924 .919 .915 .909 .904 .899 .893 .887 .881 .874 .867 .860 .853 .845 35 36 .934 .930 .925 .921 .916 .911 .906 .900 .894 .888 .882 .876 .869 .862 .854 .847 36 37 .935 .931 .927 .922 .917 .912 .907 .902 .896 .890 .884 .877 .870 .863 .856 .849 37 38 .937 .932 .928 .924 .919 .914 .909 .903 .897 .892 .885 .879 .872 .865 .858 .850 38 39 .938 .934 .930 .925 .920 .915 .910 .905 .899 .893 .887 .880 .874 .867 .859 .852 39
NOTE: Factors for additional age combinations are available from the Administrator. -47- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION ------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .939 .935 .931 .927 .922 .917 .912 .906 .901 .895 .889 .882 .875 .868 .861 .854 40 41 .941 .937 .933 .928 .924 .919 .914 .908 .903 .897 .890 .884 .877 .870 .863 .856 41 42 .942 .938 .934 .930 .925 .920 .915 .910 .904 .898 .892 .886 .879 .872 .865 .858 42 43 .944 .940 .936 .931 .927 .922 .917 .912 .906 .900 .894 .888 .881 .874 .867 .860 43 44 .945 .941 .937 .933 .929 .924 .919 .914 .908 .902 .896 .890 .883 .876 .869 .862 44 45 .947 .943 .939 .935 .930 .926 .921 .915 .910 .904 .898 .892 .885 .878 .871 .864 45 46 .948 .944 .941 .936 .932 .927 .922 .917 .912 .906 .900 .894 .887 .880 .873 .866 46 47 .950 .946 .942 .938 .934 .929 .924 .919 .914 .908 .902 .896 .889 .883 .876 .868 47 48 .951 .948 .944 .940 .936 .931 .926 .921 .916 .910 .904 .898 .892 .885 .878 .871 48 49 .953 .949 .946 .942 .937 .933 .928 .923 .918 .912 .907 .900 .894 .887 .880 .873 49 50 .954 .951 .947 .943 .939 .935 .930 .925 .920 .915 .909 .903 .896 .890 .883 .875 50 51 .956 .953 .949 .945 .941 .937 .932 .927 .922 .917 .911 .905 .899 .892 .885 .878 51 52 .957 .954 .951 .947 .943 .939 .934 .929 .924 .919 .913 .907 .901 .895 .888 .880 52 53 .959 .956 .952 .949 .945 .941 .936 .932 .927 .921 .916 .910 .904 .897 .890 .883 53 54 .960 .957 .954 .950 .947 .943 .938 .934 .929 .924 .918 .912 .906 .900 .893 .886 54 55 .962 .959 .956 .952 .948 .945 .940 .936 .931 .926 .920 .915 .909 .902 .896 .889 55 56 .963 .960 .957 .954 .950 .946 .942 .938 .933 .928 .923 .917 .911 .905 .898 .891 56 57 .965 .962 .959 .956 .952 .948 .944 .940 .935 .931 .925 .920 .914 .908 .901 .894 57 58 .966 .964 .961 .957 .954 .950 .946 .942 .938 .933 .928 .922 .917 .910 .904 .897 58 59 .968 .965 .962 .959 .956 .952 .948 .944 .940 .935 .930 .925 .919 .913 .907 .900 59
NOTE: Factors for additional age combinations are available from the Administrator. -48- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION ------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .969 .967 .964 .961 .958 .954 .950 .946 .942 .938 .933 .927 .922 .916 .910 .903 60 61 .971 .968 .965 .962 .959 .956 .952 .949 .944 .940 .935 .930 .925 .919 .913 .906 61 62 .972 .969 .967 .964 .961 .958 .954 .951 .947 .942 .938 .933 .927 .922 .916 .909 62 63 .973 .971 .968 .966 .963 .960 .956 .953 .949 .945 .940 .935 .930 .924 .919 .912 63 64 .974 .972 .970 .967 .965 .962 .958 .955 .951 .947 .942 .938 .933 .927 .922 .916 64 65 .976 .974 .971 .969 .966 .963 .960 .957 .953 .949 .945 .940 .935 .930 .925 .919 65 66 .977 .975 .973 .970 .968 .965 .962 .959 .955 .951 .947 .943 .938 .933 .928 .922 66 67 .978 .976 .974 .972 .969 .967 .964 .961 .957 .954 .950 .945 .941 .936 .930 .925 67 68 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .952 .948 .943 .939 .933 .928 68 69 .980 .978 .977 .975 .972 .970 .967 .964 .961 .958 .954 .950 .946 .941 .936 .931 69 70 .981 .980 .978 .976 .974 .971 .969 .966 .963 .960 .956 .953 .948 .944 .939 .934 70 71 .982 .981 .979 .977 .975 .973 .971 .968 .965 .962 .959 .955 .951 .947 .942 .937 71 72 .983 .982 .980 .978 .976 .974 .972 .970 .967 .964 .961 .957 .953 .949 .945 .940 72 73 .984 .983 .981 .979 .978 .976 .974 .971 .969 .966 .963 .959 .956 .952 .947 .943 73 74 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .961 .958 .954 .950 .946 74 75 .986 .985 .983 .982 .980 .978 .976 .974 .972 .969 .967 .963 .960 .956 .953 .948 75 76 .987 .985 .984 .983 .981 .980 .978 .976 .973 .971 .968 .965 .962 .959 .955 .951 76 77 .987 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .967 .964 .961 .957 .954 77 78 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .972 .969 .966 .963 .960 .956 78 79 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .968 .965 .962 .959 79
NOTE: Factors for additional age combinations are available from the Administrator. -49- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION ------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 80 .990 .989 .988 .986 .985 .984 .983 .981 .979 .977 .975 .973 .970 .967 .964 .961 80 81 .990 .989 .988 .987 .986 .985 .984 .982 .980 .979 .977 .974 .972 .969 .966 .963 81 82 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .971 .968 .965 82 83 .991 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .978 .975 .973 .970 .968 83 84 .992 .991 .990 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .972 .970 84 85 .992 .992 .991 .990 .989 .988 .987 .986 .985 .984 .982 .980 .978 .976 .974 .972 85 86 .993 .992 .992 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 .978 .976 .973 86 87 .993 .993 .992 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .977 .975 87 88 .994 .993 .993 .992 .991 .991 .990 .989 .988 .987 .985 .984 .983 .981 .979 .977 88 89 .994 .994 .993 .993 .992 .991 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 89
NOTE: Factors for additional age combinations are available from the Administrator. -50- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION --------------------
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 20 .904 .898 .892 .885 .879 .872 .864 .856 .849 .840 .832 .823 .815 .805 .796 .787 20 21 .906 .900 .894 .887 .880 .873 .866 .858 .850 .842 .834 .825 .816 .807 .798 .788 21 22 .908 .902 .896 .889 .882 .875 .868 .860 .852 .844 .836 .827 .818 .809 .800 .790 22 23 .909 .904 .897 .891 .884 .877 .870 .862 .854 .846 .838 .829 .820 .811 .802 .792 23 24 .911 .905 .899 .893 .886 .879 .872 .864 .856 .848 .840 .831 .822 .813 .804 .794 24 25 .913 .907 .901 .895 .888 .881 .874 .866 .858 .850 .842 .833 .824 .815 .806 .796 25 26 .915 .909 .903 .897 .890 .883 .876 .868 .860 .852 .844 .835 .826 .817 .808 .798 26 27 .917 .911 .905 .899 .892 .885 .878 .870 .862 .854 .846 .837 .829 .820 .810 .801 27 28 .919 .913 .907 .901 .894 .887 .880 .872 .865 .857 .848 .840 .831 .822 .813 .803 28 29 .921 .915 .909 .903 .896 .889 .882 .875 .867 .859 .851 .842 .833 .824 .815 .805 29 30 .923 .917 .911 .905 .899 .892 .885 .877 .869 .861 .853 .845 .836 .827 .817 .808 30 31 .925 .919 .913 .907 .901 .894 .887 .880 .872 .864 .856 .847 .838 .829 .820 .811 31 32 .927 .921 .916 .909 .903 .896 .889 .882 .874 .866 .858 .850 .841 .832 .823 .813 32 33 .929 .923 .918 .912 .905 .899 .892 .884 .877 .869 .861 .852 .844 .835 .825 .816 33 34 .931 .926 .920 .914 .908 .901 .894 .887 .879 .872 .864 .855 .846 .838 .828 .819 34 35 .933 .928 .922 .916 .910 .904 .897 .890 .882 .874 .866 .858 .849 .840 .831 .822 35 36 .935 .930 .924 .919 .913 .906 .899 .892 .885 .877 .869 .861 .852 .843 .834 .825 36 37 .937 .932 .927 .921 .915 .909 .902 .895 .888 .880 .872 .864 .855 .846 .837 .828 37 38 .939 .934 .929 .923 .917 .911 .905 .898 .890 .883 .875 .867 .858 .850 .840 .831 38 39 .941 .936 .931 .926 .920 .914 .907 .900 .893 .886 .878 .870 .861 .853 .844 .834 39
NOTE: Factors for additional age combinations are available from the Administrator. -51- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION -------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .943 .939 .934 .928 .922 .916 .910 .903 .896 .889 .881 .873 .865 .856 .847 .838 40 41 .945 .941 .936 .930 .925 .919 .913 .906 .899 .892 .884 .876 .868 .859 .850 .841 41 42 .947 .943 .938 .933 .927 .921 .915 .909 .902 .895 .887 .879 .871 .863 .854 .845 42 43 .949 .945 .940 .935 .930 .924 .918 .912 .905 .898 .890 .883 .874 .866 .857 .848 43 44 .951 .947 .942 .937 .932 .927 .921 .914 .908 .901 .893 .886 .878 .869 .861 .852 44 45 .953 .949 .945 .940 .935 .929 .923 .917 .911 .904 .897 .889 .881 .873 .864 .856 45 46 .955 .951 .947 .942 .937 .932 .926 .920 .914 .907 .900 .892 .885 .876 .868 .859 46 47 .957 .953 .949 .944 .939 .934 .929 .923 .916 .910 .903 .896 .888 .880 .872 .863 47 48 .959 .955 .951 .946 .942 .937 .931 .925 .919 .913 .906 .899 .891 .884 .875 .867 48 49 .960 .957 .953 .949 .944 .939 .934 .928 .922 .916 .909 .902 .895 .887 .879 .871 49 50 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .906 .898 .891 .883 .875 50 51 .964 .960 .957 .953 .948 .944 .939 .934 .928 .922 .916 .909 .902 .894 .887 .878 51 52 .965 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 .898 .890 .882 52 53 .967 .964 .960 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .902 .894 .886 53 54 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .918 .912 .905 .898 .890 54 55 .970 .967 .964 .960 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .901 .894 55 56 .971 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 .898 56 57 .973 .970 .967 .964 .961 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .902 57 58 .974 .972 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 58 59 .975 .973 .970 .967 .964 .961 .957 .953 .949 .944 .939 .934 .928 .922 .916 .909 59
NOTE: Factors for additional age combinations are available from the Administrator. -52- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION -------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .977 .974 .972 .969 .966 .963 .959 .955 .951 .946 .942 .937 .931 .925 .919 .913 60 61 .978 .976 .973 .971 .968 .964 .961 .957 .953 .949 .944 .939 .934 .929 .923 .917 61 62 .979 .977 .975 .972 .969 .966 .963 .959 .955 .951 .947 .942 .937 .932 .926 .920 62 63 .980 .978 .976 .974 .971 .968 .965 .961 .958 .954 .949 .945 .940 .935 .929 .924 63 64 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .952 .947 .943 .938 .933 .927 64 65 .982 .981 .978 .976 .974 .971 .968 .965 .962 .958 .954 .950 .945 .941 .936 .930 65 66 .983 .982 .980 .978 .975 .973 .970 .967 .964 .960 .956 .952 .948 .944 .939 .934 66 67 .984 .983 .981 .979 .977 .974 .971 .969 .965 .962 .959 .955 .951 .946 .942 .937 67 68 .985 .984 .982 .980 .978 .976 .973 .970 .967 .964 .961 .957 .953 .949 .945 .940 68 69 .986 .985 .983 .981 .979 .977 .974 .972 .969 .966 .963 .959 .955 .952 .947 .943 69 70 .987 .985 .984 .982 .980 .978 .976 .973 .971 .968 .965 .961 .958 .954 .950 .946 70 71 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .953 .948 71 72 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 .968 .965 .962 .959 .955 .951 72 73 .989 .988 .987 .985 .984 .982 .980 .978 .975 .973 .970 .967 .964 .961 .957 .954 73 74 .990 .989 .987 .986 .985 .983 .981 .979 .977 .974 .972 .969 .966 .963 .960 .956 74 75 .990 .989 .988 .987 .986 .984 .982 .980 .978 .976 .973 .971 .968 .965 .962 .959 75 76 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 .964 .961 76 77 .992 .991 .990 .989 .987 .986 .984 .983 .981 .979 .976 .974 .972 .969 .966 .963 77 78 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .971 .968 .965 78 79 .993 .992 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 79
NOTE: Factors for additional age combinations are available from the Administrator. -53- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION -------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 80 .993 .992 .992 .991 .990 .988 .987 .986 .984 .982 .980 .978 .976 .974 .972 .969 80 81 .994 .993 .992 .991 .990 .989 .988 .987 .985 .983 .982 .980 .978 .976 .973 .971 81 82 .994 .993 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 .977 .975 .973 82 83 .995 .994 .993 .992 .992 .991 .990 .988 .987 .986 .984 .982 .981 .979 .977 .975 83 84 .995 .994 .994 .993 .992 .991 .990 .989 .988 .986 .985 .983 .982 .980 .978 .976 84 85 .995 .995 .994 .994 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .980 .978 85 86 .996 .995 .995 .994 .993 .992 .992 .991 .989 .988 .987 .986 .984 .983 .981 .979 86 87 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 87 88 .996 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .986 .985 .983 .982 88 89 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .988 .987 .986 .985 .983 89
NOTE: Factors for additional age combinations are available from the Administrator. -54- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION --------------------
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 20 .787 .777 .767 .757 .746 .736 .725 .714 .702 .691 .679 .667 .654 .642 .629 .617 20 21 .788 .779 .769 .759 .748 .737 .726 .715 .704 .692 .680 .668 .656 .643 .631 .618 21 22 .790 .781 .771 .760 .750 .739 .728 .717 .705 .694 .682 .670 .657 .645 .632 .620 22 23 .792 .782 .772 .762 .752 .741 .730 .719 .707 .695 .683 .671 .659 .646 .634 .621 23 24 .794 .784 .774 .764 .754 .743 .732 .721 .709 .697 .685 .673 .661 .648 .635 .623 24 25 .796 .787 .776 .766 .756 .745 .734 .723 .711 .699 .687 .675 .662 .650 .637 .624 25 26 .798 .789 .779 .768 .758 .747 .736 .725 .713 .701 .689 .677 .664 .652 .639 .626 26 27 .801 .791 .781 .771 .760 .749 .738 .727 .715 .703 .691 .679 .666 .653 .641 .628 27 28 .803 .793 .783 .773 .762 .751 .740 .729 .717 .705 .693 .681 .668 .655 .643 .630 28 29 .805 .796 .786 .775 .765 .754 .743 .731 .719 .708 .695 .683 .670 .658 .645 .632 29 30 .808 .798 .788 .778 .767 .756 .745 .734 .722 .710 .698 .685 .673 .660 .647 .634 30 31 .811 .801 .791 .780 .770 .759 .748 .736 .724 .712 .700 .688 .675 .662 .649 .636 31 32 .813 .803 .793 .783 .772 .761 .750 .739 .727 .715 .703 .690 .677 .664 .651 .638 32 33 .816 .806 .796 .786 .775 .764 .753 .741 .730 .718 .705 .693 .680 .667 .654 .641 33 34 .819 .809 .799 .789 .778 .767 .756 .744 .732 .720 .708 .695 .682 .669 .656 .643 34 35 .822 .812 .802 .792 .781 .770 .759 .747 .735 .723 .711 .698 .685 .672 .659 .646 35 36 .825 .815 .805 .795 .784 .773 .762 .750 .738 .726 .714 .701 .688 .675 .662 .648 36 37 .828 .818 .808 .798 .787 .776 .765 .753 .742 .729 .717 .704 .691 .678 .665 .651 37 38 .831 .821 .811 .801 .791 .780 .768 .757 .745 .733 .720 .707 .694 .681 .668 .654 38 39 .834 .825 .815 .805 .794 .783 .772 .760 .748 .736 .723 .711 .698 .684 .671 .657 39
NOTE: Factors for additional age combinations are available from the Administrator. -55- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION -------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .838 .828 .818 .808 .797 .787 .775 .764 .752 .739 .727 .714 .701 .688 .674 .661 40 41 .841 .832 .822 .812 .801 .790 .779 .767 .755 .743 .730 .718 .704 .691 .678 .664 41 42 .845 .835 .825 .815 .805 .794 .783 .771 .759 .747 .734 .721 .708 .695 .681 .667 42 43 .848 .839 .829 .819 .808 .798 .786 .775 .763 .751 .738 .725 .712 .698 .685 .671 43 44 .852 .843 .833 .823 .812 .802 .790 .779 .767 .755 .742 .729 .716 .702 .689 .675 44 45 .856 .846 .837 .827 .816 .806 .794 .783 .771 .759 .746 .733 .720 .706 .693 .679 45 46 .859 .850 .841 .831 .820 .810 .799 .787 .775 .763 .750 .737 .724 .711 .697 .683 46 47 .863 .854 .845 .835 .825 .814 .803 .791 .780 .767 .755 .742 .728 .715 .701 .687 47 48 .867 .858 .849 .839 .829 .818 .807 .796 .784 .772 .759 .746 .733 .719 .705 .691 48 49 .871 .862 .853 .843 .833 .823 .812 .800 .789 .776 .764 .751 .738 .724 .710 .696 49 50 .875 .866 .857 .847 .837 .827 .816 .805 .793 .781 .769 .756 .742 .729 .715 .701 50 51 .878 .870 .861 .852 .842 .832 .821 .810 .798 .786 .773 .761 .747 .734 .720 .706 51 52 .882 .874 .865 .856 .846 .836 .825 .814 .803 .791 .778 .766 .752 .739 .725 .711 52 53 .886 .878 .869 .860 .851 .841 .830 .819 .808 .796 .784 .771 .757 .744 .730 .716 53 54 .890 .882 .874 .865 .855 .845 .835 .824 .813 .801 .789 .776 .763 .749 .735 .721 54 55 .894 .886 .878 .869 .860 .850 .840 .829 .818 .806 .794 .781 .768 .755 .741 .727 55 56 .898 .890 .882 .873 .864 .855 .845 .834 .823 .812 .799 .787 .774 .760 .747 .732 56 57 .902 .894 .886 .878 .869 .860 .850 .839 .828 .817 .805 .793 .780 .766 .752 .738 57 58 .905 .898 .890 .882 .874 .864 .855 .845 .834 .822 .811 .798 .785 .772 .758 .744 58 59 .909 .902 .895 .887 .878 .869 .860 .850 .839 .828 .816 .804 .791 .778 .764 .750 59
NOTE: Factors for additional age combinations are available from the Administrator. -56- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION -------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .913 .906 .899 .891 .883 .874 .865 .855 .844 .834 .822 .810 .797 .784 .771 .757 60 61 .917 .910 .903 .895 .887 .879 .870 .860 .850 .839 .828 .816 .803 .790 .777 .763 61 62 .920 .914 .907 .900 .892 .884 .875 .865 .855 .845 .834 .822 .810 .797 .784 .770 62 63 .924 .917 .911 .904 .896 .888 .880 .870 .861 .850 .839 .828 .816 .803 .790 .776 63 64 .927 .921 .915 .908 .901 .893 .884 .876 .866 .856 .845 .834 .822 .810 .797 .783 64 65 .930 .925 .918 .912 .905 .897 .889 .881 .871 .862 .851 .840 .828 .816 .803 .790 65 66 .934 .928 .922 .916 .909 .902 .894 .886 .877 .867 .857 .846 .835 .823 .810 .797 66 67 .937 .931 .926 .920 .913 .906 .899 .891 .882 .873 .863 .852 .841 .829 .817 .804 67 68 .940 .935 .929 .924 .917 .911 .903 .895 .887 .878 .868 .858 .847 .836 .824 .811 68 69 .943 .938 .933 .927 .921 .915 .908 .900 .892 .883 .874 .864 .854 .842 .830 .818 69 70 .946 .941 .936 .931 .925 .919 .912 .905 .897 .889 .880 .870 .860 .849 .837 .825 70 71 .948 .944 .939 .934 .929 .923 .916 .909 .902 .894 .885 .876 .866 .855 .844 .832 71 72 .951 .947 .942 .938 .932 .927 .921 .914 .907 .899 .890 .881 .872 .861 .851 .839 72 73 .954 .950 .945 .941 .936 .931 .925 .918 .911 .904 .896 .887 .878 .868 .857 .846 73 74 .956 .952 .948 .944 .939 .934 .929 .922 .916 .909 .901 .893 .884 .874 .864 .853 74 75 .959 .955 .951 .947 .943 .938 .932 .927 .920 .913 .906 .898 .889 .880 .870 .859 75 76 .961 .958 .954 .950 .946 .941 .936 .931 .924 .918 .911 .903 .895 .886 .876 .866 76 77 .963 .960 .957 .953 .949 .944 .940 .934 .929 .922 .916 .908 .900 .892 .882 .873 77 78 .965 .962 .959 .955 .952 .948 .943 .938 .933 .927 .920 .913 .906 .897 .888 .879 78 79 .967 .964 .961 .958 .954 .951 .946 .942 .936 .931 .925 .918 .911 .903 .894 .885 79
NOTE: Factors for additional age combinations are available from the Administrator. -57- SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION -------------------- (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 80 .969 .967 .964 .961 .957 .953 .949 .945 .940 .935 .929 .923 .916 .908 .900 .891 80 81 .971 .969 .966 .963 .960 .956 .952 .948 .944 .939 .933 .927 .920 .913 .906 .897 81 82 .973 .970 .968 .965 .962 .959 .955 .951 .947 .942 .937 .931 .925 .918 .911 .903 82 83 .975 .972 .970 .967 .965 .961 .958 .954 .950 .946 .941 .936 .930 .923 .916 .909 83 84 .976 .974 .972 .969 .967 .964 .961 .957 .953 .949 .945 .939 .934 .928 .921 .914 84 85 .978 .976 .974 .971 .969 .966 .963 .960 .956 .952 .948 .943 .938 .932 .926 .919 85 86 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .951 .947 .942 .937 .931 .924 86 87 .981 .979 .977 .975 .973 .971 .968 .965 .962 .958 .955 .950 .946 .941 .935 .929 87 88 .982 .980 .979 .977 .975 .973 .970 .967 .965 .961 .958 .954 .949 .945 .939 .934 88 89 .983 .982 .980 .978 .976 .974 .972 .970 .967 .964 .961 .957 .953 .948 .943 .938 89
NOTE: Factors for additional age combinations are available from the Administrator. -58- SPECIAL PROVISION E As in Effect Prior to January 1, 1976 A PARTICIPANT who is rehired after a BREAK IN SERVICE shall be treated as a new PARTICIPANT for all purposes, and the PARTICIPANT's SERVICE and compensation before the BREAK IN SERVICE shall not be recognized for any purpose of the PLAN, except as follows: (a) Upon either the death or retirement of a PARTICIPANT with broken SERVICE, the last period of CREDITED SERVICE immediately preceding the PARTICIPANT's latest employment date by EMPLOYER shall be counted as SERVICE provided: (1) The PARTICIPANT has accrued at least five years of SERVICE since last re-employed by EMPLOYER, and (2) The PARTICIPANT was last re-employed by EMPLOYER within five years of the date the PARTICIPANT's latest previous employment was terminated; and (3) The PARTICIPANT had accrued at least five years of CREDITED SERVICE prior to the date the PARTICIPANT's last previous employment with EMPLOYER terminated. (b) All other periods of prior employment with EMPLOYER, if any, shall not be counted as SERVICE. SPECIAL PROVISION F CREDITED SERVICE (a) As in effect prior to January 1, 1976: All SERVICE prior to ACTUAL RETIREMENT DATE, provided the PARTICIPANT joined the PLAN on the date when the PARTICIPANT first became eligible and participated therein continuously thereafter. An EMPLOYEE who first became eligible to join the COMPANY's Retirement PLAN prior to January 1, 1969, was permitted a grace period of six months beyond the EMPLOYEE'S eligibility date. An EMPLOYEE who first became eligible to join the PLAN on or after January 1, 1969, was permitted a grace period of 60 days beyond the EMPLOYEE'S eligibility date. Subject to these grace periods, if an EMPLOYEE did not become a PARTICIPANT when first eligible the EMPLOYEE'S CREDITED SERVICE did not begin until the EMPLOYEE became a PARTICIPANT. If a PARTICIPANT suspended contributions at any time between January 1, 1969, and December 31, 1972, inclusive. CREDITED SERVICE did not accrue to the PARTICIPANT after the date of such suspension of contributions. CREDITED SERVICE did not include any time for which a vacation allowance may be paid subsequent to an EMPLOYEE'S NORMAL RETIREMENT DATE. (b) Effective April 1, 1981: An EMPLOYEE who first became eligible to join the PLAN prior to January 1, 1973, but who for any reason did not do so, shall, except those EMPLOYEES who have had their CREDITED SERVICE previously adjusted by action of the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (EBAC), be allowed the opportunity to have such lost CREDITED SERVICE restored. An EMPLOYEE'S CREDITED SERVICE shall not be adjusted or restored except as follows: (1) Prior to April 1, 1982, any EMPLOYEE described above shall, upon application to EBAC, be permitted to buy back any portion of the five years of lost CREDITED SERVICE -59- immediately preceding the latest date on which an EMPLOYEE became a member of the PLAN. Such restored CREDITED SERVICE shall not, in combination with current SERVICE, exceed PARTICIPANT's actual COMPANY SERVICE. The cost for restoring such CREDITED SERVICE shall be computed at the rate of five percent of an EMPLOYEE'S current monthly wage rate for each month of restored CREDITED SERVICE. (2) In addition to the above, and prior to April 1, 1982, any EMPLOYEE described above shall, upon application to EBAC, be permitted to buy back any portion of the lost CREDITED SERVICE which is in excess of the five years permitted in (1) above. The cost for restoring such excess CREDITED SERVICE shall be computed at the rate of ten percent of an EMPLOYEE'S current monthly wage rate for each month of restored excess CREDITED SERVICE. For the purpose of applying Section 13 (Withdrawal of PARTICIPANT Contributions on Termination of Employment) only that portion of the payment made above, for restoration of lost CREDITED SERVICE, which the EMPLOYEE would have contributed had the EMPLOYEE participated in the PLAN at that time will be considered as CONTRIBUTIONS. SPECIAL PROVISION G PENSION AND LTD ADJUSTMENTS --------------------------- (a) Effective December 31, 1997, the PENSION of any PARTICIPANT who retired or the PENSION of a person receiving a SPOUSE's PENSION or a JOINT PENSION, will be increased as follows:
Increase -------- Retired on or before 12/31/78 9.0% Retired between 1/1/79 and 12/31/86 5.0% Retired between 1/1/87 and 12/31/92 2.5%
A minimum monthly increase of $50 will be provided to retirees with at least 30 years of SERVICE, and a retirement date at or after normal retirement age. A minimum monthly increase of $25 will be provided to surviving SPOUSES of such retirees. (b) The above adjustments shall apply to those Participants who are receiving Long Term Disability Benefit payments. (c) By Company resolutions dated June 17, 1964, February 25, 1969, April 9, 1974, September 20, 1977, March 4, 1980, July 15, 1981, and December 21, 1983, the amounts of pensions received by certain pensioners were increased in accordance with the provisions of said resolutions. The money required to fund these additional payments is based on actuarial factors and the required contributions are paid into the Plan. The Company intends to continue making these additional payments out of Plan assets and on the same basis as it has done in the past. -60- SPECIAL PROVISION H MAXIMUM PENSION This PLAN incorporates by reference the benefit limitations imposed by CODE Section 415. The annual benefit amount otherwise payable to a former EMPLOYEE at any time will not exceed the maximum permissible amount under CODE Section 415. For purposes of determining compliance with the Section 415 benefit limitations, the limitation year shall be the PLAN YEAR. If the benefit the PARTICIPANT would otherwise accrue in a limitation year would produce an annual benefit in excess of the maximum permissible amount under CODE Section 415, then the rate of accrual will be reduced so that the annual benefit will equal the maximum permissible amount. If a PARTICIPANT in this PLAN also participates in any defined contribution plan maintained by an EMPLOYER, the sum of the PARTICIPANT'S "Defined Benefit Fraction" and the PARTICIPANT'S "Defined Contribution Fraction" shall not exceed 1.0. In the event that in any PLAN YEAR the sum of the PARTICIPANT'S Defined Benefit Fraction and the PARTICIPANT'S Defined Contribution Fraction exceed 1.0, then the PENSION payable under this PLAN shall be reduced so that the sum of such fractions in respect of that PARTICIPANT will not exceed 1.0." For purposes of determining the PLAN'S compliance with CODE Section 415, the annual benefit is a retirement benefit payable under the PLAN in the form of a straight life annuity. Except as provided below, a benefit payable in a form other than a straight life annuity must be adjusted to an actuarially equivalent straight life annuity before applying the limitations of Section 415. The interest rate assumption used to determine actuarial equivalence will be the greater of rate used in Special Provision D or 5 percent. No actuarial adjustment to the benefit is required for the value of a qualified joint and survivor annuity, the value of benefits that are not directly related to retirement benefits (such as the qualified disability benefit, pre-retirement death benefits, and post-retirement medical benefits), and the value of post- retirement cost-of-living increases made in accordance with 415(d) of the CODE. The annual benefit does not include any benefits attributable to EMPLOYEE contributions or rollover contributions or the assets transferred from a qualified plan not maintained by the COMPANY. Compensation, for purposes of determining the PLAN'S compliance with Section 415 of the CODE, shall mean all of each PARTICIPANT'S wages, tips, and other Box 10 compensation on the PARTICIPANT'S Form W-2. SPECIAL PROVISION I If prior to 1989 SERVICE terminates with at least ten years of SERVICE, or with at least five years of SERVICE after 1988, the PENSION the PARTICIPANT would otherwise be entitled to receive shall be reduced because of the withdrawal. If the withdrawal occurs prior to age 55, the yearly PENSION payable at the NORMAL RETIREMENT DATE, prior to reduction for EARLY RETIREMENT (if any), shall be reduced by the product of the amount withdrawn and the applicable factor selected from the following table: -61-
Age Last Age Last Birthday At Birthday At Refund Date Factor Refund Date Factor - ------------- ------ ----------- ------ 25 .6705 40 .3225 26 .6385 41 .3072 27 .6081 42 .2925 28 .5792 43 .2786 29 .5516 44 .2653 30 .5253 45 .2527 31 .5003 46 .2407 32 .4765 47 .2292 33 .4538 48 .2183 34 .4321 49 .2079 35 .4116 50 .1980 36 .3920 51 .1886 37 .3733 52 .1796 38 .3556 53 .1710 39 .3386 54 .1629
If the withdrawal occurs after age 55, the yearly PENSION payable at the ACTUAL RETIREMENT DATE, after reduction for EARLY RETIREMENT (if any), shall be reduced by the product of the amount withdrawn and the applicable factor selected from the following table:
Age Last Birthday At Refund Date Factor ----------- ------ 55 .0775 56 .0792 57 .0810 58 .0829 59 .0849 60 .0871 61 .0894 62 .0919 63 .0946 64 .0975 65 .1000 66 .1039 67 .1074 68 .1111 69 .1151 70 .1192
Notwithstanding the foregoing, in no event will the PENSION be reduced by more than one-third. The monthly reduction is computed by multiplying the appropriate factor times the PARTICIPANT'S contributions including interest and dividing that amount by twelve months. -62- EXAMPLE: - -------- Assumptions: Age 60 Basic Pensions = $1,500.00/month Contributions = $6,000.00 Interest = 3,000.00 --------- Total = $9,000.00 - 65.33* ------ Pension with contributions = $1,434.67/month plus interest withdrawn _______________________ *Calculation: (Contributions + Interest x Age 60 Refund Factor) : 12 Months ($9,000 x .0871 : 12 Months = $65.33) -63- SPECIAL PROVISION J TOP HEAVY PROVISIONS -------------------- (a) General Rule ------------ For any PLAN YEAR for which this PLAN is a "top-heavy plan" as defined in subsection (g) below, any other provisions of this PLAN to the contrary notwithstanding, this PLAN shall be subject to the following provisions: (1) The vesting provisions of subsection (b). (2) The minimum benefit provisions of subsection (c). (3) The limitation on compensation set by subsection (d). (4) The limitation on benefits set by subsection (e). If any individual has not performed SERVICE for an EMPLOYER at any time during the five-year period ending on the last day of the preceding PLAN YEAR, any accrued benefit for such individual shall not be taken into account for purposes of determining whether the PLAN is a "top-heavy plan." For purposes of determining whether the PLAN is top-heavy, a non-key EMPLOYEE'S accrued benefit must be determined as if it is accrued not more rapidly than the slowest accrual rate permitted under CODE Section 411(b)(1)(C) (i.e., the "fractional rule"). (b) Vesting Provisions ------------------ Each PARTICIPANT who (i) has completed an hour of SERVICE during any PLAN YEAR in which the PLAN is top heavy and (ii) has completed the number of years of credited SERVICE specified in the following table shall have a nonforfeitable right to the percentage of the benefit accrued under this PLAN derived from EMPLOYER contributions correspondingly specified in the following table:
Years of Percentage of credited service: nonforfeitable benefit: 2 20 3 40 4 60 5 80 6 or more 100 "Credited service" as used in this subsection (b) shall constitute SERVICE as defined in Section 22 of this PLAN.
Each PARTICIPANT's nonforfeitable accrued benefit shall not be less than his nonforfeitable accrued benefit determined as of the last day of the last PLAN YEAR in which the PLAN was a top-heavy PLAN. If the PLAN ceases to be top- heavy, each PARTICIPANT with five or more years of SERVICE, whether or not consecutive, shall have his nonforfeitable accrued benefit determined in accordance with this Section and Section 3. Each such PARTICIPANT shall have the right to elect the applicable schedule within 60 days after the day the PARTICIPANT is issued written notice by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, or as otherwise provided in accordance with regulations issued under the provision of the Internal Revenue CODE of 1954, as amended, relating to changes in the vesting schedule. -64- This provision shall apply without regard to contributions or benefits under Social Security or any other Federal or State law. (c) Minimum Benefit Provisions -------------------------- Each PARTICIPANT who (i) is a non-key employee (as defined in subsection (i) below) and (ii) has completed 1,000 hours of SERVICE during any PLAN YEAR shall be entitled to an accrued benefit in the form of an annual retirement benefit (as defined in paragraph (1) below) that shall be not less than the applicable percentage (as defined in paragraph (2) below) of the PARTICIPANT's average annual compensation for years in the testing period (as defined in paragraph (3) below). (1) "Annual retirement benefit" means a benefit payable annually in the form of a single life annuity (with no ancillary benefits) beginning at NORMAL RETIREMENT DATE as defined in Section 22 of this PLAN or its actuarial equivalent. (2) "Applicable percentage" means the lesser of two percent multiplied by the number of top-heavy PLAN YEARs of service (as defined in paragraph (4) below) of 20 percent. (3) "Testing period" means, with respect to a PARTICIPANT, the period of consecutive years (not exceeding five) of SERVICE during which the PARTICIPANT had the greatest aggregate compensation from the EMPLOYER. The testing period shall not include any year of SERVICE not included as a year of SERVICE as defined in paragraph (4) below. The testing period shall also not include any year of SERVICE that ends in a PLAN YEAR beginning before January 1, 1984 or during which the PLAN was not a top-heavy plan. (4) "Years of service" means SERVICE as defined in Section 3 of this PLAN. Benefits taken into account under this Subsection shall not include any benefits payable under the Social Security Act or any other Federal or State law. (d) Limitation on Benefits ---------------------- In the event that the EMPLOYER also maintains a defined contribution PLAN providing contributions on behalf of PARTICIPANTS in this PLAN, one of the two following provisions shall apply: (1) If for the PLAN YEAR this PLAN would not be a "top-heavy plan" as defined in subsection (g) below if "90 percent" were substituted for "60 percent," then subsection (c) shall apply for such PLAN YEAR as if amended so that the "applicable percentage" means the lesser of three percent multiplied by the number of years of SERVICE (as defined in paragraph (4) of subsection (c)) during which the PLAN would be top- heavy (as defined in subsection (g)) and the overall applicable percentage does not exceed the lesser of 30% or 20% plus 1% for each year the PLAN is taken into account under this subsection ((e)(1)). (2) If for the PLAN YEAR this PLAN would continue to be a "top-heavy plan" as defined in subsection (g) below if "90 percent" were substituted for "60 percent," then the denominator of both the defined contribution PLAN fraction and the defined benefit plan fraction shall be calculated as set forth in Special Provision H for the limitation year ending in such PLAN YEAR by substituting "1.0" for "1.25," except with respect to any individual for whom there are no EMPLOYER contributions, forfeitures or voluntary nondeductible contributions allocated or any accruals for such individual under the defined benefit PLAN. Furthermore, the transitional rule set forth in CODE Section 415 shall be applied by substituting "$41,500" for $51,875". -65- (e) Coordination with Other Plans ----------------------------- In the event that another defined contribution or defined benefit PLAN maintained by the EMPLOYER provides contributions or benefits on behalf of PARTICIPANTS in this PLAN, such other PLAN shall be treated as a part of this PLAN pursuant to applicable principles (such as Rev. Rul. 81-202 or any successor ruling) in determining whether this PLAN satisfies the requirements of subsection (b), (c) and (d). Such determination shall be made upon the advice of counsel by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE. (f) Top-heavy Plan Definition ------------------------- This PLAN shall be a "top-heavy plan" for any PLAN YEAR if, as of the determination date (as defined in subsection (g)(1) below), the present value (as determined in subsection (g)(2) below) of the cumulative accrued benefits under the PLAN for participants (including former participants) who are key employees (as defined in subsection (h) below) exceeds 60 percent of the present value of the cumulative accrued benefits under the PLAN for all participants, excluding former key employees, or if this PLAN is required to be in a aggregation group (as defined in subsection (g)(3) below) which for such PLAN YEAR is a top-heavy group (as defined in subsection (g)(4) below). (1) "Determination date" means for any PLAN YEAR the last day of the immediately preceding PLAN YEAR. (2) The present value shall be determined as of the most recent valuation date that is within the twelve-month period ending on the determination date and as described in the regulations under the Internal Revenue CODE as of 1954, as amended. (3) "Aggregation group" means the group of plans, if any, that includes both the group of plans that are required to be aggregated and the group of plans that are permitted to be aggregated. (A) The group of plans that are required to be aggregated (the "required aggregation group") includes (i) Each plan of the EMPLOYER (as defined in subsection (j) below) in which a key employee is a PARTICIPANT, including collectively-bargained plans, and (ii) Each other plan, including collectively-bargained plans of the EMPLOYER (as defined in subsection (j) below) which enables a plan in which a key employee is a PARTICIPANT to meet the requirements of the Internal Revenue CODE of 1954, as amended, prohibiting discrimination as to contributions or benefits in favor of employees who are officers, shareholders or the highly-compensated or prescribing the minimum participation standards. (B) The group of plans that are permitted to be aggregated (the "permissive aggregation group") includes the required aggregation group plus one or more plans of the EMPLOYER (as defined in subsection (j) below) that is not part of the required aggregation group and that the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE certifies as constituting a plan within the permissive aggregation group. Such plan or plans may be added to the permissive aggregation group only if, after the addition, the aggregation group as a whole continue not to discriminate as to contributions or benefits in favor of officers, shareholders or the highly-compensated and to meet the minimum participation standards under the Internal Revenue CODE of 1954, as amended. (4) "Top-heavy group" means the aggregation group, if as of the applicable determination date, the sum of the present value of the cumulative accrued benefits for key employees under all defined benefit plans included in the aggregation group plus the aggregate of the accounts of key employees under all defined -66- contribution plans included in the aggregation group exceeds 60% of the sum of the present value of the cumulative accrued benefits for all employees, excluding former key employees, under all such defined benefit plans plus the aggregate accounts for all employees, excluding former key employees, under such defined contribution plans. If the aggregation group that is a top-heavy group is a required aggregation group, each Plan in the group will be top heavy. If the aggregation group that is a top-heavy group is a permissive aggregation group, only those plans that are part of the required aggregation group will be treated as top-heavy. If the aggregation group is not a top-heavy group, no plan within such group will be top- heavy. (5) In determining whether this PLAN constitutes a "top-heavy plan", the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (or its agent) shall make the following adjustments in connection therewith: (A) When more than one plan is aggregated, the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall determine separately for each plan as of each plan's determination date the present value of the accrued benefits or account balance. The results shall then be aggregated by adding the results of each plan as of the determination dates for such plans that fall within the same calendar year. (B) In determining the present value of the cumulative accrued benefit or the amount of the account of any employee, such present value or account shall include the amount in dollar value of the aggregate distributions made to such employee under the applicable plan during the five-year period ending on the determination date, unless reflected in the value of the accrued benefit or account balance as of the most recent valuation date. Such amounts shall include distributions to employees which represented the entire amount credited to their accounts under the applicable plan. (C) Further, in making such determination, in any case where an individual is a "non-key employee" as defined in subsection (h) below, with respect to an applicable plan, but was a key employee with respect to such plan for any prior PLAN YEAR, any accrued benefit and any account of such employee shall be altogether disregarded. For this purpose, to the extent that a key employee is deemed to be a key employee if he met the definition of key employee within any of the four preceding PLAN YEARS, this provision shall apply following the end of such period of time. (g) Key Employee ------------ The term "key employee" means any employee or former employee under this PLAN who, at any time during the PLAN YEAR containing the determination date or during any of the four preceding PLAN YEARS, is or was one of the following: (1) An officer of the EMPLOYER (as defined in subsection (j)). Whether an individual is an officer shall be determined by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE on the basis of all the facts and circumstances, such as an individual's authority, duties and term of office, not on the mere fact that the individual has the title of an officer. For any such PLAN YEAR, there shall be treated as officers no more than the lesser of: (A) 50 employees, or (B) the greater of three employees or 10 percent of the employees. For this purpose, the highest-paid officers shall be selected. Business organizations other than corporations shall be deemed to have no officers. (2) One of the ten employees owning (or considered as owning, within the meaning of the constructive ownership rules of the Internal Revenue CODE of 1954, as amended) the largest -67- interests in the EMPLOYER (as defined in subsection (j)). An employee who has some ownership interest is considered to be one of the top ten owners unless at least ten other employees own a greater interest than that employee. However, an employee will not be considered a top ten owner for a PLAN YEAR if the employee earns less than the maximum dollar limitation on contributions and other annual additions to a PARTICIPANT's account in a defined contribution plan under the Internal Revenue CODE of 1954, as amended, as in effect for the calendar year in which the determination date falls. (3) Any person who owns (or is considered as owning within the meaning of the constructive ownership rules of the CODE more than five percent of the outstanding stock of the EMPLOYER or stock possessing more than five percent of the combined total voting power of all stock of the EMPLOYER. (4) A one percent owner of the EMPLOYER having an annual compensation from the EMPLOYER of more than $150,000, and possessing more than five percent of the combined total voting power of all stock of the EMPLOYER. For purposes of this subsection, compensation means all items includable as compensation for purposes of applying the limitations on contributions and other annual additions to a PARTICIPANT's account in a defined contribution plan and the maximum benefit payable under a defined plan under the Internal Revenue CODE of 1954, as amended. For purposes of parts (1), (2), (3) and (4) of this definition, a beneficiary of a key employee shall be treated as a key employee. For purposes of parts (3) and (4), each EMPLOYER is treated separately (without regard to the definition in subsection (j)) in determining ownership percentages; but, in determining the amount of compensation, the definition of EMPLOYER in subsection (j) is taken into account. (h) Non-Key Employee ---------------- The term "non-key employee" means any employee (and any beneficiary of an employee) who is not a key employee. (i) Employer -------- The term "employer" means EMPLOYER as defined in Section 22 of this PLAN. (j) Collective Bargaining Rules --------------------------- The provisions of subsection (b), (c) and (d) above do not apply with respect to any employee included in a unit of employees covered by a collective bargaining agreement unless the application of such subsections has been agreed upon with the collective bargaining agent. (k) Distributions to Key Employees ------------------------------ Any other provisions of this PLAN to the contrary notwithstanding, distribution of the entire interest in this PLAN of each PARTICIPANT who is or any time has been a key employee shall commence no later than the end of the taxable year of the PARTICIPANT in which the PARTICIPANT attains age 70 1/2. SPECIAL PROVISION K I. Introduction ------------ -68- This Special Provision K, an amendment to the COMPANY'S RETIREMENT PLAN, adopted by the COMPANY'S Board of Directors on December 17, 1986, is the controlling and definitive statement of the Voluntary Retirement Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus --- --- of COMPANY employees in certain designated operations. The VRI is a part --- of the RETIREMENT PLAN, and except as otherwise provided in this Special Provision K, shall be administered in accordance with and subject to the terms of the RETIREMENT PLAN. Terms in all capitals are defined in Section 22 of the RETIREMENT PLAN. Terms underlined are defined in Section VII of Special Provision K. The decision of an Eligible Employee to elect to participate in the -------- -------- VRI is wholly voluntary, and an election not to participate in the VRI --- --- shall in no way affect benefits under the RETIREMENT PLAN to which an Eligible Employee might otherwise be entitled. -------- -------- II. Eligibility to Participate in the VRI ------------------------------------- Eligible Employees shall be any full-time active employee of the COMPANY or of a Participating Employer, born on or before January 1, 1937, ------------- -------- who has at least 15 years of SERVICE on January 1, 1987. For purposes of this VRI only, the term active employee shall not include an employee of --- the COMPANY or a Participating Employer, (i) who, on January 1, 1987, is ------------- -------- presently receiving benefits under Part B of the Group Life Insurance and Long Term Disability Plan; (ii) who, as of January 1, 1987, is on personal or medical leave, with or without pay; or (iii) who is a former employee whose ACTUAL RETIREMENT DATE was November 1, 1986, or earlier. Anything herein to the contrary notwithstanding, an Eligible Employee -------- -------- who (i) elects not to participate in the VRI and (ii) prior to January 1, --- 1988, is severed under the Company's Corporate Severance Program, shall be entitled to receive a Basic VRI Benefit under this Special Provision K. --- Such Basic VRI Benefit shall be in lieu of any benefits to which the ----- --- ------- Eligible EMPLOYEE would otherwise be entitled to receive under the -------- -------- Corporate Severance Program. For purposes of calculating the Basic VRI ----- --- Benefit under this provision, the VRI Retirement Date shall be the first of ------- --- ---------- ---- the month following the month in which the employee is severed. III. Election to Participate ----------------------- An Eligible EMPLOYEE must elect to participate in the VRI by -------- -------- --- submitting a completed and signed VRI enrollment form which is received by --- a designated COMPANY representative no later than January 30, 1987, except that Eligible Employees who are employed by Pacific Gas Transmission -------- --------- Company will have until the close of business, September 30, 1987, to submit their completed and signed VRI enrollment form to a designated --- employer representative. An Eligible EMPLOYEE who fails to submit a timely -------- -------- enrollment form shall be deemed to have elected not to participate in the VRI. The election of an Eligible Employee not to participate in the VRI, --- -------- -------- --- whether through failure to timely submit a VRI election form or otherwise, --- shall be conclusive and binding on the employee, employee's spouse, heirs, and assigns. IV. VRI Benefit ----------- A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner ----- --- ------- -------- -------- to participate in the VRI shall be entitled to receive a Basic VRI --- ----- --- Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit ------- formula calculated under Subsection 6(a)(1), with the following adjustments: -69- 1. BASIC MONTHLY SALARY shall mean the PARTICIPANT'S BASIC MONTHLY SALARY on January 1, 1986, increased by 5 percent; 2. SERVICE shall mean the PARTICIPANT'S SERVICE as of the VRI --- Retirement Date selected by the PARTICIPANT, increased by five ---------- ---- years; and 3. The EARLY RETIREMENT PENSION reduction provisions of Subsection 7(b) shall not apply to any Basic VRI Benefit payable under this ----- --- ------- Special Provision K. B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date ----- --- ------- --- ---------- ---- selected by the Eligible Employee and shall be paid as soon as -------- -------- practicable after the applicable VRI Retirement Date. Eligible --- ---------- ---- -------- Employees who elect to participate in the VRI shall not be subject to --------- --- the age 55 requirement contained in Section 8. C. Section 10 of the RETIREMENT PLAN shall control the conditions under which other forms of pension may be substituted for the Basic VRI ----- --- Benefit. Thus, although a PARTICIPANT is entitled to receive a Basic ------- ----- VRI Benefit, if the PARTICIPANT is married, Section 10(b) of the --- ------- RETIREMENT PLAN requires that the Basic VRI Benefit be converted to a ----- --- ------- MARITAL PENSION, unless the PARTICIPANT'S spouse CONSENTS to an alternative form of pension. D. The Basic VRI Benefit payable under this Special Provision K shall be ----- ------- in lieu of any benefit which might otherwise be payable under the RETIREMENT PLAN. E. A participant who elects to participate in VRI shall also be entitled --- to make the elections provided in Sections 10 (Forms of Pension), 12 (Withdrawal of Participant Contributions on Termination of Employment), 13 (Death Benefits), and 14 (Facility of Payment). V. VRI Retirement Dates -------------------- At such time as an employee elects to participate in the VRI, he shall --- select a VRI Retirement Date. For purposes of this Special Provision K, a --- ---------- ---- VRI Retirement Date shall mean one of the following: --- ---------- ---- A. For Eligible Employees other than Eligible Employees employed by -------- --------- -------- --------- Pacific Gas Transmission Company: 1. February 1, 1987, provided, however, that eligible participants have completed all necessary VRI enrollment procedures prior to --- January 15, 1987; 2. March 1, 1987; 3. April 1, 1987; or 4. The first of any month during the period commencing with March 1, 1987, and ending with and including October 1, 1987. This Subsection V.A.4. shall only apply in the event that the COMPANY or the Participating Employer, as the case may be, has a ------------- -------- demonstrated business need which requires the retention of the Eligible Employee. Should the business needs of the COMPANY or -------- -------- of a Participating Employer require the retention of an Eligible ------------- -------- -------- Employee beyond October 1, 1987, the VRI Retirement Date shall be -------- --- ---------- ---- the first of any month during the period subsequent to October 1, 1987, and ending with and including July 1, 1988. The selection of any such VRI Retirement Date subsequent to October 1, 1987, --- ---------- ---- shall be made by the COMPANY, or Participating Employer, through ------------- -------- an appropriate member of the COMPANY's Management Committee. -70- B. For Eligible Employees employed by Pacific Gas Transmission Company: -------- --------- 1. October 1, 1987, provided, however, that eligible participants have completed all necessary VRI enrollment procedures prior to --- September 15, 1987; 2. November 1, 1987; or 3. The first of any month during the period commencing with December 1, 1987, and ending with and including June 1, 1988. This Subsection V.B.3. shall only apply in the event that Pacific Gas Transmission Company has a demonstrated need which requires the retention of the Eligible Employee. -------- -------- The VRI Retirement Date selected shall also be the date as of --- ---------- ---- which an Eligible Employee ceases to be an employee of the COMPANY or -------- -------- a Participating Employer, as the case may be. ------------- -------- VI. Revocation of Election ---------------------- An Eligible Employee who has elected to participate in the VRI may -------- -------- --- revoke his election, provided, however, that any such revocation shall only be effective if received by the COMPANY on or before January 30, 1987, for those Eligible Employees who elected a VRI Retirement Date of February 1, -------- --------- --- ---------- ---- 1987; February 15, 1987, for those Eligible Employees who elected a VRI -------- --------- --- Retirement Date of March 1, 1987, or later; September 30, 1987, for those ---------- ---- Eligible Employees of Pacific Gas Transmission Company who elected a VRI -------- --------- --- Retirement Date of October 1, 1987; or October 15, 1987, for those Eligible ---------- ---- -------- Employees of Pacific Gas Transmission Company who elected a VRI Retirement --------- --- ---------- Date of November 1, 1987, or later. ---- VII. Definitions ----------- A. Basic VRI Benefit: The benefit calculated under Section IV of this ----- --- ------- Special Provision K. B. Eligible Employee: An employee of the COMPANY or of a Participating -------- -------- Employer who has met the eligibility criteria as set forth in Section II on January 1, 1987. For purposes of this Special Provision K only, Eligible Employee shall not include any COMPANY Officer at the vice presidential level, or above. C. Participating Employer: Natural Gas Corporation, Pacific Gas ------------- -------- Transmission Company, and Pacific Service Employees Association. D. VRI: The COMPANY's Voluntary Retirement Incentive program as set --- forth in this Special Provision K. E. VRI Retirement Date: The date selected by an Eligible Employee under --- ---------- ---- Section V of this Special Provision K. SPECIAL PROVISION M I. Introduction ------------ This Special Provision M, an amendment to the COMPANY'S RETIREMENT PLAN, adopted by the COMPANY'S Board of Directors on February 17, 1993, is the controlling and definitive statement of the Voluntary Retirement Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus --- --- of -71- COMPANY employees in certain designated operations. The VRI is a part --- of the RETIREMENT PLAN, and except as otherwise provided in this Special Provision M, shall be administered in accordance with and subject to the terms of the RETIREMENT PLAN. Terms in all capitals are defined in Section 22 of the RETIREMENT PLAN. Terms underlined are defined in Section VII of Special Provision M. The decision of an Eligible Employee to elect to participate in the -------- -------- VRI is wholly voluntary, and an election not to participate in the VRI --- --- shall in no way affect benefits under the RETIREMENT PLAN to which an Eligible Employee might otherwise be entitled. -------- -------- II. Eligibility to Participate in the VRI ------------------------------------- An Eligible Employee shall be any active employee of the COMPANY whose -------- -------- base job classification on February 17, 1993, is in a Targeted Organization -------- ------------ and who was born on or before December 31, 1942, and has at least 15 years of SERVICE on December 31, 1992. For purposes of this VRI only, the term --- active employee shall not include an employee of the COMPANY (i) who, on February 17, 1993, is presently receiving benefits under Part B of the Group Life Insurance and Long Term Disability Plan; (ii) who is on a leave of absence, with or without pay, which began on or prior to August 17, 1992; or (iii) who is a former employee whose ACTUAL RETIREMENT DATE was February 1, 1993, or earlier. III. Election to Participate ----------------------- An Eligible Employee must elect to participate in the VRI by -------- -------- --- submitting a completed and signed VRI enrollment form which is received by a designated COMPANY representative no later than April 23, 1993. An Eligible Employee who fails to submit a timely enrollment form shall be -------- -------- deemed to have elected not to participate in the VRI. The election of an --- Eligible Employee not to participate in the VRI, whether through failure to -------- -------- --- submit a timely VRI election form or otherwise, shall be conclusive and --- binding on the employee, employee's spouse, heirs, and assigns. IV. VRI Benefit ----------- A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner ----- --- ------- -------- -------- to participate in the VRI shall be entitled to receive a Basic VRI --- ----- --- Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit ------- formula calculated under Subsection 6(a)(1), with the following adjustments: 1. SERVICE shall mean the PARTICIPANT'S SERVICE as of last VRI --- Retirement Date for such Eligible Employee, increased by three ---------- ---- -------- -------- years; and 2. The EARLY RETIREMENT PENSION reduction provisions of Subsection 7(b) shall not apply to any Basic VRI Benefit payable under this ----- --- ------- Special Provision M. B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date ----- --- ------- --- ---------- ---- selected by the Eligible Employee and shall be paid as soon as -------- -------- practicable after the applicable VRI Retirement Date. Eligible --- ---------- ---- -------- Employees who elect to participate in the VRI shall not be subject to --------- --- the age 55 requirement contained in Section 8. C. Section 10 of the RETIREMENT PLAN shall control the conditions under which other forms of pension may be substituted for the Basic VRI ----- --- Benefit. Thus, although a PARTICIPANT is ------- -72- entitled to receive a Basic VRI Benefit, if the PARTICIPANT is ----- --- ------- married, Section 10(b) of the RETIREMENT PLAN requires that the Basic ----- VRI Benefit be converted to a MARITAL PENSION, unless the --- ------- PARTICIPANT'S spouse CONSENTS to an alternative form of pension. D. The Basic VRI Benefit payable under this Special Provision M shall be ----- --- ------- in lieu of any benefit which might otherwise be payable under the RETIREMENT PLAN. E. A participant who elects to participate in VRI shall also be entitled --- to make the elections provided in Sections 10 (Forms of Pension), 12 (Withdrawal of Participant Contributions on Termination of Employment), 13 (Death Benefits), and 14 (Facility of Payment). V. VRI Retirement Dates -------------------- At such time as an employee elects to participate in the VRI, he shall --- select a VRI Retirement Date. For purposes of this Special Provision M, a --- ---------- ---- VRI Retirement Date shall mean one of the following: --- ---------- ---- A. May 1, 1993; B. June 1, 1993; or C. The first of any month during the period commencing with July 1, 1993, and ending with and including June 1, 1994. This Subsection C shall only apply in the event that the COMPANY has a demonstrated business need which requires the retention of the Eligible Employee. The -------- -------- selection of any such VRI Retirement Date subsequent to June 1, 1993, --- ---------- ---- can be made only with the written approval of both of the Company's Executive Vice Presidents. The VRI Retirement Date selected shall also be the date as of which an --- ---------- ---- Eligible Employee ceases to be an employee of the COMPANY. -------- -------- VI. Revocation of Election ---------------------- An Eligible Employee who has elected to participate in the VRI may -------- -------- --- revoke his election, provided, however, that any such revocation shall only be effective if received by the COMPANY on or before April 23, 1993, for those Eligible Employees who elected a VRI Retirement Date of May 1, 1993; -------- --------- --- ---------- ---- or April 30, 1993, for those Eligible Employees who elected a VRI -------- --------- --- Retirement Date of June 1, 1993, or later. ---------- ---- VII. Definitions ----------- A. Basic VRI Benefit: The benefit calculated under Section IV of this ----- --- ------- Special Provision M. B. Eligible Employee: An employee of the COMPANY who has met the -------- -------- eligibility criteria as set forth in Section II. For purposes of this Special Provision M only, Eligible Employee shall not include any COMPANY Officer. C. Targeted Organization: Distribution Business Unit; Engineering and --------------------- Construction Business Unit; Gas Supply Business Unit except the Gas Dispatch Department and except employees with job levels of 32 and above; Nuclear Operations Support Department; Nuclear Safety and Regulatory Affairs Department; Nuclear Engineering and Construction Services Department; Nuclear Business and Financial Management Department; Nuclear Documentation and Support Department; Quality Assurance Department; human resources departments, including business unit -73- human resources organizations being consolidated with corporate human resources; computer and telecommunication services departments, including business unit and corporate services organizations being consolidated with corporate computer and telecommunication services departments; Corporate Communications departments, including business unit media and employee communications units being consolidated with Corporate Communications departments; community and governmental relations departments including regional public affairs units being consolidated with corporate governmental relations departments; and the Economics and Forecasting Department. D. VRI: The COMPANY's Voluntary Retirement Incentive program as set --- forth in this Special Provision M. E. VRI Retirement Date: The date selected by an Eligible Employee under --- ---------- ---- Section V of this Special Provision M. SPECIAL PROVISION N I. Introduction This Special Provision N, an amendment to the COMPANY'S RETIREMENT PLAN, authorized by the COMPANY'S Board of Directors on September 21, 1994, is the controlling and definitive statement of the Voluntary Retirement Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus --- --- of COMPANY EMPLOYEES. The VRI is a part of the RETIREMENT PLAN, and except --- as otherwise provided in this Special Provision N, shall be administered in accordance with and subject to the terms of the RETIREMENT PLAN. Terms in all capitals are defined in Section 22 of the RETIREMENT PLAN. Terms underlined are defined in Section VII of Special Provision N. The decision of an Eligible Employee to elect to participate in the -------- -------- VRI is wholly voluntary, and an election not to participate in the VRI --- --- shall in no way affect benefits under the RETIREMENT PLAN to which an Eligible Employee might otherwise be entitled. -------- -------- II. Eligibility to Participate in the VRI --- An Eligible Employee shall be any active EMPLOYEE of the COMPANY who -------- -------- was born on or before September 30, 1944, and has at least 15 years of SERVICE on September 30, 1994. For purposes of this VRI only, the term --- active EMPLOYEE shall not include an EMPLOYEE of the COMPANY (i) who, on September 30, 1994, is presently receiving benefits under Part B of the Group Life Insurance and Long Term Disability Plan; (ii) who is on a leave of absence, with or without pay, which began on or prior to March 30, 1994; (iii) who elected to retire under Special Provision M of Part I of the RETIREMENT PLAN or Special Provision N of Part II of the RETIREMENT PLAN; (iv) who has received or is scheduled to receive severance benefits under the COMPANY'S Workforce Management Program, Letter Agreement No. 93-42-PGE and Letter Agreement No. 93-23esc, or under any other written agreement between the COMPANY and the EMPLOYEE in which the EMPLOYEE has received benefits in connection with the termination of such EMPLOYEE'S employment; (v) who is a former EMPLOYEE who was terminated for cause; or (vi) who is a former EMPLOYEE whose ACTUAL RETIREMENT DATE was July 1, 1994, or earlier. III. Election to Participate -74- An Eligible Employee must elect to participate in the VRI by -------- -------- --- completing and signing the VRI enrollment and waiver and release forms --- provided by the COMPANY and returning the completed forms to a designated COMPANY representative no later than November 21, 1994. An Eligible -------- Employee who fails to submit timely both enrollment and waiver and release -------- forms shall be deemed to have elected not to participate in the VRI. The --- election of an Eligible Employee not to participate in the VRI, whether -------- -------- --- through failure to timely submit VRI election and waiver and release forms --- or otherwise, shall be conclusive and binding on the EMPLOYEE, EMPLOYEE'S spouse, heirs, and assigns. IV. VRI Benefit --- A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner ----- --- ------- -------- -------- to participate in the VRI shall be entitled to receive a Basic VRI --- ----- --- Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit ------- formula calculated under Subsection 6(a)(1) with the following adjustments: 1. SERVICE shall mean the PARTICIPANT'S SERVICE as of the VRI --- Retirement Date for such Eligible Employee, increased by three ---------- ---- -------- -------- years; and 2. The EARLY RETIREMENT PENSION reduction provisions of Subsection 7(b) shall not apply to any Basic VRI Benefit payable under this ----- --- ------- Special Provision N. B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date and ----- --- ------- --- ---------- ---- shall be paid as soon as practicable after the applicable VRI --- Retirement Date. Eligible Employees who elect to participate in the ---------- ---- -------- --------- VRI shall not be subject to the age 55 requirement contained in --- Section 8. C. Section 10 of the RETIREMENT PLAN shall control the conditions under which other forms of pension may be substituted for the Basic VRI ----- --- Benefit. Thus, although a PARTICIPANT is entitled to receive a Basic ------- ----- VRI Benefit, if the PARTICIPANT is married, Subsection 10(b) of the --- ------- RETIREMENT PLAN requires that the Basic VRI Benefit be converted to a ----- --- ------- MARITAL PENSION, unless the PARTICIPANT'S spouse consents to an alternative form of pension. D. The Basic VRI Benefit payable under this Special Provision N shall be ----- --- ------- in lieu of any benefit which might otherwise be payable under the RETIREMENT PLAN. E. A PARTICIPANT who elects to participate in VRI shall also be entitled --- to make the elections provided in Sections 10 (Forms of Pension), 12 (Withdrawal of Participant Contributions on Termination of Employment), 13 (Death Benefits), and 14 (Facility of Payment). V. VRI Retirement Dates --- ---------- ----- At such time as an EMPLOYEE elects to participate in the VRI, he shall --- select a VRI Retirement Date. For purposes of this Special Provision N, a --- ---------- ---- VRI Retirement Date shall mean one of the following: --- ---------- ---- A. January 1, 1995; or B. The first of any month during the period commencing with February 1, 1995, and ending with and including January 1, 1996. This Subsection B shall only apply in the event that the COMPANY has a demonstrated business need which requires the retention of the Eligible Employee. -------- -------- The selection of any such VRI Retirement Date subsequent to January 1, --- ---------- ---- 1995, can be made only with the written approval of the COMPANY'S Chief Executive Officer. The VRI Retirement Date selected shall also be the date as of which an --- ---------- ---- Eligible Employee ceases to be an EMPLOYEE of the COMPANY. -------- -------- -75- VI. Revocation of Election An Eligible Employee who has elected to participate in the VRI may -------- -------- --- revoke his election, provided, however, that any such revocation shall only be effective if received by the COMPANY on or before November 28, 1994. VII. Definitions A. Basic VRI Benefit: The benefit calculated under Section IV of this ----- --- ------- Special Provision N. B. Eligible Employee: An EMPLOYEE of the COMPANY who has met the -------- -------- eligibility criteria as set forth in Section II. EMPLOYEES of Pacific Gas Transmission Company, PG&E Enterprises, Pacific Service Employees Association, and any other subsidiary or affiliate of the COMPANY are not Eligible Employees for purposes of this VRI. -------- --------- --- C. VRI: The COMPANY's Voluntary Retirement Incentive program as set --- forth in this Special Provision N. D. VRI Retirement Date: The date selected by an Eligible Employee under --- ---------- ---- -------- -------- Section V of this Special Provision N. -76- EX-10.13 9 RETIREMENT PLAN FOR NON-EMPLOYEE DIRECTORS EXHIBIT 10.13 PG&E CORPORATION RETIREMENT PLAN FOR NON-EMPLOYEE DIRECTORS (As Amended December 17, 1997) 1. Purpose and Effective Date -------------------------- The purpose of the Plan, which was effective January 1, 1997, was to promote the interests of the Corporation by providing Retirement benefits to Directors in order to encourage their continued service on the Board of Directors of the Corporation. The Plan was terminated effective January 1, 1998, except that (i) Directors who had retired from the Corporation's Board of Directors prior to that date continue to receive payments under the Plan in accordance with the terms of the Plan as they existed prior to said date; and (ii) Directors who had not retired prior to that date were offered the one time election to (a) convert the net present value of the benefit accrued immediately prior to January 1, 1998, into units in the PG&E Stock Fund of the Deferred Compensation Plan for Non-Employee Directors and to transfer such units to that plan, the valuation of said accrued benefits to be made according to assumptions adopted by the Senior Human Resources Officer of the Corporation, or (b) to receive the benefits accrued under this Plan prior to January 1, 1998, upon their retirement from the Board in accordance with Section 3. In computing the benefits to be received under (ii)(a) or (b) above, the Retainer used shall be the Retainer applicable as of January 1, 1998. 2. Definitions ----------- The following terms shall have the meanings set forth below, if capitalized: (a) "Retainer" means the annual retainer paid to Board members for service on the Board of Directors as adjusted from time to time. The definition does not include any additional amount paid for service on a Board committee or as Board committee chairman or any amount specifically paid for attendance at Board or Board committee meetings. (b) "Corporation" means PG&E Corporation. (c) "Board" means the Board of Directors of the Corporation. (d) "Director" means a non-employee director or advisory director of PG&E Corporation. (e) "Plan" means the PG&E Corporation Retirement Plan for Non-Employee Directors, as amended from time to time. (f) "Eligible Director" means a Director who (i) is not an employee of the Corporation or its subsidiaries or affiliates at the time of the Director's Retirement; (ii) was a Director on or after January 1, 1997; and (iii) has served as a Director for a total of sixty calendar months or more, including service as an employee-director. Solely for purposes of determining whether a Director is an Eligible Director, service also shall include calendar months during which a Director (i) was serving as a director or advisory director of Pacific Gas and Electric Company, or (ii) was serving concurrently as a Director and as a director or advisory director of Pacific Gas and Electric Company. A month in which a Director was serving concurrently as a director or advisory director of Pacific Gas and Electric Company shall be counted as one month. (g) "Retirement" occurs when an Eligible Director ceases to be a member of the Board for any reason other than as a result of gross misconduct. (h) "Length of Service" is the Eligible Director's number of months of service as a Director, rounded to the next highest calendar quarter (for example, a Director who served 73 months would receive 25 quarterly payments--73 divided by 3, rounded to the next highest integer). Length of Service shall also include (i) service prior to January 1, 1997, as a director or advisory director of Pacific Gas and Electric Company; and (ii) concurrent service as both a Director of this Corporation and as a director or advisory director of the Pacific Gas and Electric Company. Length of Service shall not include service after December 31, 1997. Service as an employee-director shall not be included in the computation of Length of Service for purposes of determining the amount of Retirement benefits. 3. Retirement Payments ------------------- (a) Upon Retirement, an Eligible Director shall be paid each quarter an amount equal to the quarterly retainer paid to Directors as of the earlier of (i) the date of the Eligible Director's retirement from the Board, or (ii) the date immediately preceding the termination of the Plan. Retirement payments shall not be adjusted to reflect changes in the quarterly retainer effective after the date of the Eligible Director's Retirement. (b) Retirement payments shall begin in the calendar quarter immediately following the calendar quarter in which the Eligible Director retired from the Board or attained the age of 65, whichever comes later. The payments shall continue on a quarterly basis for a period equal to the Eligible Director's Length of Service. (c) If an Eligible Director dies after completing the service requirement for Retirement, but prior to receiving all Retirement payments, any remaining payments shall be made to such deceased Director's surviving spouse. (d) If an Eligible Director dies after completing the service requirement for Retirement, but prior to Retirement, his or her surviving spouse will receive payments equal to the amount to which the Eligible Director would have been entitled had he or she retired on the day prior to his or her date of death. 4. Disability ---------- If an Eligible Director ceases to serve on the Board as a result of disability, the Board in its sole discretion may waive the minimum service requirements or permit the commencement of Retirement benefits prior to age 65. -2- 5. Gross Misconduct ---------------- If an Eligible Director ceases to serve on the Board as a result of gross misconduct, any Retirement benefits payable under the Plan to such Eligible Director shall be canceled immediately and irrevocably. For purposes of this section, "gross misconduct" shall mean that an Eligible Director has (i) disclosed confidential business information of any type concerning the Corporation or any of its subsidiaries or affiliates to any party for any form of compensation which constitutes "gross income," as defined under Section 61 of the Internal Revenue Code or Regulations issued thereunder; or (ii) been indicted for intentionally or knowingly committing a crime against the Corporation or any of its subsidiaries or affiliates under federal law or the law of the state in which such act occurred; provided, however, an Eligible Director shall not be deemed to have committed gross misconduct if subsequent to being indicted for such a crime, the indictment is dismissed, a plea of nolo contendere is accepted, or the Eligible ---- ---------- Director has been found to be "not guilty" in a trial before an appropriate criminal court. 6. Amendment and Termination ------------------------- The Board reserves the right to amend, suspend, or terminate this Plan at any time. However, no such amendment, suspension, or termination shall have an adverse effect on Retirement payments to be made to an Eligible Director who retires prior to such amendment, suspension, or termination. 7. Prohibition or Alienation ------------------------- No Director shall have the right to alienate, assign, encumber, hypothecate, or pledge his or her interest in any payments to be made under the Plan, voluntarily or involuntarily, and any attempt to so dispose of any such interest shall be void. The Corporation shall have the right to set off against Retirement payments under the Plan any amounts due and owing from the Eligible Director to the Corporation and its parent, subsidiaries, or affiliates, to the extent permitted by law. 8. Unfunded Plan ------------- The Plan is unfunded, and the Corporation shall not be required to segregate any cash or establish any separate account or accounts to fund any Retirement payment to be made under the Plan. 9. Entire Plan ----------- This document is a complete statement of the Plan and as of its effective date supersedes all prior plans, proposals, representations, promises, inducements, written or oral, relating to its subject matter. The Corporation shall not be bound or liable to any Director for any representation, promise, or inducement made by any person which is not embodied in this document or in any authorized written amendment to the Plan. -3- 10. Applicable Law -------------- The Plan will be construed and enforced in accordance with the laws of California. -4- EX-10.15 10 LONG-TERM INCENTIVE PROGRAM EXHIBIT 10.15 PG&E CORPORATION LONG-TERM INCENTIVE PROGRAM (As amended and restated effective as of January 1, 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; (c) to designate the types of INCENTIVE AWARD being granted; - ----------------- /1/ Capitalized words are defined in Section 20 hereof. (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 DI RECTORS 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 requires approval by the COMMITTEE; (b) to determine the time or times at which INCENTIVE AWARDS shall be granted to such ELIGIBLE 2 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 RECIPIENT or the CORPORATION to terminate such employment, service as a DIRECTOR or consulting relationship at any time, with or without cause. 3 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. INCENTIVE AWARDS shall be awarded at no cost to the RECIPIENT. 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, subject to the terms and conditions set forth in the PERFORMANCE UNIT PLAN attached hereto as Exhibit B. 4 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 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. 5 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): (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; 6 (c) All conditions relating to the realization of any STOCK-BASED AWARD granted hereunder shall immediately terminate; and (d) The COMMITTEE may offer any RECIPIENT the option of having the CORPORATION purchase his or her INCENTIVE AWARD for an amount of cash which could have been attained upon the exercise or realization of such INCENTIVE AWARD had it been fully exercisable or realizable; unless the COMMITTEE in its sole discretion determines that such CHANGE IN CONTROL will not adversely impact the RECIPIENTS of INCENTIVE AWARDS hereunder and is in the best interests of the shareholders of PG&E CORPORATION. The COMMITTEE may make such further provisions with respect to a CHANGE IN CONTROL as it shall deem equitable and in the best interests of the shareholders of PG&E CORPORATION. Such provision may be made in any agreement relating to any INCENTIVE AWARD granted hereunder, by amendment to any such agreement or by resolution of the COMMITTEE. The phrase "CHANGE IN CONTROL" shall have such meaning as ascribed thereto from time to time by the COMMITTEE and set forth in any agreement relating to any INCENTIVE AWARD granted hereunder or by resolution of the COMMITTEE; provided, however, that, notwithstanding the foregoing, 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 (c) the shareholders of PG&E CORPORATION shall have approved (i) any consolidation or merger of PG&E CORPORATION in which PG&E CORPORATION is not the continuing or surviving corporation or pursuant to which shares of COMMON STOCK are converted into cash, securities or other property, other than a merger of PG&E CORPORATION in which the holders of the COMMON STOCK 7 immediately prior to the merger have the same proportionate ownership of common stock of the surviving corporation immediately after the merger, (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 PG&E CORPORATION. Notwithstanding the foregoing, the phrase "CHANGE IN CONTROL" shall not apply to any reorganization or merger initiated voluntarily by PG&E CORPORATION in which PG&E CORPORATION is the continuing surviving entity. 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 8 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 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 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 subsequent 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 October 15,1997, 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. 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. 9 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. 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 10 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. 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 CORPORATION 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. 11 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. 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. 12 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, 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 January 1, 1997) 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; (c) to designate the OPTIONS being granted as ISOS or NON-QUALIFIED STOCK OPTIONS; - ------------------ /2/ Capitalized words are defined in Section 20 hereof. 14 (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 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 15 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. 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 16 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. OPTIONS shall be awarded at no cost to the OPTIONEE. 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 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 17 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. (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. 18 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. Notwithstanding the foregoing, any ISOS held by the OPTIONEE may be exercised only within their respective terms or within three (3) months after RETIREMENT, whichever is shorter. (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 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. Notwithstanding the foregoing, any ISOS held by the OPTIONEE may be 19 exercised only within their respective terms or within three (3) months after such TERMINATION, whichever is shorter. (e) In the event of a TERMINATION for any reason other than those specified in subparagraphs (a) through (d) 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 any) shall not be credited with any dividends paid after the date of such TERMINATION. (f) Notwithstanding the provisions of subparagraphs (a) through (e) 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. 20 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. 16. Change in Control ----------------- Upon the occurrence of a CHANGE IN CONTROL (as defined below): (a) 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; and (b) The COMMITTEE may offer any OPTIONEE the option of having the CORPORATION purchase his or her OPTION for an amount of cash which could have been attained upon the exercise of such OPTION had it been fully exercisable; unless the COMMITTEE in its sole discretion determines that such CHANGE IN CONTROL will not adversely impact the OPTIONEES of OPTIONS hereunder and is in the best interests of the shareholders of PG&E CORPORATION. The COMMITTEE may make such further provisions with respect to a CHANGE IN CONTROL as it shall deem equitable and in the best interests of the shareholders of PG&E CORPORATION. Such provision may be made in any agreement relating to any OPTION granted hereunder, by amendment to any such agreement or by resolution of the COMMITTEE. The phrase "CHANGE IN CONTROL" shall have such meaning as ascribed thereto from time to time by the COMMITTEE and set forth in any agreement relating to any OPTION granted hereunder or by resolution of the COMMITTEE; provided, however, that, notwithstanding the foregoing, 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 21 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 PG&E CORPORATION shall have approved (i) any consolidation or merger of PG&E CORPORATION in which PG&E CORPORATION is not the continuing or surviving corporation or pursuant to which shares of COMMON STOCK are converted into cash, securities or other property, other than a merger of PG&E CORPORATION in which the holders of the COMMON STOCK immediately prior to the merger have the same proportionate ownership of common stock of the surviving corporation immediately after the merger, (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 PG&E CORPORATION. Notwithstanding the foregoing, the phrase "CHANGE IN CONTROL" shall not apply to any reorganization or merger initiated voluntarily by PG&E CORPORATION in which PG&E CORPORATION is the continuing surviving entity. 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 RULE 16b-3 or 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 22 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 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. 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. 23 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. --- 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. 24 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 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. ---------------- 25 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. ab. 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. ac. 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. ad. 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. ae. TANDEM refers to a DIVIDEND EQUIVALENT or SAR (as the case may be) ------ granted in conjunction with an OPTION. af. 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. ag. TERMINATION FOR CAUSE has the meaning set forth in Section 12 hereof. --------------------- 26 EXHIBIT B PERFORMANCE UNIT PLAN OF PG&E CORPORATION ___________________________ (As amended and restated effective as of January 1, 1997) 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. 27 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; b. One-third after the end of the second YEAR of the VESTING PERIOD; and 28 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. 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 29 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. 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 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. 30 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. 31 EXHIBIT C PG&E CORPORATION NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN (As amended and restated effective as of January 1, 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/4/). 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 - -------------------- /4/ Capitalized words are defined in Section 15 hereof. 32 this Section 3(a). The number of shares of DIRECTOR RESTRICTED 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, 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. 33 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 a value (as determined in accordance with the Black-Scholes stock option valuation method which will use the average November closing price of PG&E Corporation stock as the value for PG&E Corporation stock) equal to $5,000, $10,000, $15,000, or $20,000, as previously elected by the NON-EMPLOYEE DIRECTOR (the "Elected Option Value"), provided, however that a NON- EMPLOYEE DIRECTOR who has failed to make a timely election in accordance with Section 4 shall receive a grant of NON-QUALIFIED STOCK OPTIONS with a value (as determined in accordance with the Black- Scholes stock option valuation method which will use the average November closing price of PG&E Corporation stock as the value for PG&E Corporation stock) equal to $10,000. The number of shares subject to the NON-QUALIFIED STOCK OPTIONS to be granted to each NON-EMPLOYEE DIRECTOR each calendar year shall be that number which will yield a present value of the NON-QUALIFIED STOCK OPTIONS, as of the first business day of the applicable calendar year, equal to (i) the Elected Option 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), and (ii) rounding the resulting number 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 34 OPTION. The CORPORATION shall not make loans to any GRANTEE for the purpose of exercising NON-QUALIFIED STOCK OPTIONS. (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 sixty 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 to be granted to each NON-EMPLOYEE DIRECTOR each calendar year shall be determined by (i) 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 and (ii) rounding the resulting number down to the nearest whole share. 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 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. 35 (b) Each NON-EMPLOYEE DIRECTORS' PHANTOM STOCK account shall be credited quarterly on each dividend record date with additional shares of PHANTOM STOCK determined by (i) dividing the amount of dividends which would have been paid on the number of shares of COMMON STOCK equal to the number of shares of PHANTOM STOCK previously credited to the PHANTOM STOCK account by the FAIR MARKET VALUE of the COMMON STOCK on the dividend record date, and (ii) rounding the resulting number down to the nearest whole share of PHANTOM STOCK. No additional shares of PHANTOM STOCK shall be credited to a NON-EMPLOYEE DIRECTOR'S account after the date of the NON-EMPLOYEE DIRECTOR'S TERMINATION. (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 RETIREMENT or MANDATORY RETIREMENT. 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 an equal number of annual installments over a period not to exceed ten years from the date of the NON-EMPLOYEE DIRECTOR'S RETIREMENT or MANDATORY RETIREMENT. 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 36 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 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. 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 37 PHANTOM STOCK account shall become payable to the GRANTEE in accordance with Section 6(c) hereof. (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 38 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 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, unless the COMMITTEE or BOARD OF DIRECTORS determines that such CHANGE IN CONTROL will not adversely impact the GRANTEES' DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS, or PHANTOM STOCK granted hereunder and is in the best interests of the shareholders of PG&E CORPORATION. The COMMITTEE or BOARD OF DIRECTORS may make such further provisions with respect to a CHANGE IN CONTROL as it shall deem equitable and in the best interests of the shareholders of PG&E CORPORATION. Such provision may be made in any agreement relating to any DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS, or PHANTOM STOCK granted hereunder, by amendment to any such agreement or by resolution of the COMMITTEE or BOARD OF DIRECTORS. The phrase "CHANGE IN CONTROL" shall have such meaning as ascribed thereto from time to time by the COMMITTEE or BOARD OF DIRECTORS and set forth in any agreement relating to any DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS, or PHANTOM STOCK granted hereunder or by resolution of the COMMITTEE or BOARD OF DIRECTORS; provided, however, that, notwithstanding the foregoing, 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; 39 (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 (c) the shareholders of PG&E CORPORATION shall have approved (i) any consolidation or merger of PG&E CORPORATION in which PG&E CORPORATION is not the continuing or surviving corporation or pursuant to which shares of COMMON STOCK are converted into cash, securities or other property, other than a merger of PG&E CORPORATION in which the holders of the COMMON STOCK immediately prior to the merger have the same proportionate ownership of common stock of the surviving corporation immediately after the merger, (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 PG&E CORPORATION. Notwithstanding the foregoing, the phrase "CHANGE IN CONTROL" shall not apply to any reorganization or merger initiated voluntarily by PG&E CORPORATION in which PG&E CORPORATION is the continuing surviving entity. 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, 40 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. Unless terminated sooner pursuant to Section 13 hereof, the PLAN shall terminate on December 31, 2005. 15. Definitions ----------- i) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION. ------------------ ii) CHANGE IN CONTROL has the meaning set forth in Section 10 hereof. ----------------- iii) CODE means the Internal Revenue Code of 1986, as amended from time to ---- time. iv) COMMITTEE means the Nominating and Compensation Committee of the --------- BOARD OF DIRECTORS or any successor to such committee. v) 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. vi) 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). vii) 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. 41 viii) DIRECTOR RESTRICTED STOCK means RESTRICTED STOCK granted to a NON- ------------------------- EMPLOYEE DIRECTOR under the PLAN. ix) 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. x) ERISA means the Employee Retirement Income Security Act of 1974, as ----- amended. xi) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended. ------------ xii) 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. xiii) GRANTEE means the NON-EMPLOYEE DIRECTOR receiving the DIRECTOR ------- RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK or his or her legal representative, legatees, distributees or alternate payees, as the case may be. xiv) 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. xv) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE. --------------------- xvi) 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. xvii) PG&E CORPORATION means PG&E CORPORATION, a California corporation. ---------------- xviii) PHANTOM STOCK means allocated hypothetical shares of COMMON STOCK ------------- that can be converted at a future date into stock. xix) 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 42 with respect to the grant of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS, PHANTOM STOCK or other stock-based incentive awards under the PROGRAM. xx) 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. xxi) 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. xxii) RETIREMENT means TERMINATION of service on the BOARD OF DIRECTORS ---------- after serving continuously for five consecutive years. xxiii) 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. xxiv) 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). 43 EX-10.16 11 EXECUTIVE STOCK OWNERSHIP PROGRAM Exhibit 10.16 PG&E CORPORATION EXECUTIVE STOCK OWNERSHIP PROGRAM Administrative Guidelines ------------------------- (November 19, 1997) 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, 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 & VP-HR 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. 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 equivalent 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 (including vested SISOP units, as discussed below) is determined by multiplying the number of vested units held by the Eligible Executive 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 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. 2 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 7. 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. 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 PG&E Corporation Phantom Stock Fund of the Deferred Compensation Plan and converted into Units of that Fund. The initial value of a Unit shall be calculated in accordance with the valuation of initial deferrals into the PG&E Corporation Phantom Stock Fund of the Deferred Compensation Plan. Once a SISOP Unit is credited to the account of an Eligible Executive under the Deferred Compensation Plan, it shall be subject to all of the terms and conditions applicable to Units held in the PG&E Corporation Phantom Stock Fund, and such other Plan provisions which by their terms specifically govern SISOPs. 7. Forfeiture of Units. Units attributable to SISOPs do not vest until the ------------------- third anniversary of the date that they are credited to the Deferred Compensation Plan. So long as SISOP Units remain unvested, such Units are subject to forfeiture if, on each Measurement Date, the number of shares and units held by the Eligible Executive 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 vested units held by the Eligible Executive 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, vested units, and share-equivalents of vested "in the money" options is added together. This total (Current Holdings) is compared 3 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 SISOPs are forfeited. If the Current Holdings are less than the Minimum Ownership Level, then the unvested SISOPs 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 SISOPs are forfeited). 8. 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 Phantom Stock Fund of the Deferred Compensation Plan of annual awards from the Performance Unit Plan ("PUP") and the Performance Incentive Plan ("PIP"). As of any measurement date, to the extent that stock ownership levels are below Target, PUP awards shall be converted into Units and held in the Phantom Stock Fund. If, with the addition of the Units attributable to the PUP award, the stock ownership level is still below Target for any Measurement Date, any PIP award above target also shall be converted into Units held in the Phantom Stock Fund, to the extent of Target. Such conversion of PUP and PIP awards shall continue for successive Measurement Dates, if necessary, until Target is met. Units attributable to PUP and PIP awards described in this paragraph 8 will be paid from the Deferred Compensation Plan as soon as practicable after the date on which such payment will not result in a stock ownership level below Target, or such latter date as may be elected by the Eligible Executive at the time that the award is credited to the Deferred Compensation Plan for Officers. 4 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) 1997 1996 1995 - -------------------------------------------------------------------------------- EARNINGS PER COMMON SHARE (EPS) AS SHOWN IN THE STATEMENT OF CONSOLIDATED INCOME Earnings available for common stock $715,940 $722,096 $1,268,597 ======== ======== ========== Average common shares outstanding 410,040 412,542 423,692 ======== ======== ========== Basic EPS $1.75 $1.75 $2.99 ======== ======== ========== DILUTED EPS (1) Earnings available for common stock $715,940 $722,096 $1,268,597 ======== ======== ========== Average common shares outstanding 410,040 412,542 423,692 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) 211 9 126 -------- -------- ---------- Average common shares outstanding as adjusted 410,251 412,551 423,818 ======== ======== ========== Diluted EPS $ 1.75 $ 1.75 $ 2.99 ======== ======== ========== - -----------------------------------------------------------------------------
(1) This presentation is submitted in accordance with Statement of Financial Accounting Standards No. 128. EX-12.1 13 COMPUTATION 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) 1997 1996 1995 1994 1993 - ----------------------------------------------------------------------------------------------------------- Earnings: Net income $ 768 $ 755 $ 1,339 $ 1,007 $ 1,065 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) 7 Income tax expense 609 555 895 837 902 Net fixed charges 628 683 716 729 775 -------- -------- -------- ------- ------- Total Earnings $ 2,005 $ 1,996 $ 2,954 $ 2,570 $ 2,749 ======== ======== ======== ======= ======= Fixed Charges: Interest on long-term debt, net $ 485 $ 574 $ 616 $ 639 $ 652 Interest on short-term borrowings 101 75 83 77 88 Interest on capital leases 2 3 3 2 2 Capitalized Interest 1 1 - 2 46 AFUDC Debt 16 7 11 11 33 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned subsidiaries 24 24 3 - - -------- -------- -------- ------- ------ Total Fixed Charges $ 629 $ 684 $ 716 $ 731 $ 821 ======== ======== ======== ======= ====== Ratios of Earnings to Fixed Charges 3.19 2.92 4.13 3.52 3.35 - -----------------------------------------------------------------------------------------------------------
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) 1997 1996 1995 1994 1993 - ------------------------------------------------------------------------------------------------------------ Earnings: Net income $ 768 $ 755 $ 1,339 $ 1,007 $ 1,065 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) 7 Income tax expense 609 555 895 837 902 Net fixed charges 628 683 716 729 775 -------- -------- -------- ------- ------- Total Earnings $ 2,005 $ 1,996 $ 2,954 $ 2,570 $ 2,749 ======== ======== ======== ======= ======= Fixed Charges: Interest on long-term debt $ 485 $ 574 $ 616 $ 639 $ 652 Interest on short-term debt 101 75 83 77 88 Interest on capital leases 2 3 3 2 2 Capitalized Interest 1 1 - 2 46 AFUDC Debt 16 7 11 11 33 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned subsidiaries 24 24 3 - - -------- -------- -------- ------- ------- Total Fixed Charges $ 629 $ 684 $ 716 $ 731 $ 821 -------- -------- -------- ------- ------- Preferred Stock Dividends: Tax deductible dividends $ 10 $ 10 $ 11 $ 5 $ 5 Pretax earnings required to cover non-tax deductible preferred stock dividend requirements 39 39 100 96 109 -------- -------- -------- ------- ------- Total Preferred Stock Dividends $ 49 $ 49 $ 111 $ 101 $ 114 -------- -------- -------- ------- ------- Total Combined Fixed Charges and Preferred Stock Dividends $ 678 $ 733 $ 827 $ 832 $ 935 ======== ======== ======== ======= ======= Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 2.96 2.72 3.57 3.09 2.94 - ------------------------------------------------------------------------------------------------------------
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) 1997 1996 1995 1994 1993 - ------------------------------------------------------------------------------------------------------------------------- PG&E Corporation(1) For the Year Operating revenues $15,400 $ 9,610 $ 9,622 $10,350 $10,550 Operating income 1,728 1,896 2,763 2,424 2,560 Net income 716 722 1,269 950 1,002 Earnings per common share 1.75 1.75 2.99 2.21 2.33 Dividends declared per common share 1.20 1.77 1.96 1.96 1.88 At Year End Book value per common share $ 21.30 $ 20.73 $ 20.77 $ 20.07 $ 19.77 Common stock price per share 30.31 21.00 28.38 24.38 35.13 Total assets 30,557 26,237 26,871 27,738 27,234 Long-term debt (excluding current portions) 7,659 7,770 8,049 8,676 9,292 Rate reduction bonds (excluding current portions) 2,776 - - - - Preferred stock and securities of subsidiary with mandatory redemption provisions (excluding current portions) 437 437 437 137 75 Pacific Gas and Electric Company For the Year Operating revenues $ 9,495 $ 9,610 $ 9,622 $10,350 $10,550 Operating income 1,831 1,896 2,763 2,424 2,560 Income available for common stock 735 722 1,269 950 1,002 At Year End Total assets $25,147 $26,237 $26,871 $27,738 $27,234 Long-term debt (excluding current portions) 6,218 7,770 8,049 8,676 9,292 Rate reduction bonds (excluding current portions) 2,776 - - - - Preferred stock and securities with mandatory redemption provisions (excluding current portions) 437 437 437 137 75
(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 for the years 1993 through 1996 are identical because they represent the accounts of Pacific Gas and Electric Company as the predecessor of PG&E Corporation. See Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition for further discussion of the holding company formation and matters relating to certain data above. 16 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition San Francisco-based PG&E Corporation provides energy services throughout the United States and Australia. We were formed as a holding company on January 1, 1997, to respond to new business opportunities and changes in the energy industry. As a result, Pacific Gas and Electric Company became a subsidiary of its new parent holding company, PG&E Corporation, and its ownership interest in its unregulated subsidiaries was transferred to PG&E Corporation. Under our new corporate structure, we provide integrated energy services through our various business lines: Pacific Gas and Electric Company (Utility) Our Utility provides gas and electric service to Northern and Central California. Our Utility is regulated by the California Public Utilities Commission (CPUC), the Federal Energy Regulatory Commission (FERC), and the Nuclear Regulatory Commission, among others. Unregulated Business Operations We provide a wide range of integrated energy products and services designed to take advantage of the opening of the competitive energy marketplace throughout the United States. Through our other subsidiaries, we provide the following energy services: Gas Transmission: We own and operate approximately 10,000 miles of natural gas pipelines, natural gas storage facilities, and natural gas processing plants in the Pacific Northwest, Texas, and Australia through PG&E Gas Transmission (PG&E GT). PG&E GT's Pacific Northwest operations are regulated by the FERC, and its Texas operations are regulated by the Texas Railroad Commission. Electric Generation: We develop, build, operate, own, and manage power generation facilities across the United States through U.S. Generating Company (USGen). In 1998, USGen expects to complete the acquisition of the New England Electric System fossil fuel and hydroelectric power plants. This acquisition is discussed further in the Acquisitions and Sales section below. Energy Services and Commodities: We provide 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 (PG&E ES). Through PG&E Energy Trading (PG&E ET), we purchase and resell energy commodities and related financial instruments in major domestic markets, serving PG&E Corporation's other unregulated businesses, unaffiliated utilities, and large end-use customers. Overview This is a combined annual report of PG&E Corporation and Pacific Gas and Electric Company. Therefore, our Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition apply to both PG&E Corporation and the Utility. PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation and its wholly owned and controlled subsidiaries, including the Utility (collectively, the Corporation). Our Utility's consolidated financial statements include its accounts as well as those of its wholly owned and controlled subsidiaries. Because PG&E Corporation did not become the holding company for the Utility until January 1, 1997, the 1995 and 1996 consolidated financial statements represent the accounts of the Utility on a consolidated basis as predecessor of PG&E Corporation. Management's Discussion and Analysis should be read in conjunction with the consolidated financial statements. In Management's Discussion and Analysis, we explain the results of operations for the years 1995 through 1997 and discuss our financial condition. Our discussion of financial condition includes: . energy industry restructuring and how this restructuring will influence future results of operations, . liquidity and capital resources, including discussions of capital financing activities, estimated capital spending for the next three years, and uncertainties that could affect future results, and . risk management activities. 17 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition This combined annual report, including our Letter to Shareholders above and our discussion of results of operations and financial condition below, contains forward-looking statements that involve risks and uncertainties. Also, words such as "estimates," "expects," "anticipates," "plans," "believes," and similar expressions identify forward-looking statements involving risks and uncertainties. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric and gas industries, the outcome of the regulatory proceedings related to those restructurings, our Utility's ability to collect revenues sufficient to recover transition costs in accordance with its cost recovery plan, the impact of our recent or planned acquisitions as discussed in the Acquisitions and Sales section below, the approval of our Utility's 1999 General Rate Case application resulting in the Utility's ability to earn its authorized rate of return as discussed in the Letter to Shareholders above and in the Regulatory Activity section below, and our ability to successfully compete outside our traditional regulated markets, as discussed in the Letter to Shareholders above. The ultimate impacts on future results of increased competition, the changing regulatory environment, our expansion into new businesses and markets, and the CPUC's decision on the 1999 General Rate Case application are uncertain, but all are expected to fundamentally change how we conduct our business. The outcome of these changes and other matters discussed below may cause future results to differ materially from historic results, or from results or outcomes currently expected or sought by PG&E Corporation. Results of Operations In this section, we provide the components of our earnings for 1997, 1996, and 1995. We then explain why operating revenues and expenses for 1997 and 1996 were different from the year before. The following table shows our results of operations and total assets for 1997, 1996, and 1995. The results of operations for PG&E Corporation on a stand-alone basis and intercompany eliminations have been shown as Corporate and Other.
Unregulated Corporate Business and Utility Operations Other Total - --------------------------------------------------------------------------- (in millions) 1997 Operating revenues $ 9,495 $6,351 $ (446) $15,400 Operating expenses 7,664 6,433 (425) 13,672 -------------------------------------------- Operating income (loss) before income taxes $ 1,831 $ (82) $ (21) $ 1,728 ============================================ Income available for common stock $ 735 $ 8 $ (27) $ 716 ============================================ Total assets $25,147 $6,224 $ (814) $30,557 ============================================ 1996 Operating revenues $ 8,989 $ 679 $ (58) $ 9,610 Operating expenses 7,179 595 (60) 7,714 -------------------------------------------- Operating income before income taxes $ 1,810 $ 84 $ 2 $ 1,896 ============================================ Income available for common stock $ 707 $ 15 $ - $ 722 ============================================ Total assets $23,567 $2,858 $ (188) $26,237 ============================================ 1995 Operating revenues $ 9,243 $ 447 $ (68) $ 9,622 Operating expenses 6,556 376 (73) 6,859 -------------------------------------------- Operating income before income taxes $ 2,687 $ 71 $ 5 $ 2,763 ============================================ Income available for common stock $ 1,210 $ 59 $ - $ 1,269 ============================================ Total assets $24,689 $2,578 $ (396) $26,871 ============================================
Earnings Per Common Share: Basic and diluted earnings per common share were $1.75, $1.75, and $2.99 for 1997, 1996, and 1995, respectively. Earnings per common share were affected by the activity discussed below. 18 Utility Results: 1997 COMPARED TO 1996 Our Utility operating revenues in 1997 increased $506 million from 1996. The largest portion of the increase was due to transition cost recovery related to the revisions in the Diablo Canyon Nuclear Power Plant (Diablo Canyon) ratemaking structure discussed in Electric Transition Plan below. A portion of the increase is due to increased revenues associated with electric transmission and distribution system reliability authorized by California Assembly Bill 1890, the electric industry restructuring legislation. There was also an increase in energy cost revenues to recover energy cost increases and changes in sales volume provided by our Utility's energy rate recovery mechanism. Under energy rate recovery mechanisms, energy rate revenues generally equal energy costs and, thus, increases in the cost of energy do not affect operating income. Our Utility operating expenses in 1997 increased $485 million from 1996. The increase was due primarily to the increase in Diablo Canyon depreciation (which provided the revenue increases discussed above for recovery of the increased depreciation) and the increase in cost of energy. This increase was partially offset by a decrease in expenses for several 1996 one-time charges associated with gas transportation commitments and a 1996 one-time charge due to a litigation reserve. Other income increased in 1997 compared to 1996 primarily due to a gain on the buyout of a long-term contract for gas transportation service. 1996 COMPARED TO 1995 Our Utility operating revenues in 1996 decreased $254 million from 1995 due to revenue reductions ordered in the 1996 General Rate Case. The revenue decrease was also due to a decline in the Diablo Canyon generation price, as provided in the Diablo Canyon rate case settlement. This lower generation price was partially offset by higher net generation, which was a result of fewer scheduled refuelings in 1996 compared to 1995. We maintain an automatic adjustment clause (Gas Balancing Account) pursuant to which 1996 revenues were increased to reflect the increase in gas prices in 1996 as compared to 1995. However, this increase to gas revenues was offset by a corresponding revenue decrease ordered in the 1996 General Rate Case. Our Utility operating expenses increased $623 million in 1996 primarily due to charges for gas transportation commitments, increases in gas and purchased power prices, increases in expenses related to transmission and distribution system reliability, and increases in litigation costs. Unregulated Business Results: 1997 COMPARED TO 1996 Our unregulated business operating revenues in 1997 increased $5,672 million from 1996. This was primarily due to a $4,524 million increase in energy commodities and services revenues from the acquisitions of Energy Source (ES) in December 1996, Teco Pipeline Company (Teco) in January 1997, and Valero Energy Corporation (Valero) in July 1997. Also contributing to the increase were the new revenues from the gas pipeline operations of Teco and Valero. Our unregulated business operating expenses in 1997 increased $5,838 million from 1996 which essentially reflects the increase in the cost of gas for resale due to the above acquisitions and our expansion into the energy commodities and services industry. Other income increased in 1997 compared to 1996 primarily due to the gain on the sale of International Generating Company, Ltd. which was partially offset by write-downs of certain nonregulated investments. 1996 COMPARED TO 1995 Our unregulated business operating revenues and operating expenses in 1996 increased $232 and $219 million, respectively, from 1995 primarily due to the purchase of ES in December 1996. This purchase created $283 million of revenue but was offset by an increase in the cost of gas for resale. The increase in both operating revenues and operating expenses was partially offset by a decrease due to the sale of DALEN Corporation in 1995. Other income decreased in 1996 compared to 1995 primarily due to write-downs of certain nonregulated investments in 1996. 19 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition Common Stock Dividend: Our common stock dividend is based 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. The CPUC set a number of conditions when PG&E Corporation was formed as a holding company. One of these conditions requires our Utility to maintain, on average, its CPUC-authorized capital structure, potentially limiting the amount of dividends our Utility may pay PG&E Corporation. At December 31, 1997, our Utility was in compliance with its CPUC-authorized capital structure. We believe that our Utility will continue to meet this condition in the future without affecting our ability to pay common stock dividends to common shareholders. Financial Condition We begin this section by discussing the energy industry. We also discuss how the Corporation is responding to restructuring on a national level, including recent and planned acquisitions. We then discuss liquidity and capital resources and our risk management activities. Energy Industry: The Electric Business: California has been in the forefront of the nation's move towards competitive energy markets. In 1998, Californians will be able to choose who will provide their electric power. Customers within our Utility's service territory can purchase electricity (1) from our Utility, (2) from retail electricity providers (for example, marketers including our energy service subsidiary, brokers, and aggregators), or (3) directly from unregulated power generators. Our Utility will continue to provide distribution services to substantially all electric consumers within its service territory. To create this competitive generation market, California has established a Power Exchange (PX) and an Independent Systems Operator (ISO). The PX will be an open electric marketplace where electricity prices are set. The ISO will oversee California's electric transmission grid making sure that all generators have comparable access. California utilities will retain ownership of utility transmission facilities but will relinquish operating control to the ISO. Competing electric providers will bid their electric commodity into the PX. The PX will accept the lowest bids to satisfy the aggregate electric demand and establish a market price. Customers choosing to buy power directly from non- regulated generators or retailers will pay for that generation based upon negotiated contracts. The PX and ISO are expected to be operational by March 31, 1998. CPUC regulation requires our Utility to purchase all electric power for its retail customers from the PX. And, we must bid all of our Utility-generated electric power to the PX. Generation revenues currently make up approximately 30 percent of our total Utility revenues. The competitive market environment will significantly change the way our Utility earns revenues. Over the past several years, we have been taking steps to prepare for these changes. We have been working with the CPUC to ensure a smooth transition into the competitive market environment. And, we have made strategic investments throughout the nation that will further position us as a national energy provider. The following sections discuss the transition plan. A discussion of the investments we have made is included in Our Response to Changes in Our Industry, below. ELECTRIC TRANSITION PLAN In the new competitive market, our Utility's generation revenues will be determined principally by the market through sales to the PX. However, market- based revenues may not be sufficient to recover (that is, to collect from customers) all generation costs resulting from past CPUC decisions. To recover these uneconomic costs, called "transition costs," and to ensure a smooth transition to the competitive environment, our Utility in conjunction with other California electric utilities, the CPUC, state legislators, consumer advocates, and others, developed a transition plan, in the form of state legislation, to position California for the new market environment. 20 There are three principal elements to this transition plan: (1) an electric rate freeze and rate reduction, (2) recovery of transition costs, and (3) economic divestiture of Utility-owned generation facilities. Each one of these three elements, the impact of the transition plan on our Utility's customers, and the impact of the transition plan on our application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," are discussed below. The transition plan will remain in effect until the earlier of March 31, 2002, or when we have recovered our authorized transition costs as determined by the CPUC. This period is referred to as the transition period. At the conclusion of the transition period, we will be at risk to recover any of our Utility's remaining generation costs through market-based revenues. . Rate Freeze and Rate Reduction The first element of the transition plan is an electric rate freeze and an electric rate reduction. During 1997, electric rates for our Utility's customers were held at 1996 levels. Effective January 1, 1998, we reduced electric rates for our Utility's residential and small commercial customers by 10 percent and will hold their rates at that level. The rate freeze will continue until the end of the transition period. To pay for the 10 percent rate reduction, we financed $2.9 billion of our transition costs with rate reduction bonds. See Cash Flows from Financing Activities below. . Transition Cost Recovery The second element of the transition plan is recovery of transition costs. Transition cost recovery has five parts for determining: (1) which costs are eligible for recovery as transition costs, (2) when they can be recovered, (3) how transition cost revenues will be determined, (4) how transition costs will be expensed, and (5) what happens when transition cost revenues differ from the related expenses. Each of these five parts is discussed below. The first part of transition cost recovery is determining which Utility costs are eligible for recovery as transition costs. These costs include: (1) above- market sunk costs (sunk costs are costs associated with Utility-owned generating facilities that are fixed and unavoidable and currently included in our Utility customers' electric rates) and future costs, such as costs related to plant removal, (2) costs associated with the Utility's long-term contracts to purchase power at above-market prices from Qualifying Facilities (QF) 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 that are disallowed by the CPUC for collection from Utility customers will be written off. Each of the types of eligible transition costs are discussed below. Sunk costs associated with Utility-owned generation facilities are currently included in our Utility customers' rates. Above-market sunk costs are those whose values recorded on our balance sheet (book value) are expected to be in excess of their market values. Conversely, below-market sunk costs are those whose market values are expected to be in excess of their book values. In general, 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. The above- market portion of sunk costs is eligible for recovery as a transition cost. The below-market portion of sunk costs will reduce other unrecovered transition costs. A valuation of Utility-owned generation facilities where the market value exceeds the book value could result in a material charge if the Utility retains the facility. This is because any excess of market value over book value would be used to reduce other transition costs without being collected in rates. We will not be able to determine the exact amount of sunk costs that will be recoverable as transition costs until a market valuation process (appraisal, spin, or sale) is completed for each of our Utility's generation facilities. The first of these valuations occurred in 1997 when we agreed to sell three Utility- owned electric plants for $501 million. The sale is expected to close during 1998. (See Generation Divestiture below.) The rest of the valuation process will be completed by December 31, 2001. At December 31, 1997, our Utility's net investment in Diablo Canyon and Utility-owned non-nuclear generation facilities was $3.7 billion and $2.7 billion, respectively, including the plants to be sold in 1998. 21 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition Our Utility has agreed to purchase electric power from QFs and other power suppliers under long-term contracts expiring on various dates through 2028. Over the life of these contracts, the Utility estimates that it will purchase approximately 360 million megawatt-hours (MWh) at an aggregate average price of 6.3 cents per kilowatt-hour (kWh). To the extent that this price is above the market price, our 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. In addition, as of December 31, 1997, we have accumulated approximately $1.5 billion of generation-related net regulatory assets. The net regulatory assets are eligible for recovery as transition costs. The CPUC has the ultimate authority to determine which costs are eligible to be recovered as transition costs. Reviews by the CPUC to determine the reasonableness of transition costs are being conducted and will continue to be conducted throughout the transition period. The second part of transition cost recovery is determining when eligible transition costs can be recovered. Under the transition plan, most transition costs must be recovered by March 31, 2002. This recovery period is significantly shorter than the recovery period of the related assets prior to restructuring. Recovery of transition costs during this shorter period is referred to as accelerated recovery. The CPUC believes that acceleration reduces risks associated with recovery of all our Utility's generation assets, including Diablo Canyon and hydroelectric facilities. As a result, in accordance with the transition plan, we are receiving a reduced return for all of our Utility-owned generation facilities. In 1997, the reduced return was 7.13 percent as compared to an authorized return of 9.45 percent. The reduced return on non-nuclear generation assets, effective July 28, 1997, resulted in a $24 million decrease in earnings ($0.06 per share) in 1997 and will have a continued impact throughout the transition period. Although most transition costs must be recovered by March 31, 2002, certain transition costs can be included in customers' electric rates after the transition period. These costs include: (1) certain employee-related transition costs, (2) above-market payments under existing QF and power-purchase contracts 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 the facility. During the rate freeze, this charge will not increase our Utility customers' electric rates. Excluding these exceptions, we will write-off any transition costs not recovered during the transition period. The third part in transition cost recovery is determining the amount of electric utility revenues under frozen rates that are available to recover eligible transition costs. As directed by the CPUC, we have separated, or unbundled, the Utility's previously authorized cost-of-service electric revenues into separate categories. Unbundling enables us to allocate revenue provided by frozen electric rates into transmission, distribution, public purpose programs, and generation based upon their respective cost of service. Revenues provided by frozen rates will also be used to recover other authorized Utility costs, including nuclear decommissioning, rate reduction bond debt service, and transition cost recovery. The portion of the unbundled revenue to be provided for transition cost recovery is based upon mechanisms approved by the CPUC. Revenue provided for recovery of most non-nuclear transition costs is based upon their acceleration 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 acceleration of our investment in Diablo Canyon from a period ending in 2016 to a five-year period ending December 31, 2001. The fourth part of transition cost recovery addresses the depreciation and amortization of transition costs. Based on our Utility's evaluation of the transition plan and state legislation and CPUC decisions related to the transition plan, our Utility is depreciating Diablo Canyon over a five-year period ending December 31, 2001. The change in depreciable life increased Diablo Canyon's depreciation expense for 1997, as 22 compared to 1996, by $583 million. In addition, most generation-related regulatory assets are being amortized on a straight-line basis, in accordance with their recovery under the transition plan, beginning January 1, 1998. Further, upon valuation of generation facilities, any losses will be amortized over the remaining transition period as a transition cost. Any gains will be recognized and used to reduce other transition costs at the time of valuation. In the fifth part of transition cost recovery we compare (1) revenues provided for transition cost recovery with (2) the costs associated with accelerated recovery including the depreciation of Diablo Canyon and the amortization of regulatory assets. If the revenues exceed the accelerated costs, certain transition costs may be further accelerated until all transition costs are recovered or March 31, 2002, whichever is earlier. If the accelerated costs exceed the revenues, the costs will be deferred. At the end of the transition period, any over collection of these amounts will be returned to customers. Our Utility's ability to recover its transition costs during the transition period will be dependent on several factors. These factors include: (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs approved by the CPUC, (3) the market value of our Utility-owned generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, (6) the extent to which our Utility's authorized revenues to recover distribution costs are increased or decreased, and (7) the market price of electricity. Given our current evaluation of these factors, we believe that we will recover our transition costs. Also, we believe that our regulatory assets and Utility-owned generation plants are not impaired. 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. During 1997, the difference between billed revenues and authorized revenues was used to recover transition costs, including most of the accelerated Diablo Canyon sunk costs. . Generation Divestiture The third element of the transition plan is the economic divestiture of Utility- owned generation facilities. In 1997, California utilities produced a significant portion of the state's electric generation needs. In a competitive market, the CPUC is concerned that this level of generation may give existing utilities undue influence on the PX price. As part of the transition plan, we have agreed to sell a significant portion of our generation facilities to alleviate this concern. In 1997, we agreed to sell three electric Utility-owned fossil-fueled generating plants to Duke Energy through an auction process. The aggregate bid accepted for these plants was $501 million. These three fossil-fueled plants have a combined book value at December 31, 1997, of approximately $370 million and a combined capacity of 2,645 megawatts (MW). The three power plants were Morro Bay, Moss Landing, and Oakland. The sales have been approved by the CPUC. However, they are still subject to approval of the transfer of various permits and licenses. Additionally, the Utility will retain liability for required environmental remediation of any pre- closing soil or groundwater contamination at these plants. As a result of retaining such environmental remediation liability, we do not expect any material adverse impact on the Utility's or our financial position or results of operations. We expect the sale of these three plants to close in 1998. We plan to conduct another auction of our four remaining Utility-owned fossil- fueled plants and our Utility-owned geothermal facilities in the first half of 1998. These additional plants have a combined generating capacity of 4,718 MW and a combined book value at December 31, 1997, of approximately $790 million. Together the eight power plants represent 98 percent of the Utility's fossil- fueled generating capacity and all of the Utility's geothermal generating capacity. The eight plants currently generate approximately 22 percent of the Utility's total electric sales. The Utility is currently evaluating its options related to its remaining generation facilities and may decide not to retain its economic investment in those facilities. During the transition period, the proceeds from the sale of our plants will be used to offset transition costs associated with other Utility electric generation facilities. Therefore, we do not expect any material adverse impact on the Utility's or our financial position or results of operations 23 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition from any of these divestitures. . Customer Impacts of Transition Plan Under the transition plan, once the PX and ISO are operational, all electric customers may choose their electric commodity provider. During the transition period, all customers will be billed for electricity used, for transmission and distribution services, for public purpose programs, and for recovery of transition costs. Customers who choose to purchase their electricity from non- Utility energy providers will see a change in their total bill only to the extent that their contracted electric commodity price differs from the PX price. Transition costs are being recovered from all Utility distribution customers through a nonbypassable charge regardless of their choice in commodity provider. As transition costs are nonbypassable, we do not believe that the availability of choice to our customers will have a material impact on our ability to recover transition costs. In addition to supplying commodity electric power, once the ISO and PX are operational, commodity electric providers will be able to choose the method of billing their customers and whether to provide their customers with metering services. We will track cost savings that result when billing, metering, and related services within our Utility's service territory are provided by another entity. Once these cost savings, or credits, are approved by the CPUC and the customer's energy provider is performing billing and metering services, we will reduce the customer's bill by the savings. The electric provider will then charge their customers for these services. To the extent that these credits equate to our actual cost savings from reduced billing, metering, and related services, we do not expect a material adverse impact on the Utility's or our financial condition or results of operations. . The Transition Plan and SFAS No. 71 In 1997, to comply with new accounting guidance, we discontinued the application of SFAS No. 71 for the generation portion of our Utility business. The new accounting guidance requires that regulatory assets and liabilities (both those in existence today and those created under the terms of the transition plan) be allocated to the portion of the business from which the source of the regulated cash flows is derived. Under the transition plan, generation-related regulatory assets are eligible for recovery as transition costs from customers of our Utility's electric distribution business. Accordingly, they have been allocated to that business. As we believe the recovery of our transition costs from these customers is probable, the discontinuation of application of SFAS No. 71 to our Utility's generation business did not have a material effect on our financial statements. As of December 31, 1997, we have recorded approximately $1.5 billion of generation-related regulatory assets. Given the current regulatory environment, our Utility's electric transmission business and most areas of the Utility's electric distribution business are expected to remain rate regulated and, as a result, we will continue to apply the provisions of SFAS No. 71. However, as discussed above, once the ISO and PX are operational, unregulated electric providers may provide their customers with billing and metering services. In the future, electric providers may be allowed to provide other distribution services (such as customer inquiries and uncollectibles). Any discontinuance of SFAS No. 71 for these portions of our Utility electric distribution business is not expected to have a material adverse impact on the Utility's or our financial position or results of operations. The Gas Business: Through our Utility, we sell natural gas and provide natural gas transportation services to our customers. Currently, our customers may buy gas directly from competing suppliers and purchase gas transmission- and distribution-only services from us. Our Utility transmission system transports gas throughout California to our distribution system which, in turn, delivers gas to end-use customers. Utility transmission and distribution services for all customers have historically been "bundled" or sold together at a combined rate. Most of our industrial and larger commercial (noncore) customers purchase their commodity gas from marketers and brokers. Substantially all residential and smaller commercial (core) customers buy their commodity gas as well as transmission and distribution services from us. In order to ensure competitive prices for our customers, we negotiate short-term supply arrangements with numerous providers. 24 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 is expected to be implemented in March 1998. More specifically, the Accord has four principal elements: 1. The Accord separates or "unbundles" the rates for our Utility's gas transportation system. Once the Accord is implemented, we will offer transmission and distribution services as separate and distinct services to our noncore customers. Unbundling will give these customers the opportunity to select from a menu of services offered by the Utility and will enable them to pay only for the services that they use. Unbundling will also make access to the transmission system possible for all gas marketers and shippers, as well as noncore end-users. As a result, the Accord will make our Utility's transmission system more accessible to a greater number of customers. 2. The Accord increases the opportunity for our Utility's core customers to select the commodity gas supplier of their choice. Greater customer choice will increase competition among suppliers providing gas to core customers and will reduce our role in purchasing gas for such customers. Despite these changes, we will continue to purchase gas as a regulated supplier for those who request it. 3. The Accord changes the way in which our Utility's costs of purchasing gas for core customers through 2002 are regulated. Prior to 1994, we were authorized to collect all costs of purchased gas through rates as long as the CPUC deemed the costs to be reasonable. The Accord replaces the CPUC reasonableness reviews with the core procurement incentive mechanism (CPIM), a form of incentive ratemaking. Apart from a "tolerance band" constructed around market benchmarks, the CPIM will reward us if we are able to buy gas for our core customers at a price below a specified market index price and penalize us if we buy gas at a price above the market index price. Actual core procurement costs measured from 1994 through 1997 have generally been within the CPIM tolerance band. 4. The Accord settled various regulatory issues involving our 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 for the period from March 1998 through December 2002 for our Utility's core and noncore customers and eliminates regulatory protection for variations in sales volumes for noncore transmission revenues. As a result, we will be 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 distribution services will continue to be set by the CPUC and designed to provide us an opportunity to recover our costs of service and include a return on our investment. Our Response to Changes in Our Industry: ACQUISITIONS AND SALES Over the past several years, we have taken steps to take advantage of the changing electric and gas markets and to become a national energy company. In order to accomplish this, we have made several investments to position ourselves to expand and to integrate in the gas transmission market, the energy trading market, the retail energy services market, and the unregulated electric generation market. These investments are highlighted below. In 1997, we created a gas transmission business in Texas, through the acquisitions of Teco Pipeline Company (Teco) and Valero Energy Corporation's (Valero) natural gas and natural gas liquids business. Teco was acquired for approximately $378 million, consisting of $317 million of PG&E Corporation common stock and the purchase of a $61 million note. Valero was acquired for approximately $1.5 billion, consisting of 31 million shares of PG&E Corporation common stock along with the assumption of approximately $780 million in long- term debt. Valero pipeline operations have averaged approximately $147 million in revenues and expenses each month since August 1997. Teco pipeline operations have averaged approximately $6 million in revenues and expenses each month since January 1997. Further, in 1997, we strengthened our presence in the 25 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition unregulated electric generation market. We completed our acquisition of our partner's interests in three U.S. Generating Company (USGen) partnerships we previously jointly owned with Bechtel Enterprises, Inc. (Bechtel). We are now the sole owner of USGen, the largest independent power developer and manager operating in the United States, U.S. Operating Services Company, USGen's operations and maintenance affiliate, and its power marketing affiliate USGen Power Services, L.P. Additionally, we have acquired all or part of Bechtel's interest in several power projects that are affiliated with USGen. Through its affiliates, USGen has ownership or management interests in 15 electric generating facilities operating in eight states. Additionally, in 1997, USGen was selected to buy a portfolio of electric generating assets and power supply contracts from the New England Electric System (NEES) for $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, financing requirements are expected to total approximately $1.75 billion, of which approximately $1 billion will be funded through a combination of project level debt as well as debt of USGen. In addition, $750 million of equity will be contributed over two years and will be financed initially using short-term debt of PG&E Corporation. The assets contain a balance of hydro, coal, oil, and natural gas generation facilities. The acquisition is subject to regulatory approval, among other conditions. We expect the acquisition to be completed in the second half of 1998. Maximizing the benefits of the gas transmission, electric generation, and energy service supply businesses on a national level requires procurement, scheduling, and risk management capabilities. In order to assure the efficient management of the risks and rewards of supplying our customers' energy needs and to optimize our corporate assets, we have combined the trading and risk management businesses of Energy Source (acquired in 1996), Teco, and Valero to form PG&E Energy Trading (PG&E ET). PG&E ET purchases and resells energy commodities and related financial instruments in major domestic markets, serving PG&E Corporation's other unregulated businesses, unaffiliated utilities, and large end-use customers. Our national energy strategy does not currently contemplate continued investment in international generation projects. Therefore, in 1997, we sold to Bechtel our interest in International Generating Company, Ltd., a joint venture between PG&E Corporation and Bechtel, together with all of our related project interests. The sale has resulted in an after-tax gain of approximately $120 million, which was recorded in 1997. REGULATORY ACTIVITY This section discusses items affecting future Utility authorized revenues: the 1999 General Rate Case; a 1998 Revenue Adjustment associated with the electric transition plan, discussed above; and the 1998 Cost of Capital Proceeding. Any requested change in authorized electric revenues resulting from any of these proceedings would not impact our Utility's customer electric rates because these rates are frozen in accordance with the electric transition plan. However, increases in authorized electric revenues would reduce the amount of revenue available to recover transition costs. . The Utility's 1999 General Rate Case (GRC) In December 1997, we filed our 1999 GRC application with the CPUC. During the GRC process, the CPUC examines our Utility's non-fuel related costs to determine the amount we can charge customers. In our application, we requested an increase in our Utility's authorized revenues, effective January 1, 1999. The requested increase consists of an increase of $693 million in electric utility revenues and an increase of $501 million in gas utility revenues over authorized 1997 revenues. The 1999 GRC will not affect the authorized revenues of electric and gas transmission services or of gas storage services. The authorized revenues for each of these services are determined in other proceedings. Electric transmission revenues for 1998 are expected to be authorized by the FERC. In 1997, we filed an application with the FERC requesting electric transmission revenues of $305 million. The requested revenue is consistent with electric transmission revenues in CPUC-authorized 1997 electric rates. The FERC- authorized rates will be effective 26 once the ISO and PX are operational. Also, revenues associated with gas transmission and storage services were authorized as part of the Gas Accord. See Gas Business, above, for a discussion of the Gas Accord. . The Utility's 1998 Electric Revenue Adjustment The electric transition plan (see Electric Business above) allows for increases in revenues previously authorized in the 1996 GRC for system safety and reliability. The CPUC increased 1997 authorized revenues for these services by $160 million. The CPUC also authorized an additional $86 million in 1998 for system safety and reliability. . The Utility's 1998 Cost of Capital Proceeding The CPUC authorized a cost of capital for the Utility's gas and electric distribution assets in 1998 of 9.17 percent. The authorized 1998 cost of common equity is 11.20 percent which is lower than the 11.60 percent authorized for 1997. The CPUC contends that this decrease reflects the level of business and regulatory risks the Utility now faces. The authorized cost of capital will decrease 1998 authorized electric and gas revenue by approximately $25 million and $9 million, respectively. The Utility has requested a rehearing of the Cost of Capital decision. We believe that business and regulatory risks have not been reduced and that our requested cost of common equity of 12.25 percent is more appropriate. The rehearing is expected to occur in 1998. Consistent with the rate freeze, there will be no change in electric rates in 1998 and the lower authorized revenues will be offset by additional transition cost recovery. As discussed above, the CPUC separately reduced the authorized return on our Utility's electric generation-related assets to 7.13 percent. Also, the return on our Utility's electric transmission-related assets will be determined by the FERC in 1998. Finally, the return on our Utility's gas transmission and storage businesses was incorporated in rates established in the Gas Accord. Liquidity and Capital Resources: Cash Flows from Operating Activities: Net cash provided by operating activities totaled $2.6, $2.6, and $3.3 billion in 1997, 1996, and 1995, respectively. Cash from operations exceeded capital requirements for all years presented. Cash Flows from Financing Activities: PG&E CORPORATION During 1997, we issued $752 and $317 million of common stock to acquire Valero and Teco, respectively. These acquisitions did not require the use of cash. We also issued $54 million of common stock through the Dividend Reinvestment Plan and the employee Long-Term Incentive Plan. Also in 1997, we repurchased $804 million of our common stock on the open market and paid dividends of $524 million. During 1996 and 1995, we issued $220 and $140 million shares of common stock, respectively, through the employee Savings Fund Plan, the Dividend Reinvestment Plan, and the employee Long-Term Incentive Plan. In 1996, we repurchased $455 million shares of our common stock and paid dividends of $844 million. In 1995, we repurchased $601 million shares of our common stock and paid dividends of $891 million. In previous years, the Board of Directors (Board) authorized us to repurchase up to $2 billion of our common stock on the open market or in negotiated transactions. In 1997, the Board increased this authorization to a total of $4 billion. Through December 31, 1997, the Corporation had repurchased approximately $2.3 billion of its common stock under this program. As part of this Board authorization, in January 1998, the Corporation entered into a specific transaction to repurchase 37 million shares of common stock at $30.3125 per share. In connection with this transaction, the Corporation has entered into a forward contract with an investment institution. The 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 the Corporation through purchases on the open market or through privately negotiated transactions. The contract is anticipated to expire by December 31, 1998. In January 1997, we established a $500 million revolving credit facility, and in August 1997, we entered into an 27 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition additional $500 million temporary credit facility. Both of these credit facilities are to be used for general corporate purposes. There were no borrowings under these facilities at December 31, 1997. During 1997, our unregulated business operations issued $30 million and retired $109 million of long-term debt. Also in 1997, we assumed approximately $780 million of long-term debt in connection with the acquisition of Valero. In 1996, we entered into additional loan agreements of $92 million to finance the PG&E Gas Transmission acquisition of assets in Queensland, Australia. During 1995, our unregulated business operations issued $400 million of bonds, $70 million of medium-term notes, and $109 million of commercial paper which is classified as long-term debt. Substantially all of the proceeds from the debt issued in 1995 were used to refinance outstanding debt. The classification of commercial paper as long-term debt is based on the availability of committed credit facilities expiring in 2000 and management's intent to maintain such amounts in excess of one year. UTILITY In 1997, 1996, and 1995, our Utility redeemed or repurchased $225, $1,113, and $758 million, respectively, of long-term debt to manage the overall balance of our Utility's capital structure. Long-term debt maturing during 1997, 1996, and 1995 was not refinanced. In 1997, our Utility issued $360 million of variable rate pollution control bonds and repurchased the same amount of fixed-rate pollution control bonds. In 1996, our Utility repurchased $988 million of variable and fixed interest rate pollution control mortgage bonds and loan agreements which were replaced with variable interest rate pollution control loan agreements. 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 will be used by the Utility to retire debt and reduce equity. The bonds will facilitate a 10 percent rate reduction for residential and eligible small commercial customers, effective January 1, 1998. During the term of the bonds, the Utility will collect from its residential and small commercial customers a separate nonbypassable charge on behalf of the special purpose entity to recover principal, interest, and related costs of the bonds. The bonds are secured by the separate charge, which does not belong to the Utility. The bonds are not secured by the Utility's assets. While the bonds are reflected as a long-term liability on our balance sheet, creditors of the Utility do not have any recourse to revenues from the separate charge. 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 mutual agreement between the Utility and the banks. There were no borrowings under this credit facility in 1997 or 1996. The table below provides information about our debt obligations and the rate reduction bonds at December 31, 1997:
Expected maturity date 1998 1999 2000 2001 2002 Thereafter Total(1) - ---------------------------------------------------------------------------------------------------- (in millions) Long-term debt Fixed rate $659 $294 $460 $330 $515 $4,712 $6,970 Average interest rate 5.8% 6.3% 6.0% 7.8% 7.7% 7.2% 6.9% Variable rate - - - - - $1,348 $1,348 Rate reduction bonds $125 $265 $280 $300 $290 $1,641 $2,901 Average interest rate 5.9% 6.0% 6.2% 6.2% 6.3% 6.4% 6.3%
(1) The fair value of long-term debt and rate reduction bonds is essentially the same as the book value. 28 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. Capital Spending: Our estimated capital spending for the next three years is shown below:
Year ended December 31, 1998 1999 2000 - -------------------------------------------------------------- (in millions) Utility capital requirements $1,835 $1,739 $1,617 Other capital requirements 2,091 246 192 Maturing debt obligations and sinking funds 784 559 740 -------------------------- Total $4,710 $2,544 $2,549 ==========================
Utility expenditures will be primarily for improvements to facilities to enhance their efficiency and reliability, to extend their useful lives, and to comply with environmental laws and regulations. Other capital expenditures will be primarily for the purchase of electric generating assets and power supply contracts for NEES, discussed above in Acquisitions and Sales. Environmental Matters: We are subject to laws and regulations established to both improve and maintain the quality of the environment. Where our properties contain hazardous substances, these laws and regulations require us to remove or remedy the effect on the environment. At December 31, 1997, the Utility expects to spend $232 million for clean-up costs at identified sites over the next 30 years. If other responsible parties fail to pay or identified outcomes change, then these costs may be as much as $442 million. Of the $232 million, the Utility expects to recover $157 million in future rates. The liability also includes $58 million related to power plant decommissioning for environmental clean-up, which the Utility recovered through depreciation. Additionally, the Utility is seeking recovery of costs from insurance carriers and from other third parties. (See Note 13 of Notes to Consolidated Financial Statements.) Year 2000: In 1995, we began and presently continue to review and assess our computer and information systems in anticipation of the year 2000. At that time, our software programs and systems for critical financial and operational information will be required to recognize this date in the next millennium. The Year 2000 issue exists because many computer programs use only two digits to identify a year in the date field and were developed without considering the impact of the upcoming change in the century. We currently expect to complete critical software conversion modifications by the end of 1998. We do not currently anticipate any material adverse impact on the Utility's or our financial position or results of operations as a result of the Year 2000 issue. Accounting for Decommissioning Expense: In 1996, the Financial Accounting Standards Board issued an Exposure Draft (ED) entitled "Accounting for Certain Liabilities Related to Closure and Removal of Long-Lived Assets." A revised ED is expected in 1998. If the ED is adopted as currently proposed: (1) annual expense for power plant decommissioning could increase, and (2) the estimated total cost for power plant decommissioning could be recorded as a liability, with recognition of an increase in the cost of the related power plant, rather than accrued over time as accumulated depreciation. We do not believe that this change, if implemented as proposed, would have a material adverse impact on the Utility's or our financial position or results of operations. (See Note 2 of Notes to Consolidated Financial Statements for discussion of electric industry restructuring.) Legal Matters: In the normal course of business, the Corporation and the Utility are named as a party in a number of claims and lawsuits. Substantially all of these have been litigated or settled with no material adverse impact on either the Utility's or our financial position or results of operations. See Note 13 of Notes to Consolidated Financial Statements for further discussion of significant pending legal matters. 29 Inflation: Financial statements, which are prepared in accordance with generally accepted accounting principles, report operating results in terms of historic 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 future results of operations. Price Risk Management: We have established an officer-level price risk management committee and adopted a price risk management policy approved by the Board for our trading and risk management activities. The price risk management committee oversees implementation of our policy, approves the trading and price risk management policies of our subsidiaries, and monitors compliance with the policy. Our price 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). We use derivatives for hedging purposes primarily to offset underlying commodity price risks. We also participate in markets using derivatives to create liquidity and maintain a market presence. Such derivatives include forward contracts, futures, swaps, and options. 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. In 1997, we approved and implemented trading and risk management policies for PG&E ET and continued to seek regulatory approval to manage commodity price risks in our Utility business. The fair value of market risk sensitive instruments (which includes our hedging and non-hedging instruments described above) as of December 31, 1997, is immaterial for financial instruments subject to commodity price risk. Additionally, as of December 31, 1997, the Corporation calculated value-at-risk based on a 95 percent confidence level using five-day holding periods. Using this methodology, the potential for near-term losses in future earnings, fair values, and cash flows from reasonably possible near-term changes in market prices for financial instruments subject to commodity price risk is immaterial. We anticipate an increase in the level of trading and risk management activity in 1998 due to expected growth in our unregulated national energy businesses and a continuing effort to manage anticipated price risks in our Utility business. Our Utility manages price risk independently from the activities in our unregulated businesses. 30 PG&E Corporation Statement of Consolidated Income
(in millions, except per share amounts) Year ended December 31, 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------ Operating Revenues Utility $ 9,495 $8,989 $9,243 Energy commodities and services 5,905 621 379 ------------------------------------ Total operating revenues 15,400 9,610 9,622 ------------------------------------ Operating Expenses Cost of energy for utility 2,974 2,709 2,403 Cost of energy commodities and services 5,511 356 47 Operating and maintenance 3,298 3,427 3,049 Depreciation and decommissioning 1,889 1,222 1,360 ------------------------------------ Total operating expenses 13,672 7,714 6,859 ------------------------------------ Operating Income 1,728 1,896 2,763 Interest expense, net (665) (632) (678) Other income and expense 201 13 79 ------------------------------------ Income Before Income Taxes 1,264 1,277 2,164 Income taxes 548 555 895 ------------------------------------ Net Income $ 716 $ 722 $1,269 ==================================== Weighted Average Common Shares Outstanding 410 413 424 Earnings Per Common Share, Basic and Diluted $ 1.75 $ 1.75 $ 2.99 Dividends Declared Per Common Share $ 1.20 $ 1.77 $ 1.96 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
31 PG&E Corporation Consolidated Balance Sheet
(in millions) At December 31, 1997 1996 - ------------------------------------------------------------------------------ Assets Current Assets Cash and cash equivalents $ 237 $ 131 Short-term investments 1,160 13 Accounts receivable Customers, net 1,514 1,152 Regulatory balancing accounts 658 444 Energy marketing 830 387 Inventories and prepayments 626 584 -------- -------- Total current assets 5,025 2,711 Property, Plant, and Equipment Utility 32,972 31,716 Gas transmission 3,484 1,594 Other 57 - -------- -------- Total property, plant, and equipment (at original cost) 36,513 33,310 Accumulated depreciation and decommissioning (16,041) (14,302) -------- -------- Net property, plant, and equipment 20,472 19,008 Other Noncurrent Assets Regulatory assets 2,337 2,518 Nuclear decommissioning funds 1,024 883 Other 1,699 1,117 -------- -------- Total noncurrent assets 5,060 4,518 -------- -------- Total Assets $ 30,557 $ 26,237 ======== ========
32 PG&E Corporation Consolidated Balance Sheet
(in millions) At December 31, 1997 1996 - ------------------------------------------------------------------------------------------------------------------ Liabilities and Equity Current Liabilities Short-term borrowings $ 103 $ 681 Current portion of long-term debt 659 210 Current portion of rate reduction bonds 125 - Accounts payable Trade creditors 754 490 Other 620 548 Energy marketing 758 388 Accrued taxes 226 310 Other 739 653 ---------------------- Total current liabilities 3,984 3,280 Noncurrent Liabilities Long-term debt 7,659 7,770 Rate reduction bonds 2,776 - Deferred income taxes 4,029 3,941 Deferred tax credits 339 380 Other 2,034 1,663 ---------------------- Total noncurrent liabilities 16,837 13,754 Preferred Stock of Subsidiary With Mandatory Redemption Provisions 6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137 Utility 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 of subsidiary, par value $25, authorized 75,000,000 shares Without mandatory redemption provisions Nonredeemable-5% to 6%, outstanding 5,784,825 shares 145 145 Redeemable-4.36% to 7.44%, outstanding 10,297,404 shares 257 257 Common stock, no par value, authorized 800,000,000 shares; issued and outstanding, 417,665,891 and 403,504,292 shares 6,366 5,728 Reinvested earnings 2,531 2,636 ---------------------- Total stockholders' equity 9,299 8,766 Commitments and Contingencies (Notes 1, 2, 3, 4, 12, and 13) - - ---------------------- Total Liabilities and Stockholders' Equity $30,557 $ 26,237 ====================== The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
33 PG&E Corporation Statement of Consolidated Cash Flows
(in millions) Year ended December 31, 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------- Cash Flows From Operating Activities Net income $ 716 $ 722 $ 1,269 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, decommissioning, and amortization 2,014 1,316 1,449 Deferred income taxes and tax credits-net (159) (150) (116) Other deferred charges and noncurrent liabilities 159 22 (25) Gain on sale of assets (120) - - Net effect of changes in operating assets and liabilities: Accounts receivable (242) (70) 200 Regulatory balancing accounts receivable (74) 302 499 Inventories (4) 32 32 Accounts payable 210 217 62 Accrued taxes (54) 36 (162) Other working capital (85) (6) 8 Other-net 257 160 99 ----------------------------- Net cash provided by operating activities 2,618 2,581 3,315 ----------------------------- Cash Flows From Investing Activities Capital expenditures (1,822) (1,230) (945) Investments in unregulated projects (75) (70) (157) Acquisitions (41) (159) - Proceeds from sale of assets 146 - 340 Other-net 21 (120) (123) ----------------------------- Net cash used by investing activities (1,771) (1,579) (885) ----------------------------- Cash Flows From Financing Activities Net increase (decrease) in short-term borrowings (587) (115) 305 Long-term debt issued 386 1,088 591 Long-term debt matured, redeemed, or repurchased-net (961) (1,472) (1,297) Proceeds from issuance of rate reduction bonds 2,881 - - Preferred stock redeemed or repurchased - - (358) Utility obligated mandatorily redeemable preferred securities issued - - 300 Common stock issued 54 220 140 Common stock repurchased (804) (455) (601) Dividends paid (524) (844) (891) Other-net (39) (14) (22) ----------------------------- Net cash used by financing activities 406 (1,592) (1,833) ----------------------------- Net Change in Cash and Cash Equivalents 1,253 (590) 597 Cash and Cash Equivalents at January 1 144 734 137 ----------------------------- Cash and Cash Equivalents at December 31 $ 1,397 $ 144 $ 734 ============================= Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 624 $ 598 $ 645 Income taxes 801 640 1,126 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
34 PG&E Corporation Statement of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities
Preferred Preferred Stock of Stock of Subsidiary Subsidiary Total Without With Additional Common Mandatory Mandatory Common Paid-in Reinvested Stock Redemption Redemption (dollars in millions) Stock Capital Earnings Equity Provisions Provisions - ------------------------------------------------------------------------------------------------------------------ Balance December 31, 1994 $2,151 $3,806 $2,677 $8,634 $733 $137 --------------------------------------------------------------------------- Net income 1,269 1,269 Common stock issued (5,316,876 shares) 27 113 140 Common stock repurchased (21,533,977 shares) (108) (195) (298) (601) Preferred securities issued(1) (12,000,000 shares) 300 Preferred stock redeemed (13,237,554 shares) (8) (8) (331) Cash dividends declared Common stock (830) (830) Other (5) (5) --------------------------------------------------------------------------- Balance December 31, 1995 2,070 3,716 2,813 8,599 402 437 --------------------------------------------------------------------------- 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 8,364 402 437 --------------------------------------------------------------------------- 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 $402 $437 =========================================================================== (1)Relates to utility obligated mandatorily redeemable preferred securities of trust holding solely Utility subordinated debentures. The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
35 Pacific Gas and Electric Company Statement of Consolidated Income
(in millions) Year ended December 31, 1997 1996 1995 - ----------------------------------------------------------------------------- Operating Revenues Electric utility $7,691 $7,160 $7,387 Gas utility 1,804 1,829 1,856 Energy commodities and services - 621 379 ---------------------- Total operating revenues 9,495 9,610 9,622 Operating Expenses Cost of electric energy 2,501 2,261 2,117 Cost of gas 473 448 286 Cost of energy commodities and services - 356 47 Operating and maintenance 2,905 3,427 3,049 Depreciation and decommissioning 1,785 1,222 1,360 ---------------------- Total operating expenses 7,664 7,714 6,859 Operating Income 1,831 1,896 2,763 Interest expense, net (570) (632) (678) Other income and expense 116 46 149 ---------------------- Income Before Income Taxes 1,377 1,310 2,234 Income taxes 609 555 895 ---------------------- Net income 768 755 1,339 Preferred dividend requirement and redemption premium 33 33 70 ---------------------- Income Available for Common Stock $ 735 $ 722 $1,269 ====================== The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
36 Pacific Gas and Electric Company Statement of Consolidated Cash Flows
(in millions) Year ended December 31, 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------------------ Cash Flows From Operating Activities Net income $ 768 $ 755 $ 1,339 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, decommissioning, and amortization 1,914 1,316 1,449 Deferred income taxes and tax credits-net (182) (150) (116) Other deferred charges and noncurrent liabilities 167 22 (25) Net effect of changes in operating assets and liabilities: Accounts receivable (582) (70) 200 Regulatory balancing accounts receivable (74) 302 499 Inventories 12 32 32 Accounts payable (80) 217 62 Accrued taxes (62) 36 (162) Other working capital (128) (6) 8 Other-net 15 127 29 --------------------------- Net cash provided by operating activities 1,768 2,581 3,315 --------------------------- Cash Flows From Investing Activities Capital expenditures (1,522) (1,230) (945) Investments in unregulated projects - (70) (157) Acquisitions - (159) - Proceeds from sale of assets - - 340 Other-net (117) (120) (123) --------------------------- Net cash used by investing activities (1,639) (1,579) (885) --------------------------- Cash Flows From Financing Activities Net increase (decrease) in short-term borrowings (681) (115) 305 Long-term debt issued 355 1,088 591 Long-term debt matured, redeemed, or repurchased-net (852) (1,472) (1,297) Proceeds from issuance of rate reduction bonds 2,881 - - Preferred stock redeemed or repurchased - - (353) Company obligated mandatorily redeemable preferred securities issued - - 300 Dividends paid (739) (844) (891) Other-net (14) (249) (488) --------------------------- Net cash used by financing activities 950 (1,592) (1,833) --------------------------- Net Change in Cash and Cash Equivalents 1,079 (590) 597 Cash and Cash Equivalents at January 1 144 734 137 --------------------------- Cash and Cash Equivalents at December 31 $ 1,223 $ 144 $ 734 =========================== Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 547 $ 598 $ 645 Income taxes 841 640 1,126
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 37 Pacific Gas and Electric Company Consolidated Balance Sheet
(in millions) At December 31, 1997 1996 - ------------------------------------------------------------------------------------------- Assets Current Assets Cash and cash equivalents $ 80 $ 131 Short-term investments 1,143 13 Accounts receivable Customers, net 1,204 1,152 Regulatory balancing accounts 658 444 Related parties 459 - Energy marketing - 387 Inventories and prepayments 523 584 ----------------------- Total current assets 4,067 2,711 Property, Plant, and Equipment Electric 26,033 25,052 Gas 6,939 8,258 ----------------------- Total property, plant, and equipment (at original cost) 32,972 33,310 Accumulated depreciation and decommissioning (15,558) (14,302) ----------------------- Net property, plant, and equipment 17,414 19,008 Other Noncurrent Assets Regulatory assets 2,283 2,518 Nuclear decommissioning funds 1,024 883 Other 359 1,117 ----------------------- Total noncurrent assets 3,666 4,518 ----------------------- Total Assets $ 25,147 $ 26,237 =======================
38 Pacific Gas and Electric Company Consolidated Balance Sheet
(in millions) At December 31, 1997 1996 - -------------------------------------------------------------------------------------------------------- Liabilities and Equity Current Liabilities Short-term borrowings $ - $ 681 Current portion of long-term debt 580 210 Current portion of rate reduction bonds 125 - Accounts payable Trade creditors 441 490 Related parties 134 - Other 578 548 Energy marketing - 388 Accrued taxes 229 310 Deferred income taxes 149 157 Other 373 496 ---------------------- Total current liabilities 2,609 3,280 Noncurrent Liabilities Long-term debt 6,218 7,770 Rate reduction bonds 2,776 - Deferred income taxes 3,304 3,941 Deferred tax credits 338 380 Other 1,810 1,663 ---------------------- Total noncurrent liabilities 14,446 13,754 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, par value $25, authorized 75,000,000 shares Without mandatory redemption provisions Nonredeemable-5% to 6%, outstanding 5,784,825 shares 145 145 Redeemable-4.36% to 7.44%, outstanding 10,297,404 shares 257 257 Common stock, no par value, authorized 800,000,000 shares, 403,504,292 shares outstanding, each year 4,582 5,728 Reinvested earnings 2,671 2,636 ---------------------- Total stockholders' equity 7,655 8,766 Commitments and Contingencies (Notes 1, 2, 3, 12, and 13) - - ---------------------- Total Liabilities and Stockholders' Equity $25,147 $26,237 ======================
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 39 Pacific Gas and Electric Company Statement of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities
Preferred Preferred Stock Stock Total Without With Additional Common Mandatory Mandatory Common Paid-in Reinvested Stock Redemption Redemption (dollars in millions) Stock Capital Earnings Equity Provisions Provisions - ------------------------------------------------------------------------------------------------------------------------------------ Balance December 31, 1994 $2,151 $ 3,806 $2,677 $ 8,634 $ 733 $137 ---------------------------------------------------------------------------- Net income 1,339 1,339 Common stock issued (5,316,876 shares) 27 113 140 Common stock repurchased (21,533,977 shares) (108) (195) (298) (601) Preferred securities issued(1) (12,000,000 shares) 300 Preferred stock redeemed (13,237,554 shares) (8) (14) (22) (331) Cash dividends declared Preferred stock (56) (56) Common stock (830) (830) Other (5) (5) ---------------------------------------------------------------------------- Balance December 31, 1995 2,070 3,716 2,813 8,599 402 437 ---------------------------------------------------------------------------- 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 8,364 402 437 ---------------------------------------------------------------------------- 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 $437 ============================================================================
(1) Relates to Company obligated mandatorily redeemable preferred securities of trust holding solely Utility subordinated debentures. The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 40 Notes to Consolidated Financial Statements Note 1: Significant Accounting Policies 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. 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 and its wholly owned and controlled subsidiaries, including the Utility (collectively, the Corporation). The Utility's consolidated financial statements include its accounts as well as those of its wholly owned and controlled subsidiaries. PG&E Corporation and the Utility have identical 1995 and 1996 consolidated financial statements because they each represent the accounts of the Utility as a 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 1997 presentation. The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) 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: The Corporation is a national energy company providing electric and gas utility services through its regulated subsidiary Pacific Gas and Electric Company and other energy related services through its unregulated integrated subsidiaries. The Utility generates electricity and procures, transmits, and distributes both electricity and natural gas to customers throughout most of Northern and Central California. Through its other subsidiaries, the Corporation: . Owns and operates natural gas pipelines, natural gas storage facilities, and natural gas processing plants in the Pacific Northwest, Texas, and Australia. . Develops, builds, operates, owns, and manages power generation facilities across the United States. . Provides customers nationwide with competitively-priced natural gas and electricity and services to manage and make more efficient their energy consumption. . Purchases and resells energy commodities and related financial instruments in major domestic markets, serving PG&E Corporation's other unregulated businesses, unaffiliated utilities, and large end-use customers. Regulation and SFAS No. 71: The Utility is regulated by the CPUC, the FERC, and the Nuclear Regulatory Commission, 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. The Corporation and the Utility account for the financial effect of regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement allows them to record certain regulatory assets and liabilities which will be included in future rates and would not be recorded under GAAP for nonregulated entities. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires the Corporation and the Utility to write off regulatory assets when they are no longer probable of recovery. On an ongoing basis, the Corporation and the Utility review their regulatory assets and liabilities for the continued applicability of SFAS No. 71 and the effect of SFAS No. 121. 41 Notes to Consolidated Financial Statements Net regulatory assets including regulatory balancing accounts receivable and net regulatory liabilities are comprised of the following:
December 31, 1997 - ------------------------------------------------------------------------------- (in millions) Electric industry restructuring transition costs/(1)/ $1,535 Unamortized loss, net of gain, on reacquired debt 296 Regulatory assets for deferred income tax 278 Regulatory balancing accounts (net) 235 Other (net) 174 ------ $2,518 ====== December 31, 1996 - -------------------------------------------------------------------------------- (in millions) Regulatory assets for deferred income tax $1,133 Unamortized loss, net of gain, on reacquired debt 377 Diablo Canyon regulatory assets 364 Regulatory balancing accounts (net) 323 Other (net) 555 ------ $2,752 ======
/(1)/ See Note 2, "Electric Industry Restructuring," for further discussion. Revenues and Regulatory Balancing Accounts: Electric and gas utility revenues recorded by the Utility include amounts for services rendered but unbilled at the end of the year. The Utility also records revenues for changes in regulatory balancing accounts established by the CPUC. Specifically, sales balancing accounts accumulate differences between authorized and actual base revenues. Energy cost balancing accounts accumulate differences between the actual cost of gas and electric energy and the revenues designated for recovery of such costs. Recovery of gas and electric energy costs through energy cost balancing accounts is subject to reasonableness reviews by the CPUC. The regulatory balancing accounts accumulate balances until they are refunded to or received from Utility customers through authorized rate adjustments. Accounting for Derivative Instruments: The Corporation, through its subsidiaries, engages in price risk management activities for both non-hedging and hedging purposes. The Corporation conducts non-hedging activities principally through its unregulated subsidiary, PG&E Energy Trading (PG&E ET), using a variety of financial instruments. These instruments include forward contracts involving the physical delivery of an energy commodity, swaps, futures, options, and other contractual arrangements. Additionally, the Corporation engages in hedging activities using futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies. The Utility manages price risk independently from the activities in our unregulated businesses. The Corporation's net gains and losses associated with price risk management activities during 1997 were immaterial. Property, Plant, and Equipment: Plant additions and replacements are capitalized. The capitalized costs include labor, materials, construction overhead, and an allowance for funds used during construction (AFUDC) or capitalized interest. 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. Property, plant, and equipment is depreciated using a straight-line remaining-life method. The Utility's composite depreciation rates were 5.00, 3.65, and 4.09 percent for the years ended December 31, 1997, 1996, and 1995, respectively. The increase in the composite rate in 1997 as compared to 1996 and 1995 reflects higher depreciation expense associated with Diablo Canyon Nuclear Power Plant (Diablo Canyon). See Note 2, Electric Industry Restructuring. 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. 42 Inventories: 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. Other inventories include materials and supplies, gas stored underground, and fuel oil. Materials and supplies and gas stored underground are valued at average cost. 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. The Utility's short-term investments consist primarily of money market funds and some commercial paper with original maturities of three months or less. These investments were made with the proceeds from the issuance of the rate reduction bonds. See Note 7, Rate Reduction Bonds. Note 2: Electric Industry Restructuring 1997 was the first year of California's transition into a new competitive electric generation market. In the new competitive market, the Utility's generation revenues will be determined principally by the market. However, market-based revenues may not be sufficient to recover (that is, to collect from customers) certain generation costs resulting from past CPUC decisions. To recover these uneconomic costs, called "transition costs," and to ensure a smooth transition to the competitive environment, the Utility, in conjunction with other California electric utilities, the CPUC, state legislators, consumer advocates, and others, developed a transition plan, in the form of state legislation, to position California for the new market environment. There are three principal elements to this transition plan: (1) an electric rate freeze and rate reduction, (2) recovery of transition costs, and (3) economic divestiture of Utility-owned generation facilities. Each one of these three elements and the impact of the transition plan on the application of SFAS No. 71 are discussed below. The transition plan will remain in effect until the earlier of March 31, 2002, or when the Utility recovers its authorized transition costs as determined by the CPUC. This period is referred to as 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. Rate Freeze and Rate Reduction During 1997, electric rates for the Utility's customers were held at 1996 levels. Effective January 1, 1998, the Utility reduced electric rates for its residential and small commercial customers by 10 percent and will hold their rates at that level. The rate freeze will continue until the end of the transition period. To pay for the 10 percent rate reduction, the Utility financed $2.9 billion of its transition costs with rate reduction bonds. See Note 7, Rate Reduction Bonds. Transition Cost Recovery Costs eligible for transition cost recovery include: (1) above-market sunk 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) and future costs, such as costs related to plant removal, (2) costs associated with the Utility's long-term contracts to purchase power at prices from Qualifying Facilities (QF) 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 that are disallowed by the CPUC for collection from customers will be written off. Sunk costs associated with Utility-owned generation facilities are currently included in the Utility customers' rates. Above-market sunk costs are those whose values recorded on the Utility's balance sheet (book value) are expected to be in excess of their market values. Conversely, below-market sunk costs are those whose market values are expected to be in excess of their book values. In general, 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. The above-market portion of sunk costs is eligible for recovery as a transition cost. The below-market portion of sunk costs will reduce other unrecovered 43 Notes to Consolidated Financial Statements transition costs. A valuation of Utility-owned generation facilities where the market value exceeds the book value could result in a material charge if the Utility retains the facility. This is because any excess of market value over book value would be used to reduce other transition costs without being collected in rates. The Utility will not be able to determine the exact amount of sunk costs that will be recoverable as transition costs until a market valuation process (appraisal, spin, or sale) is completed for each of the Utility's generation facilities. The first of these valuations occurred in 1997 when the Utility agreed to sell three of its electric plants for $501 million. This sale is expected to close during 1998 (see Generation Divestiture below). The rest of the valuation process will be completed by December 31, 2001. At December 31, 1997, the Utility's net investment in Diablo Canyon and non-nuclear generation facilities was $3.7 billion and $2.7 billion, respectively, including the plants to be sold in 1998. The Utility has agreed to purchase electric power from QFs and other power suppliers under long-term contracts expiring on various dates through 2028. Over the life of these contracts, the Utility estimates that it will purchase approximately 360 million megawatt-hours (MWh) at an average aggregate price of 6.3 cents per kilowatt-hour (kWh). To the extent that this price is 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. In addition, as of December 31, 1997, the Utility has accumulated approximately $1.5 billion of generation-related net regulatory assets. The net regulatory assets are eligible for recovery as transition costs. The CPUC has the ultimate authority to determine which costs are eligible to be recovered as transition costs. Reviews by the CPUC to determine the reasonableness of transition costs are being conducted and will continue to be conducted throughout the transition period. Under the transition plan, most transition costs must be recovered by March 31, 2002. This recovery period is significantly shorter than the recovery period of the related assets prior to restructuring. Recovery of transition costs during this shorter period is referred to as accelerated recovery. The CPUC believes that acceleration reduces risks associated with recovery of all utility generation assets, including Diablo Canyon and hydroelectric facilities. As a result, in accordance with the transition plan, the Utility is receiving a reduced return for all of its generation facilities. In 1997, the reduced return was 7.13 percent as compared to an authorized return of 9.45 percent. The reduced return on non-nuclear generation assets, effective July 28, 1997, resulted in a $24 million decrease in earnings ($.06 per share) in 1997 and will have a continued impact throughout the transition period. Although most transition costs must be recovered by March 31, 2002, certain transition costs can be included in customers' electric rates after the transition period. These costs include: (1) certain employee-related transition costs, (2) above-market payments under existing QF and power- purchase contracts, 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 the facility. During the rate freeze, this charge will not increase 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, as directed by the CPUC, the Utility has separated, or unbundled, its previously authorized cost-of-service electric revenues into separate categories. Unbundling enables the Utility to allocate revenue provided by frozen electric rates into transmission, distribution, public purpose programs, and generation based upon their respective cost of service. Revenues provided by frozen rates will also be used to recover other authorized Utility costs, including nuclear decommissioning, rate reduction bond debt service, and transition cost recovery. The portion of the unbundled revenue to be provided for transition cost recovery is based upon mechanisms approved by the CPUC. Revenue provided for recovery of most non-nuclear transition costs is based upon their acceleration 44 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 acceleration of recovery of the Utility's investment in Diablo Canyon from a period ending in 2016 to a five- year period ending December 31, 2001. Based on the Utility's evaluation of the transition plan and state legislation and CPUC decisions related to the transition plan, the Utility is depreciating Diablo Canyon over a five-year period ending December 31, 2001. The change in depreciable life increased Diablo Canyon's depreciation expense for 1997, as compared to 1996, by $583 million. In addition, most generation- related regulatory assets are being amortized on a straight-line basis, in accordance with their recovery under the transition plan, beginning on January 1, 1998. Further, upon valuation of generation facilities, any losses will be amortized over the remaining transition period as a transition cost. Any gains will be recognized and used to reduce other transition costs at the time of valuation. Any difference between (1) revenues provided for transition cost recovery and (2) the costs associated with accelerated recovery, including the depreciation of Diablo Canyon and the amortization of regulatory assets, is being tracked. If the revenues exceed the accelerated costs, certain transition costs may be further accelerated until all transition costs are recovered or March 31, 2002, whichever is earlier. If the accelerated costs exceed the revenues, the costs will be deferred. At the end of the transition period, any overcollection of these amounts will be returned to customers. The Utility's ability to recover its transition costs during the transition period will be dependent on several factors. These factors include: (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs approved by the CPUC, (3) the market value of 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 its current evaluation of these factors, the Utility believes that it will recover its transition costs. Also, the Utility believes that its regulatory assets and generation facilities are not impaired. 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. During 1997, the difference between billed revenues and authorized revenues was used to recover transition costs, including most of the accelerated Diablo Canyon sunk costs. Generation Divestiture In 1997, California utilities produced a significant portion of the state's electric generation needs. In a competitive market, the CPUC is concerned that this level of generation may give existing utilities undue influence on the market price for power. As part of the transition plan, the Utility has agreed to sell a significant portion of its generation facilities to alleviate this concern. In 1997, the Utility agreed to sell three fossil-fueled electric generating plants to Duke Energy through an auction process. The aggregate bid accepted for these plants was $501 million. These three plants have a combined book value at December 31, 1997, of approximately $370 million and a combined capacity of 2,645 megawatts (MW). The three power plants were Morro Bay, Moss Landing, and Oakland. The sales have been approved by the CPUC. However, they are still subject to approval of the transfer of various permits and licenses. Additionally, the Utility will retain liability for required environmental remediation of any pre- closing soil or groundwater contamination at these plants. The Utility does not expect any material adverse impact on its financial position or results of operations as a result of retaining such environmental remediation liability. The Utility expects the sale of these three plants to close in 1998. The Utility plans to conduct another auction of its four remaining Utility- owned fossil-fueled plants and its geothermal facilities in the first half of 1998. These additional plants have a combined generating capacity of 4,718 MW and a combined book value at December 31, 1997, of approximately $790 million. Together the eight power plants represent 98 percent of the Utility's fossil-fueled generating capacity and all of the 45 Notes to Consolidated Financial Statements Utility's geothermal generating capacity. The eight plants generate approximately 22 percent of the Utility's total electric sales. The Utility is currently evaluating its options related to its remaining generation facilities and may decide not to retain its economic investment in those facilities. During the transition period, the proceeds from the sale of the plants will be used to offset transition costs associated with other Utility electric generation facilities. Therefore, the Corporation does not expect any material adverse impact on its or the Utility's financial position or results of operations from any of these divestitures. The Transition Plan and SFAS No. 71 The Utility accounts for the financial effect of regulation in accordance with SFAS No. 71. This statement allows the Utility to record certain regulatory assets and liabilities which would be included in future rates and would not be recorded under generally accepted accounting principles for nonregulated entities. In addition, SFAS No. 121, "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to be Disposed Of," requires the Utility to write off regulatory assets when they are no longer probable of recovery. In 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) reached a consensus on Issue No. 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71" (EITF 97-4), which provided authoritative guidance on the applicability of SFAS No. 71 during the transition period. The EITF requires the Utility to discontinue the application of SFAS No. 71 for the generation portion of its operations as of July 24, 1997, the effective date of EITF 97-4. The discontinuation of application of SFAS No. 71 did not have a material effect on the Utility's financial statements because EITF 97-4 requires that regulatory assets and liabilities (both those in existence today and those created under the terms of the transition plan) be allocated to the portion of the business from which the source of the regulated cash flows is derived. The Utility has accumulated approximately $1.5 billion of generation-related regulatory assets which are eligible for collection from distribution customers and which the Utility considers probable of recovery. Substantially all regulatory assets are reflected on the Utility's and PG&E Corporation's balance sheets in regulatory balancing accounts and regulatory assets. In addition, above-market generation-related sunk costs, which will be determined as part of the market valuation process discussed above, and above-market QF costs will be eligible for collection from distribution customers. Given the current regulatory environment, the Utility's electric transmission business and most areas of the distribution business are expected to remain regulated, and as a result, the Utility will continue to apply the provisions of SFAS No. 71. However, in May 1997, the CPUC issued decisions that allow customers to choose their electricity provider beginning January 1, 1998. The decisions also allow the electricity provider to provide their customers with billing and metering services, and indicate that electricity providers may be allowed to provide other distribution services (such as customer inquiries and uncollectibles) in the future. Any discontinuance of SFAS No. 71 for these portions of the Utility's electric distribution business is not expected to have a material adverse impact on the Utility's or the Corporation's financial position or results of operations. Note 3: Natural Gas Matters Gas Accord: In 1998, the Utility will implement a multi-party settlement, called the Gas Accord (Accord), that will continue to restructure the gas industry in California. The Accord, which received CPUC approval in 1997, has four principal elements. First, the Accord separates the rates for gas transmission services from gas distribution services. Second, the Accord increases the opportunity for residential and smaller commercial (core) customers to choose the commodity gas supplier of their choice. Third, the Accord establishes a new way to measure the reasonableness of the Utility's gas purchases based upon market indices. Fourth, 46 the Accord settled numerous regulatory issues between the Utility and other parties. The resolution of these issues did not have a material adverse impact on the Utility's or the Corporation's financial position or results of operations. The Accord also establishes gas transmission rates for the period from March 1998 through December 2002 for all customers and eliminates regulatory protection for variations in sales volumes for transmission revenues from industrial and larger commercial (noncore) customers. As a result, the Utility will be at risk for variations between actual and forecasted noncore transmission throughput volumes. However, these variations are not expected to have a material adverse impact on the Utility's or the Corporation's financial position or results of operations. 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 total amounts the Utility paid under these contracts were approximately $255, $269, and $245 million in 1997, 1996, and 1995, respectively. These amounts include payments made by the Utility to PG&E Gas Transmission (PG&E GT) of approximately $49, $57, and $70 million in 1997, 1996, and 1995, respectively. These payments are eliminated in the consolidated financial statements of the Corporation. Also, a contract for Southwest pipeline capacity expired in December 1997. Total payments associated with this contract were approximately $149 million in 1997. The following table summarizes the Utility's capacity on various pipelines and the related annual payments for capacity at December 31, 1997:
Total Firm Annual Capacity Demand Held Charges Contract Pipeline Company (MMcf/d) (in millions) Expiration ============================================================================ PG&E GT 600 $44 Oct. 2005 Transwestern 200 29 Mar. 2007 NOVA 600 20 Oct. 2001 ANG 600 13 Oct. 2005
As a result of regulatory changes, the Utility no longer procures gas for most of its 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 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. Note 4: Acquisitions and Sales In December 1996, the Corporation acquired Energy Source, a wholesale commodity marketing company for approximately $23 million. The acquisition was accounted for as a purchase. In January 1997, the Corporation acquired Teco Pipeline Company (Teco) for approximately $378 million, consisting of $317 million of PG&E Corporation common stock and the purchase of a $61 million note. Teco has investments in natural gas pipelines and gas gathering and processing facilities located in Texas. Teco also owns a gas marketing company in Houston. The acquisition was accounted for as a purchase. In April 1997, PG&E Enterprises (Enterprises), a wholly owned subsidiary of PG&E Corporation, sold its interest in International Generating Company, Ltd. (InterGen), a joint venture between Enterprises and Bechtel Enterprises, Inc. (Bechtel), and all of its related project interests, to Bechtel. The sale has resulted in an after-tax gain of approximately $120 million. On July 31, 1997, the Corporation completed its acquisition of Valero Energy Corporation's (Valero) natural gas business located in Texas. Valero also owns a gas marketing business. PG&E Corporation issued approximately 31 million shares of its common stock to acquire Valero along with the assumption of approximately $780 million in long-term debt, equating to a purchase price of approximately $1.5 billion. The acquisition was accounted for as a purchase. In August 1997, the Corporation announced that its subsidiary, U.S. Generating Company (USGen), had agreed 47 Notes to Consolidated Financial Statements to buy a portfolio of electric generating assets and power supply contracts from the New England Electric System (NEES) for $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, financing requirements are expected to total approximately $1.75 billion, of which approximately $1 billion will be funded through a combination of project level debt as well as debt of USGen. In addition, $750 million of equity will be contributed over two years and will be financed initially using short-term debt of PG&E Corporation. The assets to be acquired contain a balance of hydro, coal, oil, and natural gas generation facilities. We expect the acquisition to be completed in the second half of 1998. The acquisition is subject to regulatory approval, among other conditions. In September 1997, the Corporation completed an acquisition of two partnerships previously jointly owned by it and Bechtel. In December 1997, the Corporation closed the acquisition of a third such partnership. The Corporation is now the sole owner of USGen, an independent power developer and manager, U.S. Operating Services Company, USGen's operations and maintenance affiliate, and USGen's power marketing affiliate, USGen Power Services, L.P. Additionally, the Corporation has acquired all or part of Bechtel's interest in several power projects that are affiliated with USGen. In connection with the acquisitions completed in 1996 and 1997, discussed above, the Corporation recorded approximately $432 million of goodwill, subject to final purchase price adjustments. These amounts will be amortized on a straight-line basis over a 30 to 40 year period. Note 5: Common and Preferred Stock and Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures Common Stock: PG&E Corporation: The Corporation has authorized 800 million shares of no-par common stock of which 418 million shares were issued and outstanding as of December 31, 1997. Prior to the formation of the Corporation, the Utility held $5 par value common stock. The stock was converted to PG&E Corporation common stock (no par value) at the formation of the holding company. As of December 31, 1997, the Board of Directors has authorized the repurchase of up to $1.7 billion of common stock on the open market or in negotiated transactions. In January 1998, the Corporation repurchased 37 million shares of its common stock at $30.3125 per share. In connection with this transaction, the Corporation has entered into a forward contract with an investment institution. The 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 the Corporation through purchases on the open market or through privately negotiated transactions. The contract is anticipated to expire by December 31, 1998. Utility: The CPUC set a number of conditions when PG&E Corporation was formed as a holding company. One of these conditions requires the Utility to maintain, on average, its CPUC-authorized capital structure, potentially limiting the amount of dividends the Utility may pay PG&E Corporation. At December 31, 1997, the Utility was in compliance with its CPUC-authorized capital structure. The Corporation believes that the Utility will continue to meet this condition in the future without affecting the Corporation's ability to pay common stock dividends to common shareholders. Preferred Stock: Holders of the Utility's nonredeemable preferred stock at December 31, 1997, have rights to annual dividends per share ranging from $1.25 to $1.50. The Utility's redeemable preferred stock without mandatory redemption provisions 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, 1997, range from $1.09 to $1.86 and from $25.00 to $27.25, respectively. In January 1998, the Utility redeemed all of its 48 7.44% redeemable preferred stock, of which $65 million was outstanding at December 31, 1997, at a redemption price of $25 per share. The Utility's redeemable preferred stock with mandatory redemption provisions consists of 3 million shares of the 6.57% and 2.5 million shares of the 6.30% series at December 31, 1997. 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. The estimated fair value of the Utility's preferred stock with mandatory redemption provisions at December 31, 1997, and 1996, was approximately $146 million and $135 million, respectively, based on quoted market prices. 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. 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 approximately $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 approximately $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. The subordinated debentures may be redeemed at the Utility's option beginning in 2000 at par 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, 1997, and 1996, was approximately $304 million and $291 million, respectively, based on quoted market prices. Note 6: Long-Term Debt Long-term debt at December 31, 1997, and 1996, consisted of the following:
December 31, 1997 1996 ========================================================================== (in millions) Utility long-term debt First and refunding mortgage bonds Maturity Interest rates 1998-2001 4.63% to 8.75% $ 861 $ 880 2002-2006 5.875% to 7.875% 1,354 1,392 2007-2019 6.35% to 8.875% 160 520 2020-2026 5.85% to 8.80% 2,498 2,628 --------------------- Principal amounts outstanding 4,873 5,420 Unamortized discount net of premium (42) (50) --------------------- Total mortgage bonds 4,831 5,370 Pollution control loan agreements, variable rates, due 2016-2026 1,348 988 Unsecured medium-term notes, 4.93% to 9.9%, due 1998-2014 587 829 Debentures, 12%, due 2000 - 58 Other long-term debt 32 31 --------------------- Total Utility long-term debt 6,798 7,276 Long-term debt of unregulated business operations 1,520 704 --------------------- Total long-term debt 8,318 7,980 Current portion of long-term debt 659 210 --------------------- Long-term debt, net of current portion $7,659 $7,770 =====================
49 Notes to Consolidated Financial Statements Utility: Mortgage Bonds: All real properties and substantially all personal properties of the Utility are subject to the lien of the mortgage bonds, and the Utility is required to make semi-annual sinking fund payments for the retirement of the bonds. Additional mortgage bonds may be issued subject to CPUC approval, up to a maximum total amount outstanding of $10 billion. The Utility redeemed or repurchased $167 million and $182 million of mortgage bonds in 1997 and 1996, respectively, with interest rates ranging from 5.375 percent to 8.875 percent. Included in the total of outstanding mortgage bonds at December 31, 1997, and 1996, are $705 million of mortgage bonds held in trust for the California Pollution Control Financing Authority (CPCFA) with interest rates ranging from 5.85 percent to 8.875 percent and maturity dates ranging from 2007 to 2026. In addition to these mortgage bonds, the Utility holds long-term loan agreements with the CPCFA as described below. Pollution Control Loan Agreements: Loan agreements from the CPCFA totaled $1,348 million and $988 million, respectively, at December 31, 1997, and 1996. Interest rates on the loans vary with average annual interest rates for 1997 ranging from 3.01 percent to 3.92 percent. These loans are subject to redemption by the holder under certain circumstances. These loans are secured by irrevocable letters of credit which mature as early as 2000. Unregulated Business Operations: Long-term debt of unregulated business operations, as of December 31, 1997, consisted primarily of first mortgage bonds of $409 million, medium-term and senior notes of $404 million, unsecured notes and debentures of $397 million, and other long-term debt of $310 million. The fixed interest rates on these obligations range from 6.33 percent to 9.25 percent, with maturities ranging from 1998 to 2025. Outstanding long-term debt as of December 31, 1996, consisted primarily of $470 million of unsecured notes and debentures, and other long-term debt of $234 millon. Repayment Schedule: At December 31, 1997, the Corporation's combined aggregate amounts of maturing long-term debt and sinking fund requirements for the years 1998 through 2002, are $659, $294, $460, $330, and $515 million, respectively. The Utility's share of those sinking fund requirements is $601, $217, $223, $233, and $389 million, respectively. Fair Value: The estimated fair value of the Corporation's total long-term debt at December 31, 1997, and 1996, was approximately $8.3 billion and $8.0 billion, respectively. The estimated fair value of the Utility's total long-term debt at December 31, 1997, and 1996, was approximately $7.0 billion and $7.3 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 7: 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. The rate reduction bonds have maturities ranging from ten months to ten years, and bear interest at rates ranging from 5.94 percent to 6.48 percent. The bonds are secured solely by the transition property and there is no recourse to the Utility or the Corporation. At December 31, 1997, the combined aggregate amounts of maturing rate reduction bonds, for the years 1998 50 through 2002, are $125, $265, $280, $300, and $290 million, respectively. The estimated fair value of the rate reduction bonds was approximately $2.9 billion at December 31, 1997. 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 the Corporation, and the transition property is legally not an asset of the Utility or the Corporation. Note 8: Short-Term Borrowings In January 1997, the Corporation established a $500 million revolving credit facility, which expires in 2002. In August 1997, the Corporation entered into an additional $500 million temporary credit facility which expires in 1998. Both of these credit facilities are to be used for general corporate purposes. There were no borrowings under these credit facilities at December 31, 1997. In addition, 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 mutual agreement between the Utility and the banks. There were no borrowings under this credit facility in 1997 or 1996. At December 31, 1997, the Corporation had outstanding $103 million of short-term bank borrowings at a 6.9 percent weighted average interest rate. In addition to borrowing from banks on a short-term basis, the Corporation and certain of its subsidiaries sell commercial paper, having a maturity of one to ninety days, to provide financing for various corporate purposes. The carrying amount of short-term borrowings approximates fair value. At maturity, commercial paper can be either reissued or replaced with borrowings from the revolving credit facility. At December 31, 1997, the Corporation had no commercial paper outstanding. At December 31, 1996, the Utility had outstanding $681 million of commercial paper at a 5.83 percent weighted average interest rate. At December 31, 1997, the Utility required no short-term borrowings due to the receipt of the rate reduction bond proceeds. Note 9: 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 radio activity 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 approximately $1.4 billion in 1997 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, 1997, 1996, and 1995, nuclear decommissioning costs recovered in rates were $33, $33, and $54 million, respectively. Based on the 1997 site study, the amount approved to be recovered in rates in 1998 and annually, until the commencement of decommissioning, is $33 million. This amount will be reviewed in future rate proceedings. At December 31, 1997, the total nuclear decommissioning obligation accrued was $1.0 billion and was included in the balance sheet classification of Accumulated Depreciation and Decommissioning. Decommissioning costs recovered in rates are placed in external trust funds. The earnings on the external trusts accumulate in the fund balance and are included in the 51 Notes to Consolidated Financial Statements balance sheet classification of Other Noncurrent Assets. 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 of these nuclear decommissioning funds:
Year ended December 31, Maturity Dates 1997 1996 =============================================================================== (in millions) Amortized cost U.S. government and agency issues 1998-2027 $ 422 $375 Equity securities - 257 281 Municipal bonds and other 1998-2021 70 33 Gross unrealized holding gains 287 199 Gross unrealized holding losses (12) (5) ------------------- Fair value $1,024 $883 ===================
The proceeds received during 1997 and 1996 from sales of securities were approximately $1.4 billion and $1.5 billion in each year, respectively. During 1997 and 1996, the gross realized gains on sales of securities held as available-for-sale were $40 million and $14 million, respectively, and the gross realized losses on sales of securities held as available-for-sale were $24 million and $20 million, 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 2012. 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. Note 10: Employee Benefit Plans Retirement Plans: Several of the Corporation's subsidiaries provide noncontributory defined benefit pension plans for their employees. The Utility's plan represents substantially all of the plan assets and the projected benefit obligation. All descriptions and assumptions are based on the Utility's plan which covers the largest number of employees. The schedules below aggregate all of the Corporation's plans. Pension benefits are based on an employee's years of service and base salary. The Corporation's policy is to fund each year not more than the maximum amount deductible for federal income tax purposes and not less than the minimum legal funding requirement. The following schedule reconciles the plans' funded status to the prepaid pension cost or accrued pension liability recorded on the Consolidated Balance Sheet:
December 31, 1997 1996 ================================================================================ (in millions) Actuarial present value of benefit obligations Vested benefits $(3,659) $(3,486) Nonvested benefits (198) (178) ---------------------- Accumulated benefit obligation (3,857) (3,664) Effect of projected future compensation increases (561) (529) ---------------------- Projected benefit obligation (4,418) (4,193) Plan assets at market value 6,419 5,526 ---------------------- Plan assets in excess of projected benefit obligation 2,001 1,333 Unrecognized prior service cost 121 83 Unrecognized net gain (2,135) (1,559) Unrecognized net transition obligation 74 86 ---------------------- Prepaid pension cost (accrued pension liability) $ 61 $ (57) ======================
The Utility's share of the plan assets in excess of projected benefit obligation for 1997 and 1996 was $2.0 and $1.3 billion, respectively. The Utility's share of the prepaid pension cost for 1997 was $75 million and the accrued pension liability for 1996 was $53 million. Plan assets consist primarily of common stocks and fixed income securities. Unrecognized prior service costs and net gains are amortized on a straight-line basis over the 52 average remaining service period of active plan participants. The transition obligation is being amortized over 17.5 years from 1987. Using the projected unit credit actuarial cost method, net pension income consisted of the following components:
Year ended December 31, 1997 1996 1995 ================================================================================ (in millions) Service cost for benefits earned $ (101) $(100) $ (83) Interest cost (313) (302) (291) Actual return on plan assets 1,139 811 968 Net amortization and deferral (598) (353) (586) ----------------------------------- Net pension income $ 127 $ 56 $ 8 ===================================
The Utility's share of the plan's net pension income for 1997, 1996, and 1995 was $128, $57, and $8 million, respectively. Net pension income or cost is calculated using expected return on plan assets. 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 pension income or cost. In 1997, 1996, and 1995, 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 or cost determined for accounting purposes and that for rate making, which is based on a funding approach. The following actuarial assumptions were used in determining the plans' funded status and net pension income. Year-end assumptions are used to compute funded status, while prior year-end assumptions are used to compute net pension income.
December 31, 1997 1996 1995 ================================================================================ (in millions) Discount rate 7.5% 7.5% 7.25% Rate of future compensation increases 5% 5% 5% Expected long-term rate of return on plan assets 9% 9% 9%
Postretirement Benefits Other Than Pensions: Several of the Corporation's subsidiaries provide contributory defined benefit medical plans for retired employees and their eligible dependents and noncontributory defined benefit life insurance plans for retired employees. The Utility's plan represents substantially all of the plan assets and the total accumulated postretirement benefit obligation. All descriptions and assumptions are based on the Utility's plan which covers the largest number of employees. The schedules below aggregate all of the Corporation's plans. Most employees retiring at or after age 55 are eligible for these benefits. The medical benefits are provided through plans administered by an insurance carrier or a health maintenance organization. Certain retirees are responsible for a portion of the costs for these benefits. The CPUC has authorized the Utility to recover these benefits 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 appropriate trusts. The policy is to fund each year an amount consistent with the basis for rate recovery. The following schedule reconciles the medical and life insurance plans' funded status to the postretirement benefit liability recorded on the Consolidated Balance Sheet:
December 31, 1997 1996 ========================================================================== (in millions) Accumulated postretirement benefit obligation Retirees $(400) $(445) Other fully eligible participants (140) (132) Other active plan participants (367) (344) -------------------- Total accumulated postretirement benefit obligation (907) (921) Plan assets at market value 823 666 -------------------- Accumulated postretirement benefit obligation in excess of plan assets (84) (255) Unrecognized prior service cost 20 22 Unrecognized net gain (375) (227) Unrecognized transition obligation 393 420 -------------------- Accrued postretirement benefit liability $ (46) $ (40) ====================
The Utility's share of the accumulated postretirement benefit obligation in excess of plan assets for 1997 and 1996 was $64 and $249 million, respectively. The Utility's share of the accrued postretirement benefit liability for 1997 and 1996 was $29 and $38 million, respectively. Plan assets consist primarily of common stocks and 53 Notes to Consolidated Financial Statements fixed income securities. Unrecognized prior service costs are amortized on a straight-line basis over the average remaining years of service to full eligibility of active plan participants. Unrecognized net gains are amortized on a straight-line basis over the average remaining years of service of active plan participants. The transition obligation is being amortized over 20 years from 1993. Using the projected unit credit actuarial cost method, net postretirement medical and life insurance cost consisted of the following components:
Year ended December 31, 1997 1996 1995 ================================================================================ (in millions) Service cost for benefits earned $(21) $(22) $(17) Interest cost (65) (66) (65) Actual return on plan assets 144 91 109 Amortization of unrecognized prior service cost (2) (2) (2) Amortization of transition obligation (25) (26) (26) Net amortization and deferral (71) (38) (70) ---------------------------------- Net postretirement benefit income (cost) $(40) $(63) $(71) ==================================
The Utility's share of the plan's net postretirement benefit cost for 1997, 1996, and 1995 was $38, $61, and $71 million, respectively. The discount rate, rate of future compensation increases, and expected long-term rate of return on plan assets used in accounting for the postretirement benefit plans for 1997, 1996, and 1995 were the same as those used for the pension plan. The assumed health care cost trend rate for 1998 is approximately 9.5 percent, grading down to an ultimate rate in 2005 of approximately 6.0 percent. The effect of a one-percentage-point increase in the assumed health care cost trend rate for each future year would increase the accumulated postretirement benefit obligation at December 31, 1997, by approximately $76 million and the 1997 aggregate service and interest costs by approximately $8 million. Net postretirement benefit cost is calculated using expected return on plan assets. The difference between actual and expected return on plan assets is included in net amortization and deferral and is considered in the deter- mination of future postretirement benefit cost. In 1997, 1996, and 1995, actual return on plan assets exceeded expected return. 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, 1997, 24.5 million shares of common stock have been authorized for award under the program. At December 31, 1997, stock options on 6,181,819 shares, granted at option prices ranging from $16.75 to $34.25, were outstanding, of which 1,902,545 were exercisable. In 1997, 3,048,400 options were granted at an average option price of $22.55. Outstanding stock options expire ten years and one day after the date of grant and become exercisable on a cumulative basis at one-third each year commencing two years from the date of grant. In 1997, 1996, and 1995, stock options on 232,815, 72,960, and 235,568 shares, respectively, were exercised at option prices ranging from $16.75 to $33.13. Effective January 1, 1996, the Corporation adopted SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS No. 123 requires the Corporation to disclose stock option costs based on the fair value of options granted. For the years ended December 31, 1997 and 1996, the fair value of options granted was not material to the Corporation's results of operations or earnings per share. Note 11: Income Taxes The Corporation files a consolidated federal income tax return that includes domestic subsidiaries in which its ownership is 80 percent or more. 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. 54 The significant components of income tax expense were:
PG&E Corporation Utility Year ended December 31, 1997 1996 1995 1997 1996 1995 ================================================================================== (in millions) Current $ 707 $ 705 $1,011 $ 791 $ 705 $1,011 Deferred (119) (132) (98) (142) (132) (98) Tax credits-net (40) (18) (18) (40) (18) (18) -------------------------------------------------------- Total income tax expense $ 548 $ 555 $ 895 $ 609 $ 555 $ 895 ========================================================
The significant components of net deferred income tax liabilities were:
PG&E Corporation Utility December 31, 1997 1996 1997 1996 ===================================================================================================== (in millions) Deferred income tax assets $1,108 $1,308 $ 962 $1,308 Deferred income tax liabilities: Regulatory balancing accounts 311 294 311 294 Plant in service 3,621 3,624 3,144 3,624 Income tax regulatory asset 430 454 420 454 Other 924 1,034 540 1,034 --------------------------------------------------- Total deferred income tax liabilities 5,286 5,406 4,415 5,406 --------------------------------------------------- Total net deferred income taxes $4,178 $4,098 $3,453 $4,098 =================================================== Classification of net deferred income taxes: Included in current liabilities $ 149 $ 157 $ 149 $ 157 Included in noncurrent liabilities 4,029 3,941 3,304 3,941 --------------------------------------------------- Total net deferred income taxes $4,178 $4,098 $3,453 $4,098 ===================================================
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, 1997 1996 1995 1997 1996 1995 =============================================================================================================================== 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) 5.3 3.8 5.0 4.6 3.7 4.8 Effect of regulatory treatment of depreciation differences 8.1 6.0 3.2 7.5 5.9 3.2 Tax credits-net (3.2) (1.4) (0.8) (2.9) (1.4) (0.8) Effect of lower taxes on foreign earnings (2.2) - - - - - Other-net 0.3 - (1.0) - (0.8) (2.1) ------------------------------------------------------ Effective tax rate 43.3% 43.4% 41.4% 44.2% 42.4% 40.1% ======================================================
55 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 12: Commitments Letters of Credit: The Utility uses approximately $335 million in standby letters of credit to secure future workers' compensation liabilities. Restructuring Trust Guarantees: Tax-exempt trusts have been established to oversee the development of the operating framework for the competitive generation market (See Note 2, Electric Industry Restructuring). 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. 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 1998 through 2001. Total capacity payments are expected to remain at current levels during this period. Deliveries from these power producers account for approximately 18 percent of the Utility's 1997 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 on the accompanying balance sheet. At December 31, 1997, the total discounted future payments remaining under early termination or suspension contracts is $53 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 provider's retention of the FERC's authorization) and variable payments for operation and maintenance costs incurred by the providers. These contracts expire on various dates from 2004 to 2031. These costs are also recoverable in rates. At December 31, 1997, the undiscounted future minimum payments under these contracts are $34 million for each of the years 1998 through 2002 and a total of $349 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately four percent of the Utility's 1997 electric energy requirements. The amount of energy received and the total payments made under all of these power-purchase contracts were:
Year ended December 31, 1997 1996 1995 - ------------------------------------------------------------------------------------------------ (in millions) Kilowatt-hours received 24,389 26,056 26,468 Energy payments $ 1,157 $ 1,136 $ 1,140 Capacity payments $ 538 $ 521 $ 484 Irrigation district and water agency payments $ 56 $ 52 $ 50
Note 13: Contingencies Nuclear Insurance: The Utility has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). Under this policy, if a nuclear generating facility of a member utility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum assessments of $23 million (property damage) and $7 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. An additional $8.7 billion of coverage is provided by secondary financial protection which provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in 56 claims in excess of $200 million, the Utility may be assessed up to $159 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation: The Corporation may be required to pay for environmental remediation at sites where the Corporation 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 materials which may be determined to present a significant threat to human health or the environment because of an actual or potential release of hazardous substances. Under CERCLA, the Corporation's financial responsibilities may include 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 sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. 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. It is reasonably possible that a change in the estimate will 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 at December 31, 1997, of $232 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 $442 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 at sites for which the Utility is responsible. This upper limit of the range of costs was estimated using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change. Of the $232 million liability discussed above, the Utility expects to recover $157 million in future rates. The liability also includes $58 million related to power plant decommissioning for environmental clean-up, which the Utility recovered through depreciation. Additionally, the Utility is seeking recovery of costs from insurance carriers and from other third parties. The Corporation believes the ultimate outcome of these matters will not have a material adverse impact on its or the Utility's financial position or results of operations. Helms Pumped Storage Plant (Helms): Helms is a three-unit hydroelectric combined generating and pumped storage plant owned by the Utility. At December 31, 1997, the Utility's net investment was $691 million. This net investment is comprised of the pumped storage facility (including regulatory assets of $51 million), common plant, and dedicated transmission plant. As part of the 1996 General Rate Case decision in December 1995, the CPUC directed the Utility to perform a cost- effectiveness study of Helms. In July 1996, the Utility submitted its study, which concluded that the continued operation of Helms is cost effective. The Utility recommended that the CPUC take no action and address Helms along with other generating plants in the context of electric industry restructuring. Under electric industry restructuring, the uneconomic, above-market portion of Helms is eligible for recovery as a transition cost. However, the Utility will be placed at risk to recover its future operating costs in the newly restructured electric generation market. 57 Notes to Consolidated Financial Statements Because the CPUC has not specifically addressed the cost-effectiveness study, the Utility is currently unable to predict whether there will be further changes in rate recovery. The Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or the Utility's financial position or results of operations. Legal Matters: Chromium Litigation: In 1994 through 1997, several civil suits were filed against the Utility on behalf of approximately 3,000 individuals. The suits seek an unspecified 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. 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. The Corporation believes that the ultimate outcome of this matter will not have a material adverse 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, now known as PG&E Gas Transmission, Texas Corporation (GTT), GTT succeeded to the litigation described below. GTT and various of its affiliates are defendants in at least two class action suits and five separate suits filed by various Texas cities. The class action suits involve plaintiffs that serve as class representatives for classes consisting of every municipality in Texas (excluding certain cities which filed separate suits) in which any of the defendants engaged in business activities related to natural gas or natural gas liquids or sold or supplied gas or used public rights-of-way. Generally, these cities allege, among other things, that (1) the defendants that own or operate pipelines have occupied city property and conducted pipeline operations without the cities' consent and without compensating the cities, and (2) the defendants that are gas marketers have 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. The Corporation believes that the ultimate outcome of these matters will not have a material adverse impact on its financial position. 58 Note 14: Segment Information The Corporation's business segments consist of the Utility and Unregulated Business Operations (consisting of gas transmission, electric generation, and energy services and commodities). The Corporation's business segment information was:
Pacific Gas and Electric Company Unregulated Electric Gas Total Business Corporate (in millions) Utility Utility Utility Operations and Other Total - ----------------------------------------------------------------------------------------------------------------------------- 1997 Operating revenues $ 7,691 $ 1,804 $ 9,495 $5,905 $ -- $15,400 Intersegment revenues(1) 13 90 103 446 (549) -- ------------------------------------------------------------------------------ Total operating revenues 7,704 1,894 9,598 6,351 (549) 15,400 ------------------------------------------------------------------------------ Depreciation and decommissioning 1,521 264 1,785 104 -- 1,889 Operating income before income taxes(2) 1,510 321 1,831 (82) (21) 1,728 Capital expenditures 1,196 333 1,529 341 -- 1,870 Total assets at year end(3) 19,546 5,601 25,147 6,224 (814) 30,557 1996 Operating revenues $ 7,160 $ 1,829 $ 8,989 $ 621 $ -- $ 9,610 Intersegment revenues(1) 12 70 82 58 (140) -- ------------------------------------------------------------------------------ Total operating revenues 7,172 1,899 9,071 679 (140) 9,610 ------------------------------------------------------------------------------ Depreciation and decommissioning 920 256 1,176 46 -- 1,222 Operating income before income taxes(2) 1,758 52 1,810 84 2 1,896 Capital expenditures 922 309 1,231 173 -- 1,404 Total assets at year end(3) 18,431 5,136 23,567 2,858 (188) 26,237 1995 Operating revenues $ 7,387 $1,856 $ 9,243 $ 379 $ -- $ 9,622 Intersegment revenues(1) 13 85 98 68 (166) -- ------------------------------------------------------------------------------ Total operating revenues 7,400 1,941 9,341 447 (166) 9,622 ------------------------------------------------------------------------------ Depreciation and decommissioning 1,007 267 1,274 86 -- 1,360 Operating income before income taxes(2) 2,267 420 2,687 71 5 2,763 Capital expenditures 680 195 875 90 -- 965 Total assets at year end(3) 19,441 5,248 24,689 2,578 (396) 26,871
(1) Intersegment electric and gas revenues are accounted for at tariff rates prescribed by the CPUC. (2) General corporate expenses are allocated in accordance with FERC Uniform System of Accounts and requirements of the CPUC. (3) Utility includes an allocation of common plant in service and allowance for funds used during construction. (4) Corporate and other assets consist of cash and cash equivalents, short-term investments, receivables transferred from affiliates, and other assets. (5) Includes consolidating eliminations. 59 Quarterly Consolidated Financial Data (Unaudited) Due to the seasonal nature of the Utility business and the scheduled refueling outages for Diablo Canyon, operating revenues, operating income, and net income are not generated evenly every quarter during the year. PG&E Corporation 1997: All four quarters of 1997 reflected an increase in revenues and expenses due to the acquisitions discussed in the Notes to the Consolidated Financial Statements. In the second quarter of 1997, other income increased primarily due to the gain on the sale of International Generating Company, Ltd., which was partially offset by write-downs of certain nonregulated investments. Utility 1997: All four quarters of 1997 reflected an increase in operating revenues primarily due to the revisions to the Diablo Canyon ratemaking structure, changes in sales volume provided by the Utility's energy rate recovery mechanisms, and an increase in energy cost revenues to recover energy cost increases. Operating expenses increased primarily due to the increases in Diablo Canyon depreciation and the cost of energy. 1996: In the second quarter of 1996, operating expenses increased primarily due to the settlement of a litigation claim. In the third quarter of 1996, operating expenses increased primarily due to charges for gas transportation commitments. In the fourth quarter of 1996, operating revenues and operating expenses increased primarily due to the purchase of Energy Source in December 1996. Other income decreased due to write-downs of certain nonregulated investments. The Corporation's common stock is traded on the New York, Pacific, and Swiss stock exchanges. There were approximately 180,000 common shareholders of record at December 31, 1997. Dividends are paid on a quarterly basis.
Quarter ended December 31 September 30 June 30 March 31 - ---------------------------------------------------------------------------------------------------------------------------- (in millions, except per share amounts) 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 1996 PG&E Corporation and Utility Operating revenues $2,700 $2,522 $2,139 $2,249 Operating income 509 525 288 574 Net income 141 225 104 252 Earnings per common share, basic and diluted .34 .55 .25 .61 Dividends declared per common share .30 .49 .49 .49 Common stock price per share High 24.25 23.88 23.75 28.38 Low 20.88 19.50 21.50 22.38
60 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 the accompanying consolidated balance sheets of PG&E Corporation (a California corporation) and subsidiaries and of Pacific Gas and Electric Company (a California corporation) and subsidiaries as of December 31, 1997, and 1996, and the related statements of consolidated income, cash flows, and common stock equity, preferred stock, and preferred securities for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the management of PG&E Corporation and of 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 overall 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, 1997, and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP San Francisco, California February 9, 1998 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 the 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 is taking 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 are conducted in conformity with applicable laws and with their commitment to ethical conduct. 61 Directors Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company* Richard A. Clarke Chairman of the Board, Retired, Pacific Gas and Electric Company Harry M. Conger Chairman of the Board, Homestake Mining Company David A. Coulter Chairman and Chief Executive Officer, BankAmerica Corporation and Bank of America NT&SA C. Lee Cox Vice Chairman, Retired, AirTouch Communications, Inc. and President and Chief Executive Officer, Retired, AirTouch Cellular William S. Davila President Emeritus, The Vons Companies, Inc. (retail grocery) Robert D. Glynn, Jr. Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation and Chairman of the Board, Pacific Gas and Electric Company David M. Lawrence, MD Chairman and Chief Executive Officer, Kaiser Foundation Health Plan, Inc. and Kaiser Foundation Hospitals Richard B. Madden Chairman of the Board and Chief Executive Officer, Retired, Potlatch Corporation (diversified forest products) Mary S. Metz Dean, University Extension, University of California, Berkeley Rebecca Q. Morgan President and Chief Executive Officer, Joint Venture: Silicon Valley Network (nonprofit collaborative addressing critical issues facing Silicon Valley) Carl E. Reichardt Chairman of the Board and Chief Executive Officer, Retired, Wells Fargo & Company and Wells Fargo Bank, N.A. John C. Sawhill President and Chief Executive Officer, The Nature Conservancy (international environmental organization) Alan Seelenfreund Chairman of the Board and former Chief Executive Officer, McKesson Corporation (distributor of pharmaceuticals and health care products) Gordon R. Smith* President and Chief Executive Officer, Pacific Gas and Electric Company Barry Lawson Williams President, Williams Pacific Ventures, Inc. (venture capital and real estate, consulting, and mediation) Permanent Committees of PG&E Corporation and Pacific Gas and Electric Company** Executive Committees Within limits, may exercise powers and perform duties of the Boards. Robert D. Glynn, Jr., Chair Harry M. Conger Richard B. Madden Mary S. Metz Carl E. Reichardt Gordon R. Smith** Audit Committee Reviews financial statements and internal audit and control procedures with independent public accountants. Harry M. Conger, Chair C. Lee Cox William S. Davila Mary S. Metz Barry Lawson Williams Finance Committee Reviews long-term financial and capital investment policies and objectives, and actions required to achieve those objectives. Richard B. Madden, Chair Richard A. Clarke David A. Coulter Carl E. Reichardt John C. Sawhill Barry Lawson Williams Nominating and Compensation Committee Recommends candidates for nomination as directors, recommends compensation and employee benefit policies and practices, and reviews planning for executive development and succession. Carl E. Reichardt, Chair David A. Coulter David M. Lawrence, MD John C. Sawhill Alan Seelenfreund Public Policy Committee Reviews public policy issues which could significantly affect customers, shareholders, employees, or the communities served, and recommends plans and programs to address such issues. Mary S. Metz, Chair Richard A. Clarke William S. Davila Rebecca Q. Morgan John C. Sawhill ** The composition of the Boards of Directors is the same, except that Gordon R. Smith is a member of the Pacific Gas and Electric Company Board of Directors only. ** Except for the Executive Committee, all Committees listed above are committees of the PG&E Corporation Board of Directors. The Executive Committees of the PG&E Corporation and Pacific Gas and Electric Company Boards have the same members, except that Gordon R. Smith is a member of the Pacific Gas and Electric Company Executive Committee only. 62 Officers PG&E Corporation Robert D. Glynn, Jr. Chairman of the Board, Chief Executive Officer, and President Tony F. DiStefano Senior Vice President, Corporate Development Scott W. Gebhardt Senior Vice President Thomas W. High Senior Vice President, Administration and External Relations Jack F. Jenkins-Stark Senior Vice President Joseph P. Kearney Senior Vice President L. E. Maddox Senior Vice President Michael E. Rescoe Senior Vice President, Chief Financial Officer, and Treasurer G. Brent Stanley Senior Vice President, Human Resources Bruce R. Worthington Senior Vice President and General Counsel Leslie H. Everett Vice President and Corporate Secretary Christopher P. Johns Vice President and Controller Jackalyne Pfannenstiel Vice President, Business Planning Greg S. Pruett Vice President, Corporate Communications Daniel D. Richard, Jr. Vice President, Governmental Relations Linda Y. H. Cheng Assistant Corporate Secretary Wondy S. Lee Assistant Corporate Secretary Eric Montizambert Assistant Corporate Secretary Gabriel B. Togneri Assistant Treasurer Pacific Gas and Electric Company Robert D. Glynn, Jr. Chairman of the Board Gordon R. Smith President and Chief Executive Officer Kent M. Harvey Senior Vice President, Chief Financial Officer, and Treasurer E. James Macias Senior Vice President and General Manager, Generation, Transmission, and Supply Business Unit James K. Randolph Senior Vice President and General Manager, Distribution and Customer Service Business Unit Daniel D. Richard, Jr. Senior Vice President, Governmental and Regulatory Relations Gregory M. Rueger Senior Vice President and General Manager, Nuclear Power Generation Business Unit Shan Bhattacharya Vice President, Distribution Engineering and Planning Thomas E. Bottorff Vice President, Rates and Account Services Jeffrey D. Butler Vice President, Distribution Operations, Maintenance, and Construction Barbara Coull Williams Vice President, Human Resources Leslie H. Everett Vice President and Corporate Secretary Katheryn M. Fong Vice President, Customer Revenue Transactions Roger J. Gray Vice President, General Services Robert L. Harris Vice President, Community Relations Russell M. Jackson Vice President, Customer Service Christopher P. Johns Vice President and Controller Junona A. Jonas Vice President, Gas and Electric Supply Steven L. Kline Vice President, Regulatory Relations Thomas C. Long Vice President, General Rate Case Project William R. Mazotti Vice President, Gas and Electric Transmission Roger J. Peters Vice President and General Counsel Robert P. Powers Vice President, Diablo Canyon Operations and Plant Manager Frank J. Regan Vice President, Governmental Relations Lawrence F. Womack Vice President, Nuclear Technical Services Linda Y. H. Cheng Senior Assistant Corporate Secretary Wondy S. Lee Assistant Corporate Secretary Eric Montizambert Assistant Corporate Secretary Gabriel B. Togneri Assistant Treasurer U.S. Generating Company Joseph P. Kearney President and Chief Executive Officer P. Chrisman Iribe Executive Vice President and Chief Operating Officer PG&E Gas Transmission Jack F. Jenkins-Stark President and Chief Executive Officer Terrence E. Ciliske President and Chief Executive Officer of PG&E Gas Transmission-Texas Michael J. McDonald Managing Director of PG&E Gas Transmission - Australia PG&E Energy Services Scott W. Gebhardt President and Chief Executive Officer James C. Davis Senior Vice President, Integrated Services William R. Doucette Senior Vice President, Sales PG&E Energy Trading L. E. Maddox President and Chief Executive Officer 63 Shareholder Information Shareholder Services Office 77 Beale Street, Room 2600 San Francisco, CA 94105-1814 Call Toll Free 1.800.367.7731 Fax 415.973.7831 For financial and other information about PG&E Corporation and Pacific Gas and Electric Company, please visit our web sites, www.pgecorp.com and www.pge.com If you have questions about your account or need copies of PG&E Corporation's or Pacific Gas and Electric Company's publications, please write or call the Shareholder Services Office at: Manager of Shareholder Services David M. Kelly Mail Code B26B P.O. Box 770000 San Francisco, CA 94177-0001 1.800.367.7731 If you have general questions about PG&E Corporation or Pacific Gas and Electric Company, please write or call the Corporate Secretary's Office: Corporate Secretary Leslie H. Everett One Market, Spear Tower, Suite 2400 San Francisco, CA 94105-1108 415.973.2880 Securities analysts, portfolio managers, or other representatives of the investment community should write or call the Investor Relations Office: Manager of Investor Relations David E. Kaplan One Market, Spear Tower, Suite 2400 San Francisco, CA 94105-1108 415.973.3007 PG&E Corporation General Information 415.973.7000 Pacific Gas and Electric Company General Information 415.973.7000 Stock Held in Brokerage Accounts ("Street Name") When you purchase your stock and it is held for you by your broker, the shares are listed with us in the broker's name, or "street name." We do not know the identity of the individual shareholders who hold their shares in this manner-we simply know that a broker holds a number of shares which may be held for any number of investors. If you hold your stock in a street name account, you receive all dividend payments, tax forms, publications, and proxy materials through your broker. If you are receiving unwanted duplicate mailings, you should contact your broker to eliminate the duplications. PG&E Corporation Dividend Reinvestment Plan If you hold PG&E Corporation or Pacific Gas and Electric Company stock in your own name, rather than through a broker, you may automatically reinvest dividend payments from common and/or preferred stock in shares of PG&E Corporation common stock through the Dividend Reinvestment Plan (the "Plan"). You may obtain a Plan prospectus and enroll by contacting the Shareholder Services Office. If your certificates are held by a broker (in "street name"), you are not eligible to participate in the Plan. Direct Deposit of Dividends If you hold stock in your own name, rather than through a broker, you may have your common and/or preferred dividends transmitted to your bank electronically. You may obtain a direct deposit authorization form by contacting the Shareholder Services Office. Replacement of Dividend Checks If you hold stock in your own name and do not receive your dividend check within five business days after the payment date, or if a check is lost or destroyed, you should notify the Shareholder Services Office so that payment may be stopped on the check and a replacement mailed. Lost or Stolen Stock Certificates If you hold stock in your own name and your stock certificate has been lost, stolen, or in some way destroyed, you should notify the Shareholder Services Office immediately. [LOGO OF RECYCLED PAPER] Pages 17-64 printed on recycled paper. 64 EX-23 16 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our reports dated February 9, 1998, included or incorporated by reference in this Form 10-K, into the 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), and (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). /s/ Arthur Anderson LLP San Francisco, California March 4, 1998 EX-24.1 17 RESOL OF BOFD OF PG&E CORP & PACIFIC GAS & ELEC CO Exhibit 24.1 RESOLUTION OF THE ----------------- BOARD OF DIRECTORS OF --------------------- PG&E CORPORATION ---------------- February 18, 1998 ----------------- BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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, WONDY S. LEE, 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 on February 18, 1998; 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 4th day of March, 1998. Wondy S. Lee ------------------------ Wondy S. Lee Assistant Corporate Secretary PG&E CORPORATION [CORPORATE SEAL] RESOLUTION OF THE ----------------- BOARD OF DIRECTORS OF --------------------- PACIFIC GAS AND ELECTRIC COMPANY -------------------------------- February 18, 1998 ----------------- BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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, WONDY S. LEE, do hereby certify that I am an 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 on February 18, 1998, 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 4th day of March, 1998. Wondy S. Lee --------------------------- Wondy S. Lee Assistant Corporate Secretary PACIFIC GAS AND ELECTRIC COMPANY [CORPORATE SEAL] EX-24.2 18 POWER 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, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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 18th day of February, 1998. Richard A. Clarke Richard B. Madden Harry M. Conger Mary S. Metz David A. Coulter Rebecca Q. Morgan C. Lee Cox Carl E. Reichardt William S. Davilla John C. Sawhill Robert D. Glynn, Jr. Barry Lawson Williams David M. Lawrence, MD POWER OF ATTORNEY ROBERT D. GLYNN, 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, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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 18th day of February, 1998. Robert D. Glynn, Jr. -------------------------------- Robert D. Glynn, Jr. 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, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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 18th day of February, 1998. 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, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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 18th day of February, 1998. Richard A. Clarke Richard B. Madden Harry M. Conger Mary S. Metz David A. Coulter Rebecca Q. Morgan C. Lee Cox Carl E. Reichardt William S. Davilla John C. Sawhill Robert D. Glynn, Jr. Gordon R. Smith David M. Lawrence, MD Barry Lawson Williams 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, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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 18th day of February, 1998. 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, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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 18th day of February, 1998. 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, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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 18th day of February, 1998. Christopher P. Johns -------------------------------- Christopher P. Johns EX-27.1 19 FINANCIAL DATA 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 YEAR DEC-31-1997 JAN-01-1997 DEC-31-1997 PER-BOOK 20,472 644 5,025 2,767 1,649 30,557 6,366 0 2,531 8,897 437 402 7,579 103 0 80 659 0 0 0 12,400 30,557 15,400 548 13,672 13,672 1,728 201 1,929 665 716 0 716 485 438 2,618 1.75 1.75
EX-27.2 20 FINANCIAL DATA SCHEDULE
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 PACIFIC GAS AND ELECTRIC 1,000,000 YEAR DEC-31-1997 JAN-01-1997 DEC-31-1997 PER-BOOK 17,414 0 4,067 2,560 1,106 25,147 2,018 2,564 2,671 7,253 437 402 6,218 0 0 0 580 0 0 0 10,257 25,147 9,495 609 7,664 7,664 1,831 116 1,947 570 768 33 735 699 408 1,768 0 0
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